Horizontal
Directional
Drilling
Training
Manual
A Training Program Presented
by
Horizontal Drilling International
Houston, Texas, USA & Paris, France
for
Sumitomo Metal Industries, Ltd.
Osaka & Tokyo, Japan
February 1999
-i
© 1999 Horizontal Drilling International
Houston, Texas, USA, & Paris, France
All rights reserved.
This publication, including all paper and electronic copies, is strictly confidential and the sole
property of Horizontal Drilling International. No part of this publication may be reproduced, stored in a
retrieval system, or transmitted in any form or by any means electronic, mechanical, recording, or
otherwise, without the prior written permission of Horizontal Drilling International.
Illustrations produced by ALBACORE, Paris, France.
Technical editing, desktop publishing, and electronic publishing by
The Write Enterprise, Houston, Texas, USA.
Contents
Chapter 1
Planning and Scheduling
Chapter 2
Engineering
Chapter 3
Steering
Chapter 4
Reaming
Chapter 5
Pullback
Chapter 6
Mud
Appendix A
Units and Abbreviations
Appendix B
Glossary
-iii
Chapter 1: Planning and Scheduling
Introduction ........................................................................................ 1-1
Horizontal directional drilling .............................................................................. 1-1
The importance of planning and scheduling ...................................................... 1-1
Case study ......................................................................................................... 1-1
Dimensions and characteristics of the crossing ...............................................................1-1
Soil investigation report ...................................................................................................1-2
Identifying tasks ................................................................................................. 1-2
Site Visit .............................................................................................. 1-3
Access................................................................................................................ 1-4
Rig side .............................................................................................................. 1-4
Water source...................................................................................................... 1-4
Pipe side ............................................................................................................ 1-4
Tru Tracker™ coils............................................................................................. 1-5
Obstacles and local constraints ......................................................................... 1-5
Communications ................................................................................................ 1-5
Accommodations and board .............................................................................. 1-6
Planning and Estimating Costs ........................................................ 1-6
Size of the drilling rig and support equipment .................................................... 1-6
Drilling method and tools.................................................................................... 1-7
Pilot hole ..........................................................................................................................1-7
Reaming ............................................................................................................................1-8
Pulling ..............................................................................................................................1-8
Anchorage of rig...............................................................................................................1-8
Subcontracts ...................................................................................................... 1-8
Work schedule ................................................................................................... 1-9
Quantities ........................................................................................................... 1-9
Crew .................................................................................................................................1-9
Drilling accessories........................................................................................................1-10
Drilling consumables......................................................................................................1-10
Rig consumables and spares ..........................................................................................1-11
Mobilization/demobilization...........................................................................................1-11
Other considerations ........................................................................................ 1-12
Customs duties and taxes................................................................................................1-12
Local taxes......................................................................................................................1-12
Insurance ........................................................................................................................1-12
Weather conditions .........................................................................................................1-12
Terms of payment ...........................................................................................................1-12
Bid bond..........................................................................................................................1-12
Performance guarantee ..................................................................................................1-12
Bank guarantee upon completion ...................................................................................1-12
Closing meeting ............................................................................................... 1-12
Preparing to Work.............................................................................1-13
Permits ............................................................................................................. 1-13
Equipment ........................................................................................................ 1-13
Rig and spare parts ........................................................................................................ 1-13
Drill pipes and downhole tools ...................................................................................... 1-13
Pumps and spare parts................................................................................................... 1-13
Recycling equipment and spare parts ............................................................................ 1-13
Pipe rollers and cradles ................................................................................................. 1-13
Transporting equipment ................................................................................................. 1-13
Clearing customs............................................................................................................ 1-13
Personnel ......................................................................................................... 1-13
Selecting the crew .......................................................................................................... 1-13
Briefing the superintendent and assistant ...................................................................... 1-14
Transporting the crew .................................................................................................... 1-14
Consumables.................................................................................................... 1-14
Bentonite ........................................................................................................................ 1-14
Water .............................................................................................................................. 1-14
Fuel ................................................................................................................................ 1-14
Electric wire ................................................................................................................... 1-14
Line of sight and coil installation....................................................................... 1-14
Subcontracts..................................................................................................... 1-14
Civil works ..................................................................................................................... 1-14
Sheet piling for rig anchorage ....................................................................................... 1-15
Mud return line .............................................................................................................. 1-15
Mud trucking .................................................................................................................. 1-15
Pipeline prefabrication .................................................................................................. 1-15
Buoyancy control system................................................................................................ 1-15
Mud removal .................................................................................................................. 1-15
Communications and coordination ................................................................... 1-16
HD-650 drill unit.
ii
List of Figures
Fig. 1.1. Soil investigation report. ....................................................................................1-2
Fig. 1.2. Map view of job site...........................................................................................1-3
Fig. 1.3. Size of the drilling rig. .......................................................................................1-6
Fig. 1.4. Typical maxi-rig.................................................................................................1-7
Fig. 1.5. Typical marine installation...............................................................................1-16
List of Tables
Table 1.1. Bentonite consumption estimates. .................................................................1-10
Pipeline pullback.
iii
Notes
iv
Chapter 1: Planning and Scheduling
Introduction
Horizontal directional drilling
Horizontal directional drilling (HDD) is a
technique that comes from the oil field, but
it is applied to the crossing of rivers, railways, motorways, dikes, and other
obstacles. The drilling assembly has a bent
sub for steering purposes, and is equipped
with an electronic probe to continuously
report the position of the pilot hole to the
driller. Interpreting this information allows
the pilot hole to follow the designed path.
Then the pilot string is removed and the
hole enlarged by reaming according to the
diameter of the pipeline or conduit to be
installed. This is done with a reamer or
hole opener, which is pulled and rotated
into the pilot bore. The bentonite carries
the cuttings out of the hole, and leaves a
lining (the filter cake) on the wall of the
bored pathway. Arriving at the final size
required for the reamed hole may require
one or more passes.
The hole is lubricated and the cuttings
removed by using drilling mud (generally
bentonite-based mud). This process is
repeated until the drill bit exits on the other
side of the obstacle.
The pipeline or conduit, which has been
assembled in one continuous string, if possible, is placed on launching rollers or in a
flotation ditch. It is then connected to the
drill pipe by a swivel joint, preceded by a
reamer and is pulled into the reamed hole.
The importance of planning and scheduling
This course is designed to assist the Sumitomo project manager in planning and
scheduling an HDD project. This chapter
reviews all questions that should be
answered when a project is in planning, out
for bid, or in the process of mobilization.
By taking the time to answer these questions in the early stages of the project, the
project manager will save his company
time and money.
Case study
A case study designed to walk you through
the various planning stages is presented
throughout this chapter. Project specifics
for the case study are set in green italicized
type, as follows:
This case study concerns a seaway crossing, the Ij Meer, near Amsterdam in the
Netherlands. It was awarded to HDI in
early May 1995 and construction took
place in June 1995.
Dimensions and characteristics of the
crossing. Typically, by the time the project
is assigned to the project manager, the
pipeline route has already been established.
This being the case, the HDD considerations concerning route selection will not
be considered here. However, in those
instances where the project manager has
preliminary input to the pipeline route, following these guidelines whenever possible
will minimize construction risk:
•
Keep the crossing as short as possible.
Crossings less than 1000 ft (300 m) are
considered short, crossings between
1000 and 2950 ft (300 and 900 m) are
considered medium, crossings between
2950 and 4600 ft (900 m and 1400 m)
are considered long, and crossings
longer than 4600 ft (1400 m) are considered extremely long.
•
Keep the entry and site exit sides of the
crossing as close to the same elevation
as possible—try to avoid elevation differences of more than 50 ft (15 m).
Horizontal Directional Drilling Training Program
•
Avoid routes where the pipeline cannot
be constructed in one continuous
string.
•
Maintain a minimum separation of
50 ft (15 m) from other existing pipelines.
•
Cross the river or obstacle in a straight
line.
•
Avoid placing a crossing near large
masses of steel, such as railroad
bridges, steel piling, or docks where
barges are moored.
The client provided the following data for
the project:
Banks: No significant difference in elevation
Construction period: Award in three weeks
and construction within three months
Other: Horizontal curve 8° at 2/3 of the
crossing with 1640-ft (500-m) radius.
Soil investigation report. The single most
important consideration to the directional
drilling contractor is the nature of the soils
at the crossing location. The subsurface
condition is the primary factor in determining the methods, price, and feasibility of a
project. Clients should provide geological
information with their tender document.
Pipeline diameter: 16 in. (406.40 mm)
Wall thickness: 0.75 in. (19.10 mm)
Coating: 0.12 in. (3 mm) polyethylene (PE)
Length of the crossing: 3821 ft (1165 m)
Width of the watercourse: 3018 ft (920 m)
Depth of the crossing: 100 ft (30 m)
Vertical drilling radius: 1640 ft (500 m)
In this project, the subsoil consists of alternating layers of clay, silty clay, peat, and
sand (Fig. 1.1). The navigation channel
overlies a deep sand deposit. Standard
Penetration Test results range from 10
blows per foot (bpf) in the peat layer to
25 bpf in the clay layers, and average
35 bpf in the sand formations. No sieve
analysis was provided.
1
Fig. 1.1. Soil investigation report.
1 Soil boring
Identifying tasks
The first task is to assess the feasibility of
the crossing by HDD. The project manager
will review and analyze the data provided
1-2
by the client and visit the site, preferably
with a client representative.
Planning and Scheduling: Site Visit
The second task, once the feasibility of the
project is confirmed, is to estimate the construction costs. For this purpose, the project
manager will determine the necessary
equipment and crew, assess the drilling,
reaming and pulling methods (types of
tools and sequences), prepare a tentative
construction schedule, and estimate quantities of consumables. Then the selling price
can be determined.
When the offer is accepted by the client,
the project manager must mobilize all the
necessary equipment and consumables,
finalize the necessary subcontracts, and
brief the construction crew about the specifics of the project.
The following pages will take you through
the complete exercise, based on the specifics of the case study.
Site Visit
It is useful to visit the site with a client representative, because they will often
communicate their concerns about local
restrictions and regulations placed on them
by governing bodies. During this site visit,
take relevant photographs and write a
report to document what has been seen and
discussed; it is common that the actual construction takes place several months after
the initial site visit. If the contract specifically states, “Grounds (or roads) will be
returned to their original condition,” the
photographs are especially useful to docu-
ment that you have complied with contract
specifications.
For this project the client organized an
onsite meeting with all the prequalified
contractors, followed by a site visit. During
the meeting they were very specific about
the accuracy of the drilling profile: the permit allowed for a corridor of only 20 ft
(6 m) wide, which would be checked by a
gyroscopic survey performed after the
project’s completion by a third party at the
client’s expense (Fig. 1.2).
1
3
2
1
Fig. 1.2. Map view of job site.
1 Pipeline route
2 Initial crossing alignment
3 Revised crossing alignment
1-3
Horizontal Directional Drilling Training Program
Access
Because the drilling spread consists of
wheel-mounted loads that average 25 tons
each and measure approximately 40 ft long
and 13 ft high (12 m long and 4 m high),
make sure that it is possible to deliver all
the equipment to the rig side of the crossing. For this reason, make note of low
bridges, sharp turns in roadways, or anything else that may impede access. Usually
the access to the crossing site is a temporary construction road (dragline skids,
gravel) and the length of this temporary
access road must be estimated during the
site visit. The same is true for access to the
pipe side.
Access to the Ij Meer rig site is straightforward, via highway and paved road until
260 ft (80 m) from the entry point. The pipe
side is accessible by barges or, for light
equipment, by a narrow paved road.
Rig side
A crossing with the maxi-rig requires a
drilling site of 200 x 200 ft (60 x 60 m),
while a crossing with the midi-rig only
requires a site of 70 x 100 ft (20 x 30 m).
For a large crossing through rock or coarse
granular materials, the workspace should
be increased to 200 x 260 ft (60 by 80 m).
The total available workspace is sufficient,
but the entry point chosen by the client is
too close to the embankment of the adjacent road. During the site visit with the client, it was agreed that the entry point be
shifted by 10 ft (3 m), which is far enough
from the embankment (Fig. 1.2, item 3).
Any shift in the entry point must stay within
the crossing corridor approved by the river
authorities.
Water source
During the site visit, determine the freshwater source for mixing the mud:
•
City water: Can city water from a
hydrant be used? What notice is
required by the city water companies?
Is a meter required? Where is that
arranged? What is the cost?
If the available water source is located
some distance from the planned entry
point, the drilling spread must have enough
hose and pump capacity to move the
required volumes the distance and elevation changes that you will encounter.
River water: Can water from the river
be used? Is it fresh water?
There is no problem with pumping large
quantities of river water in the Ij Meer, but
the water salinity must be checked. A laboratory test confirms a salt content of less
than 120 mg/l, which is acceptable for mixing the bentonite (see Mud, page 6-14).
Ideally, the pipe side should have enough
temporary workspace to lay the pipeline in
a continuous string in the axis of the crossing. The pipeline should be prefabricated in
this temporary workspace starting approximately 50 to 100 ft (15 to 30 m) beyond the
exit point. This space should be 30 to 50 ft
(10 to 15 m) wide, depending on the diameter of the pipe. Larger-diameter pipelines
require larger pieces of equipment and
therefore more working room. At the exit
location, a temporary workspace of 50 ft
wide by 100 ft long (15 by 30 m) is ideal
for most intermediate crossings. For large
crossings through rock or coarse granular
materials, a temporary workspace 100 ft
wide by 150 ft long (30 by 45 m) may be
needed to accommodate the necessary
equipment.
•
Pipe side
1-4
Planning and Scheduling: Site Visit
In some cases (especially swampy areas),
the roller track can be replaced by a flotation ditch.
In this area, the pipeline cannot be built in
line with the drilling alignment. However,
by curving the right-of-way 45° about
160 ft (50 m) after the exit point, the
3821-ft (1165-m) pipeline can be welded in
one section along a road that must stay
open for traffic. A temporary bridge, made
of rollers placed on top of containers, is
installed to cross the road.
At the exit point, no room is available for
placing a mud pit. Because of the access,
no vacuum trucks can reach the site. Therefore, a small desanding unit is needed to
preclean the mud; then the mud is pumped
across the Ij Meer back to the rig side
through a temporary 6-in. (150-mm) highdensity polyethylene (HDPE) pipe attached
to a 2-in. (50-mm) steel cable to sink it.
Tru Tracker™ coils
On both sides of the river, permission is
needed to set up a wire Tru Tracker coil
from the edge of the water to either the
entry or exit points. Generally, these coils
are set as wide as the crossing is deep at the
particular location. Setting these coils disturbs very little of the surface vegetation.
For a complete discussion of setting Tru
Tracker coil, see Steering (page 3-30).
A coil could not be installed on the pipe
side because of housing and private properties. On the rig side, the coil could be
installed, but very little room was left
between the entry point and the riverbank.
Obstacles and local constraints
During the site visit, identify obstacles
such as existing pipelines, cables, or sheet
pilings. Massive steel structures such as
pilings, pipelines, or high voltage lines will
disturb the local magnetic field and create
interference for the steering tools. In these
cases, it is almost mandatory that the Tru
Tracker locating system is used to drill
accurately.
Constraints such as neighboring housing,
which limits the acceptable noise level, or
special environmental considerations about
the handling of mud, should also be identified at this stage.
At the Ij Meer location, there was no such
constraint. However, because of the narrow
corridor allowed by the water authorities,
wooden piles were installed to aid the laying of Tru Tracker coil at intervals along
the crossing. Also, a very strict criterion
was determined for accepting the pilot hole
data: if a reading made in the coil is more
than 7 ft (2.2 m) away from the centerline,
it is rejected and the joint is redrilled (the
corridor allows for 10 ft [3 m], so the reading must be accurate—2% of the depth—
and a half-diameter of pipe).
Communications
During the site visit, locate the shortest
routes to transport equipment and personnel from one side of the crossing to the
other. On a large crossing that lacks a
bridge, a barge and tug must be planned.
The Ij Meer is very shallow outside the
navigation channel and barges cannot be
used. Therefore, only the narrow road can
be used, which means limiting the number
of trucks and allowing no vacuum truck to
be used; hence the mud return line. Crew
members can easily get from one side to the
other by car. A boat is needed to install and
operate the Tru Tracker coil.
1-5
Horizontal Directional Drilling Training Program
Accommodations and board
Several reputable hotel chains exist in Holland and it is never difficult to find suitable
accommodations except during holidays.
The Ij Meer crossing was not conducted
near a holiday, so accommodations were
easy to find.
The quality of the living accommodations
and board is very important for the morale
of the crew, and a crew with good morale
will often be more efficient. The site visit is
a good opportunity to check the quality and
prices of neighboring hotels or motels;
prices are often negotiable for groups and
extended periods of stay.
Planning and Estimating Costs
Size of the drilling rig and support equipment
The choice of rig is an important decision.
The chart in Fig. 1.3 indicates the pulling
force the rig should have for various diameters and standard wall thicknesses of steel
pipes relative to the length of the crossing.
In the Engineering chapter (Chapter 2), a
more precise calculation of the pull force is
explained, which also takes into account an
eventual buoyancy control system.
F (KN)
Ø (")
5000
40"
4500
4000
36"
3500
3000
32"
2500
28"
2000
24"
1500
20"
1000
16"
500
12"
0
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
L (m)
Fig. 1.3. Size of the drilling rig.
Available torque is another important item
to consider when choosing a rig configuration for a particular job. Normally, higher
torque is required when planning largediameter hole-opening operations in soft or
hard ground and rock. Proper makeup and
breakout torque is the minimum required
torque.
A rig should also have the power to turn at
a specified rotary speed with specified
torque, without impacting the pulling or
rotation specifications. Hole opening in
rock requires higher rotary speeds in
smaller sizes and lower rotary speeds in
larger sizes. If the correct rotary speed is
1-6
not maintained, lower penetration rates will
result.
A fast carriage travel speed is recommended when drilling in soft formations. It
is rarely necessary otherwise, but does save
time.
For the above reasons, sometimes only two
(out of four) translation motors are used on
the maxi-rigs, thereby increasing the carriage travel speed on crossings where a
moderate pull force is expected, and one
(out of two) rotation motor is used with
double rotation speed on reaming small
diameters in rock or hard formations.
Planning and Scheduling: Planning and Estimating Costs
A midi-rig was too small so a maxi-rig was
chosen, using only two translation motors
and one rotation motor to increase efficiency.
For this project, one pumping skid was
used, delivering 140 cum/hr at 150 bars.
Pumping rates would be as high as 100
cum/hr during casing and reaming.
The project manager must now decide
upon the mud system, comprising a mixing
unit, mud pump(s), and recycling unit. In
the chapters on Steering (Chapter 3),
Reaming (Chapter 4), and Pullback (Chapter 5), indication of flow rates are given, as
well as the theory behind them. A typical
maxi-rig is shown in Fig. 1.4.
A standard mud mixing unit was chosen for
the rig side. In addition, mud was recycled,
with one unit able to process 150 cum/hr of
mud with 25% cuttings on the rig side. For
the reaming operations, a desanding unit
was placed at the pipe side for precleaning,
and the mud with 4 to 7% cuttings was
pumped back to the rig side with a pipeline
service pump through the 6-in. (150-mm)
mud return line.
Fig. 1.4. Typical maxi-rig.
Drilling method and tools
At this stage, it is critical to understand the
specifics of the project and define the methods. In particular, answer the following
questions about the pilot hole, reaming,
pulling, and anchorage of the rig:
Pilot hole.
•
Should a jet or mud motor be used, and
what type of bit is used?
•
Should a casing be used?
•
How many shifts per day will the crew
work?
In this project the decisions were to:
•
drill by jetting because of the soft, alluvial soils
•
use a 12-in. (300-mm) casing on the
first 500 ft (150 m) to protect the entry
curve because of the length of the
crossing and soil conditions (more
than 3300 ft [1000 m] in alluvial materials)
•
work the day shift until the casing is
installed, and a double shift after that.
1-7
Horizontal Directional Drilling Training Program
Reaming.
Pulling.
•
Is it necessary to do pre-reaming?
•
Should a buoyancy system be used?
•
What will be the final diameter of the
reaming?
•
Should a special reamer, such as a
gravel reamer, be used?
•
Will reaming be done with a fly cutter
or hole opener, and what types of cutters will be used?
•
How much space is needed between
rollers and how many rollers will be
used, or will a flotation ditch be used?
•
How many passes will it take to reach
the final diameter?
•
How many and what kind of supports
will be used for the catenary?
•
•
Will reaming be done backward or forward?
How many shifts per day will the crew
work?
•
How many and what size mud pumps
will be used?
•
Will a second rig or a winch be used to
ream in rock?
•
How many shifts per day will the crew
work?
In this project the decisions were to:
•
use no buoyancy control system
because of the small pipe diameter
(less than 27.5 in. [700 mm])
•
use a standard bullet nose or fly cutter
for pulling, rather than a special tool
(the final decision was left with the
superintendent)
•
use 50 ft (15 m) between supports,
thereby requiring 75 pipe rollers
•
fix the catenary to cross above the
road, and place rollers on top of the
containers
•
be on alert to pull with a double shift,
and to start pulling shortly after the
reaming is finished.
In this project the decisions were to:
•
execute a pre-reaming because of the
favorable soil conditions, moving
directly to a 30-in. (760 mm) diameter
with a standard fly cutter reamer
•
bring a double quantity of drill pipe to
facilitate the pre-reaming
•
ream backward, pulling the reamer to
the rig, because of the space restrictions on the pipe side; and because the
length of the crossing did not allow the
use of a side boom or dozer, but rather
a winch with at least 50 tons of pulling
capacity
•
work a double shift because of the
length of the crossing and the alluvial
soil materials.
Anchorage of rig. Because of the expected
push/pull forces, is extra anchorage
obtained by using a single-frame or doubleframe sheet piling?
A single-frame sheet piling was installed
because of the pull force necessary to
remove the casing and pull back the 3821-ft
x 16-in. (1165-m x 400-mm) pipeline.
Subcontracts
Civil works (access, site preparation, reinstatement) and pipeline prefabrication
(stringing, welding, coating, testing) can be
handled by the client when they are a pipeline contractor or the pipeline division of
your company. In this case, you have a contract for drilling services only.
1-8
Civil works can easily be integrated into
the scope of work in a turnkey contract. In
these cases, the non-drilling aspects of a
job are often subcontracted to another company or to another division of your
company. However, you can also decide to
perform the access and site preparation on
the rig side when no major earth moving is
involved.
Planning and Scheduling: Planning and Estimating Costs
When choosing a subcontractor and negotiating the subcontract, keep in mind that the
cheapest price might not always mean the
best deal. It is important to make certain
that work schedules are kept and that the
access is finished when the rig arrives, or
that the preliminary hydrotest and joint
coating are finished by the time reaming is
started.
HDI was a subcontractor of A.Hak, and the
contract only included drilling services.
Therefore, the only concern about civil and
pipeline works was the timing of the operations. Once A.Hak set the date when the
pipeline would be ready for pulling, HDI
worked backward to plan the mobilization
and drilling operations, and informed
A.Hak of the date when access and rig site
would be ready for the rig’s arrival.
Work schedule
Based on the above decisions about drilling
methods and tools, together with knowledge of usual progress rates for each
drilling step and tool in similar soil conditions, it is now time make a tentative work
schedule.
In this project the following was anticipated:
•
1/2 day (one shift) of slack time for
potential problems (shorts, mechanical failure, etc.)
•
1/2 day (one shift) for preparing the
reaming (removing the spider subs,
etc.)
•
1/2 day (one shift) for removing the 12in. (300-mm) casing
•
1 1/2 day (three shifts) for reaming the
hole and preparing for pulling
•
two days for mobilizing all the equipment to the site
•
•
three days (three shifts) for rigging up
the rig and mud system
one day (two shifts) for pulling the
pipe, with the second shift starting the
rig down
•
two days (two shifts) for rigging down
and loading all the equipment
•
two days (two shifts) for drilling the
first 1300 ft (400 m)
•
two days for demobilizing.
•
two days (two shifts) for installing
500 ft (150 m) of 12-in. (300-mm) casing
•
two days (four shifts) for drilling the
remaining 2500 ft (765 m)
The totals were:
•
four days of transportation
•
five days of rig up/rig down (five shifts)
•
10 days of horizontal directional drilling (16 shifts).
•
one mechanic/pipe sider
•
one floorman—for a total of six crew
members on small crossings.
Quantities
Crew. Once the basic decisions about the
drilling program are made (type of rig,
method, and tentative schedule), it is time
to plan the crew. Typically, a crew working
a single shift consists of:
Midi-rig:
Maxi-rig:
•
one superintendent
•
one superintendent
•
one driller
•
one driller
•
one surveyor/assistant superintendent
•
one surveyor
•
one mud technician
•
one mud engineer
•
one recycling technician
1-9
Horizontal Directional Drilling Training Program
Drilling accessories. In view of the mobilization, you must carefully plan the
quantities of drilling accessories, consisting mainly of drill pipes and rollers.
•
one mechanic
•
one pipe sider/welder
•
two floormen*
•
one operator (crane/excavator)—for a
total of 10 crew members on large
crossings.
A large crew of 10 was planned for the day
shift and a smaller crew of eight for the
night shift (without a superintendent or
mechanic).
*For medium-sized crossings, the mud
technician can also do the recycling and
only one floorman is necessary, thus reducing the number of crew to eight.
This job required 75 pipe rollers, and 2 x
1165/19.4 = 248 drill pipes with 5-in.
diameters (plus a few spare pipes—typically 10%).
Drilling consumables. An important part
of the cost of an HDD project is the mud
system. Tables compiled from experience
help estimate the quantity of bentonite
required for a job of a given size (length
and equivalent diameter), in given soil conditions (alluvium or rock), and with or
without recycling (Table 1.1).
Table 1.1. Bentonite consumption estimates.
Reaming in soft formations
Reaming sequence
Pipe
Final
Hole
diameter Ream #1 Ream #2 Ream #3 Ream #4 reaming volume
(mm)
(mm)
(l/m)
(mm)
(mm)
(mm)
(mm)
100
200
300
400
500
600
700
800
900
1000
1100
1200
400
500
600
700
800
900
1000
900
900
900
1000
1000
1100
1200
1400
1400
1400
400
500
600
700
800
900
1000
1100
1200
1400
1500
1600
1500
1600
126
196
283
385
503
636
785
950
1131
1539
1767
2011
Reaming in rock
Reaming sequence
Pipe
Final
Hole
diameter Ream #1 Ream #2 Ream #3 Ream #4 reaming volume
(mm)
(mm)
(l/m)
(mm)
(mm)
(mm)
(mm)
100
200
300
400
500
600
700
800
900
1-10
437.5
437.5
437.5
437.5
437.5
437.5
437.5
437.5
437.5
650
650
650
650
650
650
650
900
900
850
900
900
1000
1100
1200
437.5
437.5
650
650
900
900
1000
1100
1200
150
150
332
332
636
636
785
950
1131
Without
recycling
50 kg b/ft
With
recycling
50 kg b/ft
0.36
0.56
0.81
1.10
1.44
1.82
2.24
2.72
3.23
4.40
5.05
5.74
0.14
0.22
0.32
0.48
0.57
0.73
0.90
1.09
1.29
1.76
2.02
2.30
Without
recycling
50 kg b/ft
With
recycling
50 kg b/ft
1.72
1.72
3.79
3.79
7.27
7.27
8.98
10.86
12.93
0.57
0.57
1.26
1.26
2.42
2.42
2.99
3.62
4.31
Planning and Scheduling: Planning and Estimating Costs
With a given quantity of bentonite, mix a
volume of mud that, in cubic meters, is
approximately 14 to 17 times the tonnage
of the bentonite. Out of this volume anticipate that 2/3 will have to be treated or
disposed of after the project.
When there are a series of crossings in the
same area, it is also possible to plan vacuum trucks and move the liquid mud from
one job to the next if the costs of removal
are high. In this case, the project manager
should think globally about his mud
consumption.
In this case, Table 1.1 shows that with recycling, anticipate 0.48 x 50 kg x
116510.3048 = 91,730 kg of bentonite will
be used, therefore mixing a total of 14 x
57.333 = 1280 cum of mud. Approximately
213 x 1280 = 852 cum of used mud will be
left over at the end of the job.
If fresh water cannot be pumped from the
river, the total volume of water that must be
purchased is calculated the same way. For
practical reasons, locate a source of fresh
water that can deliver as much as 60 cum/
hr; otherwise plan for storage water pits to
be sure that there is enough flow when you
need it (during casing and reaming).
Rig consumables and spares. The drilling
spread should always travel with sufficient
spare parts to remediate mechanical breakdowns onsite and sufficient consumables
(wire, grease for tool joints, hydraulic oil,
etc.) for the job or series of jobs to be conducted. For estimating purposes use a day
rate, which is a daily average of the amount
spent over a year.
Give special consideration to the quantity
of fuel needed for the project—a midi-rig
spread uses an average of 300 gal (1150 l)
per 12-hr shift, while a maxi-rig spread
with complete pumping and recycling
capabilities uses as much as 520 gal
(2000 l) per 12-hr shift.
Mobilization/demobilization. When
the
type of rig, type and number of pumps,
type of recycling unit, and number of drill
pipes and rollers have been decided, the
number of trucks necessary to mobilize the
complete spread can be estimated. Of
course, the equipment might not all come
from the same place, and considerations
other than the number of trucks are important when planning a mobilization. These
other considerations will be reviewed later.
For this job the following was needed:
•
three tractors for the rig, mud tank,
and power unit
•
one tractor and a flat-bed trailer for
the recycling unit
•
two tractors and a flat-bed trailer for
the control, workshop, spares, and
crew containers
•
three tractors and a flat-bed trailer for
the 75 rollers
•
one tractor and a flat-bed trailer for
the 500-ft x 12-in. (150-m x 300-mm)
casing and the dead man
•
four tractors and a flat-bed trailer for
the 260 5-in. drill pipes and monels.
Another important consideration when
planning a job is the time needed to mobilize the drilling spread. This obviously
affects the price, since this time cannot be
used to work elsewhere and therefore represents an opportunity cost. To reduce this
cost, plan the jobs so that the crossings performed in one region are completed one
after the other during the same period of
the year. Of course, this is often a question
of opportunities, but it is important to keep
this aspect of the planning in mind.
Furthermore, when planning and pricing a
job, consider the crew mobilization and
plan the relevant train or plane tickets and
expenses. Again, if crossings in the same
region can be grouped, it is possible to
mobilize a single crew for several jobs.
When bidding the Ij Meer crossing, a contract with another client was already
signed for two 30-in. (760-mm) crossings
in the Amsterdam region. So all three crossings were completed in the same time
frame using the same rig and crew.
1-11
Horizontal Directional Drilling Training Program
Other considerations
The following considerations are listed for
completeness, since each project has its
own specifics (client, country of execution,
financing).
Customs duties and taxes. Consider
not
only the cost of these duties and taxes, but
also the time spent at the customs office.
Local taxes. Other taxes that may apply
when pricing a job include local income
taxes (which can sometimes take the form
of a percentage of the turnover) or taxes on
salaries.
Insurance. In general, the drilling contractor must present its own third-party liability
insurance. But quite often, a Construction
All Risk (CAR) policy is offered by the client or main contractor, since they have
greater bargaining power with the insurance company and can spread the risk on a
wider range of activities. If a CAR policy is
not offered by your client, you should think
about the cost of obtaining one before starting the project.
Weather conditions. Although the HDD
method for river crossings is fairly independent of weather conditions, remember a
few basic considerations when planning a
job:
•
If heavy rains are expected, pay attention to preparing and maintaining the
access roads and work areas during the
project.
•
If freezing is expected, daily progress
will be hampered by drainage proce-
dures for all the water lines and mud
lines at each end of day. Also, the
power unit must be protected from
excessive cold. One solution is to work
double shifts systematically, and install
a tent with heaters on the power unit
for moderate cold (-10°C [14°F]). For
very cold and windy conditions, plan a
Sprung structure to protect the entire
drilling spread and crew.
Terms of payment. The terms of payment
will influence the cash flow of the project
and therefore will generate financial costs
or gains.
Bid bond. Some clients request a bid bond
to be deposited in a bank of their choice
before a drilling contractor can have his bid
considered at the price opening meeting.
This has a cost, although moderate.
Performance guarantee. Some clients ask
for a performance guarantee when awarding a job to a contractor; this also has a
cost.
Bank guarantee upon completion. It
is
common that the final payment (5 or 10%)
is linked to the final acceptance of the
project. This payment is typically made
one year after the provisory acceptance,
unless a bank guarantee of the same
amount is arranged by the contractor for
the benefit of the client, with the corresponding validity period; only then is the
final payment made at the time of the provisory acceptance. These costs should also
be considered.
Closing meeting
There should always be a closing meeting
initiated by the project manager with his
management. In this meeting, the project
1-12
and its context are presented, and the selling price and conditions are discussed and
agreed upon.
Planning and Scheduling: Preparing to Work
Preparing to Work
Assume that after this careful study and
bidding, Sumitomo is awarded the construction of the project. The project
manager should now review all the tasks
described above and make sure that everything will be available and delivered on
time to start the job. Meanwhile, he should
also monitor the progress of the civil and
pipeline works to make sure that no delays
occur, or adjust the mobilization plan in
case of deviations in the planning. The following section outlines all the tasks the
project manager will need to complete.
Permits
Usually, permits are delivered by the client
or main contractor, but the project manager
should follow the progress of the permit-
ting since the onsite work cannot start until
all permits are delivered.
Equipment
Rig and spare parts. Determine which rig
you will use, check its working condition,
and replenish its spare parts stock.
Drill pipes and downhole tools. Locate the
necessary length of drill pipes and check
their condition. Locate the drilling tools
you will need (jet assembly or mud motor)
and the drill bits. Check the available reamers (barrel reamer/fly cutters/hole openers)
and their condition, and build new tools if
the required sizes are not available.
Pumps and spare parts. Check the availability of the pump(s) and replenish the
spare parts stock if necessary. Plan sufficient hoses to install the pump(s) on the
construction site.
Recycling equipment and spare parts.
Check the availability of the recycling
unit(s) and replenish the spare parts stock if
necessary. Plan sufficient hoses to install
the recycling unit(s) on the construction
site. Plan the feeding pumps accordingly.
Pipe rollers and cradles. Check the availability of the rollers. Note that rollers are
often requested to be delivered on the pipe
side before beginning the project, because
pipeline contractors might decide to install
the rollers at the same time that the pipeline is being welded. Even if a flotation
ditch is used for the complete string, placing a few rollers at the entry of the pipe in
the hole could be useful. For the launching
ramp, locate cradles of sufficient size for
the pulling operation.
Transporting equipment. Plan the schedule of the truck transports, equipment
(cranes), and crew to load and offload the
equipment. For convenience, plan to
receive the rig and support equipment
onsite the first day, and receive the drill
pipes and supplies the second day when the
rig is almost rigged up.
Clearing customs. At each border crossing there is a procedure for clearing
customs. In some cases, detailed lists of
equipment and consumables must be prepared to expedite the clearance. If this is
not prepared carefully and on time, it might
result in a considerable loss of time at the
border.
Personnel
Selecting the crew. Crew members are
selected based on their specialties and
sometimes upon other criteria, such as language skills, past relations with a given
client, or specific experience (long cross-
ings, large-diameter crossings, rock
crossings). Use a mixed crew of specifically experienced people with less
experienced people in order to train those
with less experience. Experience in the
1-13
Horizontal Directional Drilling Training Program
field is the best training ground for directional drilling.
Briefing the superintendent and assistant. Before the work starts, brief the
superintendent and possibly his assistant or
the driller about the project—especially
about the soil conditions. At this stage, the
project manager must be open to suggestions, new ideas, or requests for specific
equipment coming from the superintendent. Practical considerations of the
superintendent often save time and avoid
inconveniences onsite during construction.
Transporting the crew. Prepare the final
mobilization plan of the crew(s) and inform
all personnel. Usually the drilling superintendent is mobilized earlier to supervise the
preparatory activities at the site. Even if
these activities are not in the scope of work
but performed by the main contractor, the
superintendent must be onsite to coordinate
the effort. The superintendent also informs
the project manager about the progress to
correctly plan the equipment and crew
mobilization.
Consumables
Bentonite. Place orders for the supply of
bentonite. On large crossings with limited
working space, you can plan a gradual
delivery to the site following the progress
of the job, but only if the supplier is reliable. Avoid being left on standby because
the bentonite supply has been depleted.
Water. Check whether you need a permit to
pump in the river, and if you do need one,
be sure that you have it. When loading the
equipment on the trucks, check again that
there is sufficient length of hoses to reach
the source of fresh water for mixing the
mud. If you have to buy the water, finalize
the contract now.
Fuel. Locate a local fuel supplier and finalize a contract, stressing the importance of
regular deliveries. Again, avoid being on
standby because there is no fuel left on the
job.
Electric wire. Check the meterage of wire
for directional control. As explained in
Steering (Chapter 3), always use new wire
to try to eliminate the risk of electrical
shorts when drilling the pilot hole.
Line of sight and coil installation
Before any onsite activity, make sure that
the line of sight of the crossing and entry
and exit points of the drilling are properly
marked. Entry and exit points should be
identified by the client and checked by the
crew surveyor. The surveyor will then place
the survey stakes, marking the line of sight
of the crossing. This must be completed
before preparing the platform and installing
the sheet piling, to make sure that everything is properly placed.
The crew surveyor installs the coil while
the rest of the crew is rigging up.
Subcontracts
Civil works. Most of the time, civil works
consists only of preparing the final access
road for the rig (and pipe) site(s) and the
drilling platform, mud pits, and water pit,
when necessary. This must be ready before
the drilling and support equipment arrives.
The reinstatement will be done immediately after the tie in. As already mentioned,
the access road must be strong enough for
loads of 25 tons.
1-14
Very often, mud removal is part of another
subcontract and is not performed by the
civil works company.
The subcontract for civil works must incorporate the client’s specifications for
reinstatement. Also, since the HDD method
is environmentally friendly, reinstatement
should be done quickly and properly to
leave a good impression of the river crossing method.
Planning and Scheduling: Preparing to Work
Sheet piling for rig anchorage. When
a
sheet piling is necessary, organize it a day
or two before the drilling equipment arrives
onsite. This work can be subcontracted.
Mud return line. When a mud return line
is necessary, make sure it is in place before
the reaming operation begins. Try to install
it before the rig arrives to make sure that
reaming activities will not be delayed once
the pilot hole is finished. This preparation
can be subcontracted or executed by a few
crew members mobilized early onsite.
Mud trucking. When a mud return line
cannot be installed, for small crossings or
when forward reaming is used, you can
locally hire a few vacuum trucks or farm
tractors with tanks to move the drilling
mud surfacing in the pipe side exit pit back
to the recycling unit located on the rig site.
Finalize the contract with a service company or local farmers, making sure it also
states the working hours. Particularly,
nighttime working hours should be scheduled to ensure that the night crew has the
support they need to continue working.
Pipeline prefabrication. Finalize the subcontract for pipeline prefabrication (if any)
at this stage, although probably much (such
as the choice of the subcontractor) has been
decided during the tender and negotiation
phases of the main contract. Remember
that good pipeline works are essential for
the success of the project. The client is
interested not only in a finished product,
but in a finished product that is in good
working condition. This means that the
pipeline must withstand the expected pressures, maintain its circular shape, and have
a proper coating. The best way to achieve
this is to make sure that the prefabricated
pipeline fulfills these requirements before
you start the pulling operation.
Another important consideration when
finalizing the subcontract is the respect of
the work schedule. Avoid being on standby
after the pilot hole because the pipeline is
still not tested or because the field joint
coating materials have not yet been
delivered.
In any case, clearly identify the limits of
the subcontract and responsibilities. For
example, use a formal procedure, with an
acceptance sheet, for delivering the pipeline welded, tested, and coated to the drilling contractor; from this point the drilling
contractor is responsible for the pipeline.
Also, make it clear who supplies and welds
the pulling head (the design being, of
course, the responsibility of the drilling
company, unless stated otherwise).
The principle of a formal acceptance of the
pipeline also applies when you are a subcontractor of a pipeline main contractor.
Buoyancy control system. When a buoyancy control system is necessary, it always
remains under the direct responsibility of
the HDD contractor. Even if the supply and
installation are subcontracted, its constituents and dimensions are engineered by the
drilling contractor, and the construction
should be supervised by one of its crew
members. At this stage of the project, it is
mandatory to pass orders for the supply of
materials if they are not in stock, and plan
the construction onsite.
Even if the system can be put into place
only after the pipeline has been successfully pretested, you can plan the materials
delivery and some preparatory works (such
as double-jointing of HDPE pipes, constructing the flanges) during the pipeline
prefabrication period.
Mud removal. Devise a good solution for
mud removal at this stage of the project. If
left until the end of the project, you may
find yourself dealing with high prices and
an unhappy client.
Since the inception of mud recycling techniques on directionally drilled crossings
that use new light and mobile recycling
units, there is usually little liquid mud to be
evacuated. In some cases, farmers may
allow you to spray the mud on their fields.
Dispose of the dry cuttings coming out of
the hole (for a total equivalent to the volume of the reamed hole), which have been
separated from the mud. Often these cuttings can be locally backfilled.
In all circumstances, obtain from the bentonite supplier a composition certificate for
1-15
Horizontal Directional Drilling Training Program
his product. You may wish to conduct laboratory tests on mud samples to confirm that
it is harmless before locating a disposal
area.
As mentioned in the Drilling Consumables
section (page 1-10), when there are several
crossings in the same region, liquid mud
can be moved from one site to the next with
vacuum trucks or farm tractors with tanks,
to create as little waste as possible.
Communications and coordination
It is very important to organize a good
communication system between the job site
and the outside world (phone, fax). This
will enable the site to inform its base regularly about the progress of the project,
confirm orders for new deliveries of consumables, request spare parts from the
base, discuss technical problems with other
specialized colleagues at the base, and
make faster and better decisions.
The progress of the subcontracts and delivery of consumables during this preparatory
phase, as well as during construction, must
be watched closely by the project manager.
He is the central point of the project organization through whom all communication
must flow to make efficient decisions and
adjustments. For a successful operation,
you must establish a good working collaboration between the project manager and the
construction superintendent.
Fig. 1.5. Typical marine installation.
1-16
Chapter 2: Engineering
Generalities......................................................................................... 2-1
Presenting the engineering course .................................................................... 2-1
Strength of materials—Background ................................................................... 2-1
Basic strength of material ................................................................................................2-1
Stresses combination ........................................................................................................2-2
Beam strength of materials...............................................................................................2-2
Beam/pipeline formulas....................................................................................................2-2
Pipeline Codes.................................................................................... 2-3
Definitions .......................................................................................................... 2-3
Location classes................................................................................................. 2-3
Construction types ............................................................................................. 2-3
Pressures ........................................................................................................... 2-5
Design criteria .................................................................................................... 2-5
Stresses During Testing or Operations ........................................... 2-6
Hoop stress ........................................................................................................ 2-6
Bending stress ................................................................................................... 2-6
Temperature stress ............................................................................................ 2-6
Restrained pipeline stress.................................................................................. 2-6
Traction stress.................................................................................................... 2-6
Ground pressure ................................................................................................ 2-7
Pipeline specifications........................................................................................ 2-7
Pipeline Engineering.......................................................................... 2-7
Verifying wall thickness ...................................................................................... 2-7
Hoop stress .......................................................................................................................2-7
Ground pressure ...............................................................................................................2-8
Hydrostatic test .................................................................................................. 2-9
Operating pressure .......................................................................................... 2-10
Comments........................................................................................................ 2-10
Installation conditions....................................................................................... 2-10
Minimum radius................................................................................................ 2-10
Crossing Engineering ...................................................................... 2-11
Introduction ...................................................................................................... 2-11
The crossing’s path design .............................................................................. 2-11
River ...............................................................................................................................2-11
Exclusion area ................................................................................................................2-11
Entry angle .....................................................................................................................2-12
Exit angle........................................................................................................................2-12
Subsoil nature or obstacles ............................................................................................2-12
Design of the profile .......................................................................................................2-12
The crossing’s layout........................................................................................ 2-15
Entry side ....................................................................................................................... 2-15
Pipe side ......................................................................................................................... 2-16
Catenary......................................................................................................................... 2-18
Engineering Procedures ..................................................................2-19
Preliminary evaluation ...................................................................................... 2-19
Product line nature ........................................................................................................ 2-19
Pipe size ......................................................................................................................... 2-19
Pipe length ..................................................................................................................... 2-19
Pipe mechanical characteristics .................................................................................... 2-20
Pipeline coating and field joints .................................................................................... 2-20
Catenary ........................................................................................................... 2-21
Multiple pipeline installation.
ii
List of Figures
Fig. 2.1. Stress-strain curve. .............................................................................................2-1
Fig. 2.2. Determining the exclusion area........................................................................2-12
Fig. 2.3. Designing the pilot hole profile........................................................................2-13
Fig. 2.4. Crossing’s profile: minimum depth. ................................................................2-14
Fig. 2.5. Crossing’s profile: minimum length. ...............................................................2-14
Fig. 2.6. Typical entry side layout. .................................................................................2-16
Fig. 2.7. Typical pipe side layout. ..................................................................................2-17
Fig. 2.8. Pipe side, South Louisiana, USA. ....................................................................2-17
Fig. 2.9. Catenary with and without an exit pit. .............................................................2-18
Fig. 2.10. Length/diameter feasibility range. .................................................................2-20
Fig. 2.11. Catenary. ........................................................................................................2-22
Fig. 2.12. Pipeline string and catenary. Norfolk, Virginia, USA. ..................................2-22
List of Tables
Table 2.1. API pipeline specifications. .............................................................................2-3
Table 2.2. Classification of steel pipe construction (API Table 841.15A)........................2-4
Table 2.3. Values of design factor F (API Table 841.1A).................................................2-5
Table 2.4. Longitudinal joint factor E (API Table 841.1B). .............................................2-8
Table 2.5. Temperature derating factor T (API Table 841.1C). ........................................2-9
Maxi-rig, Southeast Texas, USA.
iii
Notes
iv
Chapter 2: Engineering
Generalities
Presenting the engineering course
This chapter reviews the objectives of horizontal
directional
drilling
(HDD)
engineering and the course plan of the
modules dealing with engineering. The
engineering exercises are aimed toward
issuing a recommendation on the feasibility
of an HDD crossing with regard to technical, scheduling, and economical criteria,
and defining the crossing’s acceptance
criteria.
It is assumed that the engineer has the following minimum information:
•
pipeline characteristics
•
pipeline route
•
obstacle profile
•
subsoil conditions.
Strength of materials—Background
Basic strength of material. The strength of
a material depends on the relationship
between external forces applied to elastic
bodies and the resulting deformations and
stresses. Forces on pipelines are produced
by gravity, buoyancy (if any), pulling on
the pipe, bending the pipe, soil reaction
(friction), and internal hydrostatic pressure.
Many mechanical properties of materials
are determined by testing, which gives the
relationship between stresses and strains,
as is explained in the following section.
Stress is the force per unit area and is
expressed in lb/in.2 (Newton/m2 or Pascal
[Pa]). The megapascal (Mpa) is often used
as a convenient multiple of the Pascal. If
the stress tends to stretch the material, it is
called a tensile stress; if it compresses or
shortens the material, it is a compressive
stress. By convention, a tensile stress is
negative.
Unit strain (or strain) is the amount by
which a dimension of a body changes when
the body is submitted to a load, divided by
the original value of the dimension. When
the load varies, you plot a curve showing
strain vs. stress. Usually, this curve is linear
until a limit called the proportional limit is
reached. Elastic limit is the maximum stress
under which a test specimen may be subjected and still return to its original length
when the load is released. If the stress
exceeds this elastic limit, the material is
said to be stressed in the plastic region
where permanent deformation occurs, until
the ultimate strength is reached, when the
material breaks (Fig. 2.1)
1
Fig. 2.1. Stress-strain curve.
5
4
1 = Strain
3
2 = Stress
3 = Proportional limit
4 = Elastic limit
5 = Ultimate limit
2
Horizontal Directional Drilling Training Program
The modulus of elasticity E, also called
Young’s modulus, is the ratio of unit stress
to unit strain, within the proportional limit.
When a material is subjected to a longitudinal strain within the proportional limit,
there is a lateral strain that is proportional
to the longitudinal strain. The ratio is called
Poisson’s ratio ν. It is important to understand that if a material is not allowed to
strain in one direction, the strain in the
other direction induces stresses in the
material.
For example, during pressure testing of a
pipeline, if the pipeline section is restrained
from shortening, you will observe a tensile
stress in the pipeline equal to the tensile
stress that results from pressure multiplied
by Poisson’s ratio. The values of E and ν
for steel are:
Poisson’s ratio: νsteel = 0.3
Young’s modulus: Esteel = 2.1 105 Mpa
or 2.1 107 T/m2
Stresses combination. Stresses cannot simply be added if they occur in different
directions. For example, if a material is
subjected to two perpendicular stresses,
both compressive or both tensile, it will
break or reach the plastic region long
before the same material is subjected to the
same stresses with one being compressive
and the other tensile. When discussing
Poisson’s ratio, it was stated that a material
that was subjected to tensile stress would
shrink in the other direction. If the material
is subjected to a tensile stress in that direction, the action of this tensile stress is very
destructive on the material that would otherwise shrink.
Different formulas are used to combine
stresses. The formulas will not be derived
here, since that is beyond the scope of this
course. They will only be mentioned when
necessary.
Beam strength of materials. When considering the strength of materials, a pipeline is
equivalent to a beam, having a constant
2-2
section. For beam calculations, you must
determine at any point x the moment of all
forces applied to the beam, either at the
right or left of that point x. These two values are equal in static equilibrium;
therefore, use the one that is easiest to
calculate.
If a beam is subjected to a longitudinal
(pulling) force, the stress caused by the Fx
component of the force F is:
F
σ = -----x
A
If M(x) is the moment of a straight and horizontal beam, then the deformation of the
beam can be calculated by resolving the
following differential equation:
M(x)
d2y
--------2 = ------------EI
dx
The stress due to moment M is tensile or
compressive, depending on the orientation
of the moment and the point in the beam
material that is considered. The maximum
stress is on the upper and lower fiber of the
beam, and equal to:
MxD
σ = ------------2l
Beam/pipeline formulas. With the notations:
D = outside diameter in m
d = inside diameter in m
e = wall thickness in m
E = modulus of elasticity
l = length
you have the following values:
Section Area “A” = π (D2 - d2)/4
= π e(D - e)
Section Inertia “I” = π (D4 - d4)/64
Engineering: Pipeline Codes
Pipeline Codes
Definitions
The code applied to the pipeline construction indicates the various basic data that
must be used to design the pipeline. A different code applies to gas or oil pipeline,
and different codes apply to each country,
according to national laws. However, most
of the “national” codes refer to the American National Standards Institute (ANSI) B
31-4 for oil pipelines and ANSI B 31-8 for
gas pipelines. The following terms are used
in this section:
Design pressure: The value of the pressure
used for pipeline design.
Operating pressure: The value of the pressure during pipeline operation.
Test pressure: The value of the pressure
used for pipeline testing.
Class Location: The class of a pipeline section as per applicable code.
Construction Type: The type of construction for a pipeline section.
SMYS: Specified Minimum Yield Strength.
This is the elastic limit of the pipe material
as defined by the American Petroleum
Institute (API) (Table 2.1).
Table 2.1. API pipeline specifications.
Grade
Minimal yield strength
A
B
X42
X46
X52
(psi)
30,000
35,000
42,000
46,000
52,000
(Mpa)
207
241
289
317
358
X56
56,000
386
X60
60,000
413
X65
65,000
448
X70
X80
70,000
80,000
482
551
Minimal ultimate tensile strength
(psi)
48,000
60,000
60,000
63,000
66,000
72,000
71,000
75,000
75,000
78,000
77,000
80,000
82,000
90,000
(Mpa)
331
413
413
434
455
496
489
517
517
537
530
551
565
620
Location classes
Class Location and Construction Type
allow you to determine, for every section of
the pipeline, the design factor F applicable
to that section. The most significant factor
contributing to the failure of a pipeline is
damage to the line by human activity along
the route of the pipeline.
You can quantify this activity by determining population density indices and relating
the design of the pipeline to the appropriate
population density index. The code
requires you to lower the stress level relative to increased activity. Four class
locations are defined in the code, from
Class 1 to Class 4.
Construction types
Class Location alone is not sufficient to
assess the risk of damage to a pipeline,
since various situations (such as road, river,
or bridge crossings) may increase the risk
regardless of the population density index.
Four construction types are defined from
Type A to D, according to the ANSI B 318-1982 Table 841.15A. (Table 2.2).
2-3
Horizontal Directional Drilling Training Program
Table 2.2. Classification of steel pipe construction (API Table 841.15A).
Characteristics
Design Factor F
Type A
Construction
0.72
Type B
Construction
0.60
Location where type A. On private
of construction will be rights-of-way in
used
Class 1 locations
B. Parallel
encroachments
on:
1) Privately owned
roads in Class 1
locations
2) Unimproved
roads in Class 1
locations
A. On private
rights-of-way in
Class 2 locations
B. Parallel
encroachments
on:
1) Privately owned
roads in Class
2 locations
2) Unimproved
roads in Class
2 locations
3) Hard-surfaced
roads, highways, or public
streets and railroads in Class
1 and 2 locations
C. Crossings with- C. Crossings without casings on pri- out casings on:
vately owned
1) Privately owned
roads in Class 1
roads in Class
locations
2 locations
2) Unimproved
public roads in
Class 1 and 2
locations
3) Hard-surfaced
roads, highways or public
streets and railroads in Class
1 locations
D. Crossings with
casings on unimproved roads,
hard-surfaced
roads, highways,
or public streets
and railroads in
Class 1 locations
D. Crossing with
casings on hardsurfaced roads,
highways, or public streets and railroads in Class 2
locations
E. On bridges in
Class 1 and 2
locations
F. Fabricated
assemblies pipelines in Class 1
and 2 locations
2-4
Type C
Construction
0.5
Type D
Construction
0.40
A. On private
A. All in Class 4
rights-of-way in
locations
Class 3 locations
B. Parallel
encroachments
on:
1) Privately owned
roads in Class
3 locations
2) Unimproved
roads in Class
3 locations
3) Hard-surfaced
roads, highways, or public
streets and railroads in Class
3 locations
C. Crossings without casings on:
1) Privately owned
roads in Class
3 locations
2) Unimproved
public roads in
Class 3 locations
3) Hard-surfaced
roads, highways, or public
streets and railroads in Class
2 and 3 locations
D. Compressor
station piping
E. Offshore platform piping,
including risers,
and for a distance
of 5 pipe diameters beyond the
bottom elbow,
bend or fitting.
Transition pieces
at the end of this
pipe are not considered fittings.
F. Near inhabited
areas in Class 1
and 2 locations
Engineering: Pipeline Codes
Usually, Type A construction applies to
Class 1 location, Type B to Class 2, and so
on, but there are many exceptions stated in
this table. Therefore, each section of the
pipeline is given a type, which determines
the factor F to be applied at the design
stage, as follows (Table 2.3; ANSI B 31-41982 Table 841.1A):
Table 2.3. Values of design factor F
(API Table 841.1A).
Construction
Types
(see 841.151)
Design
Factor F
Type A
Type B
Type C
Type D
0.72
0.60
0.50
0.40
Pressures
Maximum operating pressure is the value
of the maximum pressure in the pipeline
during operation. It is the lowest value of
the design pressure and the test pressure
divided by:
1.1 for Class 1
1.25 for Class 2
1.4 for Class 3
1.4 for Class 4.
Design pressure was previously defined as
the value of the pressure, greater than operating pressure, that is used to design the
pipeline. Test pressure varies with pipeline
class, as follows:
Class 1: (1.1*Maximum operating pressure)
Class 2: (1.25*Maximum operating pressure)
Class 3: (1.4*Maximum operating pressure)
Class 4: (1.4*Maximum operating pressure).
The test is carried out with water. The maximum operating pressure and design
pressure have a single value for the entire
pipeline. The test pressure, on the other
hand, varies with pipeline class. Each section of the same class is tested separately,
and a general test is carried out at the end
of construction according to the abovementioned coefficients, using a test pressure that does not overstress the pipeline.
Design criteria
The engineer must first determine the construction type that is most applicable to the
crossing. Based on horizontal drilling
experience, an HDD crossing can be Type
A with a design factor F equal to 0.72 if the
land section on both sides of the crossing is
also Type A. In fact, the river section is
safer than the land section because there is
no risk of human interference. Therefore,
whenever the local regulations or laws
allow it, try to use the same classification
for the crossing as for the land line.
This is important, because you must use the
design factor F to verify that the pipe is not
overstressed in different situations during
construction and operation. Stresses may
be caused by pressure inside the pipeline
(during testing or operations), pressure outside the pipeline (including ground
pressure), temperature variations, bending
the pipeline in the hole (during testing or
operations), or bending the pipeline out of
the hole (during installation).
2-5
Horizontal Directional Drilling Training Program
Stresses During Testing or Operations
Hoop stress
Hoop stress is the stress caused by internal
pressure. Its value is given by the Barlow
formula, where P is the differential pressure
(the difference between internal and external pressure), D is the outside diameter,
and t is the wall thickness. The following
formula is valid if the ratio D/t is greater
than 20.
PD
σ H = -------2t
Bending stress
The maximum bending stress is:
ED
σ b = ± -------2R
where R is the bending radius. This stress is
a compression on the “outside fiber” and a
compression on the “inside fiber.”
Temperature stress
If the temperature of the fluid carried by
the pipeline is different from the temperature during installation, you must consider
the stresses caused by temperature in the
restrained pipeline (there would be no
stresses if the pipeline was free to expand
or contract). This is the case when the pipeline is a gas pipe, where gas temperature
may be much higher than ground/installation temperature, or for an oil line where
the oil must be heated to be pumpable.
Temperature stress caused by a ∆T variation of temperature is:
σ t = Eα∆T
where α is the linear expansion coefficient
in m per unit length per degree Celsius
(11.7 10-6 m/m/˚C for steel).
Restrained pipeline stress
Earlier in this chapter (Basic Strength of
Material, page 2-1) it was mentioned that a
stress in one direction would create a stress
of the same sign in the perpendicular direction if the material was restrained from
expanding or contracting in that direction
(the restrained pipeline stress), and that the
ratio between these two stresses was the
Poisson coefficient ν. For example, hoop
stress σH would generate a longitudinal
stress equal to:
σ L = νσ H
Traction stress
If the pipeline, having a section area A, is
submitted to a pulling force PF, then there
is a longitudinal stress (traction stress)
equal to:
2-6
P
σ a = ----FA
PF
σ a = --------------------πt ( D – t )
Engineering: Pipeline Engineering
Ground pressure
When the pipeline cover is important, and
when the soil cohesion is low, you must
consider the weight of the ground on top of
the pipeline. The following formula, taken
from Dreyfuss (Thin metallic conducts
under roads and railways, Technip Edition), can be used to estimate ground
pressure σg:
D
σ g = 0.4γh ---2t
where
When the D/t ratio is high, there is a risk of
elastic instability. Elastic instability is when
a body collapses even though the load
applied to this body does not create stresses
in excess of yield. This is because the stress
formulas assume that the load is perfectly
centered and that the pipe is perfectly
round. The critical value for external pressure on a pipe is given by the formula:
2E
1
P tc = --------------2 --------------------------2
1 – ν DD 
---- ---- – 1

tt
γ = ground specific weight
h = depth of top of pipe.
where Ptc is the critical external pressure.
Pipeline specifications
API specifications 5L, 5LX and 5LS first
stated the chemical requirements of steel
used for seamless or welded pipeline. The
minimum yield limit (SMYS), minimum
ultimate tensile stress, and minimum percentage of elongation are also specified, as
are tolerances on dimensions and weight.
The API grades and corresponding SMYS
are given in Table 2.1 (metric and US
units). Some of the grades may not be used
in certain areas, especially when very low
temperatures are expected.
Pipeline Engineering
Verifying wall thickness
The engineer must first check that the wall
thickness of the pipeline is sufficient with
respect to working pressure.
t = nominal pipe wall thickness
D = nominal pipe diameter
F = design factor
Hoop stress. Hoop stress was previously
defined as the stress caused by internal
pressure in the pipeline during testing or
operations. The formula for that calculation
is given in ANSI B 31-8:
St
P = 2 ----- × F × E × T
D
where
P = design pressure
S = SMYS
E = longitudinal joint factor
T = temperature derating factor.
The values of factors F, E and T are given
by ANSI B31.8-1982, in Tables 841.1A,
841.1B, and 841.1C, respectively (reproduced here as Table 2.3, Table 2.4, and
Table 2.5, respectively). This is the Barlow
formula used to determine the strength of
materials (Bending Stress, page 2-6),
where the hoop stress σH must not exceed
SMYS x F x E x T. Please note that D is the
nominal diameter of the pipeline.
2-7
Horizontal Directional Drilling Training Program
Ground pressure. If pipeline cover is
important, you must check that the pipeline
will not collapse because of external pressure. The formula mentioned in Ground
Pressure (page 2-7) should be used:
D
σ g = 0.4γh ---2t
where
γ = ground specific weight
h = depth of top of pipe
If the calculated stress exceeds 70% of
SMYS, then proceed with a detailed analysis of collapse and out-of-roundness risks.
The elastic instability should also be
checked because a high D/t ratio increases
this risk. The critical external pressure Ptc
must be more than four times the external
pressure.
Table 2.4. Longitudinal joint factor E (API Table 841.1B).
Spec Number
ASTM A53
ASTM A106
ASTM A134
ASTM A135
ASTM A139
ASTM A211
ASTM A381
ASTM A671
ASTM A672
API 5 L
API 5 LX
API 5LS
Pipe Class
Seamless
Electric Resistance Welded
Furnace Welded
Seamless
Electric Fusion Arc Welded
Electric Resistance Welded
Electric Fusion Welded
Spiral Welded Steel Pipe
Double Submerged Arc
Welded
Electric Fusion Welded
Electric Fusion Welded
Seamless
Electric Resistance Welded
Electric Flash Welded
Submerged Arc Welded
Furnace Butt Welded
Seamless
Electric Resistance Welded
Electric Flash Welded
Submerged Arc Welded
Electric Resistance Welded
Submerged Arc Welded
E Factor
1.00
1.00
0.60
1.00
0.80
1.00
0.80
0.80
1.00
1.00*
1.00*
1.00
1.00
1.00
1.00
0.60
1.00
1.00
1.00
1.00
1.00
1.00
*Includes Classes 12, 22, 32, 42, and 52 only (definitions for the various classes of welded pipe are
given in 804.243).
2-8
Engineering: Pipeline Engineering
Table 2.5. Temperature derating factor T (API Table 841.1C).
Temperature °F
Temperature Derating
Factor T
250 or less
1.000
300
0.967
350
0.933
400
0.900
450
0.867
Note: The conversion between °F and °C is °C = 5/9 (°F + 32).
Therefore, the above temperatures’ C equivalents are:
°F
°C
250
300
350
400
450
121.1
148.9
176.7
204.4
232.2
Hydrostatic test
In Pressures (page 2-5) it was stated that
the test pressure is equal to the maximum
operating pressure multiplied by a coefficient that varies with pipeline class
location:
Class 1: (1.1*Maximum operating pressure)
Class 2: (1.25*Maximum operating pressure)
Class 3: (1.4*Maximum operating pressure)
Restrained pipe: σr = -ν σH
Longitudinal stress: σa = - |σ0| - ν |σH|
Generally, the residual traction Pr is negligible and the residual stress σ0 can be
considered zero, so essentially you have a
combination of longitudinal and hoop
stress. The Von Mises criteria is commonly
used for these stress combinations. The
combined stress is equal to:
Class 4: (1.4*Maximum operating pressure).
Maximum allowable operating pressure is
also equal to the lowest of design pressure
and test pressure divided by the above
coefficients.
However, the installed pipeline is also subjected to bending stress (page 2-6) due to
curves in the reamed hole, whether intentional or not. A residual traction (page 2-6)
may increase the longitudinal stress and the
restrained pipeline stress (page 2-6). These
stresses can be calculated as follows:
Hoop stress: σH = PD/2t
Residual traction: σ0 = Pr /(πt(D-t))
Bending stress: σb = ± ED/2R
σ2 = (σH 2 + σL 2 - σH σL + 3σs)
where σs is the shear stress. In this case the
shear stress is negligible, and the above
equation can be reduced to:
σ2 = (σH 2 + σL 2 - σH σL)
where
σL = σa ± σb
This equivalent stress σ must be less than
or equal to 95% of SMYS. Since the bending stress varies with the bending radius,
this formula will give a minimum bending
radius due to hydrostatic test Rtest.
2-9
Horizontal Directional Drilling Training Program
Operating pressure
The ANSI B31.8 article 833.4 specifies that
combined stress due to expansion, longitudinal pressure, and longitudinal flexion
must not exceed SMYS, and that the sum
of longitudinal pressure and longitudinal
flexion must not exceed 75% of SMYS.
For pipes installed by HDD, assuming that
hole diameter is closed from the pipe’s outside diameter (OD), the combined
expansion stress is negligible if the soil
resists lateral movements of the pipe and if
the pipe is not subjected to torsion during
pulling. In that case, you only need to
check that:
|σa| + |σb| ≤ 0.75 x SMYS x F x T
where
σa = σ0 - ν Pi/2t
σb = ± ED/2R
Pi = Maximum operating pressure.
The minimum radius due to operating conditions can be calculated and is equal to
Roper. However, if the temperature of the
fluid carried by the pipeline is high, ANSI
B31.4 article 419.6.4 applies, with a longitudinal stress equal to:
σa = Eα∆T - |σ0| - |σH| + |σb|
where ∆T is the difference between the
maximum operating temperature and the
installation temperature.
Comments
The above calculations apply to pipeline
installed with the HDD method only. The
soil should be strong and stable; additional
engineering is required for very soft or
muddy soils, seismic areas, and zones sub-
ject to ground slippage. This additional
engineering is beyond the scope of this
chapter because it is based on standard
pipeline engineering.
Installation conditions
During installation, the pipeline is subject
to traction forces, balance by ground friction into the hole or on the rollers, and by
bending according to drilled path profile.
You must estimate the pulling force to
check that the pipe will not be overstressed.
In addition, the pipe is generally laid horizontally on rollers or in a flotation ditch.
Since the pilot hole exits at an angle, the
pipe must be handled so that it enters the
ground with an equivalent angle. This is
what is called the catenary. The pulling
force estimation and catenary calculation
will be explained later, and for now assume
than the pulling force PF is known.
The longitudinal stress σa due to PF must
be less than 95% of SMYS. Accordingly,
calculate the minimum radius during pulling of the pipe Rpull:
σa = PF /(πt(D-t)) ± ED/2R ≤ 0.95 SMYS
Minimum radius
You have determined the minimum radius
for various conditions. The minimum
radius of the crossing must be the greatest
of:
Minimum radius during testing: Rtest
Minimum radius during operation:
Roper
2-10
Minimum radius during installation:
Rpull
However, there may be other situations
where you would use a higher radius than
this. First, the pilot hole cannot be drilled
perfectly. Use a coefficient to allow for
unexpected variations in hole profile and to
make sure that the radius cannot be less
Engineering: Crossing Engineering
than the minimum. Second, the radius is an
important factor for pull force value. For a
large pipeline, use a higher radius to reduce
the anticipated pull force. The relationship
between radius and pulling force will be
described later.
Crossing Engineering
Introduction
You now have the basic engineering information required to design a crossing. You
know how to determine the minimum
allowable radius and how to verify that the
pipe wall thickness is acceptable for HDD.
However, this is still not enough. The various parameters you must understand and
use to design a crossing and determine
whether it is feasible will now be reviewed.
First, you will learn how to design the
crossing’s profile based on the minimum
radius and exclusion area. Then the layout
on both sides of the river and the necessary
resources you must have are described.
The crossing’s path design
River. The basic information you will need
is a profile of the river. Particularly, you
should obtain the current profile of the
river—some rivers may change during a
year’s time, so old profiles must be used
and checked very carefully.
high. There may also be an existing navigation channel or one planned for the future.
If the river is dredged, you must leave an
allowance for the dredge below the nominal dredging depth.
It may sometimes be difficult to determine
where the river bottom is, especially when
the river is subject to scouring. The scouring level must be estimated according to
the river’s hydrologic data.
Exclusion area. At this stage, you should
know the pipe and entry sides, the water
source, the quality of the water, the river
bottom’s location, and the location of its
banks. These data are sufficient to start
drafting a tentative profile of the crossing.
You must also determine where the river
banks are, because the river can shift from
time to time, especially after a flood. In that
case, the banks may be the limits of the
flood area, or any other point within these
limits where you can be sure that the river
will not shift and expose the pipeline.
There may be obstacles in the bed of the
river, such as bridge piers, which may
cause problems when the river flow is very
On a drawing of the river’s profile, mark
the dredging limit (if any), the scour level
(if any), and the real banks of the river. The
area delimited by the verticals from the
banks and the lowest of river bottom, scour
level and dredging area, plus minimum
pipeline cover, is called the exclusion area.
This defines a rectangular area (Fig. 2.2)
where the pipeline must not be installed.
2-11
Horizontal Directional Drilling Training Program
1
2
Fig. 2.2. Determining the exclusion area.
1 Exclusion area
2 Bedrock
If the river is very stable, the bottom line of
the exclusion area may follow the river’s
bottom (i.e., parallel at a distance equal to
minimum pipeline cover).
Minimum pipeline cover refers to the minimum soil height that must cover the pipe to
make sure that it will not rise toward the
surface when it is empty. Generally, about
15 ft (5 m) are sufficient. This can be
reduced somewhat in rock or hard formation, but you also must remember that pilot
hole drilling is not that accurate. You can
add a drilling safety margin to the minimum cover, which should be 2 to 5 ft (1 to
2 m), according to the crossing’s length.
2-12
Entry angle. The entry angle is limited by
rig design and by safety guidelines for the
drilling crew working on the rig’s walkways. The inclination should not be more
than 18˚, and a minimum entry angle of 8˚
is suggested.
Exit angle. The maximum suggested exit
angle is 10˚, which can be reduced to 4˚ for
large-diameter pipelines. Generally, the
exit angle must be as low as possible for
large-diameter pipes.
The basic data for a crossing’s design are
the exclusion area parameters discussed
above. However, there may be another
restriction, which is the maximum ground
cover that is allowed above the pipe. It was
previously mentioned that ground pressure
(page 2-7) could be a problem. In that case,
the formula will give you a maximum
cover on top of the pipe. Mark that limit on
the profile’s drawing, which will be a horizontal line called bottom limit.
Subsoil nature or obstacles. The best soils
for river crossings using the HDD method
are sand, silt or clay. Gravel is the most difficult to work with, and bedrock is also
problematic (the problem with bedrock is
the interface between the soft and hard
ground). Therefore, whenever possible,
avoid the gravel areas and remaining higher
than the bedrock. If you have no other
alternative than to drill through the bedrock, the angle between drill path and
bedrock must be as high as possible.
There may be another reason to have a bottom limit: there may be bedrock, a hard
formation, or a gravel area that you want to
avoid. At this stage of the engineering of
the crossing, you may not know exactly
where that limit is. You can design the
crossing and adjust later, once the soil
investigations are available.
Design of the profile. You have now determined and mapped the exclusion area, and
marked the bottom line and the problematic
areas where you want to avoid drilling. You
are now ready to design the pilot hole profile, which is a simple combination of arcs
and lines. Usually, the path is split into:
Engineering: Crossing Engineering
One tangent: C0–C1
One radius: C3–C4
One tangent: C4–C5
One radius: C1–C2
The coordinates of these points are Xi and
Zi (Fig. 2.3).
One tangent: C2–C3
C5
C0
C4
C1
C2
C3
Fig. 2.3. Designing the pilot hole profile.
C0
C1
C2
C3
C4
C5
Entry
Point of curvature
Point of tangency
Point of curvature
Point of tangency
Exit
Section C2–C3 does not need to be horizontal, although this is generally the case. If
the river is deeper on one side, and if you
want to avoid some gravel area on the other
side, you can decide to make this section
with an angle.
First calculate the horizontal and vertical
projections of the two circular sections.
This is easy, since you know the radius R is
the minimum allowable radius, and you
know the entry and exit angles. With the
basic formulas mentioned in Strength of
Materials (page 2-1), you have:
X2 - X1 = - R sin(aentry)
Z2 - Z1 = - R (1 - cos(aentry))
If Z2 ≠ Z3, with amiddle being the inclination of the middle section, you have:
X2 - X1 = R (-sin(aentry) + sin(amiddle))
Z2 - Z1 = R (cos(aentry) - cos(amiddle))
X4 - X3 = R (sin(aexit) + sin(amiddle))
Z4 - Z3 = R (cos(amiddle) - cos(aexit))
Note that the angles are trigonometric
angles (i.e., horizontal is zero, a 10˚ entry
angle [100˚ on the steering tool] is -10˚,
and an 8˚ exit angle [82˚ for the steering
tool] is +8˚). Thus the entry angle is negative, exit angle is positive, and middle
section angle is either or null.
For the straight sections, with L being the
length of the section, you have:
X1 - X0 = L cos(aentry)
Z1 - Z0 = L sin(aentry)
X4 - X3 = R sin(aexit)
Z4 - Z3 = R (1 - cos(aexit))
X3 - X2 = L cos(amiddle)
Z3 - Z2 = L sin(amiddle)
2-13
Horizontal Directional Drilling Training Program
sible. You may prefer the crossing to
remain as close to the surface as possible,
especially if the soil conditions worsen
with depth.
X5 - X4 = L cos(aexit)
Z5 - Z4 = L sin(aexit)
or, if the elevation difference is given:
If you are concerned about the soil changes
that occur with depth, set the middle section as close as possible to the middle
section of the exclusion area (Fig. 2.4) and
start the circular section at the vertical section of the banks.
X1 - X0 = (Z1 - Z0)/tan(aentry)
X3 - X2 = (Z3 - Z2)/tan(amiddle)
X5 - X4 = (Z5 - Z4)/tan(aexit)
You must change the entry angle if the bottom limit of the crossing is too high
compared to - R (1 - cos(aentry)). The same
applies to the exit angle. Once you have
modified these two angles, if required, you
must decide whether you want the crossing
to be as short as possible, or as low as pos-
If you are not concerned about the depth
and want a short crossing, reduce the
length of the middle section as much as
possible (even to zero), provided that the
lowest point is still above the bottom limit
(Fig. 2.5).
1
2
Fig. 2.4. Crossing’s profile: minimum depth.
1 Exclusion area
2 Bedrock
1
2
Fig. 2.5. Crossing’s profile: minimum length.
1 Exclusion area
2 Bedrock
2-14
Engineering: Crossing Engineering
The crossing’s layout
Entry side. First, define the entry and exit
sides of your crossing. For the driller, the
entry is where the drilling tool enters the
ground. The other side is the pipe side or
exit point. From time to time, the term entry
pit is also used for the pipe side. The entry
pit is the pit that is dug at the place where
the pilot hole exits. The entry pit collects
mud returns from the hole and, if required,
reduces the height of the catenary.
age tank is required. Usually, the water
supply will not be able to meet the rig’s
demand during pre-reaming or pullback,
and in any case, you should not rely on a
third party for water. Be sure that sufficient
water, in quality and quantity, is available
during all critical phases of the job, even if
these phases last longer than scheduled.
You cannot afford to run out of water during a difficult pre-reaming or pullback.
Generally, the pipe side is selected first
because its requirements are more restrictive. However, there are also some
requirements for the entry side related to
available space, water supply, and access
roads for the equipment and crew.
As explained in the drilling fluids section
of this course (Mud, Chapter 6), water
quality is also important. During the site
visit, take water samples and proceed with
the water analysis to make sure that bentonite will mix properly with the available
water.
The total weight for a 250-ton pull force rig
and its ancillary equipment consumables is
approximately 250 tons; several single
loads weigh 30 to 35 tons. Normal transportation to the site is by truck. Access
roads must be wide and strong enough to
handle such loads safely. Overhead clearance must also be checked, as well as local
transportation restrictions.
An alternative to road transport is river
transport. Obviously, the river must be free
from ice, unless the ice is very thick. Water
depth must be sufficient for barges and tugs
to reach the site. In addition, an access
ramp must exist or be built close to crossing’s site to unload equipment.
Water is usually supplied from the river. If
this is not the case, water supply must be
provided on the entry side and a safety stor-
Another potential problem related to the
entry side is noise. Whenever possible, the
entry side must be away from housing
areas. The pipe side is generally not as
noisy.
A typical entry side layout is shown in Fig.
2.6. The area required is about 200 x 200 ft
(60 x 60 m), depending on mud and water
pit sizes. It does not need to be square, but
it is good practice to have mud pits close to
the entry point and good access to these
pits for dump trucks. Also make sure that
heavy equipment can move easily around
the rig. Remember that in most cases,
mobile cranes won’t be able to move in
front of the entry point, especially after
pre-reaming, because they may cause the
hole to collapse.
2-15
Horizontal Directional Drilling Training Program
9
19
50 m
12
10
HDT
11
Mud Pit
15 x 15 m
500 m3
17
18
12
28
HDT
20
Mud Pit
20 x 10 m
500 m3
27
50 m
13
25
16
7
Access
25
Mud Return
Line
4
6
22
14
24
1
5
15
21
Center
Line
26
2
3
Fig. 2.6. Typical entry side layout.
1 Drilling rig
11 Workshop
21 Diesel storage
2 Power unit
12 Recycling unit
22 10 m3 waste
3 Control cabin
13 250 kva generator
4
5
6
7
8
9
10
14
15
16
17
18
19
20
23 10 m3 waste
24 75 kva generator
25 Dirty mud pump
26 Clean mud pump
27 Dirty mud storage
28 Clean mud storage
20-ton mobile crane
Mud unit
Drill pipes
Bentonite storage
Spare container
Tools container
Crew room
Mud pump
Mud pump
Drill path
Cuttings dump area
Parking area
Toilet container
Site office
Pipe side. The most important requirement
for the pipe side is space for the pipe string
(Fig. 2.7 and Fig. 2.8). Water supply may
also be a problem if the pipe must be ballasted. In that case, refer to entry side
comments about water (page 2-15).
The pipeline should be welded and pretested in a single string in the alignment of
2-16
the proposed crossing. The risk of getting
stuck during pullback is increased by
standby in the pulling operation, whether it
is because of a mechanical problem or a
tie-in of two sections. A tie-in may last several hours because the pipe must be aligned
properly, welded, and allowed to cool down
before x-ray inspection; and the joint must
be coated and allowed to dry (if necessary).
Engineering: Crossing Engineering
7
8
9
6
3
1
2
4
5
Fig. 2.7. Typical pipe side layout.
1
2
3
4
Pipeline string
Pipeline rollers
Entry pit
Mud pit
5
6
7
8
9
Mud pit (dirty mud)
Pipeline handling cranes with cradles
Water hose reel for ballasting (if required)
Water pump for ballasting (if required)
Hose from water source
Fig. 2.8. Pipe side, South Louisiana, USA.
Most of the pipe side area need not be
wider than the regular right-of-way. There
are two exceptions to this rule:
1. If mud returns must be trucked out to
the entry side, there must be sufficient
space for dump trucks to maneuver
without any restrictions.
2. Close to the exit point, an entry pit
must be dug and mud pits must be
built. Moreover, the pipe must be han2-17
Horizontal Directional Drilling Training Program
dled with heavy equipment to enter the
entry pit with the correct inclination,
which is the pilot hole exit inclination.
Generally, catenary cranes or sidebooms will be on the left side of the
pipe string, looking at the river. The
truck road, along the pipe string, will
be on the right side. If possible, mud
pits must be ahead of the entry pit and
on the right side. This is because dump
trucks should be free to move between
the mud pits and the exit of the pipe
side. Also, any equipment required to
handle tools or pipe should be free to
reach the entry pit in case of emergency. Therefore, the right-of-way
must be wider in the catenary area.
Catenary. The pilot hole exits at an angle
ranging from 4 to 10° and the pipe string is
laid on the ground. Be sure to handle the
pipe without buckling it—this is what is
defined as the catenary. The catenary is the
path that the pipe must follow to limit the
stresses in the pipe and load on the cranes
or sidebooms. This path is determined with
a computer program, which will be
explained later. It is important to remember
that a small variation in the path because of
incorrect positioning of even one crane can
drastically increase the force on the
crane(s) and stresses in the pipe.
You can estimate the length of the catenary
with a simple hand calculation, once you
know the minimum installation radius (see
Installation Conditions, page 2-10). If you
approximate the catenary with a combination of circles, with a radius equal to the
above-mentioned minimum radius, the
length and height of the catenary are:
L = R sin(a) + 2R sin(a/2)
H = R(1 - cos(a))
where a is the pilot hole exit inclination. To
reduce these two values, especially the
height, dig an entry pit for the pipe string.
This will also reduce the risk of mud breakouts on the pipe side (Fig. 2.9). This is very
important for large-diameter pipes because
the handling equipment for the catenary is
very heavy (60- to 100-ton cranes) and the
soil supporting these cranes must be
reinforced.
1
2
Fig. 2.9. Catenary with and without an exit pit.
1 Catenary with exit pit
2 Catenary without exit pit; height and length increased
2-18
Engineering: Engineering Procedures
Engineering Procedures
Preliminary evaluation
At this stage you may only have a rough
idea of the pipeline route, pipeline characteristics, nature of obstacles, and subsoil
conditions. Answer questions in these four
areas:
1. The pipeline nature and characteristics:
Can you pull that type and size of pipeline, or can you recommend a different
type and size, or casing, so that you can
do the job?
2. The length of the crossing: Can you
drill that length, and can you pull it?
Can you move the route elsewhere to
shorten the length? Can you split the
crossing into two shorter ones?
3. The necessary access and work areas:
Can you lay the pipe in the alignment
of the crossing, in one single section,
or can you modify the alignment
accordingly? Do you have access for
the rig, and do you have water of
acceptable quality and quantity?
4. The subsoil: Is it “good for HDD”; i.e.,
is it possible to avoid gravel layers and
remain above the bedrock, if any?
These simple questions should be easy to
address. If, based on experience, the crossing is too long, the subsoil is too difficult to
drill through, or other problems are evident, it is best to stop now and look for
alternatives.
Product line nature. The product line must
be pulled in a pre-reamed hole, as mentioned earlier. Therefore, it is not possible
to install a water pipeline with bolted connections, for example. The line must be a
steel line, or a high-density polyethylene
(HDPE) pipe with fused connections.
Pipe size. The maximum size of pipeline
that has been installed using the HDD
method is 48 in. (1.2 m). An alternative is
to lay two lines of smaller size across the
river. However, this solution is not ideal,
since the line maintenance may become
difficult.
Pipe length. Depending on soil conditions,
the maximum length that has been drilled is
between 5000 and 6000 ft (1500 and
1800 m). You may need to cross the river at
a different place, or drill from an island in
the middle of the river (if any). You can
also run a casing during pilot hole drilling.
To help you decide, refer to Fig. 2.10,
which shows the feasible length/diameter
range for HDD, based on a good alluvial
soil or rock crossing.
2-19
Horizontal Directional Drilling Training Program
L (m)
2000
3
1800
1600
2
1400
Fig. 2.10. Length/diameter
feasibility range.
1200
1 = Feasible
1000
2 = Feasible with good alluvial
soils
800
3 = Not feasible as per state-ofthe-art
1
600
400
200
0
10“
20“ 24“
30“
36“
48“
Pipe mechanical characteristics. If
the
crossing meets the nature, length, and size
criteria, verify that its mechanical characteristics are sufficient or can be adapted to
HDD requirements. Generally, various wall
thicknesses are available for the pipeline
construction. Go through the stress calculations in this chapter and verify that the
available pipe is acceptable. If it is not, you
must find out whether acceptable pipe can
be purchased or fabricated in time for the
project.
Pipeline coating and field joints. Pipeline
coating (and cathodic protection) will not
directly influence the feasibility of a crossing. You only need to remember that certain
types of coatings are not acceptable; use
any of the following:
2-20
•
three-layer polyethylene (PE) coating
•
sintered PE coating
•
Powercrete™ coating
•
epoxy coating.
∅
A fifth coating, called polypropylene, is
being developed and appears to be better
than three-layer PE. However, some problems are still being resolved for the joint
coating.
In all cases, use a thicker coating to allow
for some surface damage without risking
the cathodic protection.
The field joints are the weakest part of the
pipe coating, except for sintered PE, where
the coating continuity is fully restored
when it is done carefully.
Shrink sleeves are an acceptable solution if
they are specially designed for river crossing applications. For standard sleeves, the
glue is soft so all gaps can be filled. For
river crossings, it must be hard to resist
shear stress. The pipe coating ends must be
carefully beveled to allow proper shrinkage
and adherence of the sleeve. The sleeve’s
outer material must be reinforced with
fiberglass, and the front end must be protected from shearing with a special band.
Engineering: Engineering Procedures
The last alternative is to use epoxy paint,
although this solution is not recommended
because these coatings are almost impossible to repair if they become damaged. For
this reason, epoxy coating is not recommended if PE coating is available.
Powercrete is a rock shield coating compatible with the fusion-bonded epoxy
corrosion coating. Powercrete has a very
low coefficient of friction and is applied
over the fusion-bonded epoxy. This combination of coatings is the most effective for
protecting the pipelines during installation.
Under any conditions, tape coating of field
joints is not recommended. The same
restrictions apply to field repairs to the
coating. Although it is quite long, a sintered PE pipe can be repaired using the
same procedure as for field joints. For
major repairs on a three-layer PE coating,
shrink sleeves can be used. Patches are
acceptable for small repairs. For epoxy
coatings, epoxy repair paint is a possible
solution.
Catenary
It was mentioned earlier that the pipeline
string can be considered as a beam with
constant inertia. This beam is subjected to
its own weight, including the weight of the
buoyancy control system, if any, and to
reaction forces at each roller or cradle. It is
also subjected to the weight of the pulling
assembly (reamer or bullet nose, swivel,
pull head) and to the pull force necessary to
balance the friction on the rollers.
The rollers are generally installed 40 ft
(12 m) apart, which is the average distance
between each field joint. There is no need
to calculate the stresses for the whole string
lying on its rollers since the hyperstatic
problem takes much longer to solve when
the number of supports increases. However, the rollers that are more than 330 ft
(100 m) away from the cranes have no
influence on the loads and stresses in the
cranes area. Therefore, the catenary calculation will consider the two or three cranes
and the first five to 10 rollers.
The strength of materials problem is to
determine the rollers’ reaction for a given
position and determine the number of rollers/cranes. The length of pipe string that is
not input into the calculation applies a friction force at the pipe end. The pulling
assembly and pull force are equivalent to a
given force at the other end of the pipe
string, on the entry pit side. The direction
of that force is known, since it is the inclination of the pilot hole exit. The horizontal
projection of that force must be equal and
opposite to the friction force. Therefore,
you can calculate the vertical projection,
and the only unknown values are those of
the n reactions on the n rollers/cranes (Fig.
2.11 and Fig. 2.12).
2-21
Horizontal Directional Drilling Training Program
5
7
2
1
6
3
4
6
8
9
Fig. 2.11. Catenary.
1
2
3
4
5
6
7
8
9
Pipe end for catenary calculation
Crane and cradle number 1
Crane and cradle number 2
Crane and cradle number 3
Pulling assembly (pull head, swivel, reamer or bullet nose)
Pipeline rollers
Force at pipe end (friction on remaining rollers)
Pulling force
Weight of pulling assembly
Fig. 2.12. Pipeline string and catenary. Norfolk, Virginia, USA.
2-22
Chapter 3: Steering
Guidance Principles........................................................................... 3-1
Basic principles .................................................................................................. 3-1
Instrumentation .................................................................................................. 3-1
Coordinate systems ........................................................................................... 3-2
Calculation systems and methods ..................................................................... 3-2
Mathematical review .......................................................................................... 3-3
A review of basic trigonometry.........................................................................................3-3
Tangential method ............................................................................................................3-4
Tangential calculations ....................................................................................................3-4
Average angle method ......................................................................................................3-6
Average angle calculations. .............................................................................................3-6
Radius of curvature method..............................................................................................3-7
Radius calculations ..........................................................................................................3-8
Magnetics............................................................................................ 3-8
Borehole direction and inclination ...................................................................... 3-8
Geographic location ........................................................................................... 3-9
Magnetic sensor spacing ................................................................................. 3-10
Z axis interference ..........................................................................................................3-10
Spacing ...........................................................................................................................3-11
Outside sources of interference ....................................................................... 3-11
In-ground sources...........................................................................................................3-11
Above-ground sources ....................................................................................................3-13
Magnetic interference....................................................................................... 3-14
Steering tool interference ...............................................................................................3-14
Using Tru Tracker ..........................................................................................................3-22
Accuracy ........................................................................................... 3-27
Accuracy vs. repeatability ................................................................................ 3-27
Instrumentation ................................................................................................ 3-27
Human error ..................................................................................................... 3-28
Magnetic variation ............................................................................................ 3-28
Course length variation .................................................................................... 3-29
Job Site Actions—Pilot Hole ........................................................... 3-29
Arrival ............................................................................................................... 3-29
Walk the line ...................................................................................................................3-29
Unload and check equipment .........................................................................................3-30
Tru Tracker layout ............................................................................................ 3-30
Width .............................................................................................................................. 3-30
Length............................................................................................................................. 3-30
Wire ................................................................................................................................ 3-30
Corners........................................................................................................................... 3-30
Elevations....................................................................................................................... 3-30
Line sags ........................................................................................................................ 3-31
Coil shapes ..................................................................................................................... 3-31
Offset coils...................................................................................................................... 3-31
Testing ............................................................................................................................ 3-31
Preparing Tru Tracker data........................................................................................... 3-31
Steering tool rig-up ........................................................................................... 3-31
Profile ............................................................................................................... 3-32
Physical measurements ................................................................................... 3-33
Rig measurements .......................................................................................................... 3-33
BHA measurements ........................................................................................................ 3-33
Drill pipe measurements ................................................................................................ 3-33
Line azimuth shoot ........................................................................................... 3-33
Pressure testing................................................................................................ 3-35
Spud................................................................................................................................ 3-35
Drilling ahead.................................................................................................... 3-36
Tool operation................................................................................................................ 3-36
Data quality.................................................................................................................... 3-36
Projections ..................................................................................................................... 3-36
Directional control decisions............................................................................. 3-37
Radius control ................................................................................................................ 3-37
Intermediate targets ....................................................................................................... 3-37
Radius calculations ........................................................................................................ 3-38
Radius averaging ........................................................................................................... 3-38
Directions to driller............................................................................................ 3-39
Angular targets .............................................................................................................. 3-39
Position targets .............................................................................................................. 3-39
Drilling problems............................................................................................... 3-39
Wireline shorts ............................................................................................................... 3-39
Wireline leaks................................................................................................................. 3-40
Wireline opens................................................................................................................ 3-40
Tripping pipe out............................................................................................................ 3-40
Tripping pipe in.............................................................................................................. 3-41
Punchout .......................................................................................................... 3-41
Construction of as-built..................................................................................... 3-41
ii
List of Figures
Fig. 3.1. Right triangle......................................................................................................3-3
Fig. 3.2. Charting a 500-ft (152-m) crossing..................................................................3-18
Fig. 3.3. Charting a 1700-ft (518.5-m) crossing.............................................................3-20
List of Tables
Table 3.1. Survey tabulation sheet. ...................................................................................3-5
Table 3.2. Calculating linear azimuth correction factors................................................3-16
Table 3.3. Calculating straight line azimuth correction factors. .....................................3-16
Table 3.4. Scales for constructing a Mag/Dip Chart.......................................................3-18
Table 3.5. Magnetic mapping of the shoot area..............................................................3-32
Table 3.6. First test of line azimuth shoot data. ..............................................................3-34
Table 3.7. Second test of line azimuth shoot data. .........................................................3-35
Drilling the pilot hole.
iii
Notes
iv
Chapter 3: Steering
Guidance Principles
This chapter covers the basics of guidance
services. These services may be provided
by using surface locators, surface coil sys-
tems, gyroscopic systems, and magnetic
azimuth systems.
Basic principles
The principle of borehole guidance is to
accurately determine the relative position
of the bore from an entry point so that the
bore can be directed to a predetermined
exit point. Using a wireline steering tool,
positions and steering criteria can be calculated from four basic measurements:
Pipe length: The distance measured along
the course of the borehole from the entry
point.
Inclination: The angle between the vertical
and the axis of the borehole at a chosen distance from entry.
Azimuth: The angle between the horizontal component of the borehole at a specified
point measured clockwise from magnetic
north. All azimuths are expressed in the 0
to 360° system.
Tool face: A measurement of the position
of the bias of a bottomhole assembly
(BHA) perpendicular to the axis of the
borehole.
From the above measurements, standard
trigonometry can be used to calculate from
entry an elevation and left/right position of
the bore at the instrument’s position. From
tool face, a deflection tool can be oriented
to maintain or change the direction or elevation of the bore.
Instrumentation
The inclination and azimuth readings are
measured by electronic survey instruments
within the borehole, and the distance away
from the entry is measured by direct pipe
measurement at the rig.
A wireline steering tool consists of a sensor
section and a wireline transmission section.
The sensors contained are three accelerometers and three magnetometers mounted
orthogonally. The gravity and magnetic
data obtained from any attitude of the tool
in space can resolve its inclination and
azimuth.
The transmission section receives the sensor data, converts it from analog to digital
format, and transmits it along a single conductor wireline to the surface interface. The
signal then moves from the interface to a
laptop or desktop computer. After processing, the data are displayed on the computer
screen and sent back to the interface, where
it is provided through another wireline to a
remote display located directly in front of
the driller. The entire process occurs about
once every second. The data are used by
the software to calculate and store survey
calculations of current and previous bore
positions.
Since the tool measures the earth’s magnetic field to resolve magnetic north, it is
important to house the downhole probe in
an area free of any extraneous magnetic
interference. The bit, downhole motors,
most subs, and the drill pipe are strong
sources of magnetic fields. The high carbon
content of the high-quality steel needed for
the drilling process generates high residual
fields. The probe is housed within a nonmagnetic collar separating the drill pipe
and the drilling assembly. Therefore, magnetic sensors are spaced away from the
interference fields of the assembly and the
drill pipe.
Horizontal Directional Drilling Training Program
Coordinate systems
Plans for drilling operations are represented on paper, but the work is done in
three dimensions on the curved surface of
the earth. It is not possible to represent a
sphere precisely in two dimensions; however, since most jobs connect an entry and
exit with a straight line, two dimensions are
normally sufficient.
In many cases, a pipeline’s length from its
origin is used to measure or position the
entry point. This is called a station, which
has an origin point (0 + 00) at the beginning of the pipeline. Sometimes the profile
is represented based on stations. In every
case, you are dealing with distance away
from the entry, however represented, and
elevations.
Actual planned profiles begin at the entry
point and terminate at the exit point, or the
local coordinate system, which is determined for a specific project. A client will
accept data on a local system as long as the
entry point is known.
Elevations also may be expressed in a local
system with the entry point considered to
be zero. Often, mean sea level (MSL) or
another local datum is required. Once the
coordinate system is determined, a drilling
profile is drawn.
Calculation systems and methods
Calculating survey data for plotting on a
directional plan involves fundamental trigonometry. This section covers various
calculation methods and some operational
recommendations to use in the field. Read
the following definitions before beginning
the section to review important
information.
Measured distance: The total length of the
drill pipe and that part of the BHA up to the
probe’s sensor, measured from the entry
point.
Vertical depth: The vertical distance from
the surface reference elevation datum to the
probe’s sensor.
Inclination: The angle of the borehole in
degrees, measured from the vertical or horizontal plane.
Entry point: The point of entry chosen as
the beginning of the vertical and horizontal
profiles. Normally, the point where the drill
pipe enters the ground in front of the rig.
Exit point: The target expressed in distance
from entry, elevation, and a position left,
right, or directly on a centerline. This may
be a planned exit or an actual exit point.
Horizontal plan: A projection in plan view
of the left or right position of the bore
against a planned centerline.
3-2
Profile: A projection of the vertical position of the bore against a planned vertical
profile.
Vertical section: A mathematical calculation to express 3-D positions in two
dimensions.
Radius: An expression defining the exact
curvature of a line, expressed in feet or
meters.
Dogleg severity: The total 3-D change of
angle between two given points. This is
expressed by the calculation program in
degrees per 100 ft (30.5 m) and may be
directly converted to a radius between the
two points.
Raw data are used to determine the position
of a point along a borehole. Instruments
currently in use produce the raw data,
which are then used in calculations to
obtain the final values.
Many new methods have improved the calculation of the curved path of the bore
between two survey stations. Since the calculation’s accuracy depends on the
frequency of survey stations and surveying
takes time, much effort has been expended
in mathematically modeling the theoretical
bore path between stations. These models
are the tangential method, average angle
method, and radius of curvature method.
These methods are discussed in detail in
Steering: Guidance Principles
the following sections, along with the calculations appropriate for each method.
None of these methods take into account
the fact that the driller can influence the
calculation method. He sees his angular
position at every foot drilled and makes
corrections as needed. Normally, he is
given an inclination target that he must hit
at the end of the joint to be drilled. Usually,
he hits this target within the first third of
the joint and uses the balance of the joint to
hold his target angle. In a 30-ft (9.2-m)
joint, the first 10 ft (3 m) would then be a
curve, while the following 20 ft (6 m)
would be a straight line at the desired
higher angle. Since the angles measured
form the basis for the resulting calculated
position, the driller can bias the calculations by changing when he reached the
desired angular target during the joint. This
bias must be accounted for.
Mathematical review
This section covers the fundamental mathematics required for the job. As a minimum,
basic trigonometry is necessary, while a
working knowledge of geometry is also
beneficial.
A review of basic trigonometry. A
right
triangle is composed of one angle equal to
90°, and two angles less than 90° (Fig. 3.1).
The side opposite the 90° angle is called
the hypotenuse, labeled c. All three angles
must add up to 180°.
lp
ril
(d
a (vertical)
c
e)
ip
Fig. 3.1. Right triangle.
A
b (horizontal)
If the length of any two sides of the right
triangle are known, the length of the other
side can be determined by Pythagorean’s
Theorem:
are listed below for the angle marked A in
Fig. 3.1.
a
sin A = -c
a2 + b2 = c2
For example, if c = 10 ft and b = 9 ft, then:
a =
10 2 – 9 2 = 4.36ft
Furthermore, if one side of the triangle and
an angle (other than 90°) are known, all
other sides and angles can be solved using
trigonometric functions. These functions
b
cos A = --c
tan A = --ab
For directional drilling, the hypotenuse of
the triangle c is the drill pipe, side b is the
away or horizontal distance, and side a is
the vertical drop, or build.
3-3
Horizontal Directional Drilling Training Program
For example, if angle A = 12° and side c =
10 ft, then:
a
sin 12° = -----10
10 sin 12° = a
10 ( 0.208 ) = a
2.08 = a
To solve for side b:
b
cos 12° = -----10
10 cos 12° = b
10 ( 0.978 ) = b
9.78 = b
Tangential method. This method assumes
that the bore maintains the same inclination
angle and hole azimuth as measured at the
end of a drilled joint.
Advantages.
•
The method is easily calculated by
hand.
•
The error tends to show a slight
increase in elevation over distance,
thereby better reflecting how most
drillers drill a joint.
Disadvantages.
•
No theoretical justification.
•
Automatically generates an elevation
increase over distance.
or walkover system positions. Use the best
fit.
Tangential calculations. As
covered
above, the tangential method of calculating
position is quick and easy. Refer to the survey tabulation sheet (Table 3.1) for use in
this example. A 10°-entry angle and 30-ft
drill pipe stems will be used.
Line A is the bit-to-sensor measurement.
This is the physical measurement from the
bit to the probe sensors in the non-magnetic collar.
D = C - (A + B)
With the initial course length, calculate the
away station using the tangential method,
distance left or right, and the elevation.
Remember that the initial entry angle was
10°, but note that the probe reads 80°—
this is the number used in the calculation.
Suppose that the course length in Column
D is 11.5 ft and that the angle is built to
80°. This angle at the bottom of the drilled
joint is the angle to use with the tangential
method. The azimuth is also used to calculate closures. If the line azimuth (Az) is
150° and, because of magnetic interference
near the rig, it was necessary to plug the Az
at 150°:
Away = course length x sin (Inc) x
cos (Az)
Note that this Az in the calculation is the
difference between line Az and drilled Az,
which in this case would be 0. Therefore:
Away = 11.5 x sin (80.6°) x cos (0°)
Away = 11.5 x 0.9866 x 1
Away = 11.34 ft
Recommendations. Always begin a job
using this calculation method. Watch how
the driller obtains his targets. If he aggressively chases the target early, stay with the
tangential method. If he waits to obtain his
desired angle at the bottom of the joint,
change to another method of calculation.
Compare both methods to direct elevation
readings from Tru Tracker™ coil positions
3-4
This number is placed in Column H.
Next, calculate the distance moved left or
right of centerline:
Right = course length x sin (Inc) x
sin (Az)
Table 3.1. Survey tabulation sheet.
Client
Location
Country
Job No.
Engineer
Probe No.
Ground Elevation: Entry
Date
Remarks
Jt. No.
Time
Sht
Of
Sht Azi.
Mag
Bit–Sensor
Vice–Entry
TF Offset
BHA Length
Crossing Length
Coil File
Sumitomo
Directional Drilling Systems
Dip
Rig Azi.
Surv.File
A
B
C
Exit
Pipe Length
CL
MD
D
K
E
L
High
Side
Inclination
Raw
Avg
F
Azimuth
Raw
Avg
G
Mag
Dip
Elevation
Station
Away Survey
TT
H
I
Survey
Left
Right
Ja
Tru Tracker
Left
Right
Jb
Steering: Guidance Principles
3-5
Horizontal Directional Drilling Training Program
Again, this AZ is the difference between
the line Az and drilled Az.
Right = 11.5 x sin (80.6) x sin (0°)
Right = 11.5 x 0.9866 x 0
Right = 0 ft
Because the Az did not change, it did not
deviate from centerline. This number is
entered in either Column Ja or Jb, depending on whether it moved left or right of
centerline.
Now calculate the elevation drop or true
vertical depth (TVD):
TVD = Course length x cos (Inc)
TVD = Course length x cos (80.6)
The average angle method treats the bore
as a straight line, but approximates the
slope of the line by taking the average of
the inclination angles at each end of the
drilled section. This process is also carried
out for the hole direction (azimuth) readings. These averages are used in a standard
tangential calculation to determine elevations and left/right positions.
This method becomes less accurate as the
difference between either pair of angles
increases or as the distance between survey
stations becomes large. Within these limitations, however, the results obtained with
this method differ little from those obtained
from more sophisticated methods.
Advantages.
•
Fairly accurate, and good repeatability
with other more advanced methods.
•
Calculations are simple enough for
field use with a non-programmable calculator.
TVD + 11.5 x 0.1633
TVD = 1.878 ft
By drilling 11.5 ft and moving from an
entry angle of 80° to a drilled angle of
80.6°, TVD has dropped approximately
1.9 ft in elevation. This number goes in
Column I.
The next course length, Column K, will be
added to the initial measured depth, Column E, to determine the new measured
depth, Column L. Use Column K to do the
next set of calculations. Note:
1. From now on, the difference in azimuth will be the difference between the
previous azimuth and the present azimuth.
2. After calculating the away, elevation,
and left/right, add these to the previous
distances to maintain a running tally.
Average angle method. This
calculation
method, also called the angle averaging
method, assumes that the borehole is parallel to the simple average of both the
inclination and hole azimuth angles
between two survey stations (the beginning
and end of a joint).
3-6
Disadvantages.
•
No theoretical justification.
Recommendations. On many crossings,
this method works well. Always compare
the tangential method with the average
angle method at various points during a
crossing. The choice of methods should be
based on driller bias and further comparison with surface location systems.
Average angle calculations. Calculating
with the average angle method will now be
reviewed, using the same numbers that
were used in the tangential method.
Course length = 11.5 ft
Inclination1 = 80° (entry angle)
Inclination2 = 80.6° (drilled angle)
Azimuth1 = 150° (line Az)
Azimuth2 = 150° (plugged Az)
Steering: Guidance Principles
To calculate the away station using the average angle method:
( Inc 1 + Inc 2 )
( Az 1 + Az 2 )
- × cos ----------------------------Away = Course length x sin ------------------------------2
2
( 80° + 80.6° )
( 150° + 150° )
Away = 11.5 x sin --------------------------------- × cos ---------------------------------2
2
Az 1 + Az 2
------------------------- = Az 3
Note:
2
Just as in the tangential method, take the cosine of the difference between line Az and Az 3
to use in this formula.
Away = 11.5 x 0.9857 x 1
Away = 11.33 ft
This number will be placed in Column H. Next, calculate the distance moved left or right
of centerline:
( Inc 1 + Inc 2 )
( Az 1 + Az 2 )
- × sin ----------------------------Right = Course length x sin ------------------------------2
2
Az 1 + Az 2
Again, ------------------------ = Az 3
2
Take the cosine of the difference between line Az and Az3.
Right = 11.5 x sin (80.3°) x sin (0°)
Right = 11.5 x 0.9857 x 0
Right = 0
Finally, calculate the elevation change or TVD.
( Inc 1 + Inc 2 )
TVD = Course length x cos ------------------------------2
TVD = 11.5 x cos (80.3°)
TVD = 11.5 x 0.1685
TVD + 1.9376 ft
Radius of curvature method. In the radius
of curvature method, the data from two survey stations are used to define the assumed
circular arc trajectory of the borehole
between these points. The borehole is
assumed to be curved in either or both vertical and horizontal planes.
Advantages.
•
Sound theoretical justification.
Disadvantages.
•
Complex calculations require a programmable calculator or computer.
3-7
Horizontal Directional Drilling Training Program
•
Rarely different from average angle
calculations.
•
Not easily explained to customers.
If calculating the horizontal distance of the
same curve using the same information,
use the following formula:
Horizontal distance = cos 78° x 1000 ft
Radius calculations. With any horizontal
crossing, the depth and the horizontal distance of a curve must be calculated. To
make these calculations, some basic information is needed. If the drop in an entry
curve is calculated, the expected entry
angle and radius to be drilled must be
known. In the following calculations, an
entry angle of 78°, a radius of 1000 ft, and
the end of the curve at 90° (horizontal) are
used:
Drop = R - (sin 78° x R)
Drop = 21.85 ft
Horizontal distance = 207.91 ft
The horizontal distance and the amount of
drop in the curve are now known.
Situations may arise where you have a
known entry angle and the horizontal distance to the location where the curve must
end at 90°. If given an entry angle of 78°
and a horizontal distance of 300 ft, you can
calculate the radius you must drill to
accommodate the known data. Do this by
using the following formula:
Radius = 300 ft/cos 78°
Radius = 1442.92
Magnetics
During the process of drilling a borehole,
the steel components of the drill string
become magnetized. Magnetic surveying
devices placed within the drill string are
affected by magnetized components of the
drill string. Therefore, surveying devices
are always placed in a non-magnetic section of drill string. These non-magnetic
sections act as spacers, causing the magnetic poles to be “spaced” away from the
sensors/compass. By spacing the sensor/
compass a proper distance from the magnetic poles, the interference on the sensor/
compass will be minimized. Magnetic field
interference varies with the inverse square
of the distance between the source and the
sensor/compass. That is:
PoleStrength
InterferingForce = ---------------------------------Dis tan ce 2
Therefore, as the distance between the
magnetic source and the sensor/compass
increases, the force on the sensor/compass
decreases exponentially. For example, if a
force F is affecting a sensor/compass at a
distance of 4 ft, then the interfering force
(IF) will be reduced to 1/4 strength at 8 ft,
or to 1/9 strength at 12 ft.
Borehole direction and inclination
A leveled magnetic sensing device, such as
a compass or a magnetometer, actually
relies only on that portion of the earth’s
magnetic field that is in the horizontal
plane. Therefore, only that portion of the IF
(caused by magnetized steel) that is in the
horizontal plane will affect the magnetic
setting. As the inclination of the drill string
becomes more horizontal, the greater will
be the IF that exists in the horizontal plane.
Therefore, at high inclinations (e.g., 90°
borehole) the effect on the sensor is maxi3-8
mized. The horizontal component of the
interfering force IFH is defined as:
PoleStrength
IF H = ---------------------------------× sin ( inclination )
Dis tan ce 2
The direction (azimuth) in which the drill
string is positioned is also a factor in determining the effect of the IF on the magnetic
sensor. If IFH is divided into north-south
and east-west components, then angle a
Steering: Magnetics
represents the direction of the drill string.
IFH can be divided into a north component
(IFH north) and an east component
(IFH east). At angle a the following vectors
can be determined:
Total north vector = H + IFH north
Total east vector = IFH east
The following formula mathematically
expresses the vector addition of magnetic
north and the IF (north and east)
components:
IFtotal = Total north vector +
Total east vector =
( H + IF H north ) 2 + ( IF H east ) 2
The total IF will cause the sensor to read an
erroneous magnetic north. The azimuth
error is represented by angle Z and can be
expressed as:
IF H east
sin Z = -----------------IF total
or
IF H east
Z = Arc sin -----------------IF total
The above formulas are included to make
you aware that it is possible to calculate
interference originating from the drill
string. This is called Z axis interference,
since the Z axis, magnetometer (the one in
the pipe axis) is the one picking up most of
the interference from the drill string.
Remember that if Z axis interference is
present while drilling, the resultant azimuth
will be affected differently as inclination
and direction changes.
Geographic location
Geographic location must also be considered when understanding the effects of
magnetic interference caused by magnetized drill string components. As stated
earlier, a leveled magnetic sensing device
senses the horizontal component of the
earth’s magnetic field. The amplitude of the
horizontal component of the earth’s magnetic field varies with geographic location.
The horizontal component of the earth’s
magnetic field is at a maximum near the
(magnetic) equator, and at a minimum near
the north and south poles. Only the horizontal component of this magnetic field
affects a leveled magnetic sensor used to
indicate azimuth (such as a compass or
sensor). As the latitude increases north or
south from the equator, the angle of dip of
the earth’s magnetic field increases. This
increases the effects of the vertical component of the earth’s magnetic field and
decreases the effects of the horizontal component. Thus, any magnetic sensor is
required to act on a diminishing horizontal
component as it is moved north or south
from the equator, and it is more likely to be
affected by interference from other horizontal field effects. Therefore, a magnetic
sensor can sense magnetic north easier at
the equator than near the poles because a
stronger natural horizontal force will be
exerted on the sensor. If an IF is present, it
will have a more noticeable effect on directional readings taken near the poles than on
readings taken near the equator. That is, the
magnetic north vector (H) will be less pronounced at the poles, so the effect of an
IFHeast or IFHwest will be even more influential. Understand that the increase or
decrease in magnetic interference at different geographic locations is not caused by
an increase or decrease in the IF of the
magnetized drill string, but is caused by the
increase or decrease of the horizontal component of the earth’s magnetic field. Any
lessening of the earth’s natural field allows
the drill string field to have more influence.
Sensing devices measure the inclination
and direction of the hole as well as the high
side of the BHA. When magnetic interference is present, some of these sensors will
be affected. Since the inclination and high
side tool face are measured by accelerometers and are fairly independent of magnetic
north, they are not affected. However, hole
direction is referenced to magnetic north
and any error in detecting magnetic north
3-9
Horizontal Directional Drilling Training Program
will result in an erroneous hole direction or
azimuth.
At points on the earth’s surface where the
horizontal component of the magnetic field
is minimal, a dip needle will rest with its
axis vertical. Such points are called dip
poles. Principal poles of this kind are situated near the north and south geographical
poles; they are called the magnetic north
and magnetic south poles. (The dip pole
near the geographic north pole is, in reality,
a south magnetic pole, although it is
referred to as magnetic north.)
Magnetic sensor spacing
As noted earlier, the BHA and drill pipe are
strong sources of magnetic interference,
commonly called Z axis interference,
which must be minimized. The greatest
responsibility during rig-up on location is
to accurately establish the line azimuth.
This cannot be done with confidence if Z
axis interference is present.
Z axis interference. Take the following
steps to test for Z axis interference:
1. Locate a magnetically clean area by
connecting a test lead to a steering tool
probe and roughly aligning with the
axis of the planned bore. Ensure the
probe is rotated to probe high side and
is not software-corrected. Note H-Total
and dip on scratch paper. Move the
probe 5 ft (1.5 m) right or left and note
data. Move 5 ft (1.5 m) forward or
back and note data. The three readings
should be very close as long as tool
high side has not been changed during
movement.
If the readings differ by more than 0.1°
dip or more than 40 in the H-Total,
move back to first locations and
attempt to repeat initial readings. They
should repeat. After repeating, move
the probe in directions opposite from
the first moves. Again, look for differences. If different, continue moving
forward until a location is found that
repeats the dip and H-Total within
specs. Once a clean location is found,
orient the probe to centerline. Note dip,
H-Total, and azimuth on paper.
2. Lay the BHA on the ground at least
15 ft (4.6 m) from the probe. Lay down
the jet or motor 12 in. (30.5 cm) from
the front of the probe, and look at the
data. If different from what was noted
3-10
on paper, continue moving the motor or
jet forward, further from the probe
until the original readings are obtained.
At this point, move the assembly an
additional 24 in. (61 cm). Leave the
assembly in position on the ground.
3. Pick up the crossover sub and lay it in
its normal connected position on the
ground. Check that the data are not
affected. If so, move sub and motor or
jet further from the probe.
4. Pick up the non-magnetic collar and
lay it alongside the probe, being careful
not to touch or move the probe. Note
the data on paper.
5. Pick up a joint of drill pipe with its
crossover installed and lay it in its normal running location behind the nonmagnetic collar. Check data. If
affected, begin moving it further
behind the assembly until the original
readings are obtained. At this point,
move the drill pipe an additional 24 in.
(61 cm) and measure the distance from
the shoulder of the crossover sub on the
end of the drill pipe to the shoulder of
the non-magnetic drill collar. This is
the length of additional non-magnetic
collar that you need.
6. Measure the distance from the shoulder
of the bottom of the probe to the probe
connection shoulder in the orienting
sub. This is the distance to space the
probe away from the drilling assembly.
7. You now have a clean BHA that is not
producing Z axis interference.
8. In some cases, non-magnetic collars
will become slightly magnetized. This
would have been noted in step 4. Nor-
Steering: Magnetics
mally, it is OK to drill with some interference.
If you locate a magnetically clean area, pull
the probe through the non-magnetic collar
and print screen at each foot of length. The
resulting magnetic picture should be the
same throughout. If it is not, identify
exactly where the “hot spots” are and
ensure that you space away from these
spots.
Spacing. Once all measurements of the
BHA have been made, check the following
three points, taking into account spacing
away from Z axis interference:
1. Distance from bit to probe sensors:
This is the physical measurement from
the end of the bit to a point between the
magnetometers and the accelerometers.
Record this measurement on the field
sheet in the space allotted.
2. Entire BHA: The physical measurement from the face of the bit to the
shoulder of the crossover sub above the
non-magnetic collars, including the
sub. Record the measurement on the
field sheet in the space allotted.
3. Make up BHA: Once the assembly is
made up before spud, ensure the previous measurements are reasonable. This
can take the form of a second measurement, stepping off the length or, in
some cases, estimating the length.
Once you’ve done this, refer back to
your initial measurements and compare
them. If they are correct, proceed to
spud.
If you do determine a BHA measurement
difference, note it on the field sheet and
attempt to quantify the error before spud.
Note the same in your daily report.
Outside sources of interference
Z axis interference relative to the drill
string was previously discussed. In addition, you may also see Z axis interference
when approaching an outside magnetic
field. If so, usually you will not be able to
quantify it as Z axis, unless you are horizontal and not changing direction. By
watching the sensor readings and seeing no
changes in your X and Y magnetics, but
some change in Z, you may identify an isolated occurrence of Z axis interference.
Usually, you will not have time to watch
sensor readings in isolation, but will be
watching H-Total and dip for interference
warning purposes. Normally, in utility and
pipeline drilling, there are many sources of
interference to look for. Immediately on
arrival in a new location, make time to walk
the line. Keep your eyes open for any
potential magnetic problems. Look at the
topography and the surrounding landscape, and make notes for later reference.
In-ground sources. There
are
many
sources of underground interference. Look
at the field drawings. Pipelines and services
will be shown—most of the time. Abandoned services, however, usually will not.
Pipelines. Buried pipelines are common,
and they may cross perpendicularly or
obliquely anywhere. If trenched, they will
normally be 3 to 5 ft (0.9 to 1.5 m) below
the surface. If drilled, they may be anywhere. It is important to locate pipelines
relative to the bore path being drilled. This
should take the form of physically measuring its location and transferring the
measurements to the drilling plan, if it
could pose a hazard to progress. Magnetically, it is important to understand exactly
where the line is.
Pipelines normally have a cathodic protection current running through the line. This
is a direct current (DC) source; normally
low-current, powering cathodes. These are
used to slow the oxidation process of a
pipeline by sacrificing a faster oxidizing
metal. If Tru Tracker coils are associated
with cathodic protection, the readings will
be affected. Normally, unless the bore path
is very close (5 in. [12.7 cm] or less),
cathodic protection will not affect azimuth.
The steel of the pipeline will, however. If
the bore path is within 30 ft (9 m) of a 12in. (30-cm) line or larger, some interference
can be expected. Measure the distance both
3-11
Horizontal Directional Drilling Training Program
horizontally and vertically. Beyond 30 ft,
you should be aware of the line.
Entry and exit points are critical. With permission, expose any line you are
approaching in azimuth or elevation. Do
not fall back on the client’s “as laid” drawings. Alert the client to the possible
problem and ask to expose the line while
you drill at the sensitive point.
Underground tunnels. Expect that tunnels
will have significant associated steel within
their construction. Their size will determine their affect on azimuth.
Fiber optic cables. All the above comments
relative to safety pertain to fiber optic telephone cables. These cables normally have a
steel outer shield. The effect on azimuth
normally is minimal, depending on your
distance from it.
Underground trash. Old building foundations, bridge abutments, landfill areas, and
many other items may cause guidance
problems. Normally, by walking the bore
path, you will locate many potential problems. Make notes and physically measure
those that could have the most impact on a
job. Draw them on the drilling plan to
scale.
Power cables. All comments relative to
safety pertain to power cables. These
cables vary from very low alternating current (AC) to steel-coated, oil-filled
megawatt transmission lines. They will
affect azimuth and Tru Tracker readings.
Telephone cables. All comments relative to
safety pertain to copper telephone cables.
In many areas high- and low-volume copper cable is still in use, rather than fiber
optic cable. Since telephone lines use DC
current, they are a major source of azimuth
and Tru Tracker interference.
All other cables. Most underground cables
will generate interference. It is best to stay
as far away as possible from them and note
on the drilling plan exactly where they are.
Plastic pipelines. Plastic pipelines will not
generate interference. It is still best not to
plan a bore near them, although normally it
is not possible to choose the best path every
time.
Sheet piling. Normally, sheet piles are
associated with river banks, although they
may be found in any area for ground consolidation. They are usually steel and will
significantly affect magnetic azimuth when
drilling under or parallel them. Tru Tracker
will be affected if the coil wire is placed
such that the pile is located between the
probe and the coil wire. It will also be
affected when attempting to enter sheet3-12
piled exit pits. Expect major interference
within 30 to 60 ft (9 to 18 m) of sheet
piling.
Bridges. Pipeline crossings often are
planned near bridges since the right-of-way
permissions are easier to obtain. Bridges
pose real guidance problems if close
enough to impact magnetic azimuth.
There are two problems to overcome with
bridges. First is the mass of the bridge
itself. Regardless of the type of construction, steel or concrete, there is a very
significant mass of iron to be concerned
about. The actual bridge may rise in elevation toward the center of the span, causing
different magnetics on every joint. Second,
the bore path may not be parallel to the
bridge, also causing different magnetics on
every joint. The footings of the bridge will
be supported either by bedrock or deep
construction pilings. As drilling progresses
near bridge footings, the magnetic intensity
of the interference increases and decreases
as the footings are passed. Expect magnetic
problems from the span about the same
horizontal distance as the height of the
span. Depending on the type and depth of
the footings, expect problems closer than
100 ft to the footings. The magnetics will
be different on the entry and exit sides of
the river.
Measure and plot on the drilling plan the
orientation of the span relative to the bore
path. Also, measure and plot the footings
against distance on the bore plan.
Steering: Magnetics
Above-ground sources.
transmitting frequencies and length of
transmissions.
Bridges. Note above comments on bridges.
Buildings. The amount of interference differs with the size and type of building
construction, as well as how far away the
bore path is planned. Expect minimal problems with housing construction and
significant problems with office towers.
All transmitting antennas and repeater stations are grounded to the earth. During
transmissions an in-ground field will be
established, causing potential Tru Tracker
interference. This has been noticed up to
200 ft (61 m) away, although it was difficult to determine if the transmission or the
antenna ground was the cause.
Tanks and tank farms. A single tank (or
metal object with mass) has significant
magnetic properties associated with it.
These are generally local in nature and may
be bypassed relatively quickly. Once 30 ft
(9 m) or more away, the interference
diminishes.
Railroads. There are three problems with
railroad crossings. First is the steel rails
themselves, which cause a local field as
you pass under them. Tru Tracker will not
be affected by the rails alone.
A storage tank farm, on the other hand,
generates a significant local anomaly in the
earth’s magnetic field strength and dip. If
drilling within the tanks, the magnitude of
interference will render azimuth readings
worthless. If Tru Tracker coils are laid
improperly, these data will also be affected.
Always refer to office personnel for assistance in determining correct coil layouts
when drilling within a tank farm.
Second are the various services that may be
present. Rail rights-of-way are used by
many utility companies for in-ground services. The railroad itself will use the rightof-way for signal cables, switching cables,
and communication cables. Tru Tracker
will be affected significantly by signal and
switching cables. The effect will be an offset position when the signal or switching
current is on. Since you do not know when
this happens, you are faced with secondguessing the data.
In planned crossings that drill toward, away
from, or parallel to tank farms, expect
changing magnetics in varying degrees up
to 1000 ft (305 m) away from the nearest
tank. Azimuth differences will occur
between entry and exit readings. Benchmark an entry and exit shoot to account for
these differences.
Grain elevators. Normally, consider these
as buildings with local problems only.
Cranes and other heavy equipment. These
create local problems only, which will
diminish quickly when passed.
Communication station antennas. Shortwave (SW), very high frequency (VHF),
ultra-high frequency (UHF), and microwave antennas generate electromagnetic
fields. The high frequency of the emissions
normally will not affect magnetic azimuth
a great deal. Long-wave (LW) and very low
frequency (VLF) will affect azimuth within
a mile (1.6 km) or so of the transmitting
station. The magnitude of interference will
not be quantifiable because of different
Third, in most areas of the world, you will
find electric trains powered by an overhead
system consisting of traction current. This
DC current is applied to the overhead from
a cable underground at various points along
the length of the rail line. As the train
moves between sectors, it will draw its
power requirements from the nearest
source.
As a train approaches, the current nearest
the probe will increase, reaching the maximum current draw when the train is at its
nearest point to the probe. Since the magnetic field’s magnitude follows the current
curve, both azimuth and Tru Tracker will
be affected somewhat as soon as the train
begins drawing its power from the local
power sector.
The azimuth error magnitude will increase
smoothly with the train’s approach and
decrease as the train moves away. A Tru
Tracker reading will show increasing offsets as the train approaches, and decreasing
offsets as it moves away. Interference has
3-13
Horizontal Directional Drilling Training Program
been noticed up to 200 ft (61 m) away from
the tracks. These problems normally may
be overcome by simply waiting for trains to
pass, although in highly traveled areas in
large cities, it remains a major problem.
The client must be kept advised of the
problems and an attempt to determine or
quantify degradation of accuracy should be
made.
Overhead cables. Generally, overhead
cables cause few problems since you pass
under and move away from them. Usually
they will not affect readings within 100 ft
(30.5 m), although with megawatt lines
parallel to bore path the influence can
exceed 100 ft.
The magnetic field generated from the
overheads will vary with time, causing azimuth and Tru Tracker readings to offset.
The magnitude of the offset sometimes
may be quantifiable, allowing operations to
continue safely.
Magnetic interference
First determine the accuracy of the azimuth
or Tru Tracker reading. Identify the interference and attempt to quantify it. If done
in an organized manner, the punchout accuracy will improve. This section covers both
azimuth and Tru Tracker interference.
Steering tool interference. As noted previously, the earth produces a magnetic field
that can be measured with magnetometers.
If three magnetics are used orthogonally,
the measurements will resolve the earth’s
field strength, dip angle, and azimuth relative to the instrument. If the instrument is
moved physically in a straight line and the
magnetic field does not change, the azimuth produced will be the same at all
points on the line. If the dip or field
strength changes because of a local magnetic anomaly, the azimuth reading will
change even though the instrument continues to move in a straight line. This effect
forms the basis of most interference
troubleshooting.
The field data sheet (Table 3.1) has columns for azimuth, mag, and dip to be
recorded. They should be noted at every
survey station during the pilot hole. In
some cases where strong local fields are
encountered, it may be necessary to stop
the drilling operation every few feet to
check the change in mag and/or dip.
while the best case is a north/south
orientation.
Unlike Z axis interference, which is predictable in terms of the direction of the
error, interference from surface or subsurface sources affects all three sensors, with
the X and Y sensors being most affected.
This is much more difficult to predict since
in many cases you will not be able to identify the source. If the source is identifiable,
the problem becomes much easier to
handle.
It is not possible to quantify from the data
the amount of error you see in a given survey. It is possible to judge whether the
interference causes an increase or decrease
in the azimuth reading when the only interference source is located to the right or left
of the bore path and is a surface source
(such as buildings, towers, or bridges) An
underground source whose elevation is
lower than the bore path should produce an
opposite effect of a source located higher
than the bore path. The polarity of a magnetic field will produce opposite effects
when reversed.
Azimuth effect if known source of interference is right of the bore path.
When drilling north:
Interference to the azimuth occurs when
the intensity or dip angle changes. The
worst case (largest magnitude) of interference occurs in an east/west orientation,
3-14
•
If dip goes up, azimuth goes down.
•
If dip goes down, azimuth goes up.
Steering: Magnetics
When drilling east:
•
If dip goes up, azimuth goes down.
•
If dip goes down, azimuth goes up.
When drilling south:
•
If dip goes up, azimuth goes up.
•
If dip goes down, azimuth goes down.
When drilling west:
•
If dip goes up, azimuth goes up.
•
If dip goes down, azimuth goes down.
Azimuth effect if known source of interference is left of the bore path.
When drilling north:
•
If dip goes up, azimuth goes up.
•
If dip goes down, azimuth goes down.
When drilling east:
•
If dip goes up, azimuth goes up.
•
If dip goes down, azimuth goes down.
When drilling south:
•
If dip goes up, azimuth goes down.
•
If dip goes down, azimuth goes up.
When drilling west:
•
If dip goes up, azimuth goes down.
•
If dip goes down, azimuth goes up.
Magnitude of error quantification.
Any
attempt to quantify the amount of azimuth
error must be based on a significant amount
of data and its logical presentation. A Mag/
Dip Chart will assist in graphically keeping
track of the data in a logical format. The
questionable areas of interference will be
immediately apparent and azimuth decisions can be made on a structured basis.
The chart should be used on every occasion
where interference is experienced, where
Tru Tracker is not used, and where exit limits are tight. Benchmarking a magnetic
azimuth may be undertaken directly from
the chart. Methods of constructing the
Mag/Dip Chart follows this section
(page 3-17).
Given a clean Z axis situation and a clean
probe orientation where mag, dip, and azimuth have been noted before spudding the
bore, the mag and dip will be constant for
the entire length of the bore.
If the mag or dip changes, the resultant azimuth will be affected, as stated earlier.
Magnetic intensity also produces proportional changes, but they are more difficult
to quantify. Roughly, its effect on azimuth
follows dip somewhat, but since it is an
expression of force, it is much more difficult to predict. For the purpose of
quantifying errors, the methods will be limited to dip angles.
Since the magnetic field size causing the
problem is not known, the magnitude of the
error cannot be accurately predicted; however, some rules of thumb may be applied:
1. When drilling north or south and the
interference source on either side of the
bore path is not known, large dip
changes produce small azimuth errors.
2. When drilling east or west and the
interference source is on the right of
the bore path, small dip changes produce small azimuth errors, and large
dip changes produce large azimuth
errors.
3. When drilling east or west and the
interference source is on the left of the
bore path, small dip changes produce
large azimuth errors, and large dip
changes produce even larger azimuth
errors.
The worst case of interference will be a
source to the right of the bore path when
the line azimuth is east or west. Consider
this when planning jobs and while drilling.
Apply the above principles when attempting to quantify the amount of error in
azimuth. In addition, closely study the
topography and relate it to the error problems that are occurring. Plot known
sources or expected sources of interference
3-15
Horizontal Directional Drilling Training Program
on the Mag/Dip chart within a judged
scale.
Calculating linear azimuth correction
factors. While drilling, if you encounter a
2° increase in dip combined with a 5°
increase in azimuth, and a building is
located 30 ft (9 m) to the left of the bore
path, which is east, a very large error in azimuth will occur.
If at the end of the next joint drilled, the dip
returned to normal and azimuth decreased
by 5°, you would now have a real quantification of dip-to-azimuth correction (+2° of
dip = +5° of azimuth). Note this situation
only applies if azimuth is identical on both
sides of the interference; in other words,
you have drilled straight ahead with no hor-
izontal turn. Apply this determination in a
linear methodology (if 2 = 5 then 1 = 2.5,
etc.) throughout the balance of the crossing
as long as the additional problems encountered have a similar mass and are a similar
distance from the bore path—in this case
on the left.
This will occur when drilling near bridges
or along overhead cable rights-of-way,
where the bridge pillars or footings and the
overhead cable pylons are evenly spaced
away from the bore path.
For the calculations, change the azimuth of
the joint where the error occurred to more
reasonably reflect the bore path movement
from the previous reading to the next reading (Table 3.2).
Table 3.2. Calculating linear azimuth correction factors.
Horizontal
distance
ft (m)
Dip
(%)
Raw
azimuth
(%)
Azimuth
correction
(%)
Corrected
azimuth
(%)
650 (198)
680 (207)
710 (217)
740 (226)
770 (235)
800 (244)
830 (253)
51.5
51.5
52.0
53.5
52.5
51.5
51.5
91.5
91.6
92.2
96.5
94.0
91.5
91.5
0.0
0.0
1.2
5.0
2.5
0.0
0.0
0.0
0.0
91.5
91.5
91.5
0.0
0.0
Calculating
straight
line
azimuth
correction factors. More normally when
drilling with interference, the bore will turn
according to formation tendencies and/or
driller bias. The following readings would
be corrected more subjectively (Table 3.3).
Table 3.3. Calculating straight line azimuth correction factors.
3-16
Horizontal
distance
ft (m)
Dip
(%)
Raw
azimuth
(%)
Azimuth
correction
(%)
Corrected
azimuth
(%)
650 (198)
680 (207)
710 (217)
740 (226)
770 (235)
800 (244)
830 (253)
860 (262)
890 (271)
920 (281)
51.5
51.5
52.0
53.5
53.5
52.5
52.5
52.0
51.5
51.5
91.5
91.5
92.2
96.5
96.5
94.0
93.5
91.7
89.7
89.5
0.0
0.0
0.2
0.5
0.8
1.0
1.3
1.5
0.0
0.0
91.5
91.5
91.3
91.0
90.7
90.5
90.2
90.0
89.7
89.5
Steering: Magnetics
In this case, you were drilling east,
attempting to drill as straight as possible.
You entered the interference at 710 ft
(217 m) out and drilled ahead to 920 ft
(281 m) out. The dip evened out at 890 ft
(271 m) while azimuth continued to drop.
The bore began to turn at some point.
While watching the driller’s orientations
during the period of interference, you
would have noted a slight bias to the left,
causing the bore to turn. Without the bias,
the formation may have pushed the bore off
line.
Correct the survey position by applying a
correction to those azimuths experiencing
interference. Do this on a best-guess basis,
applying a straight line correction factor
between good shots. The bore moved 1.8°
over seven stations. Divide 1.8 by 7 to
determine the correction factor to apply on
a cumulative basis (see Table 3.3 above).
Recalculate the survey to determine an
updated position.
Inform the driller or client that the bore is
1.8° off line. Either pull back and sidetrack
to bring it back to line or turn the bore right
and approach the line.
The averaging nature of this method
assumes that the bore will start turning
immediately when interference is noticed.
If the driller bias was noticed only after 770
or 800 ft (235 to 244 m) out, you could reasonably assume that the bore before the
bias was straight and the turn occurred only
after 800 ft (244 m) out. You would then
straight line a 1.8° correction over only two
or three stations, yielding a higher rate of
turn.
Note that stations at 890 and 920 ft (271
and 281 m) showed a rate of turn of only
0.2°. In this case, the bore probably began
to turn at a very low rate. To achieve 1.8°, it
probably took five or six joints. When a
high rate of turn is present, the same or
greater rate will normally be present on the
next station unless the turn is broken by
applying opposite bias.
If the rate of turn at 920 ft (281 m) corresponds to the straight line method, it is
possible to derive a correction factor for
dip similar to that used in the first example.
Note the correlation between the two
methods.
Almost all azimuth corrections will be
made using one of these two methods or a
combination of the two. The key is determining when you do and do not have
interference. To make this determination,
be comfortable with the initially established line azimuth and the clean mag and
dip readings.
Constructing a Mag/Dip Chart. On a
length of graph paper, lay out a convenient
scale along the bottom of the horizontal
distance of the crossing. A scale of 1 in. =
50 ft (2.54 cm = 15 m) works well for rigs
using 10- or 15-ft (3- to 4.6-m) joints,
while a scale of 1 in. = 100 ft (2.54 cm =
30.5 m) works well for rigs with 30-ft
(9-m) joints. From the bottom, move up
about 2 in. (5 cm) and draw a horizontal
line along the entire length of the page.
Draw a vertical line about 1 in. (2.54 cm)
from the left side of the paper. Near the
center of the paper, draw another horizontal
line from 0 ft to the end of the crossing.
About 2 in. (5 cm) down from the top of
the page, draw another horizontal line from
0 ft to the end of the crossing. Label the
scale of horizontal distance every inch
(2.54 cm) from 0 ft to the end of the
crossing.
From the land survey notes, draw in the relative locations of all possible sources of
magnetic interference that were noted
against distance and left/right of the line. It
may be necessary to adjust the scale to
ensure space. Now the plotting axis for azimuth on the bottom, dip in the center, and
dip at the top is established.
Refer to your field sheets to obtain the
readings you established as your initial line
azimuth, clean mag, and dip. Note these
readings to the left of the vertical line on
the left of the paper. You must now choose
a plotting scale for all three.
It is important to always orient yourself and
the readings to the physical line on the
ground. If your line azimuth is 190°, left of
the line would be a smaller azimuth and
right of the line would be a larger azimuth.
Therefore, all numbers on the chart should
3-17
Horizontal Directional Drilling Training Program
increase from top to bottom. Good workable scales would be as follows (Table 3.4):
needs to be completed throughout, especially when Tru Tracker is not used.
Table 3.4. Scales for constructing a
Mag/Dip Chart.
While drilling, make notes of anomalies as
they occur against distance. When the azimuth changes, question whether it is a real
turn or interference. Refer to previous positions where dip and azimuth changed and
attempt to quantify the amount of error.
Become familiar with the presentation of
the data in graphical form and use the valuable information derived.
1 in. = 50 ft (2.54 cm = 15 m) or
1 in. = 100 ft (2.54 cm = 30.5 m)
Azimuth
1 in. (2.54 cm) = 2 or 2.5 or 4°
Dip angle
1 in. (2.54 cm) = 2°
Mag intensity 1 in. (2.54 cm) = 1000 gammas
Distance
On the field tabulation sheet, write down all
the information as it is obtained. Update
the chart by plotting the measured points as
necessary. In the midst of major interference, it is necessary to plot the chart as the
data are gathered. Decisions must be made
regarding the data immediately, and the
trends must be identified and acted upon.
Dip angle
Mag. field
If you are in a relatively clean area, you
may drill a few joints before catching up
with the plotting. In any case, the chart
Using the Mag/Dip Chart. Two charts are
presented as examples. The first (Fig. 3.2)
discusses a 500-ft (152-m) crossing. The
following shoot information is provided:
•
Line azimuth = 189.5°
•
Dip = 68.6°
•
Mag = 55,600 gammas
•
Shoot location = 65 ft (20 m) in front
of rig.
52,500
53,500
54,500
55,500
56,500
57,500
58,500
66
68
70
72
74
76
180
182
Azimuth
184
186
188
190
192
194
196
198
0
50
100
150
200
250
300
350
400
450
500
550
Away
Fig. 3.2. Charting a 500-ft (152-m) crossing.
Observe the following:
1. Major interference from 0 to 200 ft (0
to 61 m). This is relatively common
since the area near the rig (within
100 ft [30.5 m] on large rigs and 60 ft
[18.3 m] on smaller rigs) will be
3-18
affected by the rig mass. Also, ground
consolidation construction is common
around rivers. In this case, steel piling
was used to construct a wall at the
river’s edge.
2. Note the sine wave signature of mag,
dip and azimuth. This will occur when-
Steering: Magnetics
ever passing directly under a magnetic
source. You must look for it, since the
center of the sine wave will identify
roughly the distance away from the
entry point of the steel piling. This is
very important on the exit side on occasions where you are unsure of total distances.
3. Dip readings correlate exactly with the
shoot readings, while the magnetic
intensity is off by about 500 gammas.
This indicates slight interference in the
shoot location 65 ft (20 m) in front of
the rig. Since the bore direction is
southerly, the impact on azimuth would
be minimal, if any.
4. Observe the azimuth and dip at about
70 ft (21 m) out and then again at about
260 ft (79 m). There is a significant
offset in areas where both mag and dip
are well within the expected areas.
Remember the azimuth correction
methods described in Calculating Linear Azimuth Correction Factors
(page 3-16). Since there is an offset,
review Calculating Straight Line Azimuth Correction Factors (page 3-16).
Place a straight edge between the azimuths at 220 and 300 ft (67 and
91.5 m) out. The rate of turn in that
80 ft (24 m) projected back to the previous good azimuth at 70 ft (21 m)
indicates a constant driller bias to the
right. Every azimuth between 70 and
220 ft (21 and 67 m) could have been
corrected using the straight line
method.
In addition, an assumption could have
been made regarding the distance from
0 to 70 ft (0 to 21 m) out. Since the
reading at 70 ft was good and matched
the shoot azimuth, it would have been a
reasonable assumption that all azimuths between 0 and 70 ft were
similar. Those azimuths could also
have been corrected with the straight
line method.
5. During this job, the surveyor assumed
there was too much interference to pre-
dict an accurate line azimuth. He
attempted to drill as straight as possible
and wait for the mag and dip to remain
constant. This happened between 220
and 250 ft (67 and 76 m) out where the
azimuth was 192°. He assumed he had
drilled straight ahead, chose 192° as a
correct azimuth, discounted his original shoot azimuth (even though the
mag and dip were almost identical),
and drilled ahead to his target.
The ground exit was 17 ft (5.2 m)
right, which was unacceptable. The
pipe was pulled back, sidetracked, and
redrilled from 350 ft (107 m) out, causing an additional day of pilot hole
operations.
6. The surveyor failed in three areas.
First, when he originally arrived on
location and observed the topography,
he realized the entry side had magnetic
problems. Wall, sheet piles, and rig
location indicated that he would have
magnetic interference problems. The
exit side had no sheet piles and no
other visible magnetic sources. He
failed to make an exit side confirmation
shoot to attempt to match the entry side
shoot. Had he done so, he would have
accurately established his original line
azimuth, and determined at 220 ft
(67 m) out that he was off line.
Second, he failed to recognize good,
clean azimuth at 70 and 220 ft (21 and
67 m) out. He allowed the magnitude
of the interference to affect his
reasoning.
Finally, he assumed the driller could
drill 200 + ft (61+ m) straight ahead,
without moving off line, and based the
entire job on that assumption. In some
cases, this is the only way to proceed.
Normally, a pullback and redrill will
occur when this assumption is made.
Therefore, it should be a last resort
assumption. In this case, the assumption was made to avoid spending the
time and effort of doing an exit side
shoot.
3-19
Horizontal Directional Drilling Training Program
In Fig. 3.3, a 1700-ft (518.5-m) crossing is
presented, using a combination of magnetic
and Tru Tracker problems in a single job. It
was designed to focus your attention on
usable techniques and corrective measures
when confronted with similar problems.
The shoot information is as follows:
•
Line azimuth = 137.8°
•
Dip = 65.3°
•
Mag = 53,000 gammas
•
Shoot location = 90 ft (27 m) in front
of rig.
Azimuth
Dip angle
Magnetic field
65,000
60,000
55,000
50,000
45,000
40,000
35,000
80
75
70
65
60
55
50
45
110
120
130
140
150
160
Bridge supports
170
0
100
200
300
400
500
600
700
800
900 1,000 1,100 1,200 1,300 1,400 1,500 1,600 1,700 1,800 1,900
Away
Fig. 3.3. Charting a 1700-ft (518.5-m) crossing.
Observe the following:
1. This crossing was planned to be drilled
30 ft (9 m) left of a double-span highway bridge starting about 325 ft (99 m)
away from the entry point. The shoot
was performed at 90 ft (27 m) in front
of the rig and an exit side shoot was not
done. The exit side was clean magnetically, while the entry side was located
30 ft left of a major highway approach
to the bridges and inside a heavily used
recreational parking area. The exit side,
also 30 ft left of the highway, was next
to dense woods.
The two highway spans were 50 ft
(15 m) wide separated by a gap of 20 ft
(6 m). An offset Tru Tracker coil was
laid on the nearest bridge span, outside
of the bridge on each side. The elevation of the bore was 30 ft (9 m) below
the river bottom. Water depth averaged
18 ft (5.5 m). The bridges were about
12 ft (4 m) above the water. Tru
Tracker coils were laid between 400
3-20
and 750 ft (122 and 229 m) away from
exit on the closest bridge, yielding a
coil width of 50 ft (15 m).
Before the job was started, the surveyor failed in a number of areas. First,
the line azimuth was not accurately
established. He did not establish a
clean shoot area between the rig and
the river. Clean magnetics existed
between 120 and 300 ft (37 and
91.5 m) away.
He did not elect to do an exit side shoot
where the magnetics were obviously
better. As was stated in Magnitude of
Error Quantification (page 3-15), he
did not realize that he was in a magnetically worst-case situation and did not
make stronger efforts to set up the job
properly.
Tru Tracker was available throughout
the length of the crossing, but he failed
to use proper coil-building techniques
in specifying the coil shape. He was
Steering: Magnetics
drilling 30 ft (9 m) to the left of the coil
that was only 50 ft (15 m) wide. In
addition, he was drilling 60 ft (18 m)
below the Tru Tracker elevation. Using
the precept that the coil width should
be at least 5% wider than the depth, he
should have expected his intensities
from the coil to be very low. Also,
since the search area outside of an offset coil is roughly half the width of the
coil, drilling at 30 ft left was 5 ft
(1.5 m) outside the search area.
2. While drilling at 120 ft (37 m) away,
the azimuth moved from the shoot azimuth to 139.5°, and this continued to
300 ft (91.5 m) away. Tru Tracker readings throughout the entry coil indicated
a straight course. The surveyor did not
recognize this as the real azimuth and
continued using the shoot azimuth.
With Tru Tracker confirmation, this
was incorrect.
At 300 ft (91.5 m) away, the first interference problems began with an
increasing dip and azimuth. The dip,
mag, and azimuth began moving up
and down at roughly the same rate and
quantity. Drilling continued “blind” to
about 430 ft (131 m), where the first
bridge Tru Tracker coil was set. The
coil indicated a small movement to the
right but the intensities were so low
that the information was disregarded.
Drilling continued through the coil to
about 700 ft (213.5 m). Tru Tracker
readings began showing a stronger
right movement but were still disregarded, since the intensities and
mismatch readings were out of scale.
yielding very low intensities, was also
reading a right-hand movement. This
was correct but rejected.
3. Drilling continued with the azimuth
spikes increasing in magnitude to
about 1000 ft (305 m) away. The azimuth spikes’ magnitude built to
approximately 17°. At this point, the
spikes reversed and began spiking in
the opposite direction. At 1050 ft
(320 m), a spike of 30° was noted.
4. At 1100 ft (335.5 m) the mag and dip
returned to near normal until 1150 ft
(351 m).
5. Between 1150 and 1300 ft (351 and
396.5 m) the same scenario occurred as
was noted between 350 and 600 ft (107
and 183 m).
6. At 1320 ft (403 m) a very large spike
of 34° occurred. This was similar to the
spike at 1050 ft (320 m).
7. Between 1350 and 1480 ft (412 and
451 m), the spikes again reversed.
8. Good mag and dip readings began at
1500 ft (457.5 m) and continued
throughout the balance of the drilling.
The surveyor failed to recognize that
with an increasing magnitude of spike,
the bore must have been approaching
the bridge (see 2, 3, and 5 above). He
also failed to recognize that a very
large spike could only occur when
close to a major source of magnetic
interference. At this point, he passed
under a bridge footing (see 3 and 6
above).
The surveyor failed to measure and
plot the locations of each of the bridge
footings relative to centerline and distance away. The observed spikes
occurred only when the probe was
located the same distance away from
the bridge footings.
The surveyor failed to recognize that a
reversal of the spikes indicated he was
drilling on the opposite side of the
interference (see 3 and 7 above). He
also failed to recognize that good mag
and dip readings indicate good azimuth
readings (see 4 and 8 above).
The azimuth throughout continued
moving up and down with an increasing magnitude and was averaging a
right-hand movement. This was correct
but disregarded. The Tru Tracker coil,
even though improperly set up and
The overall effect of all the guidance failures in this case would be a bore passing
under both bridges; if it had been punched
out, it would have been more than 200 ft
(61 m) to the right of the target. In addition,
the bore would have passed directly under
3-21
Horizontal Directional Drilling Training Program
at least two bridge footings. The dotted line
of the drawing indicates a fair representation of the actual azimuth movement using
the correction methods introduced above.
Lost time and redrills would have resulted.
This job could have been completed with
few problems if the proper setup techniques and magnetics correction methods
had been used.
Using Tru Tracker. Since the Tru Tracker
system is a secondary means of determining a bore position, it is important to
understand not only its method of operation, but also how to judge the relative
accuracy of the output.
Operating guidelines and techniques. The
Tru Tracker coil, when accurately installed
on the ground and in the correct position,
generates a magnetic field that can be accurately predicted through mathematical
modeling. The field shape and relative
strength at every position within and some
distance outside of the coil is magnetically
unique. The magnetometers in a steering
tool measure those parameters both in a
positive and negative polarity, compare the
data to the model, determine the closest
match to the field’s unique parameters, and
print out the result.
The input data are the amount of amperage
input to the coil and the horizontal distance
of the probe as calculated by the survey
program in the computer.
Setup. A Tru Tracker coil is only as good
as the input data the surveyor enters into
the computer. A proper setup is imperative
for an accurate shot. The most important
aspect of Tru Tracking is determining
where to place corners.
By walking the coil area on both the entry
and exit sides, a surveyor can determine
where coil corners are necessary. Corners
need to be placed anywhere there is an
anomaly in the coil path, both in elevation
and/or distance left and right of centerline.
Once you have established the location of
the corners, sturdy stakes must be placed at
these points.
3-22
The surveyor now needs to measure the
horizontal distance from the entry point to
each corner along the centerline and the
perpendicular distance to each corner from
centerline. This is very important. A leftright error in a distance of 2 ft (0.6 m) will
mean a 2-ft error in tool positioning.
The transit must be set up to get an accurate elevation of each corner relative to
entry elevation. As the Tru Tracker accuracy is 1 to 2% of total probe depth, it is
critical that you obtain accurate elevations
on your corners.
Coils should be as wide as the anticipated
depth of the probe. For example, if the
probe is expected to be 50 ft (15 m) deep,
then the effective search area of a coil W
wide would be 3W at a depth of W.
The coil wire must be stretched straight
and tight from one corner to the next. If
you cannot go in a straight line from one
corner to the next, then you will need to
place another corner between these two
points.
Always number the coil corners in a clockwise direction. Corner measurements must
be in the same length units as the directional survey and must use the same
reference tie-in (i.e., from the entry point).
If entry is listed as 0 away and 0 elevation,
then the corners must be measured relative
to this point.
A corner left of centerline looking toward
the exit point must be entered with a negative sign for the right coordinate. If you are
using actual survey station numbers for the
tie-in and you are drilling backward relative to the stations, all corners must have a
negative sign for the away distance. For
example, if your entry station is 2000 and
your exit point is 1000, and you are drilling
backward relative to these stations, then
each corner must be entered with a negative
value.
After loading your coil into the computer, it
is always a good idea to select Load and
Print a Coil to double-check for accuracy.
Taking measurements. Once a joint has
been drilled down, it is time to take a sur-
Steering: Magnetics
vey. Go to Take A Survey on the menu. The
computer will prompt:
Enter course length:
Plug the azimuth (Y/N)
Use Tru Tracker? (Y/N)
You will next be prompted to enter forward
current. If the current is negative, it must
have a minus sign in front of it. Ask the coil
operator for forward current. There are two
important criteria at this stage. The first is
that the coil operator must ensure that the
current has stabilized before giving this
information to the surveyor. The second is
that the operator cannot break the connections loose until the surveyor is prompted
to do so by the computer. Breaking loose
too soon will result in measurement errors
and inaccurate data.
The operator should also be aware that keying the mike near the Tru Tracker box will
cause the readings to fluctuate. The current
should be read before transmitting the data.
Once the surveyor has been prompted for
reverse current, the operator can reverse the
leads. When current stabilizes and the reading has been put into the computer, the
computer will begin its search. Do not
break the leads loose until the computer
has completed its search and locked onto
the tool.
Determining the accuracy of a Tru Tracker
shot will be covered in Determining Shot
Validity (page 3-25).
Power source problems. A solid direct current (DC) power source is required to use
Tru Tracker properly. Insufficient or fluctuating power can cause erroneous readings
and inaccurate surveys. A good DC welder
is normally used to power a Tru Tracker
coil. Ensure that there are no nicks in the
welder leads that can ground to earth.
Cable problems. Nicks in the coil wire or
insufficient wire size for the length of the
coil are two areas where cable problems
can occur. Check the wire thoroughly after
laying out the coil to ensure there are no
areas where the current can go to ground,
especially at splices.
If the coil is 1000+ ft (305+ m) long then
American Wire Gauge (AWG) 6 wire is
recommended. If it is less than 1000 ft,
then AWG 8 wire should be sufficient. On
200- to 300-ft (61- to 91.5-m) coils where
you do not anticipate going very deep, then
you may be able to use 10-gauge wire,
although paralleling two lengths of AWG
10 wire is recommended to ensure that you
are getting sufficient current and the wire
does not overheat.
Testing amperage. After a coil has been
loaded into the computer, go to the selection titled Predict Field at a Known Point.
This selection will allow you to enter theoretical closures (away, right, elevation) and
the total current anticipated. The computer
calculates the radial angle, radial intensity,
and axial intensity. This option will help
you determine the current necessary to provide a 2000- to 5000-gamma radial
intensity.
Best-case layouts. A coil with as few corners as possible, thereby introducing less
human error into the equation, is the best
scenario. If possible, use an away station of
zero and an entry elevation of zero for your
entry point. This will give you a simple
benchmark for setting up your corner data.
For example, suppose you anticipate being
50 ft (15 m) deep toward the end of your
coil. As stated before, the coil must be as
wide as the anticipated depth, but to do this
you would need to put two additional corners in the coil to maneuver around an
obstacle. To keep the coil as basic and simple as possible, it would be better to make
the coil 55 ft (17 m) wide at this point. This
will provide a straight line to the corners
without having to add the additional corners necessary to go around the obstacle.
The best-case scenario is to use as few corners as possible, but to still place corners at
anomalies. If you can put fewer corners
and still not upset the depth-of-probe to
width-of-coil ratio substantially, then do so.
A depth of 50 ft (15 m) with a coil width of
40 to 60 ft (12 to 18 m) will not cause you
to lose accuracy on your Tru Tracker shots.
In another example, assume you have a 5-ft
(1.5-m) error in elevation over a 30 ft (9 m)
horizontal distance. If you can get your
3-23
Horizontal Directional Drilling Training Program
wire tight enough to go from point A to
point B without placing a corner at point C,
and ensure that there is no sag in the wire,
then do so. There is less chance for error
without compromising accuracy.
Keep the number of corners to a minimum
while still maintaining coil integrity. By
placing as few corners as possible, and taking into consideration elevation and left/
right anomalies, there are fewer chances for
error.
Worst-case layouts. The worst-case scenario for your Tru Tracker coil is where
there are numerous corners because of
extreme elevation changes or many obstacles in the path of your coil.
A coil may have up to 256 corners, but one
coil of this size will be very susceptible to
inaccuracies. Try to keep the number of
corners to a minimum, or make several
coils to allow for these anomalies. This will
enhance the overall accuracy of your coils
by minimizing the human errors.
Extreme elevation changes will cause the
most inaccuracy in coil configurations. It is
imperative that the surveyor obtains an
exact elevation on the corners for these
coils. Errors in elevation cause errors in
depth during Tru Tracking. The transit may
have to be moved several times to ensure
accuracy, but this is very important.
It is also imperative that correct horizontal
distances are input for coils in which you
encounter extreme elevation changes. Do
not use the distance from stake to stake
when measuring the corners, but rather use
the horizontal distance. This mistake can
cause extreme errors in the accuracy of the
measurements from your coils.
3-24
bottom is the most accurate way to determine the elevations of your corners when
laying water coils. If sounding is not possible, then using the elevation of the
centerline can help keep the surveyor on
course.
The most effective way to lay coils in the
water is to weigh them down with lead
weights to help ensure that currents or tides
do not move the coil during the course of
your drilling operation. Establish benchmarks on the entry and exit side of the river
to help guide you in a straight path.
If it is necessary to have splices in the line
you are laying across the water, you must
make sure that efficient, watertight connections are made. If you do not have a good
heat shrink available, then it is recommended that you use vulcanized tape
followed by electrical tape to prevent seepage into your splices. Any leakage can
cause erroneous readings.
Coils terminating in the water are more difficult to lay, but are a very effective way to
help ensure course accuracy. The most
effective way to lay a coil that terminates in
the water is by using divers. Professional
divers can establish a credible centerline on
the water bottom, and through the surveyor’s guidance, create a viable Tru
Tracker coil. The surveyor must work
closely with the divers to make them fully
aware of his needs with respect to distances
left/right of centerline to maintain course
integrity.
Suspended coils. Suspended coils are
somewhat more difficult to establish. The
main priority when constructing a suspended coil is to keep as much sag out of
the wire as possible. Any sags will create
errors in your Tru Tracker depths.
Extreme deviations left and right can also
cause errors in measurement. Remember
that a tool W in depth with the coil W wide
has 3W search area. Coils too wide or too
narrow can give erroneous readings. In
such cases, you may need to lay offset coils
to enhance the accuracy of the information
received.
Try to keep the wire out of the water, as this
can also cause errors. The current from the
water can cause the wire to sway, preventing you from obtaining an accurate shot.
Usually the computer will tell you that it
cannot lock on the tool and no shot will be
available.
Water coils. Water coils can be very useful
tools when drilling across areas of extreme
magnetic interference. Sounding the river
If there is a sag in the wire, then you must
establish a corner at the sag point. This can
be done by setting up the transit on the
Steering: Magnetics
bank and transporting the range rod to the
lowest point in the sag. By holding the rod
at water level, an elevation can be established. You can also shoot stadia to
establish an away station at this point.
Determining shot validity. A Tru Tracker
shot should be evaluated and monitored to
ensure that the data obtained is accurate
and reliable. The following indicators are
used to determine the accuracy of a Tru
Tracker shot: H-Total, G-Total, Radial
Intensity, Radial Angle, Radial Angle Mismatch, Radial Intensity Mismatch, and
Axial Intensity Mismatch. The values are
printed as the shot is taken and should be
reviewed at each shot.
H-Total. The data from the magnetometers
are used by the software to locate the
probe. Since the H-Total is also monitored
to detect possible magnetic interference, a
static or natural H-Total should be recorded
at the probe shoot and maintained on a survey tabulation sheet to serve as a reference.
As was previously discussed, the H-Total
or magnitude of the earth’s magnetic field
is region-specific and can be determined
before the start of a bore.
If the probe is located somewhere within
the confines of the coil, the following
results can be expected:
1. A forward current will result in an HTotal somewhat higher (ideally
between 1000 and 5000 gammas) than
the natural or background H-Total
recorded at the shoot.
2. A reverse current will yield a lower HTotal of similar magnitude. You can
determine a current strength requirement by applying forward current
while the tool is idle and monitoring
the H-Total displayed on the screen.
If an increase of 1000 gammas or more is
noted, then the setting on the DC power
source is acceptable. If the H-Total falls
below the background value, then one of
two situations exists: either the polarity of
the input current is reversed, or the probe is
outside of the confines of the coil. Determine which it is and proceed.
G-Total. The G-Total is the result from the
accelerometers, which are gravity-sensing
devices. The G-Total is primarily used by
the software to ensure that the tool
remained stationary while the forward and
reverse currents were being recorded. The
software will alert the operator if it detects
a discrepancy in an accelerometer sample
between the forward and reverse current
applications. A warning will appear on the
screen that the tool moved and the shot is
invalid.
Radial intensity. The value of the radial
intensity is a quick indicator of the current
strength that the magnetometers are sensing. This value should be between 1000
and 5000. While a reading of below 1000
should not be discounted totally, the absolute accuracy of the shot should be
scrutinized. If this value is above 5000, too
much current is being applied to the coil.
Damage to the magnetometers can occur if
an extremely high current is allowed to
persist.
Radial angle. The radial angle value
should read between 180° and 360° (the
proper operating range), or 270° if the
direction of the magnetic field vector is
closely aligned with the probe. The radial
angle can indicate improper coil connections to the Tru Tracker control box if it is
out of the specified parameters or if the
probe is beyond the effective search area of
the coil. The coil wire leaving the operator’s left hand should be connected to the
positive terminal of the control box.
Radial angle and radial intensity
mismatch. Mismatch percentages are the
differences between actual and theoretical
results.
Axial intensity mismatch. The axial intensity mismatch will fluctuate more than the
radial angle and radial intensity mismatches. Ideally, it should remain less than
15%. Factors that will cause this mismatch
to be more than 15% are proximity of the
beginning or end of a coil, or entering of an
erroneous away distance value. Doublecheck the pipe count. A good rule of thumb
is that the probe is inside the coil by at least
one-half the width of the coil when a shot
is considered good.
3-25
Horizontal Directional Drilling Training Program
Tru Tracker interference.Tru Tracker is not
a panacea—it cannot be run in a magnetically corrupt environment (such as when
the H-Total is near 70,000). Constant lowlevel noise or interference, intermittent
surge noise, or spike-type interference can
be recognized, and an operator can make
allowances or modify the procedures to
compensate for such anomalies.
Positive vs. negative readings. It is good
practice to apply the following procedure
periodically throughout any bore, at least to
test that no unknown DC sources or hidden
ferrous masses are distorting Tru Tracker
results.
Once comfortably inside a coil, you may
make a shot using the following method:
When the computer prompts for Forward Current, apply forward current as
usual. When the request is made for
Reverse Current, do not apply any current to the coil and simply enter H as a
reverse current value. Wait for the
results, and when the prompt for Take
A Repeat appears, answer Yes. Repeat
the process. Apply no forward current
and enter for this value. Apply the normal reverse current and enter it
accordingly. If there is a source of
interference on one side, the axial
intensity will reflect that source. If the
normal forward current and H reverse
current results show an almost 0%
axial intensity mismatch, the H forward current and normal reverse
current results show a 3 to 4% axial
intensity mismatch, and movement of 3
to 5 ft (0.9 to 1.5 m) to the right is
noted, then there is a source of interference paralleling the bore to the right of
the bore path. The operator may choose
to continue using an H reverse current
method if the DC source is large
enough to supply ample current to the
coil, or he may elect to reset the entire
coil to a configuration that locates the
source of interference outside of the
coil.
Corridor benchmarking. The above procedure is effective for sources of
interferences that remain stable or constant.
Some sources of interference are variable
and interfere at a regular frequency. The
3-26
suggested method of detection and control
is described here:
To determine if Tru Tracker results are
being corrupted by a variable-strength
source, take four shots at the same
location, not moving the probe, and
apply current at a consistent level. If
variable interference is affecting the
shots, the results may wander 5 ft (1.5
m) or more to the left or right. Plot all
of these points. Drill another joint and
repeat this procedure. Plot all of the
points. As the bore proceeds, a corridor
of some constant width or spread will
develop. The operator should steer the
bore until the corridor straddles the
desired centerline, and continue the
bore in this fashion until exit or the
corridor narrows to a negligible width.
Determining azimuth from Tru Tracker
data. An operator is often forced to begin a
bore without a true, undistorted heading
because of the expanse of the obstacle to be
crossed, which is usually a body of water
and nearby magnetic interference. Using
Tru Tracker, it is possible to resolve a true
heading or confirm the heading chosen. If
this method is used, extremely accurate
measurements must be taken when laying
out the coil.
When in highly congested areas where
there is no opportunity to shoot offsets to
escape corruption, the operator may resort
to this method to help establish a line azimuth or determine that the chosen azimuth
is valid. As mentioned before, if this
method is used, all measurements must be
exact and the coil must be constructed so
that every side is a precise, straight line
between corners:
1. Shoot the rig in on line and monitor the
entry of the first joint with the survey
instrument, if possible. This will
ensure as straight an entry as possible.
2. Instruct the driller to drill only straight
up and straight down, taking time to
stop, reorient, and then continue his
push. This will eliminate some of the
wander caused by right-hand rotation,
and is good practice at the start of any
bore.
Steering: Accuracy
3. Proceed with the bore. When reliable
Tru Tracker shots are recorded, three
shots at the same away distance agree
with each other, and the azimuth indicators of the steering settle to a reliable
repeating constant (dip and H-Total are
constant).
4. Steer to maintain on centerline according to Tru Tracker. Take standalone
shots at five intervals to provide a database for determining a trend.
5. Plot the Tru Tracker vs. the calculated
course on a 10 to 1 (or more) scale.
Continue this procedure until there is
no more coil.
6. Adjust the line azimuth using the tangential method until the calculated values fall in line with the Tru Tracker
values. This will be your final line azimuth and should require few further
adjustments.
Accuracy
Within this industry, there is much discourse concerning accuracy. Is accuracy
defined as exit point accuracy or instrument
accuracy? Within most drilling contractors’
contracts, there will be a clause specifying
accuracy. In some, the limits of job accuracy will be specified in terms of the exit
point. Some will specify exit point limits,
cover limits and, in some cases, corridor
limits. Some will specifically note instrument accuracies. Finally, some will
mention all of the above.
As a guidance company, you should be
aware of accuracy in all its various forms
and be able to correctly transmit this information to your clients.
Accuracy vs. repeatability
Accuracy is the quality or state of being
exact or precise. Repeatability is the ability
to produce the same result again and again.
In terms of instrumentation, accuracy can
be defined as comparing survey results
from one device to survey results from
another device to confirm that similar data
have been generated from both types of
survey instrumentation.
Repeatability is a procedure that is used to
confirm a survey tool’s accuracy and
ensure that the downhole environment has
not affected the accuracy of the instrument.
Switch-on to switch-on repeatability is
necessary.
Measuring instruments are calibrated to a
particular accuracy, which is determined by
the application. Beam accelerometers nor-
mally measure gravity, resolve inclination,
and tool face or roll. Magnetometers measure the earth’s magnetic field and resolve
tool azimuth relative to magnetic north. All
sensors are calibrated to resolve tool accuracy to 0.1° in inclination and 0.1° in
azimuth. Tool face or roll will also resolve
to 0.1°.
In addition, a tool will repeat itself to the
specified accuracy if it is within calibration
specifications. Switch-on to switch-on
should repeat itself as long as the tool is not
moved or the earth’s field has not changed.
As long as a tool will repeat itself within
specs, its overall calibration in terms of
magnetic north has nothing to do with the
accuracy of the ground exit. Its calibration
in reference to gravity, however, has everything to do with elevation accuracy.
Instrumentation
There will always be some error in any survey instrument’s compass. The errors in the
instrument itself are less than the opera-
tional errors that may result from outside
influences.
3-27
Horizontal Directional Drilling Training Program
The accuracy of punchout is dependent
upon many conditions, some of which may
produce compensating errors and others
cumulative errors. Since these conditions
or a combination of conditions are important factors in punchout accuracy, it is
difficult to isolate the exact cause other
than interference, which is relative easy to
identify. Therefore, interference becomes a
catch-all answer to punchout accuracy.
Recognize that two surveys might err
within reasonable limits in the same direction, while they also might err in opposite
directions, producing large differences. A
steering tool is within specification if it
achieves a repeatable horizontal survey
accuracy of 1.7 ft per 1000 ft (sin 0.1° x
1000 ft). In other words, at a distance of
1000 ft (305 m) away from the drilling rig,
the tool could be 1.7 ft (0.5 m) left or right
of the planned centerline and 1.7 ft higher
or lower than the planned elevation. Most
tool error is not cumulative; therefore, the
actual position should be much better than
a radius of 1.7 ft. Tool face accuracy has
little to do with job accuracy.
Keep in mind: tool accuracy is only that!
The tool must be placed in a protective
housing, and then placed into a drilling
assembly that is bent relative to the hole
axis. The bend, if not properly accounted
for, can cause elevation errors. The drilling
assembly may exert magnetic influence on
the azimuth. The formation will exert side
forces on the assembly, which can prohibit
its proper steerability with any type of
guidance instrument. Finally, human error
will cause major job accuracy problems.
None of these are tool problems. The tool
transmits a measurement, and it is up to the
surveyor to interpret the data and determine
a position reference.
Human error
In today’s computer age, we are familiar
with the phrase “garbage in, garbage out,”
meaning that bad solutions will result from
bad data. The surveyor has total control
over the quality of the data, within reasonable limits.
When the surveyor is presented with magnetic problems, if he has spent the time to
set up properly on the first day, if he uses
his training and experience, and if he uses a
structured problem-solving methodology,
he will normally be able to overcome problems and provide generally acceptable
results. However, there will be many occasions where the magnetics are sufficiently
confused to cause major error in position
and human uncertainty. When this happens,
punchout accuracy will be seriously
affected. All surveyors must communicate
to the client’s supervisory personnel the
factors affecting job accuracy as they
occur.
Magnetic variation
A survey instrument, even though operated
in non-magnetic drill collars, will be
deflected from its normal heading in the
earth’s magnetic field by the magnetized
drill string, unless the length of the nonmagnetic drill collar removes the compass
completely from the horizontal component
of the drill string’s magnetic field (Z axis
interference). It is probable that many jobs
have been completed with this interference
and were slightly in error from the beginning. These errors can range from a
minimum while drilling north/south to a
maximum while drilling east/west. Errors
of this nature will always cause the azimuth
to read further to the north than is really the
3-28
case. Therefore, an easterly crossing would
normally exit further to the right of target,
while a westerly crossing would normally
exit further to the left of target.
The amount of compass deflection caused
by a magnetized drill string is directly proportional to the magnetic pole strengths,
and inversely proportional to the square of
the distance from the instrument to the
pole. Since drill string components are
often changed during the course of a bore,
and since even the magnetism of any particular drill string component might vary
somewhat from day to day, it would seem
highly probable that a particular BHA,
Steering: Job Site Actions—Pilot Hole
being different magnetically from the previous assembly, will produce a different
azimuth once back on bottom.
magnetic elements to compensate for the
known effects of drill string magnetism,
which also provides insurance against
unknown effects.
The solution to this type of problem consists of using an adequate length of non-
Course length variation
Unlike land surveys where backsight and
foresight are visible from every point, a
borehole survey position is made up of a
series of tangents to the curves of the borehole. Therefore, the shorter the course
lengths, the more accurate the surveyed
position. It also follows that unless the survey points of different surveys of the same
borehole are identical, the coordinates of
the survey will probably differ.
30-ft course length survey would produce a
left/right position of 30 ft, while the 15-ft
course length calculation would produce a
left/right position of 15 ft.
The following hypothetical case will illustrate this point. Suppose two surveys, one
using 30-ft (9-m) course lengths and one
using 15-ft (4.6-m) course lengths are
made over 500 ft (152.5 m) of hole where a
uniform turn of a 500-ft radius exists.
Using a standard tangential calculation, the
There is a strong case for using shorter
course lengths in the turn sections of a
bore, and longer course lengths in the tangent or straight sections of a bore. The
extra time required must be evaluated
against benefit, and normally this time is
spent only when exit tolerance is tight.
Errors caused by excessively long course
lengths and to the location of survey points
with respect to hole curvature may be
either random or cumulative, depending
upon the configuration of the bore.
Job Site Actions—Pilot Hole
The single most important function during
the job setup is establishing the initial line
azimuth. Failure to spend the time to do
this accurately will result in, at the very
least, pullback on the exit side, resulting in
lost time. It will definitely result in a course
change within the Tru Tracker coil on the
exit side, causing excess friction during
pullback of the pipeline.
The surveyor responsible for guidance
must have good, logical observation skills
and must apply practical methodologies.
This section covers the basic actions
required of the surveyor to successfully
complete a pilot hole.
Upon your arrival and after the initial introductions are made, look at the job in
overview. This is normally the last time
you will have the opportunity to do this.
Once the job begins, you will be concentrating on solving problems of detail, with
no time to sit back and consider the overall
project.
1. Be observant as you walk. Make notes
of potential magnetic problems and
their locations.
Arrival
Walk the line. Take the following steps
when walking both sides of the line:
2. Determine where you will do a probe
shoot based upon observation.
3. Plan your setup of Tru Tracker coils as
you walk. Determine if this is a
straightforward setup or if you will
need any special equipment.
3-29
Horizontal Directional Drilling Training Program
4. Study the topography, keeping in mind
how you will shoot centerlines and lay
out Tru Tracker.
5. Finally, determine from the client how
much time you have to get rigged up
and ready to spud. Fully discuss with
him any problems you have observed
and advise him of how much time you
will need. Ask for assistance where
required.
Unload and check equipment. After walking the line and before you do anything
else, unload your equipment. Set the interface, readout, computer, printer, power
supplies, cables, etc., in their locations.
Make up the probe in its housing and set
aside. Check your equipment now to make
sure you have everything you need for the
job.
Tru Tracker layout
Having walked the line and studied the
plans, you will have a clear idea of how to
proceed with the Tru Tracker layout. The
following issues should be addressed
whenever possible conflicts or clarity problems arise.
Corners.
Lay wire ready for spud on the entry side.
If possible, set corner stakes on the exit
side ready for wire.
2. Ensure that any deviation in wire direction or elevation begins and ends at a
peg or stake. Do not allow the wire to
curve. Make the segments straight.
Width. From the drilling plan, locate the
total elevation change between the entry
point elevation and proposed depth at the
end of the entry coil. The width of the coil
at the deepest point of the bore should be
about 5% wider than the depth. The extra
width will compensate if you lose angle
while drilling the entry curve and end up
deeper at the end of the coil. In addition,
after the coils have been laid, and during
the job, the client might wish to replan to a
deeper point.
3. Shoot a centerline from entry to exit
and place centerline stakes perpendicular to each corner. Use a right-angle
surveyor’s prism.
Finally, if drilling deeper than the coil
width, it is common for radial intensities to
decrease rapidly and the field to flip.
Always make the coil 5% or more wider
than the planned depth.
5. From the entry point, measure the horizontal distance to each centerline stake
and note the distances. Against each
centerline distance, measure the left/
right distance to its representative coil
stake.
Length. Make the coil’s length as long as
required within the limits of strong measured fields. A coil of 1000 ft (305 m) at
60 ft (18 m) of depth will work, whereas an
elevation of 80 ft (24 m) might not yield a
strong enough radial intensity.
Wire. Use insulated AWG 8 (or 10) squared
stranded wire. Make strong splices that will
not pull apart. Insulate with rubber bonding
tape and cover with electrical vinyl tape.
3-30
1. Number the corners in a clockwise
direction, starting from the corner
where you set the power source (welding machine).
4. Place centerline stakes perpendicular
to any obstructions you noted when
you walked the line. Measure their distance from entry and note the measurements on the coil data sheet. Measure
the distance from centerline left or
right to the obstruction.
6. Measure the topographic elevations.
7. Check on the progress of the rig crew
as they prepare to spud. Discuss your
progress with the client.
Elevations. Measure and record your elevations accurately, because corner
elevation inaccuracies will affect Tru
Tracker readings significantly.
Steering: Job Site Actions—Pilot Hole
Line sags. If you are building an unsupported coil segment across a river or canal,
you will need to consider line sag. You
must ensure that any splices in the segment
can survive the pulling forces required to
tighten the wire and support its own
weight.
If the ground elevation on each side is the
same, the process of developing measurements is relatively easy. The lowest point of
the sag will occur exactly in the middle of
the segment. If you have constructed both
the left and right sides parallel, the away
distance can be derived once and used for
both sides. If they are not parallel, you will
need to plot the centerline and both sides to
scale on graph paper. Using a right-angle
triangle, scale the center of each side
against the centerline and use this for its
away distance. Then scale the left or right
distance of the lowest point of the sag to
the centerline.
Finally, determine the amount of the sag. If
a boat is available, use it to physically measure the lowest point. Again, if both sides
are the same elevation, this is easy. Measure the distance of the wire from the water
and relate this to the distance of each side
to the water. Subtracting one from the other
yields the line sag elevation.
If the elevations are different on each side,
you must again use graph paper and draw
the stake elevations on each side to scale.
Measure the elevation of the water and plot
it against the sides. Finally, measure the
lowest point of the line sag in the water and
plot it. This will be the elevation of the line
sag. Measure both the left and right side
every time.
Ensure that this phantom corner is accurately noted in the proper sequence on the
Tru Tracker coil data sheet.
Coil shapes. A Tru Tracker coil should be
longer than it is wide. The most accurate
coils are rectangles, so try to attain a rectangle where possible. On the entry and
exit, you may taper the beginning and end
back to the entry and exit points, always
ensuring that it remains wider than it is
deep.
Generally, a coil can attain any shape as
long as it roughly approximates a rectangle. Zigzags in the sides over a short
distance should be avoided at all times. If
the surface topography requires this, consider setting out two coils. Otherwise, do
not trust your readings within 50 ft (15 m)
of the zigzag. The zigzag produces erroneous axial readings where the probe is not
expecting them, causing errors.
Offset coils. It is possible to offset the
coils. Ensure that measurements are very
accurate and the widths are adequate to
produce a strong field that is readable by
the probe.
Testing. Once the entry side is ready, hook
up the power source and make tests. Vary
the current and note amperages. Refer to
the Tru Tracker program to project these
amp readings against depth to ensure your
coil will produce high enough radial
intensities.
Preparing Tru Tracker data. Complete the
Tru Tracker data sheet now, while the measurements are fresh in your mind. Do not
leave this step to later, because you may
forget a measurement.
Steering tool rig-up
Check on progress of the rig crew as they
prepare to spud. Discuss your progress
with the client and how long you will need
to get ready.
box. Lay out a shoot test lead to the shoot
location. Tighten the probe connections
and move it to the shoot location. Connect
the test lead and power the probe.
Rig up your surface equipment and power
up. Input your coil data files and make up a
survey tabulation sheet. Note the coil data
file names on the sheet in the appropriate
Turn the probe to its high side and point it
generally toward the exit point. Print screen
and move the probe 10 ft (3 m) right, still
pointed toward the exit. Print screen. Note
3-31
Horizontal Directional Drilling Training Program
the position of the probe relative to the first
check in writing on the printout. Move the
probe 10 ft toward the exit point back on
centerline. Print screen. Move the probe
10 ft left of the first check and print screen.
Finally, move the probe 10 ft closer to the
rig on centerline. Print screen. You have
magnetically mapped the shoot area. Create a table as follows (Table 3.5):
Table 3.5. Magnetic mapping of the shoot area.
Distance
ft (m)
Position
H-Total
(gammas)
Dip
(degrees)
90 (27 m)
100 (30.5 m)
100 (30.5 m)
100 (30.5 m)
110 (33.6 m)
CL
-10
CL
+10
CL
48557
48530
48558
48560
48555
60.3
60.2
60.3
60.2
60.3
By the H-Total, you can see that the centerline shots are consistent. The only anomaly
seems to be the left position. Walk around
and look at the area for the cause of the different magnetics. Recheck the position
with the probe. Move it to a position 20 ft
(6 m) left and see if the H-Total continues
to drop. In the above example, the magnetics are clean and ready for the shoot. If they
are not, in practice, continue testing until
you locate a clean position.
At this point, you have a lot of data generated from the Tru Tracker coil layout. You
must relate this to the profile provided by
the client or to the data provided. If you
will be drawing the profile, now is the best
time. You may wait until after the probe
shoot, but you take the chance of needing
to change the profile if the client’s data are
wrong (remember, it is wrong in some way
95% of the time).
the client if the radius is too small for the
line with a four times safety factor. If the
client proposes to proceed without the
safety factor, advise the office by phone as
soon as possible, and fax the information in
your evening report.
Ensure proper probe operation. Remove the
test lead and connect it to your spare probe.
If you have time, leave a probe connected
and rig up your spare interface and spare
driller’s readout. Test them to ensure proper
operation. If you do not have time now, you
should make time to do it later.
Profile
On the vertical profile, draw in the surface
topography and all in-ground or surface
obstructions you noted when you walked
the line. Remember, you measured distances to each obstruction when you set up
Tru Tracker. On the horizontal plan, draw
in the obstructions to scale if possible.
Ensure that the proposed radius will work
for the pipeline to be pulled. Discuss it with
3-32
Make sure the profile fits the topography,
length, and cover limits, and circumvents
all in-ground obstructions. If you must
approach a cable or in-ground line, make
sure their positions are accurately known.
If you have concerns, express them to the
client and always have a firm recommendation ready. You may advise the exposure of
in-ground services before spud if you must
converge or pass close to any live line.
Once the profile is checked and ready, set it
aside.
Steering: Job Site Actions—Pilot Hole
Physical measurements
A number of measurements must be made
on the surface and downhole equipment.
Make these measurements before the probe
shoot and note them on paper.
Rig measurements. Note
measurements on paper:
the
following
•
A—Horizontal distance from the center of the vises on the rig to the planned
entry point.
•
B—Height of the center of the vises
from ground level and then to the same
elevation as the entry point.
•
C—Distance from the center of the
vises to the entry point.
You have now measured a right triangle.
From the vise elevation and the rig angle,
calculate the projected horizontal distance
to the entry point:
(vise elevation/tan of entry angle) =
horizontal distance from vises to
entry
Compare the calculations to your physical
measurements—they should be the same.
If not, find out why and discuss this with
the client. Note the difference on paper. It
will produce a new physical entry point relative to the plan.
Be careful when measuring the center of
the vises, because some rigs have movable
front vises. You may need to establish the
point of pipe breakoff during drilling oper-
ations and use this instead of the center of
the vises.
You should always check the rig angle
yourself before spud. If a mistake was
made, you need to know now, not during
the confusion that always occurs while
drilling the first few joints. Discuss your
findings with the client and how the inaccurate rig angle will affect the job.
BHA measurements. Now is the time to
measure all drill string components of the
BHA. Make a list of each component and
note the measurements of each, shoulder to
shoulder, starting with the bit or nose of the
jet:
•
Bit = 1.2 ft (0.4 m)
•
Bit sub = 8 ft (2.4 m)
•
Motor = 20.7 ft (6.3 m)
•
Orientation sub = 2.3 ft (0.7 m)
•
Non-mag drill collar = 27.5 ft (8.4 m)
•
Non-mag drill collar = 15.0 ft (4.6 m)
•
Drill pipe crossover = 1.8 ft (0.6 m)
•
Total BHA = 69.3 ft (21.1 m).
Drill pipe measurements. Tell your client
that you need to know the measurements of
each joint of drill pipe. Ask him to have
them measured row by row as they are
being used and provide the measurements
to you. Find out exactly how many joints of
drill pipe are on location and make a note
of it. Count them yourself to double-check.
Line azimuth shoot
The following procedure assumes that the
non-magnetic collars were magnetically
tested back at the shop and found clean:
1. Power up the probe to be used. Place
the probe in its protective case on V
blocks or non-magnetic orientation
stands. Using one of the centerline Tru
Tracker stakes about 30 to 50 ft (9 to
15 m) from the probe position, set up
the theodolite, and confirm its centerline position by sighting the entry and
exit point. Using a plumb bob or the
instrument’s optic plumb, center the
instruments over the stake and level
accurately. Shoot the exit point and flip
to backsight. Shoot the entry point. If
misaligned, move the instrument and
relevel. Continue doing this until foresight and backsight intersect the exit
and entry point, respectively. Make
sure the instrument is leveled.
3-33
Horizontal Directional Drilling Training Program
2. Using the backsight, shoot the power
sub on the carriage. Estimate how
much the rig is misaligned and in what
direction. Note this on paper. Flip to
foresight.
3. Sight the front and rear of the probe
using the vertical crosshair in the
scope. Lay the crosshair alongside the
probe case and continue adjusting the
probe until it is exactly parallel to the
crosshair. Turn the probe to its high
side.
4. Recheck the centerline position by
again sighting the exit and entry points
using backsight and foresight. Check
that the instrument is level. Again,
check that the probe is parallel to the
vertical crosshair.
5. Print screen; turn to a tool high side of
90°. Print screen; turn to 180°. Print
screen; turn to 270°. Print screen; turn
back to high side at 0°. Print screen.
Construct the following table (Table
3.6) and set it aside for later.
Table 3.6. First test of line azimuth shoot data.
Orientation H-Total
(degrees) (gammas)
0
90
180
270
0
48560
48555
48572
48520
48555
6. On the theodolite, recheck the line
using foresight and backsight and then
recheck the probe orientation. It sometimes moves during the probe roll,
which would necessitate another roll
set of readings. If all is OK, continue.
7. Instruct the crew to bring the motor,
bit, and orientation sub to a position
about 5 ft (1.5 m) from the exit side of
the probe. Lay the assembly on line.
8. Check the H-Total, dip, and azimuth on
the screen. If different than during the
probe roll, move the motor farther
away by 3 ft (1 m). Check again. Continue moving the motor away from the
probe until the exact azimuth measurement noted during the probe roll is
obtained. Measure the distance from
the shoulder of the orientation sub to
the T slot on the probe. This is the
spacing required from the top of the
orientation sub to the probe to obtain
clean magnetics during the job.
9. Total the lengths of the two sections of
non-magnetic collars. In the example
3-34
Dip
(degrees)
Azimuth
(degrees)
60.3
60.2
60.3
60.1
60.3
27.3
27.2
27.4
27.0
27.3
above, they total 42.5 ft (13 m). Measure this distance from the shoulder of
the orientation sub toward the rig and
place a marker. Instruct the rig crew to
bring one joint of drill pipe, including
the crossover sub, to this position and
lay them on line. You may need to
move the theodolite.
10. Print screen and note the readings on
the paper. The H-Total, dip, and azimuth should be the same as during the
roll test. If not, add another non-magnetic collar until the readings match. If
this is not possible, do the following:
•
Move the motor assembly out of
the way completely. Move the drill
pipe toward the rig until the magnetic readings match the shoot
readings. Then begin approaching
the probe with the motor online,
until you reach the non-magnetic
collar measurements. Again, in the
example above, the length of the
two non-mags was 42.5 ft (13 m).
•
Print screen and note the measurements on paper. Now, repeat the
Steering: Job Site Actions—Pilot Hole
probe roll and construct another
table (Table 3.7).
Table 3.7. Second test of line azimuth shoot data.
Orientation H-Total
(degrees) (gammas)
0
90
180
270
0
48460
48455
48472
48420
48455
Remember, if you must drill with Z axis
interference, it is best to have the interference in front of the probe and not behind it.
The drill pipe has a stronger magnetic
influence than the motor and can change
often downhole through rotation.
Dip
(degrees)
Azimuth
(degrees)
60.6
60.6
60.7
60.4
60.6
27.8
27.8
27.7
27.3
27.8
With the theodolite, recheck the line and
the probe orientation. Do not neglect this
step—always recheck that the probe has
not moved once you have established a line
azimuth for the job.
Pressure testing
Before spudding, it is necessary to pressure
test the system. Push the motor or jet
assembly to the ground and engage the
pumps at a low rate. Establish mud flow
through the jet or motor.
Note on paper the pressure on the gauge at
the point the bit begins turning. Turn off the
pump and reengage. Note again the point
where the bit begins to turn. Do this until
you have a repeatable projected pressure to
begin motor operation.
Once this step has been completed,
increase the flow and watch the pressure.
Continue increasing until you reach recommended drilling pressure for the type of
motor you are running. When you reach the
recommended pressure, stop immediately.
In the case of the jet, establish stroke count
at your projected drilling pressure.
Ensure that the bit will enter the ground at
the entry point without a sag in the pipe.
Attempt to prop up the string until it is
obvious that the rig will have a straight
push—not left/right, sagging, or too high.
Work with the crew to ensure that the push
is straight. Push ahead into the ground
about 5 ft (1.5 m), and then stop. Observe
the entry closely to again check alignment.
Physically measure the exact entry point
relative to the planned entry and note the
actual numbers on paper.
Go inside and observe the inclination reading on the probe. At this point, you will be
reading only the actual rig inclination, not
the inclination on the drilling assembly in
the ground. This is the reason for the extra
care in spudding for a straight push.
Throughout the test, observe the probe
operation, watching for shorts or any
improper operation. Also, observe the rig
systems to ensure proper operation.
You will be able to easily observe if the
motor or jet is building angle too fast. If so,
pull back until the bit is just below ground
and begin rotation. Rotate ahead for the
same 5 ft (1.5 m) and check that you have
dropped angle. Continue to adjust until you
have the alignment you need.
Spud. You have now completed all preparations and are ready to spud. Leave the
tool operating and advise the driller to
begin pushing the bit into the ground, staying on the high side and using your hand
signals. Go outside near the entry point
where the driller can see you.
Again, push ahead on the high side another
5 ft (1.5 m). If you are building too much
angle, withdraw to your previous position
and again begin rotation. Rotate ahead 10 ft
(3 m) and stop. Check that you have a
straight push and continue working the
motor or jet into the ground very carefully.
3-35
Horizontal Directional Drilling Training Program
Always be high when you spud and work
yourself down to the correct position.
Remember, it is easy to drop angle in surface soil, but it is impossible to build angle
once you’ve already dropped. Continue
working the motor into the ground until the
non-mag collar is in the vises. Print screen,
and note the position on the printout. Add
the final length of the BHA. Push this to the
vises using a combination of high side and
rotation.
At this point, reenter the Set Up Survey
File and correct the tie-in information if the
actual entry point is different from the
planned entry point that was previously
input.
Take the first survey, using the first course
length you calculated earlier. Note all data
on the tabulation sheet. Carefully study the
data as a reasonable test. Does the calculated position look correct relative to what
you observed? If not, look for your mistake
and correct it before continuing to drill.
Make sure now that everything is correct
and ready to drill. If so, you have just completed a successful straight spud.
Drilling ahead
You will serve many functions during drilling operations. Not only will you be
ensuring proper tool operations, but you
will also be concerned with the position of
the bore.
you make relative to the data quality. Take
these steps to ensure high-quality data:
Tool operation. Throughout the job, you
are responsible for the proper tool operation. You not only need to watch constantly
for problems, but also ensure good data
quality. With this in mind, keep all required
records up-to-date. Fill out the tabulation
sheet and your daily reports completely as
the job progresses. Observe the tool operation constantly, looking for shorts in the
wireline.
2. Ensure that switch-off and switch-on
readings are the same. If not, find out
why.
Be available to the driller to answer his
questions regarding magnetics and what is
or is not possible. Focus on the job of
ensuring good equipment operation. Be the
first to spot something wrong, either with
your equipment or theirs. Make the driller
aware of your concerns and have him shut
down until equipment problems can be
explained and rectified. Also, assist the
driller in looking out for the safety of the
rig crew.
Data quality. In addition to proper tool
operation, you are responsible for the accuracy of the bore path, with or without
interference! Since your performance is
measured by where the bore exits relative
to the target and the distance you may be
off centerline during drilling, the data quality is critical to that performance. You must
have justifiable reasons for any decision
3-36
1. Construct a Mag/Dip Chart (page 3-17)
when you have interference.
3. In some cases, take a survey before the
probe has settled to a final number.
Switch off after the survey and tell the
driller to make a connection. After the
connection, if you switch on and find
the inclination is now half a degree
lower, immediately delete the survey
you took and retake it—all while still
at the top of the next joint. Then correct
your paperwork and begin drilling.
4. While drilling with a motor, the readings will bounce around as the GTotals decrease. Be available to assist
the driller in determining the correct
number.
Projections. Always be ready to project
ahead mathematically from your current
position. Base this projection on the
response from your drilling assembly during the build sections of the bore. For
example, if you are not achieving your
expected radius, you must calculate exactly
how much deeper than plan you expect to
be. This must be brought to the client’s
attention for his approval.
Steering: Job Site Actions—Pilot Hole
In this example, you will not only be lower
than plan, but you will need to replan the
exit curve, taking into account the larger
radius you are achieving. This will change
the entire profile, in some cases making it
an impossible situation. The earlier you
know this, the sooner you can correct the
situation with a trip to change assemblies.
The earlier you involve the client with
problems, the easier it will be to gain his
approval for your recommended actions.
Always project ahead to satisfy yourself
that everything is being done to meet your
objectives.
Directional control decisions
Always know where you are relative to the
plan, the surrounding topography, and subsurface obstructions.
Radius control. You should know where
your course is relative to the planned
radius. To do this you must plot radius targets on the vertical profile. The fastest and
easiest procedure is as follows:
sin 1° x planned radius = measured distance along curve
Take the resulting distance and with an
engineer’s scale, begin scaling the distance
from the beginning of the curve. Place a tic
mark at each scaled distance. For example,
if the planned radius is 2000 ft (610 m) and
the entry angle is 12°, then:
than planned, if you respect the radius
limit. At this point you will need to discuss
radius limits with the client, pointing out
your position on the plot and what you will
need to do to bring the curve back on line.
Do not make this decision yourself.
If your inclination is higher than plan at
any point, you will reach the bottom of the
plan higher than planned. You may relax
the radius slightly. Do not do this over two
or three joints. Project ahead a smaller
radius to reach 90° at the same point as the
original plan.
Always compare the plotted position’s
inclination to the planned inclination at the
same away distance. This is the only way
you will get an early warning of future
location problems.
sin 1° x 2000 = 34.9 ft (10.6 m)
Measuring this distance from the beginning
of the curve, place a tic mark 34.9 ft
(10.6 m) along the curve. From that point,
place another tic mark 34.9 ft further along
the curve. Continue placing the tic marks
and scaling until you reach the end of the
curve. This should measure exactly that
point where the planned curve reaches 90°.
If it does not, check for errors.
Once the tic marks are plotted, write the
planned inclination at about an inch
(2.54 cm) above the marks. Again, if you
started at 12° (78° from vertical), you will
have ascending numbers: 78, 79, 80,
81…90.
Your plan is now in place. While drilling
the curve, plot your position as normal.
Look at the inclination and compare it to
the planned inclination at that point. If your
actual inclination is lower than plan, you
will reach the bottom of the curve lower
Intermediate targets. Every joint you drill
should be toward an intermediate target.
Setting targets is a function of present inclination and azimuth, planned inclination,
and azimuth vs. present and planned
positions.
You will know if you are ahead or behind
the curve from the radius tics. If you are on
the curve and do not need to break or relax
the radius, the projected inclination target
is easy:
next joint length/(sin 1° x radius) =
expected degrees per joint
Add the quantity derived to the previous
inclination to generate the next intermediate target.
If the centerline is straight, the target azimuth should be the same. If you are right or
left of the line, you should normally
attempt to close the line slightly by giving
3-37
Horizontal Directional Drilling Training Program
the driller a target pointing toward the line.
Normally, a 5° left or right tool face setting
on one joint, on both the high and low side,
will achieve an azimuth movement of
between 0.1 and 0.3°. A 10° tool face setting will achieve 0.2 to 0.5° of azimuth.
Example 2:
2000-ft radius planned =
0.86° per 30-ft joint
Previous inclination = 80.5°
Previous azimuth = 271°
Present inclination = 81.3°
Radius calculations. Never turn the bore
without considering radius. In the example
above of a 2000-ft (610-m) radius, if you
achieve the exact planned radius on inclination and 1/2° of turn in a joint, you will
have exceeded or broken the radius by a
factor of approximately 10%.
Use the following rule of thumb to calculate a combined radius: if you add the
change in inclination and the change in azimuth in degrees, and take 70% of the
result, you will roughly approximate the
angle on a combined basis. Then determine
the radius of the change in combined angle:
Present azimuth = 271.5°
81.4° – 80.5° = 0.8°
271.5° – 271° = 0.5°
(0.8 + 0.5)(0.7) = 0.91°
30 ft/(sin 1 x 0.91°) = 1889-ft radius
Example 3:
2000-ft radius planned =
0.86° per 30-ft joint
Previous inclination = 80.5°
Previous azimuth = 271°
Present inclination = 81.0°
Present azimuth = 271.5°
30-ft joint/(sin 1 x angle) =
resulting radius
81.0° – 80.5° = 0.5°
271.5° – 271° = 0.5°
Example 1:
0.5 + 0.5 x 70% = 0.70°
30 ft/(sin 1 x 0.70°) = 2455-ft radius
2000-ft radius planned =
0.86° per 30-ft joint
Previous inclination = 80.5°
Previous azimuth = 271°
Present inclination = 81.5°
Present azimuth = 271.5°
81.5° – 80.5° = 1°
271.5° – 271° = 0.5°
(1.0 + 0.5)(0.7) = 1.05°
30 ft/(sin 1 x 1.05°) = 1637-ft radius
3-38
You can see from these examples how sensitive the radius actually is to combined
changes.
In determining an intermediate target, you
must ensure that you respect the radius on a
vertical and combined basis. If you exceed
the radius, you must have the client’s permission to do so. The survey printout at the
end of the job will form the basis of proof.
Radius averaging. It is not realistic to
attempt to drill a perfect radius. The formation will push you up, down, left, and right
as you drill, making the attempt of a perfect
bore nearly impossible to achieve. You
must control the radius rather than letting it
control you. This means making early decisions, ensuring good communications with
the client, and averaging.
Steering: Job Site Actions—Pilot Hole
The expression of dogleg on the screen is
an angular expression of radius. Using the
formula above:
30-ft joint/(sin 1 x dogleg angle
degrees) = radius
After surveying a joint, look at the dogleg
angle. Change it to radius by using the
above formula. If the result is acceptable,
note it on your tabulation sheet. Continue
making notes on every joint.
Since dogleg is an expression of a combined radius as an angle, and it is projected
out over 100 ft (30.5 m), it is correct to
average three 30-ft (9-m) joints to better
approximate the real radius. A point 30 ft
from the previous one that results in a
1600-ft (488-m) radius when the target
radius is 2000 ft (610 m) may be accepted
if the following two joints average 2200 ft
(671 m). The sum of the three joints will
total 6000 ft (1830 m) which, when averaged, will be an average radius of 2000 ft.
Use a running average throughout the
curve.
Remember when using dogleg that this is a
combined curve angle. The probe resolves
azimuth from the earth’s magnetic field.
Therefore, if there is magnetic interference,
the dogleg angle will be incorrect. You
must correct the azimuth first, by plugging
the azimuth when you take a survey, or by
editing the survey file and recalculating,
before you can use the dogleg in radius
terms.
Directions to driller
There are two types of drillers—those who
want you to give them angular targets, and
those who want you to give them position
targets.
tion to a particular number, such as 86.5°,
azimuth of 217.5°. You will have already
calculated these numbers and have them
available when required.
Angular targets. This target is one where
you ask the driller to build or hold inclina-
Position targets. This target is subjective—
build 2° and go straight ahead, for instance.
Drilling problems
Wireline shorts. With any wireline, you
will experience electrical shorts. You need
to understand how to troubleshoot shorts to
determine their location. A short is exemplified when the amp needle on the front of
the interface moves to maximum or the
power fuse blows. Use the following procedure to locate a short:
1. The most likely place for a short is
downhole at a wireline connection or at
the centralizer blades on top of the
probe. You should begin looking downhole. Rig a test lead from the positive
terminal of the interface box long
enough to reach the wireline from the
pipe in the rig vises. Remove the existing power lead from the interface and
connect the test lead.
2. Switch on the probe and determine
proper operation.
3. If the test indicates a short is present,
the short is downhole. Trip pipe back
until the short is located.
4. If the probe works normally, the short
is somewhere between the interface
box and the wire connection on the rig
carriage.
5. Continue isolating discrete strings of
wire and testing either with the probe
or with a continuity tester until you
locate the short.
6. In some cases, the short will be intermittent. These are the most difficult to
locate. You must continue moving the
wire uphole or downhole until the location is found.
3-39
Horizontal Directional Drilling Training Program
7. Many times a quick test with a voltage
output meter (VOM) of the probe will
tell you if the short is downhole:
•
First, disconnect the test lead from
the wireline of the joint in the
vises. Using a VOM, set the resistance scale to at least 300 ohms,
and connect the leads between the
power wire and ground. Use the
joint for ground.
•
You should read a resistance of
between 20,000 and 40,000 ohms.
If you read more than 40,000, a
wireline leak exists between the
test lead and the probe. Pull on the
wireline at times during the test to
attempt to make the readings vary,
which would indicate a leak.
•
Reverse the test leads. Watching
the meter, you should see a capacitance kick. The needle should kick
to about 300 ohms and gently
bleed back near zero.
Wireline leaks. A leak is still defined as a
short, but probe operation continues. A leak
is not yet large enough (200 ma) to stop
probe operation. Leaks will generally turn
into shorts with time. In some cases, they
will cause a trip within a couple of joints,
and in other cases, you may drill the entire
crossing with the leak.
A leak is usually caused by wire insulation
damage. The wireline may be skinned,
exposing the wire to the mud. Power will
be lost to the mud in varying amounts until
the leak becomes too great and the fuse
blows.
A leak may “heal” itself on occasion. The
electrolysis effect of copper and the mud
can cause oxidation of the copper wire,
effectively building a non-conductive coating around the wire. This then seals the
mud away from the current, reducing the
quantity of amperage being lost. This will
happen only with very small leaks where
the insulation has only a slight cut. This
insulation effect will be lost completely if
you ever elect to change the mud system
from mud to water. The water will wash the
coating away, again leaving the copper
exposed to the fluid.
3-40
Downhole leaks should be treated as
shorts, identified, and a course of action
determined. It is normally wise to trip to
locate and repair the leak early, rather than
tolerate it for a whole job. On the other
hand, if you are 2 to 300 ft (0.6 to 91.5 m)
from punchout, the client may wish to
complete the distance. This should always
be his decision, but he is depending on you
to make a judgment of success.
Wireline opens. A wireline open is defined
as zero continuity between the interface
and the probe. The amp needle on the interface will not move, indicating a wireline
break somewhere in the system. The positive or negative wire may be broken.
If the wire breaks downhole, normally you
will see some amperage on the needle.
Begin looking for an open on the surface
between the interface and the rig
connections.
Tripping pipe out. You must keep track of
exactly how many joints of pipe are below
the vises at all times. All your measurements are made from this reference point,
which makes it very important. When drilling problems force a decision to trip out,
either a few joints or all of them, you must
keep track.
Since you normally start drilling a new
joint that has not been surveyed, you
should lay down that first joint and note its
unsurveyed depth and number on the field
tabulation sheet. For each additional joint
you lay down on the rack, indicate on the
left side of the tabulation sheet an arrow
pointing up, next to the joint number. Continue removing joints and noting the arrows
until you reach the planned number.
Once you have removed the required number, go outside and count the joints you
have removed. Compare the number to
your noted numbers for agreement. If they
do not agree, count all joints on location,
add the downhole joints, and compare the
total joints to the total joints on location
that you counted at the beginning of the
job. Be precise and make sure you can
account for every joint.
Steering: Job Site Actions—Pilot Hole
Tripping pipe in. On your return into the
hole, place an arrow pointing down against
each arrow you previously noted coming
out, once each joint is down. Using a test
lead, power up the probe about every five
joints and take a print screen. Note the
inclination and azimuth on the tabulation
sheet against the representative data. Compare constantly—the readings should be
similar.
Punchout
Well before punchout, you determined your
margin for error in elevation. Given good
Tru Tracker readings, you will know where
you are in elevation within a small tolerance. If you are on a long job, the elevation
accuracy may degrade because of a number
of factors, such as driller bias, distance
errors, formation tendencies, short Tru
Tracker coils, no Tru Tracker coils, and
survey calculation methods.
You should recalculate your complete survey against both average angle and
tangential methods several times during the
job to compare the methods. Normally, one
method will match Tru Tracker better than
the other. In most cases, the methods will
produce a bracket of elevation numbers.
Tangential calculations may indicate you
are at -22.5 ft (-7 m), while average angle
calculations indicate -26.0 ft (-8 m). At the
same point, Tru Tracker will often be
between the two, such as at -23.5 ft (-7 m).
This will normally indicate the actual elevation to be between the tangential and Tru
Tracker readings.
Plot each elevation as points throughout the
last 200 ft (61 m). Discuss the different calculation methods and error possibilities
with the client and determine his wishes as
to crossing length. He may prefer you to be
short rather than long. He may indicate that
he only has the required length of pipeline
as planned, meaning that you cannot be
long.
The best case, naturally, is that all methods
are close—but don’t count on it! Play the
percentages and plan ahead. Remember,
when you punch out long, failing a major
pullback and sidetrack, you will not be able
to redrill to a shorter location. Punching out
short gives you the option of pulling back a
couple of joints and lengthening the distance considerably.
Construction of as-built
As soon as feasible, you should construct
your as-built print out. Physically measure
the punchout position and note it on your
tabulation sheet and daily report.
the closure angle between the two positions
as follows:
•
Divide the difference between the
actual and calculated left/right positions by the horizontal length of the
crossing. Take the arc sin of the result.
This is the overall angular difference
from the beginning of the crossing
which, when applied to the line azimuth, will overlay the actual exit point
and the calculated exit point.
•
If you have plugged azimuths based on
justifiable analysis, compare the course
with Tru Tracker positions to find the
best fit. You may find that the best fit
causes you to change the values of the
previously plugged azimuths.
Take an initial print of the survey using the
Survey Processing and Print Screen in the
program. Compare the final position on
paper to the actual punchout position. Use
the calculation method that best approximates the actual punchout elevation.
Determine the calculated left/right position
and compare it to the actual punchout location. If you have been steering to punchout
using Tru Tracker readings and not azimuth, there will be a difference. Determine
3-41
Horizontal Directional Drilling Training Program
Notes
3-42
Chapter 4: Reaming
General ................................................................................................ 4-1
Purpose of reaming............................................................................................ 4-1
Enlarging the drilled pathway..........................................................................................4-1
Removing cuttings from the hole ......................................................................................4-1
Reaming alternatives ......................................................................................... 4-1
Selecting tools.................................................................................................... 4-1
Troubleshooting ................................................................................................. 4-1
Determining the number of passes .................................................................... 4-1
Definitions........................................................................................... 4-2
Types of Reaming .............................................................................. 4-6
General .............................................................................................................. 4-6
Silt and sand .....................................................................................................................4-6
Clay...................................................................................................................................4-6
Rock ..................................................................................................................................4-6
Teeth sizing: Bottom’s up .................................................................................................4-7
Number of passes..............................................................................................................4-7
Pre-reaming ....................................................................................................... 4-8
Reaming and pulling .......................................................................................... 4-8
Back reaming ..................................................................................................... 4-8
Forward reaming .............................................................................................. 4-10
Tool Selection................................................................................... 4-11
General ............................................................................................................ 4-11
Fly cutter reamers ............................................................................................ 4-11
Fly cutter with stabilization ring ....................................................................................4-11
Fly cutter with stabilization ring and reversing skirt .....................................................4-11
Fly cutter without stabilization ring ...............................................................................4-11
Barrel reamers ................................................................................................. 4-12
Barrel reamers with buoyancy control...........................................................................4-12
Barrel reamers without buoyancy control......................................................................4-12
Bullet-nose reamers ......................................................................................... 4-12
Centralizers/stabilizers ..................................................................................... 4-13
Centralizers ....................................................................................................................4-13
Stabilizers .......................................................................................................................4-13
Hole openers.................................................................................................... 4-13
Hydraulics..........................................................................................4-14
Annular velocities and flow rates ...................................................................... 4-14
Weight and rotary speed .................................................................................. 4-14
Size of completed reamed pathway ................................................................. 4-15
Penetration rates .............................................................................................. 4-15
Pumping ........................................................................................................... 4-16
Velocity/annular velocity ................................................................................... 4-17
Viscosity ........................................................................................................... 4-19
Acceptable yield point....................................................................................... 4-19
Acceptable plastic viscosity .............................................................................. 4-19
Sand content .................................................................................................... 4-19
Troubleshooting................................................................................4-20
General............................................................................................................. 4-20
Increasing torque.............................................................................................. 4-20
Increasing torque—a few seconds ................................................................................. 4-20
Increasing torque—several minutes............................................................................... 4-20
Increasing torque—sudden lockup................................................................................. 4-20
Twistoff of drill pipe........................................................................................... 4-20
Fishing .............................................................................................................. 4-21
Recovery .......................................................................................................... 4-21
Salvaging hole................................................................................................................ 4-21
Severing drill pipe .......................................................................................................... 4-22
Lost or decreased circulation............................................................................ 4-23
Stuck reaming assembly .................................................................................. 4-23
Mud pressure increase ..................................................................................... 4-23
Mud pressure decrease.................................................................................... 4-23
Inadvertent returns ........................................................................................... 4-24
Reduced penetration rate ................................................................................. 4-24
ii
List of Figures
Fig. 4.1. Fly cutter. ...........................................................................................................4-2
Fig. 4.2. Barrel reamer......................................................................................................4-2
Fig. 4.3. Bullet-nose reamer. ............................................................................................4-3
Fig. 4.4. Bullet-nose reamer completing a pullback. Mobile Bay, Alabama, USA. .......4-3
Fig. 4.5. Conventional hole opener. .................................................................................4-3
Fig. 4.6. Centralizer/stabilizer. .........................................................................................4-5
Fig. 4.7. Back reaming. ....................................................................................................4-9
Fig. 4.8. Forward reaming. .............................................................................................4-10
Fig. 4.9. Mud pumps.......................................................................................................4-17
Fig. 4.10. A fishing tool completing a pullback. ............................................................4-21
List of Tables
Table 4.1. Bottom’s up chart.............................................................................................4-4
Table 4.2. Minimum annular velocities and flow rates for cleaning large-diameter
holes (metric and US units)......................................................................................4-14
Table 4.3. Weight and rotary speed recommendations for hole openers (metric
and US units)............................................................................................................4-14
Table 4.4. Penetration rates chart....................................................................................4-16
Table 4.5. Velocity chart. ................................................................................................4-18
iii
Notes
iv
Chapter 4: Reaming
General
This chapter outlines the different topics
that pertain to reaming. Reaming means to
enlarge a hole from one size to another size
of greater diameter.
Purpose of reaming
Enlarging the drilled pathway. To determine the size of the reamed hole, you must
know the size of the pipe to be installed.
Normally, the reamed hole is 1.5 times the
diameter of the pipe to be installed. On
crossings that are greater than 4000 ft
(1500 m) with a diameter greater than
30 in. (762 mm), or where you may
encounter gravel, you may choose to
increase this factor.
Removing cuttings from the hole. To install a pipe in a pre-reamed pathway, it is
important to remove the native materials
(cuttings) from the pathway.
Reaming alternatives
There are many considerations when planning a reaming exercise:
•
use one or two rigs to facilitate the
reaming.
•
pull the pipeline and ream at the same
time
The following sections will cover all of the
ways you can ream a hole.
•
ream forward or backward
Selecting tools
Proper tool selection is one of the most
important decisions you will make in a
reaming strategy. Your decision will make a
tremendous difference in your progress,
your risk, and your success rate.
Troubleshooting
Your success will largely be determined by
your ability to identify problems and cor-
rect them. As problems occur, record them
and their solution for future reference.
Determining the number of passes
When reaming for large-diameter pipe
installations, it is sometimes necessary to
ream the pathway in stages. The main consideration in determining the number of
reaming passes you must make is the types
of soils that will be encountered. In softer
formations, the determining factor is generally the volume of cuttings that must be
removed with each pass, while in harder
formations, the torsional requirements and
volume of cuttings must both be
considered.
Horizontal Directional Drilling Training Program
Definitions
Fly cutter: A fly cutter is a reaming device
that has a center shaft with three or four
spokes (Fig. 4.1). When facing the tool, the
spokes are at the 10, 2, and 6 position on a
clock face. A fly cutter can be fabricated
with or without a circumventing ring. This
tool is used as the primary cutter when
enlarging a hole through alluvial
formations.
Fig. 4.1. Fly cutter.
Barrel reamer: A barrel reamer is a center
shaft mounted concentrically in a cylinder
of pipe that may have a wide range of
diameters and lengths (Fig. 4.2). Both ends
of the reamer are tapered at approximately
40° off the center shaft. The barrel reamer
can be baffled at either end (or neither end)
for buoyancy control.
Fig. 4.2. Barrel reamer.
4-2
Reaming: Definitions
Bullet-nose reamer: A bullet-nose reamer
(Fig. 4.3 and Fig. 4.4) is the same as a barrel reamer, with one exception. The ends,
instead of being tapered, are made from
weld caps. They are used more for pulling
in front of the pipeline during pullback or
as a centralizer. They are not used for reaming, but for cleaning cuttings from the hole.
Fig. 4.3. Bullet-nose reamer.
Fig. 4.4. Bullet-nose reamer completing a pullback. Mobile Bay, Alabama, USA.
Conventional hole openers: Conventional
hole openers (Fig. 4.5) are designed for use
in rock, from the softest to the hardest formations. A conventional hole opener is
cast, and has a center shaft with three to six
arms onto which are mounted roller cones.
The cones come with or without sealed
bearings. The cones range from mill teeth
for the softer formations, to tungsten carbide inserts for the harder formations.
Fig. 4.5. Conventional hole opener.
4-3
Horizontal Directional Drilling Training Program
Kennemetal teeth: Kennemetal™ is a brand
name for cutting teeth that are used, almost
exclusively, on cutters and reamers in this
industry. They can be inserted into holders
that are welded on the cutters or reamers,
or welded directly on the cutters and reamers without the holders.
Gauge: Gauge is the scale of measurement
of a bit, reamer, or hole opener. It is the
absolute outside diameter of a given bit
size or reamer.
Chisel teeth: Chisel teeth can be fabricated
by most machine shops and are used when
you expect to encounter cobbles or boulders embedded in normal soils. The
approximate dimensions are 1.5 in.
(38 mm) in diameter and 2 to 4 in. (50 to
Bottom’s up: Bottom’s up is a reference of
time and volume pertaining to a cylinder or
hole. Bottom’s up time is the time required
to displace a known quantity of fluid from
the bottom of a hole to the surface. Bottom’s up volume is the amount of fluid that
must be displaced in a hole (see Table 4.1).
100 mm) long. The cutting edge is chiselshaped and made of tungsten.
Table 4.1. Bottom’s up chart.
Hole diameter
(in.)
Enter
Distance
from rig (ft)
bbl/
3
min ft /min
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
4-4
5.61
11.23
16.84
22.46
28.07
33.69
39.30
44.92
50.53
56.15
61.76
67.38
72.99
78.61
84.22
89.84
95.45
101.07
106.68
112.30
117.91
123.53
129.14
134.76
140.37
400
800
1200
1600
Hole radius
(ft)
31.75
1.32
2000
2400
Volume of 1 ft
of hole (ft3)
5.4981408
2800
3200
3600
4000
4400
Result in minutes
391.68
195.84
130.56
97.92
78.34
65.28
55.95
48.96
43.52
39.17
35.61
32.64
30.13
27.98
26.11
24.48
23.04
21.76
20.61
19.58
18.65
17.80
17.03
16.32
15.67
783.35 1175.03 1566.71
391.68 587.52 783.35
261.12 391.68 522.24
195.84 293.76 391.68
156.67 235.01 313.34
130.56 195.84 261.12
111.91 167.86 223.82
97.92 146.88 195.84
87.04 130.56 174.08
78.34 117.50 156.67
71.21 106.82 142.43
65.28
97.92 130.56
60.26
90.39 120.52
55.95
83.93 111.91
52.22
78.34 104.45
48.96
73.44
97.92
46.08
69.12
92.16
43.52
65.28
87.04
41.23
61.84
82.46
39.17
58.75
78.34
37.30
55.95
74.61
35.61
53.41
71.21
34.06
51.09
68.12
32.64
48.96
65.28
31.33
47.00
62.67
1958.39
979.19
652.80
489.60
391.68
326.40
279.77
244.80
217.60
195.84
178.04
163.20
150.65
139.88
130.56
122.40
115.20
108.80
103.07
97.92
93.26
89.02
85.15
81.60
78.34
2350.06
1175.03
783.35
587.52
470.01
391.68
335.72
293.76
261.12
235.01
213.64
195.84
180.77
167.86
156.67
146.88
138.24
130.56
123.69
117.50
111.91
106.82
102.18
97.92
94.00
2741.74
1370.87
913.91
685.43
548.35
456.96
391.68
342.72
304.64
274.17
249.25
228.48
210.90
195.84
182.78
171.36
161.28
152.32
144.30
137.09
130.56
124.62
119.21
114.24
109.67
3133.42
1566.71
1044.47
783.35
626.68
522.24
447.63
391.68
348.16
313.34
284.86
261.12
241.03
223.82
208.89
195.84
184.32
174.08
164.92
156.67
149.21
142.43
136.24
130.56
125.34
3525.09 3916.77 4308.45
1762.55 1958.39 2154.22
1175.03 1305.59 1436.15
881.27 979.19 1077.11
705.02 783.35 861.69
587.52 652.80 718.07
503.58 559.54 615.49
440.64 489.60 538.56
391.68 435.20 478.72
352.51 391.68 430.84
320.46 356.07 391.68
293.76 326.40 359.04
271.16 301.29 331.42
251.79 279.77 307.75
235.01 261.12 287.23
220.32 244.80 269.28
207.36 230.40 253.44
195.84 217.60 239.36
185.53 206.15 226.76
176.25 195.84 215.42
167.86 186.51 205.16
160.23 178.04 195.84
153.26 170.29 187.32
146.88 163.20 179.52
141.00 156.67 172.34
Reaming: Definitions
Tripping out: Tripping out means to remove
the drill pipe from the borehole.
Cuttings: Cuttings are the formation materials removed from the hole and suspended
in the drilling fluid.
Centralizer/stabilizer: These two items are
discussed together because the same tool is
used as both a centralizer and a stabilizer.
The difference is in their placement in the
hole. A centralizer/stabilizer can be a barrel
or bullet-nose reamer, or other tools of different shapes and sizes (Fig. 4.6).
A centralizer is run in front of the primary
cutter, and is used to hold the cutting
assembly up in the center of the hole,
guarding against the cutter’s normal tendency to drop to the bottom and cut the
hole in a tear-drop shape.
A stabilizer is run behind the primary cutter
for stabilization and to keep the primary
cutter from bouncing and tilting.
Fig. 4.6. Centralizer/stabilizer.
Cutter sets: Hole openers can be fitted with
different types of teeth, depending on the
formation material. Each type of teeth
comes in a numbered cutter set.
Tungsten carbide inserts: On the hole
opener, tungsten carbide inserts (TCIs) are
the cutting teeth on the roller cones that do
the actual cutting or breaking of the rock.
TCIs are used in medium and hard rock
formations.
Mill tooth cutters: Mill teeth are teeth that
look more like blades than inserts and are
used in soft rock formations.
PDC teeth: Polycrystalline diamond compact (PDC) teeth are made of manmade
diamonds and are used mainly in shales.
4-5
Horizontal Directional Drilling Training Program
Types of Reaming
General
This section covers reaming in different
types of soils, determining the number of
passes, and removing cuttings from the
drill path.
For discussion purposes, the soil types are
divided into silt, sand, clay, and rock. The
formation will usually consist of combinations of these soil types—silty sands, sandy
clays, sand with gravel, etc.
Silt and sand. Silty and sandy soil densities can vary from loose and
unconsolidated to very dense and compact.
In dense silts and sands, your rate of penetration will depend on the pull and torque
required to physically cut through the formation. With these limitations, the major
concern in reaming will be pumping
enough fluid to completely remove the cuttings from the pathway.
In unconsolidated silts or sands, the torque
required to rotate the reamer will be low
and you will be tempted to ream too fast.
When tempted to ream at a faster rate,
remember what you are trying to accomplish. The silt and sand must be removed
from the pathway, and what is not removed
should be encapsulated with bentonite so it
cannot compact. This can only be accomplished by reaming at the proper
penetration rates. If you ream too fast, the
sand that is cut in the pathway will settle
out of the drilling fluid shortly after passing
through the reamer. The result will be an
insufficiently cleaned pathway or improperly encapsulated sand left in the pathway.
You may be able to complete smaller-diameter, shorter-length crossings that have
been reamed too fast. Generally, on these
types of crossings, you can make mistakes
and still be successful. However, as the
lengths and diameters of crossings
increase, the chances for failure will also
increase unless you use proven, time-tested
methods.
4-6
Clay. Similar to silts and sands, the clayey
soils range from soft to very stiff. The
stiffer the clay, the more difficult it is to
ream fast; the softer the clay, the easier it is
to overpenetrate. When you penetrate soft
clay too fast, you tend to remove the clay in
slabs that will pile up behind the reamer
and eventually plug the hole, causing mud
returns to stop. In most cases, the only way
to remove the slabs is to rotate back
through the reamed hole and recut the
slabs. There will be times that you will
need to pull the cutter all the way back to
the surface to remove the slabs and regain
drilling fluid returns. If you examine the
slabs that come to the surface, upon breaking them open you will see that they are dry
on the inside, exactly as they were in situ.
If you allow these slabs to accumulate
behind the reamer, your chances of completing the pipe installation will be
reduced. Remember, one of the main functions of the reaming process is to remove
enough material from the pathway to allow
the pipe installation. Generally, when the
pipe is being pulled into place, a bulletnose reamer is used in front of the pipe.
This reamer is designed to force the slurry
and remaining solids outside of the hole.
Clay slabs resulting from a too-fast ream
will litter the pre-reamed pathway and be
pushed ahead of the bullet-nose reamer,
eventually clogging the entire pathway. If
enough of these slabs are forced outside of
the bullet-nose reamer and accumulate
around the pipe, they can cause the pipe to
become lodged.
When clay is reamed properly, the pipe can
be pulled through the pathway with a minimum of force and as fast as the rig carriage
will travel. Clay should be the most conducive soil for directional drilling if
approached properly.
Rock. Reaming in rock is performed with
special downhole reamers known as hole
openers. Hole openers can be configured in
a variety of ways, depending on the type of
rock encountered. Typically, the driller has
a good idea of the type of rock by the time
Reaming: Types of Reaming
reaming is necessary, both from geotechnical studies and from drilling the pilot hole.
Reaming in rock requires the widest range
of reamer and cutter types. A tooth that will
cut 2000-psi (14-Mpa) rock will not last
half a day in 10,000-psi (70-Mpa) rock. A
tooth that will cut 10,000-psi rock is so
short that you will make little progress in
2000-psi rock. Normally, one to three types
of teeth should be tried for a specific
project. You must learn to determine which
tooth is most effective. Drilling the pilot
hole will give you a good idea of which
type of tooth cutter to use, but the only way
to know for certain is to run different types
of teeth in the hole.
Teeth sizing: Bottom’s up. Since the size
of the tooth determines the size of the cuttings, and the amount of cuttings returned
out of the hole depend on the drilling procedures and mud program, choose the most
aggressive tooth you have. When you start
reaming, look at the cuttings coming across
the primary shaker: if you see only cuttings
smaller than the size you are cutting, either
change your mud program or put a less
aggressive tooth in the hole. An additional
cleaning practice is to pump bottom’s up
periodically so that any cuttings that drop
out can be picked up and circulated out of
the hole. This is also a good practice if you
plan to stop reaming for a specified time,
such as when you are working a single
shift. By pumping bottom’s up, you purge
all of the fluid that is laden with cuttings
from the reamer to the surface. Simply stop
reaming (occasionally rotate the pipe and
reamer to stir the hole) and pump your
known volume for a specified time. If the
drilling fluid in the hole is heavy with cuttings and your new fluid is much lighter,
the new fluid will channel along the top of
the hole. You can easily determine this if
your clean fluid returns to the surface much
faster than calculated.
Number of passes. To determine the number of passes to make, you must first know
the type of material you will be reaming.
As stated earlier, if you are reaming in
rock, some of your decisions have already
been made. The pilot hole diameter will
probably be 9 7/8 in. (251 mm) and there
are only a few openers that will cut from
this hole size.
The 17 1/2-in. (445-mm) opener is the largest conventional opener that will cut from a
9 7/8-in. (251-mm) diameter. Assuming
you need to open a hole in mediumstrength rock to 42 in. (1067 mm), the recommended number of passes is typically:
•
a 17 1/2-in. (445-mm) pass
•
a 26-in. (660-mm) pass
•
a 36-in. (914-mm) pass
•
a 42-in. (1067-mm) pass.
To establish the exact number of passes,
you must determine the volume of material
you are attempting to remove. The four
passes listed above, plus the pilot hole,
contain the following volume in US units:
17 1/2 in. - 9 7/8 in. = 1.14 ft3 of material per linear foot of hole
26 in. - 17 1/2 in. = 2.01 ft3 of material
per linear foot of hole
36 in. - 26 in. = 3.39 ft3 of material per
linear foot of hole
42 in. - 36 in. = 2.55 ft3 of material per
linear foot of hole
or in metric units:
445 mm - 251 mm = 0.032 m3 of material per linear meter of hole
660 mm - 445 mm = 0.057 m3 of material per linear meter of hole
914 mm - 660 mm = 0.096 m3 of material per linear meter of hole
1067 mm - 914 mm = 0.072 m3 of
material per linear meter of hole.
You can see that the third pass is the largest
cut. You might decide, depending on your
first two passes, to add a 30-in. (762-mm)
pass. You would determine this when you
have all the pertinent information.
Another consideration when planning and
executing rock reaming is the size of the
4-7
Horizontal Directional Drilling Training Program
pilot hole, or the preceding hole-opening
pass and the size of the next cutters’ core
buster. The core buster is the set of blades
in front of the hole opener designed to keep
rock pieces from accumulating in the inner
circle of the hole opener, and to help centralize the hole opener for concentric holeopening passes. Always double-check the
sequence of planned hole-opening passes
to ensure that the hole-opener sizes on the
job site are correct, and that there is no part
of the formation that will be missed by one
of the hole openers.
Always measure every hole opener as it
arrives onsite and make a sketch in your
field notes. By doing this, you know what
you have on hand and whether you need to
order additional equipment. It is much better to solve problems in advance of the
need.
Pre-reaming
Pre-reaming means that you enlarge the
hole before pulling the pipeline. It is not
always done, but it always reduces your
risk.
Reaming and pulling
Reaming and pulling means that the hole is
reamed simultaneously as the pipe is
pulled. Hundreds of lines have been
installed in this manner, but they were not
long, large-diameter crossings. Generally,
the time saved by reaming and pulling is
not worth the risk of sticking the pipe.
Back reaming
Back reaming is a term used when the hole
is enlarged from the exit side of the crossing (Fig. 4.7). The main advantage is that
the rig has complete control of the drill
pipe and the reamer. The rig operator can
more easily control the torque and pull than
when forward reaming. The main disadvantage is that the return fluid is returned to
the exit side of the crossing and all of the
cleaning equipment is at the entry side of
the crossing. This requires one or more of
the following:
4-8
•
setting up a cleaning system and pump
at the exit side
•
setting up a cleaning system at the exit
side, and hauling or pumping the fluid
back to the entry side
•
holding the fluid in pits or tanks and
later sending to a disposal site.
When the pilot hole is completed, the jetting assembly (or motor) and non-magnetic
collar are removed and a reamer is installed
onto the drill pipe. The pipe is then rotated
by the rig and pulled toward the rig to
enlarge the hole to a predetermined diameter. For hole sizes up to 30 in. (762 mm),
this is usually accomplished in one pass
(except for rock or very dense or stiff alluvial deposits). For larger hole sizes, two or
more passes are usually required.
As the reamer is rotated and pulled, a predetermined volume of fluid is pumped
through the drill pipe and exits the reamer
through jet nozzles. The fluid is then mixed
with the soils being cut away by the
reamer, and the fluid becomes the medium
through which the soils are removed from
the hole. The primary objective is for all
the slurry to pass back through the enlarged
hole to a pit at the exit point of the
borehole.
Reaming: Types of Reaming
1
2
3
4
Fig. 4.7. Back reaming.
1
2
3
4
Rig
Drill pipe
Fly cutter reamer
Drill pipe
For the first 15 years in the horizontal
directional drilling (HDD) industry, reaming was first done by means of a bit on the
end of the pipeline, and later by back reaming. The main reason for this was that mud
disposal was not a problem, as the mud
was allowed to flow directly into the river.
At the time, neither mud nor mud disposal
was of great concern, and 95% of the crossings were short to medium length, small to
medium diameter, and never through rock.
As the industry grew and longer crossings
with larger-diameter pipe were being
attempted, the mud volume and viscosity
changed to accommodate the hole sizes and
lengths. Also, the industry expanded into
rock crossings, and the volumes needed to
power the mud motors increased rapidly.
Up until the mid to late 1980s, it was
unusual to have a pump on location that
would pump more than 4 to 5 bbl/min or
160 to 200 gal/min (636 to 794 l/min).
Then, as the requirements changed, so did
the pumps. Soon mud motors that required
up to 30 bbl/min or 1200 gal/min (4770 l/
min) were being used. Naturally, the bentonite usage increased with these increased
volumes.
If you assume a pumping rate of 4 bbl/min
(636 l/min) with an average of 20 lb of bentonite per barrel (57 kg per m3), the hourly
consumption of bentonite would be about
4800 lb (2180 kg) or 44 50-kg sacks. If you
then increase this pumping rate to 30 bbl/
min (4770 l/min) with the same bentonite
proportion, you are using 36,000 lb
(16,344 kg) each hour, or 326 50-kg sacks.
Not only is this cost-prohibitive, it requires
physically adding a 100-lb sack every 10
seconds through the hopper; neither the
personnel nor the mixing units can keep up
with this requirement.
Adding to the problem was disposing of
these tremendous quantities of fluid. With
today’s concern for the environment, large
quantities of drilling fluid cannot be
allowed to directly enter a waterway.
4-9
Horizontal Directional Drilling Training Program
Forward reaming
Forward reaming is enlarging a hole from
the entry side (Fig. 4.8). To forward ream,
you need some source of pulling power at
the exit side. HDI has used a second rig, a
dozer, a track hoe, and/or a pulling unit.
Using a second rig is the preferred choice,
but it is the most expensive. In addition to
the extra mobilization of the rig and components, you have to employ additional
personnel to man the rig.
In most cases, HDI uses a track hoe or
dozer. The disadvantage is that you try to
pull as many joints as possible before disconnecting so that less time is wasted.
However, since the rig must not only turn
the pipe in the hole, but also the pipe on the
ground at the exit side, you are limited in
how far you can go before breaking the
drill string.
3
2
1
Fig. 4.8. Forward reaming.
1 Pulling machine
2 Swivel
3 Recycling unit
While communication is important when
you are back reaming, it is critical when
forward reaming. The operator at the entry
side must continuously instruct the opera-
4-10
tor at the exit side to pull more, pull less,
stop pulling, start pulling, etc., throughout
the procedure.
Reaming: Tool Selection
Tool Selection
General
In this business, planning is just as important as executing a job. With short
crossings, you can devise a plan quickly,
and then totally disregard the plan once
drilling commences and still be successful.
This is never the case for longer crossings,
where there is little room for error. Jobs
must be planned well and the plan must be
followed precisely to expect success.
On large crossings, there will be hundreds
of steps to follow. There will be a multiplestep mud program that must be adhered to,
and omitting one step can be disastrous.
The pilot hole must be planned so that
nothing is overlooked, and planned reaming rates must be followed. Tool selections
must be adhered to unless field conditions
prove the plan wrong.
Fly cutter reamers
The fly cutter (Fig. 4.1) was the first reaming tool used in HDD and is one of the
most commonly used reamers today. It is
used in clay, silt, sand, combinations of
sand and gravel, silt and sand, and even soft
rock. The first and most basic fly cutter was
a center shaft with three spokes. If you face
the fly cutter, you will see a spoke at the ten
o’clock, two o’clock, and six o’clock
positions.
Fly cutter with stabilization ring. This is a
basic fly cutter with a ring encircling the
spokes. The ring is normally about 6 in.
wide and 1/2 in. thick.
Purpose and application. The ring is used
to stabilize the fly cutter while reaming in
sand, and to help eliminate the tendency of
the fly cutter to walk over logs that are buried beneath rivers and streams. Normally,
the rings are only used on sandy crossings.
Nozzle sizing and configuration. On sandy
crossings, the nozzle size may vary from
16/32 in. (12.7 mm) to no nozzle at all.
Sometimes, if you do not have the proper
size jets for sand, you should remove the
nozzle altogether. You need to be able to
pump high volumes with minimum pressures, to minimize disturbing the sand
outside the diameter of the ring.
The number of jets on a fly cutter depends
on its size relative to arm length. You
should open all jets on the cutting side of
the fly cutter that will be against the face.
Open three to four on the backside of the
fly cutter for cleaning, and in case you need
to pull the fly cutter out of the hole.
Fly cutter with stabilization ring and
reversing skirt. This is the same as
described above, except that on the back
side of the ring there is a skirt slanted
toward the center to assist when pulling the
fly cutter backward out of the hole.
Purpose and application. The original fly
cutter and ring had no skirt, and when it
was pulled backward it had a tendency to
cut down in the hole, preventing a rapid
retraction. The skirt helps keep it in the
original hole for easy retraction.
Nozzle sizing and configuration. The same
as for a fly cutter with stabilization ring.
Fly cutter without stabilization ring. Usually the ring is removed when reaming in
clay. With the ring, the fly cutter tends to
ball up more easily. The clay packs the
openings between the spokes, and when
they are completely closed, the fluid cannot
flow back through the openings. When this
happens, the fluid under pressure will fracture to the surface, causing a loss of
returns.
Purpose and application. A fly cutter without a stabilization ring is used to lessen the
probability of balling. Removing the ring
allows the fly cutter to clean itself more
easily.
Nozzle sizing and configuration.
Using
nozzles from 8/32 to 12/32 in. (6.4 to
9.5 mm) increases the pressure to help cut
the clay. You will find the proper penetration rate by your torque. The nozzles
4-11
Horizontal Directional Drilling Training Program
should cut just ahead of the cutting tips so
that your torque is reduced.
If you are reaming from pilot hole diameter
to 30 in. (762 mm), open all the jets on the
cutting side of the fly cutter. If you are
reaming from 30 to 42 in. (762 to
1067 mm), close the inside circle of jets so
that you can get more hydraulic cutting
power to the outside where you need it.
As always, leave three or four jets open to
the back of the fly cutter in case the cutter
needs to be retracted from the hole.
Barrel reamers
A barrel reamer (Fig. 4.2) is a center shaft
mounted concentrically inside a section of
pipe 2 to 8 ft (0.6 to 2.4 m) long with varying diameters. The ends are conicalshaped, with a 30 to 40° taper off the center
shaft. They are used in front of or behind
primary cutters.
If you try to ream with a barrel reamer, the
fluid and cuttings cannot flow around it
because the cutting diameter is the same as
the diameter of the barrel. The fluids will
be forced to fracture and hole cleaning will
not be adequate.
Barrel reamers with buoyancy control. A
barrel reamer with buoyancy control has
sealed chambers that allow the fluid to
reach the nozzles, but restrict the fluid from
entering the center chamber.
Purpose and application. These are typically used in the larger-sized barrel reamers
to reduce weight in the hole and, consequently, the torque requirements.
Nozzle sizing and configuration. Since the
barrel reamers are not used as primary cutters, the nozzle sizing and configuration are
not important. You simply want to open
enough nozzles to keep the reamer face
clean and get additional volume in the hole.
Barrel reamers without buoyancy control. These are built the same as those with
buoyancy control, except that the fluid
completely floods the inside of the reamer,
making the reamer heavier. The reamers
without buoyancy control cost much less to
build.
Bullet-nose reamers
The basic design of a bullet-nose reamer is
a center shaft mounted concentrically
inside a pipe of varying diameters (Fig.
4.3). Instead of having conical-shaped
ends, a bullet-nose uses weld caps on
which are mounted a minimum number of
teeth.
Purpose and application. The bullet-nose
has been in use for only six to eight years.
As the holes were better cleaned, the speed
of the pullback drastically increased.
Something was needed that required almost
no torque and had no tendency to recut the
hole. The bullet-nose was the answer, since
it is approximately 6 in. (152 mm) smaller
than the hole diameter and approximately
6 in. larger than the diameter of the pipeline. These reamers are primarily pulled in
front of the pipeline during pullback.
Nozzle sizing and configuration. Nozzles
range from 16/32 to 1 in. (12.7 to
4-12
25.4 mm). Larger nozzles are necessary so
that you can get the fluid to the hole without plugging the jets.
When deciding what size nozzles to use,
always know what your filtering system is
capable of and be confident that it will
work properly. If you are taking water from
a river, you should have filters on the water
supply. You should always have a filter
between the mixing tank and the pressure
pumps.
Operators walking on top of the tank will
loosen small rocks or pebbles that were
picked up while on the ground. These pebbles will fall into the tank and be pumped
downhole if there is no inline filter. If the
pebbles are larger than the nozzles they
will block them, causing the reaming to
stop and a trip out of the hole for cleaning.
Reaming: Tool Selection
Centralizers/stabilizers
A centralizer is used in front of the primary
cutter to centralize the cutter, and a stabilizer is used behind the primary cutter to
stabilize the cutter (Fig. 4.6).
Centralizers. Centralizers can be specially
fabricated for a particular project and may
have rollers mounted to ease the torque.
More often than not, the centralization is
by means of a barrel reamer or bullet-nose
reamer.
Purpose and application. A constant problem in horizontal drilling is the tear-drop
effect you get when reaming a hole, especially when several passes are required.
The normal tendency, without centralization, is for the drill pipe in front of the
cutter to drop to the bottom of the hole,
which prevents the cutter from cutting a
concentric hole. Centralizers are used to
hold the center of the primary cutter up in
the center of the previously reamed hole.
Stabilizers. Stabilizers, like centralizers,
can be specifically fabricated for a project,
but often barrel reamers or bullet-nose
reamers are used to stabilize the primary
cutter.
Purpose and application. If you are reaming a large hole (30 in. [762 mm] or more)
without stabilization, the center of the drill
pipe is a minimum of 15 in. (380 mm)
above the bottom of the hole. The weight of
the drill pipe during rotation causes the fly
cutter or hole opener to tilt backward,
reducing its cutting efficiency. By adding a
stabilizer behind the fly cutter, the tilt of the
fly cutter is eliminated.
You will notice when you remove the stabilizer that there is more wear on the end
away from the fly cutter. This is because
the stabilizer is being weighed down by the
trailing drill pipe.
Hole openers
When the HDD industry first experimented
with rock crossings in 1980, the existing
tools, which were built for vertical use,
could not endure the side loading inherent
in horizontal drilling.
Due to the cost, time required, and lack of
interest on the part of the tool companies to
modify their tools, it was almost seven
years before another rock crossing was
attempted. During this seven-year period,
no change was made to the tools required
to enlarge the holes or to the bits used for
drilling the pilot holes. Eventually, as more
and more river crossings were attempted in
rock, modifications were made to the hole
openers to improve their performance and
longevity.
Hole openers are reaming devices used to
enlarge holes in rock formations. A hole
opener consists of roller cones mounted on
shafts or pins. The number of cones ranges
from three on the smaller hole openers to
six on the larger hole openers. The cones
revolve around the center shaft as the hole
opener is rotated. As weight and rotation
are applied, the cones rotate in the opposite
direction of the drill pipe. The rock is fractured under the weight and movement of
the cones and the teeth.
Purpose and application. The purpose of
the hole opener is to enlarge a hole from
any given size to a size of greater diameter
when the formation consists of rock of
varying strengths.
Nozzle sizing and configuration. Jet nozzles on a hole opener clean the cutters by
creating turbulent fluid action at the face of
the rock being cut, forcing the cuttings
away from the face. In some cases, the jet
nozzles also aid in the cutting action.
For nozzle sizing, you must determine the
volumes that you will be pumping, calculate the pressure drop at the nozzle (assume
a size), and the line loss in your drill pipe.
If the result is a pressure that you can
accommodate, you need not change the
nozzle size. If the pressure you calculated
cannot be accommodated, increase the size
of the jets and recalculate.
4-13
Horizontal Directional Drilling Training Program
Hydraulics
Annular velocities and flow rates
Nozzle selection is based on proper hole
opener hydraulics calculations. Some generally accepted rules of thumb are used to
help with the calculations. For example,
basic guidelines for minimum annular
velocities and flow rates for efficient cleaning of large-diameter holes are shown in
Table 4.2. These values should be considered only guidelines, since operators and
contractors have developed their own minimum flow rates and annular velocities
based on their experience. When viewing
the chart, you will see that these numbers
will be very difficult to attain.
Table 4.2. Minimum annular velocities and
flow rates for cleaning large-diameter holes
(metric and US units).
Hole size
(mm)
Annular
velocity
(m/min)
Flow rate
(m3/min)
445
660
914
1067
18–21
14–17
8–11
6–8
2.650
4.540
4.920
5.390
Hole size
(in.)
Annular
velocity
(ft/min)
Flow rate
(gal/min)
17 1/2
26
36
42
60–70
45–55
25–35
20–25
700
1200
1300
1425
Weight and rotary speed
The weight and rotary speed recommendations for hole openers are found in Table
4.3. Again, you will probably deviate from
these numbers in actual reaming. When
using Table 4.3, keep in mind that these
numbers are for vertical drilling where they
can put an exact weight on the bit. Since
you will be drilling in a horizontal position,
your calculations will be different.
Table 4.3. Weight and rotary speed recommendations for hole openers
(metric and US units).
Size
Soft shale
Rotary
Weight
speed
Metric units (weight x 1000 kg)
445
4.5/6.8
50/90
660
6.8/11.4
45/80
711–762
9.0/15.9
50/70
813–914
9.0/15.9
40/60
965–1067
9.0/15.9
30/50
Size
Soft shale
Rotary
Weight
speed
US units (weight x 1000 lb)
17 1/2
10/15
26
15/25
28–30
20/35
32–36
20/35
38–42
20/35
4-14
50/90
45/80
50/70
40/60
30/50
Medium shale
Rotary
Weight
speed
Hard limestone
Rotary
Weight
speed
6.8/11.4
11.4/15.9
13.6/50
13.6/50
13.6/50
9/13.6
13.6/5
15.9/60
15.9/60
15.9/60
40/70
35/55
35/50
30/45
30/40
Medium shale
Rotary
Weight
speed
15/25
25/35
30/50
30/50
30/50
40/70
35/55
35/50
30/45
30/40
25/45
25/40
15/30
15/30
10/25
Hard limestone
Rotary
Weight
speed
20/30
30/5
35/60
35/60
35/60
25/45
25/40
15/30
15/30
10/25
Reaming: Hydraulics
Size of completed reamed pathway
The rule of thumb in determining what size
hole to ream is 1.5 times the diameter of the
pipe. However, because of the pipe sizes,
you will not always have a reamer that is
exactly 1.5 times the pipe diameter. You
may have a reamer that is 1.3 times larger
and one that is 1.7 times larger. In normal
conditions, use the one that is more than
1.5 times larger. If you have reamed
through material such as gravel, consider
making one pass larger than the rule to give
the pipe a little more freedom in the hole.
Penetration rates
Penetration rates are largely determined by
the pumping capacity you have onsite.
There is a direct relationship between
pumping and the rate at which you can
penetrate. The relationship between reaming and pumping is one of the most
important relationships in drilling. If you
pump too little, in most cases you will stick
your pipe. If you pump too much, you can
fracture the formation, cause a washout in
the hole, or simply waste your time and
effort by mixing and pumping more than is
required.
Stated another way, penetration rates are
directly related to the amount of material
you are trying to remove from the pathway.
The amount of material that can be
removed from the pathway depends on the
quality and volume of the drilling fluid.
The quality of the drilling fluid is discussed
later in this chapter (page 4-17).
Assuming that the quality of the drilling
fluid is adequate, the optimum percentage
of cuttings that can be removed by the fluid
is approximately 20%. This means the only
way to safely increase penetration rates is
to increase the quantity of fluid that is
pumped during the reaming process.
This figure of 20% has become the basis
for establishing reaming rates. After determining the amount of solids to be removed
and the pumping capacity, your penetration
rates can be calculated.
For example, if you plan to ream a 762-mm
(30-in.) hole, calculate the volume of one
linear foot of hole:
0.762 2 × π ⁄ 4 = 456 liters of solids per
linear meter of hole (4.91 ft3 per
linear foot)
If your maximum pumping capacity is 954
l/min (6 bbl/min), you must calculate the
ratio of solids/pumping capacity:
456/954 = 47.8%
Remember it was stated that you can penetrate at a rate where the solids do not
exceed 20%.
20/47.8 = 0.42 m/min (1.37 ft/min)
These calculations tell you that if you are
going to ream a 762-mm (30-in.) hole and
your maximum pumping capacity is 954 l/
min (6 bbl/min), you should not penetrate
at a rate faster than 0.42 m/min (1.37 ft/
min).
Table 4.4 will help you determine your
allowed penetration rates. First, look under
Hole Diameter for the size you want to
ream. Then, go down the left side of the
chart until you find your maximum pumping capacity. Draw your finger across the
chart until you find a number that is 20% or
just below 20%. Now go up the column to
find your Rate of Penetration. For the
example above, you will see that 1.5 ft/min
is too fast and 1 ft/min is not fast enough.
The charts make it easier to quickly determine the penetration rates.
4-15
Horizontal Directional Drilling Training Program
Table 4.4. Penetration rates chart.
Hole
Hole
diameter radius
(in.)
(ft)
Rates of
penetration
(ft/min)
ft3 of
material
bbl/ bbl in
min
ft3
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
5.61
11.23
16.84
22.46
28.07
33.69
39.30
44.92
50.53
56.15
61.76
67.38
72.99
78.61
84.22
89.84
95.45
101.07
106.68
112.30
117.91
123.53
129.14
134.76
140.37
Enter
30
1.25
0.5
1
1.5
2
2.5
3
3.5
4
4.5
5
5.5
2.45
4.91
7.36
9.82
12.27
14.73
17.18
19.64
22.09
24.54
27.00
393%
197%
131%
98%
79%
66%
56%
49%
44%
39%
36%
33%
30%
28%
26%
25%
23%
22%
21%
20%
19%
18%
17%
16%
16%
437%
219%
146%
109%
87%
73%
62%
55%
49%
44%
40%
36%
34%
31%
29%
27%
26%
24%
23%
22%
21%
20%
19%
18%
17%
481%
240%
160%
120%
96%
80%
69%
60%
53%
48%
44%
40%
37%
34%
32%
30%
28%
27%
25%
24%
23%
22%
21%
20%
19%
Percentage of cuttings removal
44%
22%
15%
11%
9%
7%
6%
5%
5%
4%
4%
4%
3%
3%
3%
3%
3%
2%
2%
2%
2%
2%
2%
2%
2%
87%
44%
29%
22%
17%
15%
12%
11%
10%
9%
8%
7%
7%
6%
6%
5%
5%
5%
5%
4%
4%
4%
4%
4%
3%
131%
66%
44%
33%
26%
22%
19%
16%
15%
13%
12%
11%
10%
9%
9%
8%
8%
7%
7%
7%
6%
6%
6%
5%
5%
175%
87%
58%
44%
35%
29%
25%
22%
19%
17%
16%
15%
13%
12%
12%
11%
10%
10%
9%
9%
8%
8%
8%
7%
7%
219%
109%
73%
55%
44%
36%
31%
27%
24%
22%
20%
18%
17%
16%
15%
14%
13%
12%
12%
11%
10%
10%
10%
9%
9%
262%
131%
87%
66%
52%
44%
37%
33%
29%
26%
24%
22%
20%
19%
17%
16%
15%
15%
14%
13%
12%
12%
11%
11%
10%
306%
153%
102%
76%
61%
51%
44%
38%
34%
31%
28%
25%
24%
22%
20%
19%
18%
17%
16%
15%
15%
14%
13%
13%
12%
350%
175%
117%
87%
70%
58%
50%
44%
39%
35%
32%
29%
27%
25%
23%
22%
21%
19%
18%
17%
17%
16%
15%
15%
14%
Pumping
The relationship between penetration rates
and pumping is the most important in this
business. Learn to constantly monitor what
you are pumping and you will be able to
head off potential problems with your hole.
Make everyone on the site aware of what is
4-16
going on and train them to notify someone
when there is a deviation from the normal.
Fig. 4.9 shows typical mud pumps in
operation.
Reaming: Hydraulics
Fig. 4.9. Mud pumps.
Velocity/annular velocity
This topic is divided to demonstrate the
benefit of velocity when a pipe is inserted
into the hole. By doing this, the differences
between vertical drilling and horizontal
drilling and the role velocities play will be
demonstrated.
The original cleaning systems adopted
from the vertical drilling industry were not
designed to cope with the high-viscosity
fluids that are common to horizontal drilling. The main reason is that in vertical
drilling, velocity plays a much bigger part
in cleaning the hole than viscosity does.
The cuttings that might fall during a connection will only fall a few centimeters or
meters, and are immediately picked up
when the pumps are started after the connection is made. In horizontal drilling,
viscosity is kept higher to prevent the cuttings from settling to the low side of the
hole, which is only a few centimeters away.
The cuttings must be kept in suspension so
that they can be circulated out of the hole at
a much lower velocity. In addition, most
horizontal drilling projects are based on 12hour single-shift work, and the drilling
fluid must be capable of holding the cuttings in suspension during the work
stoppages.
Refer to the velocity chart (Table 4.5) to
understand the relationship between hole
sizes and velocities. In the chart, you can
see the tremendous differences in vertical
cleaning and horizontal cleaning. To illustrate these differences, assume an average
velocity in vertical drilling of 18 m/min
(60 ft/min). You will quickly see from the
charts how difficult it is to achieve these
numbers in horizontal drilling.
Refer to Table 4.5 for a 762-mm (30-in.)
diameter hole. At the bottom of the page,
you see that at 6.4 m3/min (40 bbl/min), the
velocity is only 13.9 m/min (45.75 ft/min).
You need to pump more than 7.9 m3/min
(50 bbl/min) to reach a velocity of 18 m/
min (60 ft/min). Assuming that you install
a 508-mm (20-in.) pipe in this hole, you
still need to pump more than 4.7 m3/min
(30 bbl/min) to achieve a velocity of 18 m/
min (60 ft/min). Even though it is possible
to pump this amount, it is not economically
feasible to have that much pumping capacity onsite.
Lost circulation and its effects on velocity
must also be addressed. It is rare to complete a crossing without having lost
circulation at some point in the crossing.
When this happens, there is a section of the
hole where velocity is zero. To reiterate, the
drilling fluid must be capable of holding
these cuttings in suspension until the subsequent pass when they can be circulated
out of the hole.
4-17
Horizontal Directional Drilling Training Program
Table 4.5. Velocity chart.
Hole diameter
(in.)
Hole radius
(ft)
Volume of 1 ft
of hole
30
1.25
4.91
(bbl/min)
(ft3)
(ft/min)
(ft/sec)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
5.61
11.23
16.84
22.46
28.07
33.69
39.30
44.92
50.53
56.15
61.76
67.38
72.99
78.61
84.22
89.84
95.45
101.07
106.68
112.30
117.91
123.53
129.14
134.76
140.37
145.99
151.60
157.22
162.83
168.45
174.06
179.68
185.29
190.91
196.52
202.14
207.75
213.37
218.98
224.60
1.14
2.29
3.43
4.58
5.72
6.86
8.01
9.15
10.29
11.44
12.58
13.73
14.87
16.01
17.16
18.30
19.45
20.59
21.73
22.88
24.02
25.17
26.31
27.45
28.60
29.74
30.88
32.03
33.17
34.32
35.46
36.60
37.75
38.89
40.04
41.18
42.32
43.47
44.61
45.75
0.02
0.04
0.06
0.08
0.10
0.11
0.13
0.15
0.17
0.19
0.21
0.23
0.25
0.27
0.29
0.31
0.32
0.34
0.36
0.38
0.40
0.42
0.44
0.46
0.48
0.50
0.51
0.53
0.55
0.57
0.59
0.61
0.63
0.65
0.67
0.69
0.71
0.72
0.74
0.76
Enter
4-18
Reaming: Hydraulics
Viscosity
Viscosity plays an important role in horizontal drilling. Learn to perform the proper
tests and be on top of the fluid situation at
all times. Train your personnel to keep the
viscosity at whatever level you prescribe.
The technicians on the tanks should take
readings about every 15 min (with a Marsh
Funnel) and report to you every hour. By
recording these readings and your pumping
data, you will quickly learn the ratios of
bentonite to water for your different
applications.
Acceptable yield point
Yield point (YP) can range from singledigit numbers up to perhaps 60 cp. Look
for a number that is two to three times the
number for plastic viscosity (PV). For
instance, if you are recycling on a large
project, you might start with readings of 45
for YP and 12 for PV. These are very good
readings that show a high capacity for carrying the solids out of the hole. However, if
you do not add bentonite, you will see over
the next few days that the readings may
change to 30 YP and 30 PV. At this point,
you should consider dumping and replacing and, at the very least, adding
considerable bentonite to raise the YP.
The YP and PV are determined by a rheometer. You should require your technicians to
perform rheometer tests on the fluid at least
twice per shift. By performing these tests
on a regular basis, you can correct any deficiencies in the drilling fluid before the
problem gets out of control.
Acceptable plastic viscosity
PV is an indicator number that tells you the
ratio of fine solids in your fluid relative to
the amount it can carry. These numbers are
derived from rheometer tests.
Sand content
Know the sand content of your fluid at all
times. Sand can enter the system either
through the water source or from the cuttings in the fluid. Your technician can give
you these numbers by using a sand content
testing unit. The test takes about 2 min and
should be performed and logged at least
once per hour.
Your recycling equipment should keep
your sand content below 0.5%. You should
not attempt to pump the fluid through your
pumps if the sand content is above 1%,
because you will damage your pumps.
4-19
Horizontal Directional Drilling Training Program
Troubleshooting
General
There are many problems you can encounter while drilling, and the following
sections cover a few of them. For general
troubleshooting:
1. If fluid is not passing through the
cones, replace or adjust where applicable.
2. If you get a low pressure reading,
check in the following order: tank
level, suction plugging, and pump. If
everything checks to the pump, first
check the packing and, finally, the
impeller for wear.
Increasing torque
The most common reasons for increased
torque are listed below.
3. Ask them to make sure the pipe outside
the hole is not restricted from turning.
Increasing torque—a few seconds. If you
experience rapid increase in torque, contact
the opposite side immediately to determine
if any of the following might be the cause:
4. Check the fluid viscosity.
1. Check to make sure a pump has not
gone offline (the mud gauge should be
constantly monitored).
Increasing torque—sudden lockup. STOP
EVERYTHING! Contact the opposite side
to determine if everything is normal (someone can inadvertently close the vice or
tongs).
2. Check the pilot hole data to make certain there is no unusual bend at this
section of the hole. This should have
already been checked and marked on
the reaming sheet as a section in which
to expect possible increased torque.
3. Check the pilot hole data to see if this
area was marked hard or difficult (if so,
it should have been flagged on the
reaming sheet).
Increasing torque—several minutes. If
the torque increases over several minutes:
1. First, contact the opposite side to determine if they are doing anything differently.
2. Ask them to check the swivel.
5. Switch to a crossover filter and check
the used filter.
1. Alluvial materials: STOP AND MAKE
CONTACT! Lockup is much less
likely to happen in alluvial soils and,
for this reason, is usually more serious.
If the cause is not above-ground, you
have probably hit something in the
pathway.
2. Rock: This is a common occurrence in
rock reaming, but you should never
overlook or expect it. Continue to contact the opposite side every time lockup
happens. Normally, you can pull or
push while trying to turn and it will
free itself. However, there are times
that the opposite side will need to pull
you back to free the reamer.
Twistoff of drill pipe
When a twistoff occurs, STOP IMMEDIATELY. Assemble all the decision-makers
in the control cab and discuss all the
options. If you attempt to go fishing, log all
pertinent information, mark a reference
4-20
point on the rig, and measure all the pipe
that comes out of the hole. You will want to
know, to the centimeter, exactly where your
fish is when you go back in the hole.
Reaming: Troubleshooting
Fishing
Fishing is very difficult, at best, in HDD.
When the break occurs, the fish falls to the
bottom of the hole or to the side of the hole.
If the soils are soft and you plan to use an
overshot, you will have great difficulty just
getting the tool to the fish, much less getting it over the fish. The same is true for a
taper tap—just getting it to the fish is a
major hurdle.
Generally, you have less than a 50% chance
of getting the tool to the fish, and if you do,
you have less than a 50% chance of getting
on the fish and reestablishing contact
between the two sides. If the separation
occurred during the pilot hole, it is
extremely difficult to salvage. A fishing
operation is shown in Fig. 4.10.
Fig. 4.10. A fishing tool completing a
pullback.
Recovery
This section concerns reaming, where you
will have pipe sticking out both sides of the
crossing. This gives you many options, a
few of which are covered below.
Salvaging hole. The first order of business
after a twistoff is to stop all work and discuss all the options. The options available
will depend on where the pipe has
separated.
Usually the separation will occur between
the reamer and the drilling rig providing
the rotation, but it can also occur on the
other side of the reamer. The following is a
discussion of the different types of separations and possible remedies.
One remedy is to use one rig pulling the
reamer toward the rig from the pipe side. If
the separation occurs between the reamer
and the rig, you will know it by the lack of
torque required to turn the drill string, the
carriage surging back, and the mud pressure dropping. First, cease all operations.
Try to determine what events happened just
before the separation. If the drill pipe on
the pipe side was spinning and stopping
erratically, it is possible that the pipe in
front of the reamer just unscrewed. Attempt
to move the pipe slowly forward away from
the rig while rotating. If the pipe has
become unscrewed, you may be able to
screw back into the pipe. If these efforts are
not successful and the separation is close to
the pipe side, you may be able to retract the
reamer with conventional equipment without rotating, and reestablish your hole by
pushing the pipe from the drilling rig while
pulling the reamer.
As a last resort when salvaging the hole,
consider moving the drilling rig to the pipe
side of the river and retracting the reamer
using the drilling rig. If you choose to exercise this option, retract the pipe on the rig
side and determine where the break
4-21
Horizontal Directional Drilling Training Program
occurred. After you have removed the drill
pipe and reamer, you will have to move the
drilling rig back to the rig side and reestablish the hole by pushing a floater back
through the pathway. Once this is accomplished, you can continue reaming. A
floater is a blunt-nosed assembly on the
end of the drill string. This assembly has a
large blunt nose with holes cut in it through
which you will pump small amounts of
drilling fluid. Because it is somewhat
rounded on the end, it is possible to push
the assembly through a pre-reamed pathway without sidetracking. This assembly
works about 70% of the time, and works
best in more consolidated materials.
ing fluid from the opposite side of the river
as the equipment is configured. Consequently, you will not be able to remove the
reamer. In this event, salvage as much of
the pipe between the surface and the
reamer as possible.
If, while reaming and pulling to the drilling
rig, you separate behind the reamer, stop all
operations and try to determine what
caused the separation. This type of separation will only be noticed on the pipe side.
The pipe will stop rotating and pulling into
the pathway. On the rig side, it may be that
nothing will appear to have changed. The
chances of pushing the reaming assembly
and the pipe back into a joint that has
become unthreaded are minimal. However,
it is still worth trying. More than likely
your best option will be to continue the
ream until the reamer has exited on the rig
side. The drill pipe on the pipe side of the
reamer can be removed using conventional
equipment. Once the ream is completed, try
to reestablish the hole, again using the
floater assembly.
If you have two drilling rigs available during the reaming process, a lot of time can
be saved in the event of a pipe separation.
If the break is in front of the reamer, the rig
at the exit side can rotate the reamer and
withdraw the pipe to the exit side. At the
same time, the rig at the entry side can add
joints and follow the reamer out to the exit.
If the break is behind the reamer and plug,
the rig at the entry side can withdraw the
pipe while the rig at the exit side is adding
joints and following with the pipe out of
the hole. If the break is between the reamer
and the plug, the reamer must be pushed
out by the rig at the entry point, while the
rig at the exit point withdraws only fast
enough to stay just ahead of the reamer.
Constant communication must be maintained between the two rigs. If you are
unable to follow the reamer out in either of
the above situations, you can still use the
floater assembly to reestablish the pathway.
If the separation occurs while you are
reaming away from the drilling rig, but
between the drilling rig and the reamer, you
should stop all operations. This type of failure will be noticed on the drilling rig side
by loss of torque and loss of mud pressure.
On the pipe side, the crew should notice
that the pipe has stopped rotating. Gather
all the information just prior to the mishap
and try to find out how the separation
occurred. If you assume that the pipe
became unscrewed you can attempt to
screw back into it, but you will have little
chance of success. You can attempt to
secure and use fishing tools, but again,
because of the size of the hole, your
chances will not be very good.
Because of the pipe plug in front of the
reamer, you will not be able to pump drill4-22
If, while reaming away from the rig, the
pipe separates in front of the reamer, stop
all operations and analyze the situation. In
all probability, you will have to retract the
reamer to the rig side and pull the remaining drill pipe out on the pipe side. At this
point you can either take the rig to the pipe
side or resign yourself to redrilling the pilot
hole.
If the attempt to reestablish the hole in any
of the above situations is unsuccessful, you
will be forced to move the rig and redrill
the pilot hole, starting from scratch.
Severing drill pipe. If you decide to redrill,
you want to recover all that is salvageable.
If the reamer itself is stuck, you must try to
recover everything up to the reamer, on
both sides.
Many companies prefer to twist the pipe
off and recover whatever they can, as
opposed to placing a shaped charge and
severing the pipe at a predetermined point.
However, if you happen to be stuck 3000 ft
Reaming: Troubleshooting
from the rig and you twist off just below
the ground, you have made a bad decision.
Base your decision on economics.
Lost or decreased circulation
Most project managers tend to neglect
decreased or lost circulation with the mindset that there is not a lot they can do, or that
to try to rectify the situation is only a waste
of time. This thinking is in error and irresponsible. Your risks are greatly reduced
when you are successful in maintaining circulation. It is true that you can be
successful even when you lose circulation,
but your chances are greatly increased if
you maintain returns.
Train your personnel to watch the return pit
so that they can immediately notify super-
visors of any decrease in returned drilling
fluid. If you are using a recycling system,
you will quickly notice that you are getting
less back than you are pumping. The level
in the recycling tank will drop and it should
be noticed in time to prevent total loss.
When a reduction in returns is noticed,
make every effort to regain the lost fluid,
even if it means tripping all the way out of
the hole. It is understood that you want to
progress and do not like to pull back, but
regaining circulation will help you later on.
Stuck reaming assembly
If the reaming assembly becomes stuck and
you are in a rocky formation, you should be
able to free it up with enough time and
effort. If the reaming assembly becomes
stuck in gravel or as a result of a gravel collapse, you probably will not be able to free
it. If you become stuck in sandy soils, you
must free it quickly or you might be unable
to free it.
If you are using a rig on each side of the
river and the reamer becomes stuck in rock,
you have the advantage of turning the
reamer in both directions, first from one
side and then the other. Also, you can pull
from either side while the opposite rig
applies the torque. While doing this, pump
high-viscosity sweeps, which can sometimes aid in extricating the reamer or pipe.
Mud pressure increase
If there is a mud pressure increase, the
probable causes are:
•
the pump(s) have been throttled up
•
the viscosity has increased
•
the reamer nozzles are restricted
•
the borehole has packed off and you
are about to fracture the formation.
If the increase is caused by the pumps or
viscosity, the problem is easily solved. If
the problem is caused by either the jet nozzle(s) or the borehole packing off, you will
be able to distinguish between the two.
When the borehole packs off, the pressure
increase will be less than 20 psi (140 Kp).
When a jet nozzle is restricted, the increase
will likely be 50 to 200 psi (350 to 1350
Kp). Check to make sure the filter does not
have a rupture or tear that is allowing pebbles to pass unobstructed down the hole.
Mud pressure decrease
If there is a mud pressure decrease, the
probable causes are:
•
the pump is not being fed properly by
the mix tank
•
the pump drive has been throttled
down, or there is a problem with the
pump internally (if this is the case you
will usually hear the banging)
4-23
Horizontal Directional Drilling Training Program
•
the mud filter between the mix tank
and the pump is plugged
•
there is a washout downhole, usually at
the reamer.
Again, you should be aware of what is
going on around you and should be able to
say, within a few minutes, that the problem
is downhole. You must determine whether
or not to make a trip, depending on where
you are in the hole.
Inadvertent returns
Normally, inadvertent returns are caused by
either overpenetrating or overpumping. You
can cause this by not letting the clues tip
you off to the potential problems. For
instance, you may gradually increase your
viscosity until you are over 250 sec, and
then notice that when disconnecting from a
joint, the pressure is escaping through the
open end of the drill pipe. At the same
time, while removing a joint from the rig,
you notice that the fluid cannot even run
out of the pipe because it is so thick. If you
are not using polymers, you are exerting a
tremendous pressure on the formation and
it may not be able to withstand the
pressure.
Another cause of inadvertent returns is the
following: You dig a mud pit in front of the
rig and call it an entry pit. When you spud
in the bottom of the pit, the return fluid
comes back through the hole at a certain
velocity and enters the pit, and the velocity
drops immediately to zero. The cuttings
drop out in the bottom of the pit and, over
time, will plug the entry hole. It can and
will build up to the point that the fluid can
no longer push through it, and will instead
surface at some other point where the
ground is weaker. This happens many
times. If you have the space, it is better to
dig your pit to the side of centerline so that
the fluid can continue to move until it is
away from the entry hole.
Reduced penetration rate
Reduced penetration rates are caused by
many things:
1. The most common cause is that the formation has changed to a harder formation. The notes from the pilot hole
should mention if this is the case. If
increasing the force on the cutter creates too much torque, you will probably have to accept the slower
penetration rates.
2. If the Kennemetal teeth, cutter blades,
or inserts on hole openers or reamers
become worn, the penetration rate will
naturally decrease. Depending on the
amount of reaming left, you must
decide whether to trip out the assembly
and replace or repair it before continuing with the reaming.
3. If you are not applying enough force
against the face of the formation, penetration rates will decrease. To correct
this, you must apply more force.
4-24
4. If your rotary speed is too slow, the
penetration rate will probably be
reduced. If possible, increase the rotary
speed to remedy this situation.
5. When reaming in rock formations and
in some alluvial formations with very
abrasive soils, sometimes the gauge of
the reamer is worn down to the extent
that the outside wall of the reamer
begins to be pinched by the side of the
reamed pathway. This can increase
torque and consequently reduce your
penetration rate. Depending on how
much reaming remains, you may opt to
trip the assembly out of the hole and
repair or replace the reamer or cutters.
6. If the pumping volume/pressure relationship changes, the penetration rate
may be reduced.
7. The pressure loss may be the result of
less fluid being pumped or the jet nozzles on the reamer being washed out. If
it is the jet nozzles, decide whether to
proceed at a slower rate or trip the
Reaming: Troubleshooting
assembly and repair or replace the jet
nozzles.
8. In clay, the reamer or hole openers will
sometimes ball up. This results from
the adhesive material filling all the
areas between the teeth or cutter
blades. This material can become so
tightly packed that the protruding teeth,
blades, or inserts cannot make sufficient contact with the face of the pathway you are cutting. Progress will
gradually come to a halt, once the clay
material is simply rubbing against the
wall of the pathway. There are some
additives that can be injected into the
mud to prevent balling, but not many of
them work after the fact. The best solution is to trip the reamer or cutter and
clean it on the surface. Then use the
additives when proceeding with the
reaming to prevent balling.
4-25
Horizontal Directional Drilling Training Program
Notes
4-26
Chapter 5: Pullback
Pipeline................................................................................................ 5-1
General .............................................................................................................. 5-1
Steel pipeline...................................................................................................... 5-1
Pipe diameter....................................................................................................................5-1
Pipe wall thickness ...........................................................................................................5-1
Buoyancy control..............................................................................................................5-1
Coatings............................................................................................................................5-3
HDPE pipe ......................................................................................................... 5-3
Standard Dimension Ratio ...............................................................................................5-3
Buoyancy control..............................................................................................................5-4
Soils..................................................................................................... 5-4
Clay .................................................................................................................... 5-4
Sand................................................................................................................... 5-4
Rock ................................................................................................................... 5-4
Mud Program ...................................................................................... 5-5
Drilling fluids....................................................................................................... 5-5
Volumes ............................................................................................................. 5-5
Fluid control........................................................................................................ 5-5
Disposal ............................................................................................................. 5-5
Pulling Assistance ............................................................................. 5-6
Support equipment............................................................................................. 5-6
Breakover or overbend....................................................................................... 5-6
Pulling support ................................................................................................... 5-8
Pulling Program.................................................................................. 5-8
BHA.................................................................................................................... 5-8
Pulling speed...................................................................................................... 5-8
Pulling loads....................................................................................................... 5-8
Pulling across the bottom of the profile and the pull increases with every joint .............5-9
Pulling across the bottom of the profile and the pull suddenly increases........................5-9
Pulling through the exit side vertical curve and the pull increases with every joint .......5-9
Pulling through the exit side vertical curve and the pull suddenly increases ..................5-9
Pulling and the pull suddenly decreases ..........................................................................5-9
Salvaging Stuck Pipe ......................................................................... 5-9
List of Figures
Fig. 5.1. Buoyancy control with styrofoam cylinder. ...................................................... 5-2
Fig. 5.2. Buoyancy control with HDPE pipe. .................................................................. 5-2
Fig. 5.3. Pipeline with Powercrete coating. Providence, Rhode Island, USA. ................ 5-3
Fig. 5.4. Breakover or overbend. ..................................................................................... 5-7
Fig. 5.5. Gravel shield reamer. .................................................................................. 5-8
Notes
ii
Chapter 5: Pullback
Pipeline
General
The final objective when planning, designing or executing a horizontal directional
drilling (HDD) project is the installation or
pullback of the pipeline or pipelines (bundle). To properly plan a directionally
drilled crossing, you must know the diameter, wall thickness, and type of pipe
material to be installed, and the types of
soils that will be encountered. This chapter
discusses the factors you should consider
when installing steel pipeline, concretecoated pipe, and high-density polyethylene
pipe (HDPE).
Steel pipeline
Steel pipelines are manufactured in various
diameters, wall thicknesses, and grades of
steel. Each of these components should be
considered when planning a directionally
drilled crossing. The difficulty of directionally drilled crossings increases geometrically with increasing diameters and
installation lengths.
Pipe diameter. The pipe diameter is crucial
when designing a directionally drilled
crossing. The larger the pipe diameter, the
larger the radius required to facilitate the
installation and limit the amount of stress
on the outer fiber of the pipe. The minimum radius should be 100 ft (30.5 m) for
each diameter inch (25.4 mm). Therefore, a
pipeline with a diameter of 30 in.
(762 mm) would warrant a minimum
radius of curvature of 3000 ft (91.5 m).
This design will limit the amount of stress
on the pipe once the installation is complete. This is discussed in greater detail in
Engineering (Chapter 2).
Pipe wall thickness. The pipelines proposed for directional drilling should have a
diameter-over-thickness ratio of 50 or less.
The reason for specifying a minimum
diameter-over-thickness ratio is to prevent
pipe collapse during the installation. Largediameter pipelines with thinner walls can
collapse under the pulling stresses, as well
as the external pressure of the hydrostatic
head of the drilling fluid around the pipe.
Buoyancy control. In any directionally
drilled crossing, one of the main considerations of the pullback is the weight of the
pipe in the pathway and the associated
force necessary to overcome this resistance. Obviously, the heavier the pipeline,
the more difficult the operation. When
installing large-diameter pipelines, the
buoyancy of the pipe in the fluid creates
more resistance than the gravitational
weight of the pipe. To successfully install
large-diameter pipelines, you must consider the weight and buoyancy of the pipe.
If the pipe is too buoyant, consider adding
weight to the pipe.
The preferred method for combating buoyancy is to add water into large-diameter
pipelines during the pullback operation.
The simplest method is to pump water
directly into the pipe through a filler line or
pipe. This water is pumped into the pipeline as it goes below the ground surface
without adding weight to the pipe on the
surface. The problem with this method is
that you have no control over the distribution of the water, and you may end up with
too much water at one point and not
enough at the higher elevations.
There are several different means of controlling the water distribution. One method
is shown in Fig. 5.1. Styrofoam cylinders
are placed inside the pipe at specified intervals, with a filler pipe running through the
center and water filling the space between
the styrofoam and the pipe. Another
method is shown in Fig. 5.2. Smaller-diameter HDPE pipelines can be placed inside
Horizontal Directional Drilling Training Program
the large-diameter carrier pipe and filled
with water as the pipeline is installed. The
latter of these two methods has been the
most successful. With a little planning, you
can essentially cause the large-diameter
Buoyancy force
pipelines to have a neutral weight in the
pre-reamed pathway, thereby significantly
reducing the amount of pull force that will
be required to install crossings.
1
Fig. 5.1. Buoyancy control with
styrofoam cylinder.
3
1 = Styrofoam cylinder
2
2 = Drill pipe
3 = Filler pipe
4 = Water
4
Weight
Concrete coating, although an excellent
means of achieving the additional weight
needed, can cause problems for the HDD
contractor. It increases the diameter of the
pipeline, which is generally large to begin
with. It may crack and break off during the
installation, possibly into the reamed pathway. In addition, its coarse exterior surface
will add resistance to the pullback effort,
1
and it is difficult to handle on the surface
because of its weight. In the future, these
disadvantages will be solved and concrete
coating will be the preferred choice for
decreasing the buoyant effect of largediameter pipelines. Until then, adding
water to large-diameter pipes to control the
effects of buoyancy is the easiest and most
effective method.
Buoyancy force
Fig. 5.2. Buoyancy control with
HDPE pipe.
1 = Carrier pipe
3
2 = HDPE pipeline
3 = Water
2
Weight
5-2
Pullback: Pipeline
Coatings. The main purpose of pipe coatings is to protect the pipe in place against
corrosion. The coatings should have a low
coefficient of friction so that they do not
adversely affect the installation. In most
instances in alluvial soils, the fusionbonded epoxy coating applied at a thickness of 0.8 to 0.9 in. (20 to 24 mm) is
sufficient for protection. However, in areas
with large concentrations of angular gravel
or in rock installations, additional protection is recommended. A rock shield coating
known as Powercrete® is compatible with
the fusion-bonded epoxy corrosion coating
(Fig. 5.3). Powercrete has a very low coefficient of friction and is applied over the
fusion-bonded epoxy. This combination of
coatings is the most effective for protecting
the pipelines during rock installations. In
Europe, polyethylene coatings (three-layer
or sintered) are also commonly used.
A more thorough discussion of coatings
can be found in the Engineering chapter
(page 2-20).
Fig. 5.3. Pipeline with Powercrete coating. Providence, Rhode Island, USA.
HDPE pipe
The use of HDPE pipe is increasing, especially for conduits, water lines, buoyancy
control, and environmental work. HDPE
allows you to drill much tighter radius
holes, and it will bend around buildings
and other surface structures. The forces that
are incorporated into steel pipeline pullbacks will not apply when using HDPE.
Standard Dimension Ratio. Standard Dimension Ratio (SDR) is the ratio of the
pipe outside diameter (OD) to the minimum thickness of the pipe wall. Phillips
Driscopipe, a manufacturer of HDPE pipe,
subscribes to the SDR method of rating
pressure pipe. It can be expressed mathematically as:
SDR = D/T
where:
D = Pipe OD in millimeters or inches
T = Pipe minimum wall thickness in
the same unit as D.
For a given SDR, the ratio of the OD to the
minimum wall thickness remains constant.
An SDR 11 means the OD of the pipe is 11
times the thickness of the wall. This
remains true regardless of diameter. For
example, a 14-in. (355.6-mm) diameter
pipe with a wall thickness of 1.273 in.
(32.3 mm) is an SDR 11 pipe. An 18-in.
(457.2-mm) diameter pipe with a wall
thickness of 1.637 in. (41.6 mm) is also an
SDR 11 pipe. Standard SDR ratios are 9.3,
11, 13.5, 15.5, 17, 19, 21, 26, and 32.5. For
5-3
Horizontal Directional Drilling Training Program
high SDR ratios, the pipe wall is thin compared to the pipe OD. For low SDR ratios,
the wall is thick compared to the pipe OD.
Thus, high SDRs correspond to low pressure ratings and low SDRs correspond to
high pressure ratings because of the relative wall thickness.
Buoyancy control. When installing an
HDPE pipe, fill the pipe with water during
the installation. This should be done with
pipe diameters greater than 10 in.
(254 mm) to prevent collapse from external
pressure.
During the installation, make sure that the
hole is clean and open to prevent pulling
the pipe apart because of the friction load
along the pipe’s exterior and the relatively
low tensile strength of the material. When
drilling in gravelly sands, ream the hole
oversized to allow more open space in the
hole.
Soils
A few of the soil types you will encounter
and the effects they have on the pipe are
discussed in this section. Additional infor-
mation on soils can be found in the
Reaming chapter (page 4-6).
Clay is the easiest of the soils to drill
through, being very predictable and easy to
manipulate. By the time you reach the pullback phase, you will be aware of the
characteristics of the clay through which
you have drilled and reamed. At this stage
you should be confident that you have
reamed the hole to the required diameter,
cleaned the hole by running a wiper or
swab pass, and planned your pullback,
complete with contingency plans for anything unexpected.
Sand is less predictable than clay, but can
be controlled by using proven reaming and
pullback methods. The biggest problem
with sand is that you do not have the freedom to shut down for extended periods of
time. This is because the longer the pullback is delayed, the greater the probability
that sand will settle out of the drilling fluid
around the pipe.
In rock, pullback will proceed much the
same as in clay if you have prepared for it
through your drilling and reaming practices. If the hole is reamed to the proper
size and is clean, your success should be
guaranteed. An exception is when drilling
through a weathered rock formation, which
may crumble and fall into the hole. If this
happens, your actions will depend on
whether the rock fragments fall in front of
the bullet nose or in front of the pipe. If you
are experiencing torque from the rock, continue and try to break it up. If they fall in
front of the pipe and cause your pull to
increase, it is better to pull the pipe back to
get the piece of rock in front of the bullet
nose.
Clay
Sand
Rock
5-4
Pullback: Mud Program
Mud Program
Drilling fluids
The drilling fluids chosen for the pilot hole
and reaming will also work for the pullback, except that you may want to add
extra lubrication. This can be applied
directly to the pipe or mixed with the fluids
you are pumping.
Volumes
The volume of drilling fluid you pump will
depend on how much hole cleaning is necessary. If you are reaming and pulling at
the same time, use the bottom’s up chart
that is used for reaming (page 4-4).
For large-diameter crossings, you can significantly reduce the volume pumped
because of the amount of fluid being displaced by the pipe. This is especially true
for clay or rock crossings where the holes
are normally very clean for pullback, and
less true for sand and sandy gravel
crossings.
For example, when pulling a 36-in.
(914-mm) pipe at the rate of 31 ft/min
(9.4 m/min), almost 40 bbl/min (6.4 m3/
min) of fluid is being displaced and exiting
the hole at one end or the other. In this
case, you are moving enough fluid through
the hole that very little is required to be
pumped through the bullet nose.
Fluid control
When executing an HDD crossing, it is
essential to maintain control over the drilling fluids being used. While you want to
have enough drilling fluids mixed so as to
avoid a shutdown, you do not want such an
excess of drilling fluids onsite that you
have to cease operations to control the
fluids.
Closely monitor the mixing of your drilling
fluids in a closed-loop system. You will
have to continually mix fluids while drilling forward and with each reaming pass to
account for the increase in the size of your
pathway—but guard against mixing too
much. Mixing too much fluid will be an
unnecessary expense during the installation
and can also cause additional cleanup
costs.
At each location, especially the largerdiameter and longer crossings, you will
need a certain holding capacity for excess
fluids. This holding capacity can be in the
form of mud pits or steel holding tanks.
Disposal
Although the drilling fluid used in the
HDD industry is not harmful to the environment, it can create a mess around the
drilling location and surrounding area if
not controlled. You will also have the problem of disposing of the excess drilling
fluid.
2000 ft (600 m) long by 30-in. (762-mm)
pipe. Onsite you have a return pit to collect
the return fluid, a 6-in. (150-mm) transfer
pump to transfer the fluid to the recycling
unit, two pumps to transfer the fluid
through the tank, and a pump to transfer the
fluid to the mix tank.
The following is a quick comparison of
practices and their resultant costs for a
sample project. This comparison is based
on one of the most common reasons you
might inadvertently build excess volume.
Assume you have a beach approach of
If any of these pumps are taken offline for
repair, the circulation through the loop
stops or the drilling or reaming must stop,
and you do not want to shut down the rig
for any reason. However, if the problem is
with the pump at the entry pit, you will
5-5
Horizontal Directional Drilling Training Program
usually have to shut down. The error here
was that there was no spare pump that
could be put online in a matter of minutes.
If the problem is with one of the pumps on
the recycling unit, the fluid is normally
diverted to holding tanks, water and bentonite are continuously added to the mixing
tank, and the rig continues to work. The
result is that you are building volume that
you must eventually use or dispose of. This
scenario is acceptable if there is sufficient
reaming remaining to use the volume to fill
the hole. Unfortunately, the volume in the
holding tanks is usually forgotten and even
added to.
At the pullback phase, the 42-in.
(1067-mm) hole is full of fluid, the entry
pit is full, the mixing tank is full, the recycling tank is full, and you do not know
when the fluid will start coming to the
entry side during pullback. What do you do
with the 30 bbl/min (4800 l/min) of fluid
that will be displaced by the pipe as it is
pulled in the hole at rates of 30 ft/min
(9.1 m/min), as well as the 5 to 8 bbl/min
(790 to 1270 l/min) that you will be pumping? The result is excess drilling fluid at the
entry, which will cost time and money to
clean up. These costs can be reduced or
eliminated through proper planning. By
keeping the excess volumes as low as possible, your disposal costs will be
minimized.
Pulling Assistance
Support equipment
As a drilling contractor, you must be
knowledgeable about the equipment
requirements on the pipe side of the crossing. Preferably, you will have experienced
pipe-handling personnel on the pipe side
who will prepare the carrier pipe for instal-
lation. Adequate equipment and personnel
to handle the pipe during the installation
process are essential to the successful
installation of a directionally drilled
crossing.
Breakover or overbend
Breakover or overbend is the bend through
which the pipe must pass from its horizontal position on the rollers to its alignment
with the hole (Fig. 5.4). This angle should
5-6
be as low as possible so that the pipe does
not require undesirable heights above the
ground to conform to the bend.
Pullback: Pulling Assistance
Fig. 5.4. Breakover or overbend.
For example, assume that you have a 30-in.
(762-mm) pipe to pull, the exit angle is 8˚,
and the minimum allowable radius is
1800 ft (550 m). The top of the overbend,
or the point at which the pipe is the highest
above-ground (assuming the ground is
level) is 17.5 ft (5.33 m); this point is 250 ft
(76.2 m) from the exit point. If the lifting
equipment is spaced 60 ft (18.3 m) apart,
four pieces of equipment will be required
to handle this section. Also remember that
the pipe behind the overbend must curve
back toward the ground, in a reverse curve,
until it rests on the rollers or in the flotation
ditch. This will require a minimum of three
pieces of equipment. To minimize the
equipment requirement, either lower the
exit angle, shorten the radius, or place most
of the overbend below-ground.
Assume you have the same 30-in.
(762-mm) pipe with the same exit angle
and are restricted to the same minimum
allowable radius. However, instead of placing the overbend from ground level to a
point 17.5 ft (5.33 m) above-ground, place
the overbend from a point 14 ft (4.3 m)
below the exit elevation to a point 3.5 ft
(1 m) above the ground elevation. The pro-
cedure is as follows, starting at pilot hole
completion:
When the pilot bottomhole assembly
(BHA) has exited, remove the BHA so
that nothing but steel drill pipe remains
in the hole. Strip back along the pipe to
the correct elevation point that places
the top of the pipe overbend at a level
equal to the top of your rollers. If you
plan to place sheet piling on both sides
of the pipe to prevent cave-ins, do this
now. Reference the point to which you
have dug with a survey so that you can
return.
You can now begin and complete all
phases of reaming. When you are ready
to place the pipe for pullback connection, place your rollers so that they are
at the proper elevations. When the pipe
is placed on these rollers, you will have
an overbend that begins 250 ft (76.2 m)
from the point at which you are 14 ft
(4.3 m) deeper than the exit elevation,
and it breaks over to lay on the rollers
in a perfect curve. The last roller will
be placed 60 to 70 ft (18.3 to 21.3 m)
from the point you originally surveyed
that is 14 ft (4.3 m) below the exit
5-7
Horizontal Directional Drilling Training Program
point. This results in the same configuration, the only difference being that it
is mostly below-ground and requires
no equipment to keep it in position.
Pulling support
As the lengths and diameters of crossings
increase, so will the need for assistance to
install the pipe. The assistance can be in the
form of dozers with winches or pulling
units that are anchored to allow maximum
pulling assistance from the opposite side.
Many of our crossings would not have been
successful without this assistance. In other
cases, failed crossings would have been
successful had assistance been obtained.
Pulling Program
BHA
For pullbacks, the conventional BHA consists of a bullet-nose reamer and an
exposed swivel connected to the pipeline
with shackles. An unconventional BHA,
called a gravel shield reamer (Fig. 5.5), was
introduced for rock and gravel crossings.
The basic difference in the gravel shield
reamer and the conventional pulling BHA
is that every part of the BHA is enclosed
except the reamer. The reamer can be a bullet-nose, fly cutter, barrel reamer, or hole
opener. The main purpose is to prevent any
large material from building up in front of
the pull head, which could hinder the pipe
pulling.
Fig. 5.5. Gravel shield reamer.
Pulling speed
If you have properly reamed and cleaned
the hole, you should be able to pull the pipe
as fast as your rig will travel. This is usually true even if you have a sandy or
gravelly soil to pull through.
Begin the first 100 or 200 ft (30 or 60 m) of
your pullback by pulling at reasonable
speeds, allowing the pipe to find its proper
position, which you will know by the
torque readings. If you are getting torque in
the first part of the hole where none was
expected, it is usually due to angle misalignment. This can be corrected by adding
water, removing water, slowing your pull,
or adjusting your breakover. When you are
certain that the pipe is properly aligned and
your torque has disappeared, pull the pipe
as fast as practicable.
Pulling loads
You will have some indication of what
pulling loads to expect prior to pullback,
but you will only know for certain once
you begin pulling. There are too many
5-8
unknowns to predict exactly what the loads
will be. Some of the nuances of pulling are
covered below, which should aid you in
diagnosing different situations.
Pullback: Salvaging Stuck Pipe
Pulling across the bottom of the profile
and the pull increases with every joint.
This situation is the most difficult because
you may have several hundreds of feet yet
to pull and you don’t know whether to stop
or continue. You must make that decision
based on how much you have pulled and
how much you have yet to pull. You can
determine what the pull might reach if you
project from the information you have.
For example, if the pull was increasing for
the past 15 joints at about 100 psi
(689 Kpa) per joint, observe the current
gauge reading. If the pull gauge was reading 1000 psi (6.9 Mpa) before the last 15
joints, and is now reading 2500 psi
(17 Mpa), determine whether your pull will
maximize if you continue. If you have only
15 joints remaining, you should continue.
If you have 30 joints remaining, you should
probably stop. There is no clear-cut answer
and it is something that you must determine onsite.
Pulling across the bottom of the profile
and the pull suddenly increases. It is possible you have experienced a sudden hole
collapse but, more than likely, something
has happened above-ground on the opposite side. You should immediately stop
pulling and contact the supervisor on the
exit side to ask if anything unusual has happened. The person at the return pit should
have reported by this time if circulation has
been lost.
If circulation suddenly stopped, you have
probably experienced a hole collapse and
only additional pulling will tell you if you
should continue. If you are in rock, it is
possible that a piece of rock has jammed
between the pipe and the outside of the
hole. If this is the case, you will continue to
have circulation. You should pull back a
short distance to try to release the rock that
has caused the jam and move it in front of
the reamer. If it is in front of the reamer,
you can try to keep skipping it forward
until it finds a place to fall out; however, it
may pass by the reamer and jam the operation again. You must make this
determination on the job.
Pulling through the exit side vertical
curve and the pull increases with every
joint. Usually, the pull will drop once you
are around the curve and into straight hole.
Pulling through the exit side vertical
curve and the pull suddenly increases. If
you have accepted a bend in one joint that
is greater than allowed, it should have been
marked as a place to slow the pull. If it was
not, check your data sheet. When it is a
bend, the torque will also increase.
Pulling and the pull suddenly decreases.
Stop and contact the exit side to see if they
have made any adjustment and if the pipe
was still moving when you stopped.
These are just a few of the possibilities that
can occur. Accumulate the facts and base
your decision on those facts, although there
will never be a standard response to every
conceivable problem. You must learn from
every situation and record the experience
for future reference.
Salvaging Stuck Pipe
In the case of stuck pipe, the first thing you
must do is gather all the facts. Have an
open discussion with everyone involved
and come to an agreement as to the best
course. Make a list of what you need to do;
determine what, if anything, you need to
mobilize; and proceed in an orderly
fashion.
Prepare a report for your client that
includes what happened, and what your
plan is for the short term and the long term.
Provide the client with a schedule of events
to demonstrate that you have the situation
under control. Be sincere in your dealings
with your employees, your subcontractor
or prime contractor, and your client.
Meet with your supervisors and begin discussing what the course of action will be if
you are unsuccessful in retrieving the pipe.
If additional right-of-way will be required,
now is the time to begin working on it.
5-9
Horizontal Directional Drilling Training Program
Notes
5-10
Chapter 6: Mud
Functions of a Drilling Fluid.............................................................. 6-1
Cooling and lubricating the drill string ................................................................ 6-1
Removing cuttings.............................................................................................. 6-1
Suspending and releasing cuttings .................................................................... 6-1
Forming a filter cake........................................................................................... 6-1
Providing geological information ........................................................................ 6-2
Protecting the formation ..................................................................................... 6-2
Transmitting hydraulic horsepower .................................................................... 6-2
Supporting the drill pipe weight .......................................................................... 6-2
Drilling Fluid Tests ............................................................................. 6-3
Mud weight......................................................................................................... 6-3
Viscosity: Marsh Funnel ..................................................................................... 6-4
Viscosity: Rotational Viscom .............................................................................. 6-5
Measuring YP and PV ......................................................................................................6-5
Gel strength ......................................................................................................................6-6
Filtration (low-temperature test) ......................................................................... 6-7
Sand content ...................................................................................................... 6-8
pH....................................................................................................................... 6-9
Chemical analysis ............................................................................................ 6-10
Clay Chemistry ................................................................................. 6-11
Basic chemistry ................................................................................................ 6-11
Atomic and molecular weights ......................................................................... 6-11
Valence and chemical bonds ........................................................................... 6-12
Dissociation and equivalent weights ................................................................ 6-12
Clay chemistry.................................................................................................. 6-12
Montmorillonite................................................................................................. 6-12
Na-montmorillonite ........................................................................................................6-12
Ca-montmorillonite ........................................................................................................6-12
The structure of clays....................................................................................... 6-13
Montmorillonite ..............................................................................................................6-13
Attapulgite ......................................................................................................................6-14
Sepiolite ..........................................................................................................................6-14
Effects of adding positive ions.......................................................................... 6-14
Salt clay ..........................................................................................................................6-14
Yield ................................................................................................................................6-15
Rheology............................................................................................6-16
Introduction....................................................................................................... 6-16
Non-Newtonian fluids ....................................................................................... 6-17
Bingham plastic model ..................................................................................... 6-18
PV................................................................................................................................... 6-19
YP ................................................................................................................................... 6-19
Gel strength.................................................................................................................... 6-19
Power Law model ............................................................................................. 6-20
Power Law ..................................................................................................................... 6-20
n index ............................................................................................................................ 6-21
K index ........................................................................................................................... 6-22
Modified Power Law model .............................................................................. 6-22
Slip velocity .................................................................................................................... 6-22
Critical velocity.............................................................................................................. 6-23
Reynolds number ............................................................................................. 6-24
Filtration.............................................................................................6-24
Conditions affecting filtration ............................................................................ 6-24
Time.................................................................................................................. 6-25
Control of filter cake permeability ..................................................................... 6-25
Filtration control additives................................................................................. 6-25
Clays............................................................................................................................... 6-25
Starch ............................................................................................................................. 6-25
Dispersants..................................................................................................................... 6-26
CMC ............................................................................................................................... 6-26
Solids Control ...................................................................................6-26
Introduction....................................................................................................... 6-26
Monitoring solids content.................................................................................. 6-27
The solids removal system ............................................................................... 6-28
Shale shakers................................................................................................... 6-29
Screen arrangement ....................................................................................................... 6-29
Position of vibrator ........................................................................................................ 6-29
Screen type ..................................................................................................................... 6-29
Sand traps ........................................................................................................ 6-30
Desander .......................................................................................................... 6-30
Desilter ............................................................................................................. 6-32
Mud cleaner...................................................................................................... 6-33
Centrifuges ....................................................................................................... 6-33
ii
List of Figures
Fig. 6.1. Mud balance. ......................................................................................................6-3
Fig. 6.2. Marsh Funnel. ....................................................................................................6-4
Fig. 6.3. Fann viscometer. ................................................................................................6-5
Fig. 6.4. Dial reading vs. rotary speed..............................................................................6-6
Fig. 6.5. Standard filter press............................................................................................6-7
Fig. 6.6. Sand content kit..................................................................................................6-9
Fig. 6.7. pH meter...........................................................................................................6-10
Fig. 6.8. Water hydration of montmorillonite. ...............................................................6-13
Fig. 6.9. Yield curves for four different clays (A through D). .......................................6-15
Fig. 6.10. Shear stress vs. shear rate for a Newtonian fluid. ..........................................6-16
Fig. 6.11. Shear stress vs. shear rate for a typical mud. .................................................6-17
Fig. 6.12. Viscosity vs. shear rate for a typical mud. .....................................................6-17
Fig. 6.13. Newtonian and non-Newtonian fluids. ..........................................................6-18
Fig. 6.14. Comparison of Bingham and Power Law models..........................................6-20
Fig. 6.15. Velocity profile of fluids with different n indices..........................................6-21
Fig. 6.16. Power Law on log-log paper. .........................................................................6-22
Fig. 6.17. Solids content of low-weight muds................................................................6-27
Fig. 6.18. Mud weight vs. solids content........................................................................6-28
Fig. 6.19. Particle size distribution. ................................................................................6-28
Fig. 6.20. Desander.........................................................................................................6-31
Fig. 6.21. Centrifuge.......................................................................................................6-34
List of Tables
Table 6.1. Approximate n values of standard field muds................................................6-21
Table 6.2. Cuttings classification and recommended removal equipment......................6-29
Table 6.3. Mesh size and equivalent US screen grade....................................................6-30
Mud at the exit pit.
iii
Notes
iv
Chapter 6: Mud
Functions of a Drilling Fluid
The main functions of a drilling fluid are
to:
•
•
•
cool and lubricate the drill bit and
string
remove cuttings and transport them to
the surface
hold cuttings in suspension when circulation is stopped
•
line the hole with a thin, impermeable
filter cake to minimize fluid losses
•
provide geological information about
the formation
•
protect the formation from damage or
contamination
•
transmit hydraulic power
•
partially support the weight of drill
pipes or pipeline.
Cooling and lubricating the drill string
Considerable heat is generated by the cutting action of the bit and the drill pipe
rubbing on the sides of the wellbore. The
circulating drilling fluid effectively cools,
lubricates, and prolongs the working life of
the bit, while a slick filter cake reduces the
frictional load when the pipe is pulled.
Removing cuttings
Efficiently removing cuttings from the bottom of the hole is essential to maximize
drilling rates. As the mud ascends the annulus, the natural tendency is for entrained
cuttings to settle out and sink to the bottom
of the hole. It is vital to maintain an adequate annular mud velocity that exceeds
the settling rate of the suspended solids,
such that the resultant motion of the parti-
cles is up toward the surface where they
can be removed. The units for measuring
velocity and volume are:
•
pump output (l/min)
•
annular velocity (m/min)
•
annular volume (l/m)
Suspending and releasing cuttings
A drilling fluid should be thixotropic. This
means that when mud circulation is
stopped, the mud should have sufficient gel
strength to hold the cuttings in suspension
until they are transported to the surface.
When circulation resumes, the mud should
revert to its lower viscosity so the cuttings
may be carried to the surface.
You should check the sand content of the
mud from the flow line and after being processed by all the solids control equipment
to verify that the sand is being released and
not being recirculated down the hole. Any
sand carried forward will cause serious
abrasion to pumps and equipment. Whenever possible, do not allow the sand content
to exceed 1%.
Forming a filter cake
When porous formations are encountered,
the drilling fluid will deposit a thin, impermeable filter cake that minimizes fluid loss
and consolidates the formation. This wall-
building property of mud is enhanced by
the addition of bentonite, whose colloidal
nature and platelet structure effectively seal
the formation.
Horizontal Directional Drilling Training Program
Providing geological information
Inspecting the cuttings removed by the
shale shaker will provide geological infor-
mation about the formation you are
penetrating.
Protecting the formation
A drilling fluid must be carefully selected
to minimize formation damage. Whenever
possible, never use a fluid that will react
with the formation.
Transmitting hydraulic horsepower
The role of the drilling fluid in transmitting
hydraulic horsepower is becoming more
important due to the increasing use of
downhole motors, turbines, and hydraulically operated downhole equipment.
The bit hydraulics and pressure drop
required by any downhole equipment must
be carefully considered when planning a
mud program. Optimum hydraulic horsepower should be available to assist in
cuttings removal while drilling hard formations. However, if the formation is very
soft, the size of jet nozzles should be
increased. Although this will reduce the
hydraulic horsepower at the bit, the lower
jet velocities will allow you to use a higher
pump rate, resulting in increased hole
cleaning. The lower velocities will also
help avoid hole washouts and irregular trajectories, especially when drilling a
deviated hole.
The flow properties and mud weight
greatly affect the hydraulics program and
should be carefully controlled to ensure
that the hydraulics of the system are within
the required limits.
Supporting the drill pipe weight
The mud in the hole partly supports the
weight of the casing and drill pipe because
of the buoyancy effect. Savings in wear and
6-2
tear on rig equipment and electrical power
consumed are additional factors attributable to mud buoyancy.
Mud: Drilling Fluid Tests
Drilling Fluid Tests
Mud weight
Use the following procedure to measure
mud weight using a mud balance (Fig. 6.1):
5. Read the mud density off the appropriate scale and immediately clean the
balance.
1. Place the base (pivot) of the mud balance on a level surface.
6. Use the following mathematical relationships:
2. Fill the cup (which should be clean and
dry) with the mud to be tested. Tap the
cup gently to remove trapped air.
3. Place the cap on the cup and rotate it
until it is firmly in contact with the top
of the cup.
4. Place the arm in position on the base,
and move the balance weight until the
arm is balanced horizontally.
•
specific gravity = lb per ft3/62.3
•
mud gradient = lb per ft3/144
•
mud gradient = lb per gal/19.24
•
mud gradient = specific gravity/
2.31
7. Calibrate the mud balance as necessary. When calibrated correctly, fresh
water at 21˚C should give a reading of
1.0 (8.33 lb/gal).
Fig. 6.1. Mud balance.
6-3
Horizontal Directional Drilling Training Program
Viscosity: Marsh Funnel
The Marsh Funnel (Fig. 6.2) is used to
measure the funnel viscosity, which is the
number of seconds required for the outflow
of 946 cm3 (1 qt) from a standard Marsh
Funnel containing 1500 cm3 (1.6 qt) of
fluid. Use the following procedure:
3. With the Marsh Funnel held vertically,
simultaneously remove your finger and
start a stopwatch. Allow the mud to run
into a clean, dry viscosity cup.
1. Check the orifice of the Marsh Funnel
to ensure that it is free from any
obstruction.
4. Stop the stopwatch when the level of
the mud reaches the mark on the viscosity cup (946 cm3). Record this time,
to the nearest second, as the funnel viscosity. Also record the temperature of
the sample.
2. Cover the orifice with a finger and pour
a fresh mud sample through the top
screen until the fluid level reaches the
bottom of the screen.
5. The Marsh Funnel viscosity of fresh
water at 21˚C should be 26 ± 1/2 sec. If
it is not, then replace the funnel,
because it cannot be recalibrated.
Fig. 6.2. Marsh Funnel.
6-4
Mud: Drilling Fluid Tests
Viscosity: Rotational Viscom
The Rotational Viscom (also called Fann
Viscom) is also used to measure viscosity.
There are several types of viscoms avail-
able, but horizontal directional drilling
(HDD) rigs are usually equipped with the
Fann VGM six-speed viscom (Fig. 6.3).
Fig. 6.3. Fann viscometer.
All viscoms operate on the same principle.
Mud is placed in the annular space between
two cylinders. The outer cylinder (the
sleeve) is rotated at constant preset speed.
The effect of this rotation on the mud sets
up a torque on the inner cylinder (the bob),
which itself rotates until the torque in the
restraining spring attached to the bob is
equal and opposite to the torque applied by
the mud movement. A numerical value is
given to this torque by reading a dial
attached to the torsion spring. The instrument is designed and built so that the
plastic viscosity (PV) and yield point (YP)
values can be calculated by using the dial
readings obtained when the outer cylinder
is rotated at 600 and 300 rotary speed.
Notes on use of the viscom:
•
Change the gears only when the motor
is running.
•
Clean the viscom thoroughly after use.
To do this properly, remove the outer
sleeve by rotating it slightly to release
the lock and then pull the sleeve downward.
Measuring YP and PV. To measure YP and
PV:
1. Pour a fresh mud sample into the metal
container provided with the viscom, up
to the line marked in the container.
2. Position the container properly on the
base of the viscom, and lift the base
into a position such that the cylinder
sleeve is immersed in the mud up to the
mark on the sleeve.
3. With the gearing in the 600/300-rotary
speed position, start the motor by putting the switch into the “High”
(600 rotary speed) position. Allow the
dial reading to reach a steady value,
which you will record as the 600-rotary
speed reading.
6-5
Horizontal Directional Drilling Training Program
4. Move the switch to the “Low” position
and allow the dial reading to reach a
steady value, which you will record as
the 300-rotary speed reading.
5. Obtain the PV (in cp) by subtracting
the 300-rotary speed reading from the
600-rotary speed reading.
6. Obtain the YP (in lb/100 ft2) by subtracting the PV from the 300-rotary
speed reading (Fig. 6.4).
7. Obtain the apparent viscosity (AV) by
dividing the 600-rotary speed reading
by 2. Thus:
600-rotary speed readings. PV is the
slope of the line joining the 300 and
600 rotary speed values (projected on
the y axis) and the intercept of the
extrapolated line is YP.
Gel strength. To obtain a gel strength
measurement:
1. Stir the same mud sample (by rotating
the outer cylinder at 600 rotary speed)
for 10 sec, change the gearing to the
300/600-rotary speed position, and turn
off the motor after 10 sec.
AV = θ600/2
2. Move the switch into the “Low” position, note the maximum reading on the
dial, and turn off the motor. This value
is the 10-sec initial gel in lb/100 ft2.
where θ600 is the dial reading at
600 rotary speed and θ300 is the dial
reading at 300 rotary speed. A flow
diagram of dial reading vs. rotary
speed can be drawn using the 300- and
3. Allow 10 min to elapse and then turn
the motor on by moving the switch to
the “Low” position. Note the maximum reading. This value is the 10-min
gel in lb/100 ft2.
PV = θ600 - θ300
YP = θ300 - PV
θ 600
θ 300
}
}
1
Fig. 6.4. Dial reading vs.
rotary speed.
1
1 = Plastic viscosity
2 =Yield point
2
300
6-6
600
Rotary speed
Mud: Drilling Fluid Tests
Filtration (low-temperature test)
The static filter-cake building and fluid loss
control characteristics are measured using a
filter press (Fig. 6.5). The low-temperature
test is the only test used for HDD, and is
carried out at room temperature and
100 psi differential pressure.
6
1
2
7
3
8
4
9
10
5
11
12
13
Fig. 6.5. Standard filter press.
1
2
3
4
T bar
Pressure inlet
Mud container
Stand
5
6
7
8
Graduated cylinder
Top cap
Rubber gasket
Cell body
The American Petroleum Institute (API)
fluid loss is reported as that volume
(in cm3) of filtrate lost from the filter press
in 30 min. Use the following procedure:
1. Before assembly, check the drain tube
for any obstruction. Also, check the
rubber gaskets.
9
10
11
12
13
Rubber gasket
Filter paper
Wire mesh screen
Rubber gasket
Bottom cap with drain tube
2. Carry out the assembly in the following order: base cap, rubber gasket, wire
screen, one sheet of filter paper (Whatman n˚50), and rubber gasket. Then
lock the cell body into the base cap by
turning clockwise until tight.
3. Fill the cell with a new sample of mud
to within 1/4 in. (7 mm) of the top.
Then put on the top cap (with rubber
6-7
Horizontal Directional Drilling Training Program
gasket) and fit the complete unit into
the filter press frame. Hold in place by
turning the “T” bar on top of the stand
until it is tight.
4. Insert a new CO2 cartridge below the
regulator.
5. With the measuring cylinder in place
below the drain tube, turn the pressure
regulator handle clockwise until the
pressure gauge shows 100 psi (689 Kp)
and start the stopwatch as soon as the
pressure is applied.
6. After 30 min have elapsed, note the
volume of filtrate in the measuring cylinder to the nearest 0.1 cm3. This volume is the API fluid loss. If you note a
fluid loss greater than 60, it should be
reported as “No Control.”
7. Before disassembly, turn the regulator
handle counter-clockwise to isolate the
CO2 cartridge, and bleed the pressure
off the cell by lifting the plastic pressure release valve.
8. Remove the cell from the frame and
disassemble, taking care not to disturb
the layer of filter cake on top of the filter paper.
9. Measure the thickness of the filter cake
to the nearest 1/32 in. (mm).
10. Save the filtrate for the chemical analysis described later.
11. Clean and dry the equipment.
Sand content
Any sand not removed from the mud will
have a detrimental effect on the life of the
mud pumps and centrifugal pump parts.
Thus, you should monitor the sand content
of the mud closely. The following method
determines the percentage of sand and
other coarse material (having a particle size
greater than 74 µ or 200 mesh) contained in
the mud:
1. The equipment is composed of a plastic cylinder containing a 200-mesh
screen, a funnel that fits onto the cylinder, and a graduated glass tube (Fig.
6.6).
2. Pour the mud into the graduated glass
tube until it reaches the “Mud to Here”
mark.
3. Add water to the graduated tube until it
reaches the “Water to Here” mark.
4. Block the mouth of the tube and shake
it vigorously.
6-8
5. Pour the mixture onto the clean
200-mesh screen. Add more water to
the tube, agitate, and empty the contents onto the screen.
6. Repeat this operation until the tube is
clean.
7. Wash any remaining mud off the sand
retained by the screen.
8. Fit the funnel upside down over the
screen, and invert the assembly and
place it so that the funnel outlet is
inserted into the mouth of the graduated tube.
9. Wash the sand off the screen with a
spray of water into the tube.
10. Allow the sand to settle. Read the volume of sand directly from the graduated marks and record it as the volume
percent of sand in the mud.
Mud: Drilling Fluid Tests
Fig. 6.6. Sand content kit.
pH
pH is a measure of the hydrogen ion concentration of a fluid, reported on a
logarithmic scale ranging from just less
than 1 to 14. Distilled water is neutral and
has a pH of 7, while a fluid with a pH of
less than 7 is considered acidic. A fluid
with a pH greater than 7 is considered alkaline. pH is usually measured with pH paper
or a pH meter (Fig. 6.7).
pH is important because:
•
certain chemical additives perform better at certain pH levels
•
pH change may be an early indication
of contamination
•
certain formations are pH sensitive and
an 8.0 to 9.0 is required to reduce formation damage
•
drilling fluids are generally alkaline,
with pH in the range of 8.0 to 12.0,
with 9.0 to 10.5 being most common.
6-9
Horizontal Directional Drilling Training Program
Fig. 6.7. pH meter.
Chemical analysis
6-10
The following chemical analyses can be
performed on drilling fluids:
•
cation exchange capacity (methylene
blue test)
•
filtrate alkalinity
•
potassium content.
•
whole mud alkalinity
•
lime content
•
chloride content
•
total hardness (calcium and magnesium)
•
calcium content
•
calcium sulfate (excess gypsum) content
It is beyond the scope of this chapter to
derive or demonstrate all these measurements, which require a mud engineering
background. If mud problems cannot be
solved by the HDD engineer, you should
have a drilling mud engineer from the oil
industry come to the site and conduct all
the necessary tests. However, the basics of
clay chemistry are reviewed below, since
HDD mud is usually simple bentonite mud.
Mud: Clay Chemistry
Clay Chemistry
The most commonly used drilling fluid is
mud made up with water as the continuous
liquid phase (a water-based mud). Various
solids are present as a result of drilling, and
others may be added to alter the characteristics of the mud to meet operational
requirements.
Moreover, for HDD, environmental considerations further limit the materials that can
be added to water to fabricate the mud,
since it is almost impossible to control or
confine mud returns.
To fully understand the effects of various
additives on water-based mud, you must
first understand the basics of elementary
chemistry.
Basic chemistry
Pure substances are composed of a single
element or compound. An element is a
material made up of only a single atom.
When two or more different kinds of atoms
react to form a new material, the resultant
material is called a compound. Thus,
sodium (Na) and chlorine (Cl) are elements, although Cl normally appears as a
Cl molecule resulting from the combination of two Cl atoms. When Na and Cl
react, a new material, sodium chloride
(NaCl), is formed. This new material is a
compound composed of two different kinds
of atoms. When elements or compounds
are mixed without a chemical reaction taking place so that the original materials
retain their identity, the result is simply a
mixture.
An atom is the smallest particle of an element, exhibiting all the chemical properties
of that element. Its structure determines the
chemical and physical properties of the ele-
ment and different structures produce
different elements. An atom is made up of a
nucleus surrounded by orbiting electrons of
varying numbers and different orbits or
shells. The nucleus contributes most to the
mass of the atom and consists of protons
and neutrons. The proton is a fundamental
particle of high mass with a positive electrical charge. Neutrons do not have an
electrical charge. The mass of a proton is
almost identical to that of a neutron and far
greater than the mass of an electron.
In all atomic nuclei there is a surplus of
protons, so that the nucleus always carries
a positive electrical charge that is counterbalanced by an equal number of negatively
charged electrons, making the whole atom
electrically neutral. It is the configuration
of the outer shell of orbiting electrons that
gives the atom most of its individual chemical properties.
Atomic and molecular weights
The atomic weight of an element is determined by the number of protons and
neutrons contained in its nucleus and, to a
lesser extent, the number of electrons. For
example, originally the oxygen (O) atom
was used as the standard by which to compare all other elements. (Today, atomic
weights are more accurately based on the
carbon isotope C12). The O nucleus contains eight protons and eight neutrons and
has an atomic weight of 16.
Some typical atomic weights (based on
C12) of common elements are:
•
hydrogen (H): 1.00797
•
carbon (C): 12.01115
•
oxygen (O): 15.9994
•
sulfur (S): 32.064
•
chlorine (Cl): 35.453
It follows that since compounds consist of
groups of atoms called molecules, then the
molecular weights of compounds can be
calculated by simple addition. The approximate molecular weights of some common
substances are as follows:
6-11
Horizontal Directional Drilling Training Program
•
water (H2O) = (2 x 1) + 16 = 18
•
carbon monoxide (CO) = 12 + 16 = 28
•
sulfuric acid (H2SO4) =
(2 x 1) + 32 + (16 x 4) = 98
Valence and chemical bonds
The valence of an atom can be described as
the number of H atoms it can combine
with, and is determined by the number of
electrons in the outer shell. Some elements
with few electrons orbiting in the outer
shell have a tendency to lend or borrow
electrons from adjoining atoms. These elements are termed reactive and would
include H and Cl.
Atoms having given up or gained an electron are no longer at zero potential and are
called ions. Those atoms acquiring a positive charge (i.e., losing electrons) become
cations, while those atoms acquiring a negative charge (i.e., gaining electrons)
become anions.
Dissociation and equivalent weights
In certain circumstances, it is possible to
separate a molecule into ions by dissolving
the material in a solvent. This process is
known as dissociation, which enables the
ions to become unattached charged particles. The equivalent weight of an atom is its
atomic weight divided by the charge of the
ion it forms (i.e., its valence).
Clay chemistry
The earliest type of drilling mud was
“muddy water,” which provided the early
rotary drillers with considerable improvements in hole cleaning when compared to
plain water. Their initial experiments in
dissolving soils and clays in the mud to
increase viscosity were gradually refined
until one type of clay was found to be ideal.
This clay was Wyoming bentonite. It produced the maximum viscosity for
the minimum amount of materials added.
Wyoming bentonite is known chemically as
sodium montmorillonite (Na-montmorillonite) and possesses properties that enable it
to expand and absorb large quantities of
water. It is these two characteristics, and its
makeup of very small particles that have a
huge total surface area, that govern its
chemical and physical reaction in drilling
muds.
Montmorillonite
6-12
Montmorillonite was originally discovered
in Montmorillon, France, and it appears in
two forms, Na-montmorillonite and calcium montmorillonite (Ca-montmorillonite).
Ca-montmorillonite. Ca-montmorillonite
(commonly known as sub-bentonite) will
only swell to less than half the volume of
bentonite, and also produces slightly larger
and thicker particles, thus limiting its suitability for producing a thin, impervious
filter cake.
Na-montmorillonite. Na-montmorillonite
(bentonite) is an extremely high-quality
clay used for drilling. It has the ability to
swell when mixed with water to at least 10
times its original volume, giving good fluid
loss control and filter cake properties.
The primary use of Ca-montmorillonite is
to improve particle size distribution, especially in areas where the mud system is not
incorporating solids from mud-making
shales, or in making sea water muds where
improved particle size enhances the effectiveness of fluid loss control agents.
Mud: Clay Chemistry
The structure of clays
Clay structure consists of fine-grained
materials which, when dispersed in water,
form particles of around 2 µ or less. These
particles remain in suspension in the water,
forming colloids.
Montmorillonite. The structure of montmorillonite is unique when compared with
+
-
+
+
+
-
+
+
+
+
other clays (Fig. 6.8). The crystal lattice
structure consists of sheets of atoms that
are much thinner and are more readily separable in water than those of other clays.
Thus, montmorillonite clays exhibit a
much larger surface area when added to
water than do other clays. This is especially
true for Na-montmorillonite.
Cations
Calcium montmorillonite
+
-
+ Silica
Aluminum
+
- Silica
+
+
+
+
+
+
+
+
+
Cations
Hydration water
Montmorillonite
Silica
Aluminum
Silica
+ Water
Silica
Aluminum
Silica
Silica
Aluminum
Silica
Silica
Aluminum
Silica
Sodium or Calcium
montmorillonite
Sodium montmorillonite
Fig. 6.8. Water hydration of montmorillonite.
Montmorillonite is made up of a great
number of nearly flat, thin sheets, very similar to mica. These thin, sheet-like particles
are themselves made up of three plateletlike layers (i.e., two outside, tetrahedrally
shaped silica (Si) plates surrounding an
octahedrally shaped aluminum (Al) plate
[Fig. 6.8]). The clay platelet is negatively
charged and has a cloud of Na or Ca cations associated with it. The monovalent Na
cation will attract the negative platelet;
however, the more positively charged, divalent Ca cation will exert an even stronger
attraction on the negative platelets, as
shown in Fig. 6.8.
When the clay is hydrated, the bulk of the
water absorbed is attracted around the
platelets. A greater volume of water can be
6-13
Horizontal Directional Drilling Training Program
absorbed by Na-montmorillonite than Camontmorillonite.
Attapulgite. Attapulgite is a chain-structure clay of hydrous magnesium aluminum
silicate. Attapulgite clays have been widely
used to improve the viscosity of drilling
fluids made up with salt or brackish water.
One of the main attributes of attapulgite is
that when properly dispersed and sheared,
it produces as much viscosity in salt water
as it does in fresh water. One drawback,
however, is that it does not give any significant filtration control and additional
chemicals must be used.
Sepiolite. Sepiolite is a rod-structure clay
similar to attapulgite, but is much more stable at high temperatures.
Effects of adding positive ions
Clay particles can associate in three ways:
face-to-face, edge-to-edge, or edge-to-face,
depending on the chemical balance. The
linking of particles in these ways may proceed simultaneously, or one type may
predominate. Face-to-face association, or
aggregation, merely leads to the formation
of thicker plates or packets. This decreases
the number of individual particles and
decreases the viscosity.
Divalent exchange cations can cause aggregation. This is observed when gypsum is
added to a hydrated bentonite suspension.
After an initial increase in the viscosity
(due to flocculation), the suspension will
thin to some value of viscosity that is lower
than the original viscosity of the suspension. Dispersion, the reverse of aggregation, leads to a greater number of particles
and higher viscosity. Clay platelets are normally aggregated before they are hydrated
and, as they hydrate, some dispersion takes
place. The degree of dispersion depends on
the electrolyte content of the water, time,
temperature, the exchangeable cations on
the clay, and the clay concentration.
Edge-to-edge or edge-to-face association is
a flocculation process that forms a “house
of cards” structure. This also increases the
viscosity. Particle linking is governed by
the forces acting on them and the availability of particles to be linked. Anything that
reduces the repelling forces between particles, or shrinks the absorbed water layer
(such as adding a limited quantity of divalent cations, or high temperatures) will
promote flocculation.
Note that divalent cations (such as Ca when
gypsum is added) will cause the clays to
aggregate. Certain chemicals added to mud
6-14
neutralize the charges on the platelets, with
the result that particles no longer associate
edge-to-edge-to-face; the mud has been
deflocculated. An example of a deflocculating chemical is lignosulphonate. Only a
small concentration of this chemical is
needed to fully deflocculate a low solids
content mud, since there is a relatively
small area on the edge of the plates where
lignosulphonates are absorbed. Chrome
lignites are used to deflocculate muds in
high-temperature situations where lignosulphonates are ineffective.
Salt clay. The effect of positively charged
ions, such as Ca, is to flocculate bentonite
muds by disturbing the balance of charges
in the bentonite suspension. The presence
of negatively charged ions, such as chlorides, will also reduce the efficiency of
these types of drilling fluids by a similar
mechanism.
If the mud is to be mixed in salt water, bentonite will not economically provide
adequate viscosity. Also, if large salt sections will be drilled, bentonite will be
flocculated by the salt, giving poor rheology. However, salt clay, or attapulgite, can
be mixed and will provide viscosity in the
presence of strong electrolytes such as salt.
The structure of attapulgite consists of needle-shaped particles of hydrous magnesium
aluminum silicate. The structure requires
shearing to provide viscosity, although it
will not provide control of filtration or
water loss. If attapulgite muds are used,
some additional fluid loss control agent
will be required. The most cost-effective
materials are starches or carboxyl methylcellulose (CMC).
Mud: Clay Chemistry
Yield. The yield of a clay is defined as the
number of barrels of 15-cp mud that can be
produced from 1 ton of dry clay by adding
fresh water. Fig. 6.9 shows the yield vs.
viscosity curves for a range of muds. In
general, there is little change in the viscosity for large additions of clays until a
viscosity of 15 cp is reached, after which
there is a large increase in viscosity for
small increases in solids content.
Pounds Per Cubic Foot
67.5
63.7
8.5
71.2
Pounds Per Gallon
9.5
10.0
9.0
B
A
60
75.0
78.7
82.5
10.5
86.2
11.0
11.5
90.0
12.0
D
C
Viscosity in Centipoise
50
40
30
20
10
0
0
5
10
200 100 75
2
10
50
4
20
30 40
15
20
25
30
35
Percentage Solids by Weight
40
40
30
25
20 18 16
14
12
Yield (15 Centipoise Mud) in Barrels Per Ton
6
50
10
12
14 16 18
20
Percentage Solids by Volume
75
100
150
Solids in Pounds Per Barrel of Mud
45
50
Specific Gravity of Solids = 2.4
10
25
8
200
9
8
30
250
Fig. 6.9. Yield curves for four different clays (A through D).
Clays have an essential role to play in the
formulation of drilling fluids. Where there
is no excessive formation pressure to counterbalance, a low-solids, high-viscosity
mud with good fluid loss control can be
achieved by adding high-yielding bentonite
to fresh water. A yield in excess of 90 bbl/
ton can be anticipated. However, if the
makeup water contains salts or certain ions,
there is a marked reduction in the yield.
This is caused by the cations in the makeup
water that neutralize the negatively charged
platelets and thus restrain them from separating and absorbing water. One way of
partially overcoming this problem is to pre-
hydrate the clay with fresh water and then
add salty water to the slurry. The overall
yield will be less than if just fresh water
had been used, but an improved yield will
be achieved over that obtained by hydrating
with only salty water.
Due to its plate-like structure, bentonite is a
perfect medium for deposition on the borehole wall surface, where it forms a thin,
compressible filter cake, minimizing fluid
loss into the formation.
Attapulgite is much better suited for mixing with salt water and gives a similar
6-15
Horizontal Directional Drilling Training Program
viscosity to bentonite for the same concentration. A yield in excess of 100 bbl/ton can
be expected.
Rheology
Introduction
It is vital that you understand the quality of
a drilling fluid under a wide range of operating conditions, and that you can control
the various parameters of the fluid to
ensure that it performs effectively. The
drilling fluid viscosity is one such parameter. The science of flow and deformation of
fluids is known as rheology.
As a fluid flows through a pipe, there is a
layer of fluid adjacent to the pipe wall that
is stationary. As the point of reference
moves from the pipe wall, the velocity
increases and attains a maximum at the
centerline of the pipe. The force required to
move a unit area of a layer of liquid with
respect to an adjacent layer is known as the
shear stress. The rate at which one layer
moves relative to an adjoining layer is
known as the shear rate.
For a simple fluid like water or glycerine,
shear stress is proportional to shear rate, as
illustrated in Fig. 6.10. Such liquids are
classified as Newtonian. The slope of the
graph is a constant K, and since shear stress
is proportional to shear rate, it can be
written:
shear stress = K x shear rate
ss
K = ----- = vis cos ity
sr
Ss
Fig. 6.10. Shear stress vs.
shear rate for a Newtonian
fluid.
Ss = Shear stress
Sr = Shear rate
K
Sr
6-16
Mud: Rheology
Non-Newtonian fluids
Unfortunately, drilling fluids are more
complex than water and do not display constant viscosity over a range of shear stress/
shear rate ratios. They are classified as nonNewtonian fluids.
The graph for a typical drilling fluid would
be similar to the one shown in Fig. 6.11. As
can be seen from the graph, no longer is the
relationship of shear stress/shear rate a
straight line, it is now a curve. In addition,
the curve does not start at zero but at some
positive value of shear stress, which indicates an initial resistance to movement. The
slope of the curve K is continually changing, and since K = viscosity, the value of
viscosity at any given shear rate is known
as the apparent viscosity.
Ss
Fig. 6.11. Shear stress vs.
shear rate for a typical
mud.
Ss = Shear stress
Sr = Shear rate
Sr
Therefore, it is possible to plot a graph of
apparent viscosity vs. shear rate for any
given fluid, as shown in Fig. 6.12. Shear
stress is normally expressed in lb/100 ft2,
and shear rate is normally expressed in
reciprocal seconds, or sec –1.
Ss
Fig. 6.12. Viscosity vs. shear
rate for a typical mud.
Ss = Shear stress
Sr = Shear rate
Sr
In the field, a simple test to determine viscosity is to pour a mud sample into a Marsh
Funnel and note the number of seconds it
takes for a quart of mud to pass through it.
The resultant measurement is known as
funnel viscosity and is a quick test performed routinely by drilling crews (see
page 6-4).
6-17
Horizontal Directional Drilling Training Program
A more accurate instrument for measuring
a range of apparent viscosity is the Fann
VGM, which is also described on page 6-4.
You can determine apparent viscosity in
centipoise units by applying a simple formula to the observed readings.
Because of the complexity of drilling fluids
and the range of apparent viscosity that can
be determined for various shear rates, a
mathematical model became necessary to
more accurately forecast the viscosity profile over a range of shear rates, given
a minimum of basic data.
Bingham plastic model
Bingham developed his mathematical
model to express plastic flow, and from it
you can plot PV and YP. This is achieved
by adding a sample of mud to a Fann
VGM, noting the Fann dial readings at 300
and 600 rotary speed, and plotting a graph
(Fig. 6.4).
PV (in cp) =
Fann reading (600 rotary speed) Fann reading (300 rotary speed)
YP = Fann reading (in lb/100 ft2) PV (300 rotary speed)
The Fann VGM is scaled so that the dial
readings give the PV in cp units and the YP
in lb/100 ft2. The formula can now be simplified as:
Dial reading = YP + PV x (Fann rotary
speed)/300
Fig. 6.13 shows the ideal curve produced
for a non-Newtonian fluid. It is important
to note in Fig. 6.13 that initially no movement takes place as the shear stress is
increased from zero. This is because the gel
strength of the fluid resists the shearing
action. A transitional period follows as the
fluid starts to flow, with increasing shear
rate until a linear relationship is established
between shear rate and shear stress. The
linear phase is known as viscous flow and
the slope of the line gives PV at 300 rotary
speed. Extrapolating the straight-line part
of the graph intersecting the shear stress
axis gives the YP.
Ss
Fig. 6.13. Newtonian and
non-Newtonian fluids.
A
1 = Bingham YP
2 = Transition from plastic
to viscous flow
1
3 = Plug flow
2
4 = True yield
3
A = Plastic
4
B = Newtonian
B
Sr
6-18
Mud: Rheology
PV. PV is a measure of the viscosity produced by mechanical friction of the solids
and particles present in the mud once the
mud is flowing, plus the shearing effect of
the liquid phase.
As solids are ground down in size, their
surface area increases and adds to the viscosity of the mixture. To maintain an ideal
viscosity, drilled solids should be removed
at the surface by settling or mechanical solids control. This subject is discussed in
detail later in this chapter (page 6-26). The
mud viscosity should be maintained at a
sufficient level to carry cuttings to the surface and hold weighting agents in
suspension.
YP. YP is a measure of the electrochemical
resistance to flow as a result of the electrical interaction between the surface of
adjacent particles. The YP value is a function of several different considerations:
•
the surface charges present on the solids
•
the concentration of solids
•
the concentration and types of ions
present in the liquid phase of the mud.
High YPs (which, in general, should be
avoided) can be caused in the following
ways:
•
Salt, cement, or anhydrite contamination of the drilling fluid causes flocculation by neutralizing the negative
charges on the clay particles.
•
Highly reactive shales disperse in the
mud, resulting in an increased surface
area exposed to attractive forces and
leading to flocculation of the particles.
Adding suitable chemicals, such as lignins
and lignosulphonates, neutralizes the
attractive forces and promotes deflocculation. Ca or magnesium (Mg) ion
contamination should be precipitated out
with soda ash, thus lowering the YP. In
some cases, where the contaminant cannot
easily be removed by precipitation (such as
with Cl contamination) water can be added
to reduce its concentration, but this action
will also lower mud weight, so great care
should be exercised.
Gel strength. Gel strength is a measure of
the electrochemical attractive forces
present in a static liquid. A typical drilling
fluid has a tendency to gel when allowed to
stand for a while. This feature is very
important as it allows cuttings to be held in
suspension when circulation is stopped.
However, excessive gel strength can cause
problems, such as:
•
excessive pressure generated when
resuming circulation
•
difficulty in separating drilled cuttings
from the mud on the surface
•
excessive swabbing and surging during
trips.
Thixotropy, as previously defined (page 61), is the ability of a mud to change from a
gelled state to a pumpable viscous fluid as
a result of an applied shearing action, and
to gel again when circulation has stopped.
All good drilling fluids should be
thixotropic.
To determine the thixotropic value of a
mud, tests are carried out with a Fann
VGM. Readings are taken and noted after
the mud has been allowed to gel for 10 sec,
and again 10 min later. If a large difference
in readings is apparent, the mud has a progressive gel. This implies that the gelling
effect noted after 10 min would continue to
increase with time until an unacceptably
high gel strength was reached, necessitating a high pump pressure to break
circulation. A small difference in readings
between the 10-sec and 10-min gel
strengths indicates a fragile gel, which is the
desired condition.
6-19
Horizontal Directional Drilling Training Program
Power Law model
Power Law. While the Bingham plastic
model gives satisfactory results at higher
shear rates equivalent to a Fann VGM reading of 300 to 600 rotary speed, it is not as
accurate at shear rates below 225 sec-1
(equivalent to a Fann VGM reading of
130 rotary speed). Since these lower shear
rates are encountered in the annulus, a
model was developed to cover these shear
rates.
A more accurate shear stress/shear rate profile over the whole range of shear rates
from zero upward can be calculated from
the Power Law formula:
Ss = KSrn
K = Consistency Index, dynes secn/cm2
Note:
1. 1.067 is a constant for the Fann viscom
(converts dial readings of θ to
lb/100 ft2)
2. 1 lb/100 ft2 = 4.788 dynes/cm2
3. Shear stress, dynes/cm2
= θ x 1.067 x 4.788
= 5.11 x θ
The Consistency Index is calculated as
lb - secn/100 ft2:
K = 1.067 x θ300/511n
Equation 1
Equation 4
which is often written:
Sr = Shear rate, sec -1
K = θ300/511n
Ss = Shear stress, dynes/cm2
= θ x 5.11
n = 3.32 log10 x θ600/θ300
Equation 2
n = Power Law Index (no units)
K = 5.11 x θ300/511n
Equation 3
Shear rate (sec-1) = rotary speed reading of viscom x 1.703 Equation 5
Fig. 6.14 shows a comparison between the
Bingham plastic model, Power Law model,
and actual curves for shear stress/shear
rate. All three curves closely follow each
other until the lower shear rates (i.e., annular shear rates) are encountered.
Ss
30
1
20
Fig. 6.14. Comparison of
Bingham and Power Law
models.
3
1 = Bingham plastic model
2
2 = Actual mud
3 = Power Law model
10
Sr
50
6-20
100
150
Mud: Rheology
n index. In the Power Law formula, n is a
measure of the non-Newtonian behavior
that a fluid shows over a range of shear
rates. In the case of a Newtonian liquid
such as water, oil, or glycerine, the n value
= 1. Such liquids have a velocity profile
1
across a pipe, as indicated in Fig. 6.15. A
fluid with a parabolic velocity graph
(where n = 1 in Fig. 6.15) has very poor
hole-cleaning characteristics, since cuttings
tend to move and collect in areas of low
velocity.
A
B
200
160
120
n = 1.0
n = 0.667
n = 0.5
n = 0.25
n = 0.125
n
Ss = KSr
80
40
0
2
3
4
5
6
Fig. 6.15. Velocity profile of fluids with different n indices.
1 Liquid velocity (ft/min)
2 Radius (in.)
The flatter characteristic produced by liquids with n values less than 1 have
excellent hole-cleaning characteristics (low
shear rates in the annulus give high annular
viscosity, enabling cuttings to be carried to
the surface). n is generally reduced by adding a viscosifier such as XC Polymer™.
Reducing the n value produces a more
pseudoplastic liquid that makes it more
shear thinning. This characteristic leads to
a lower viscosity at the bit (an area of high
shear), which promotes increased penetration rates. Conversely, in areas of low
shear, such as in the annulus, the viscosity
will increase, thereby improving the carrying capacity of the mud. See Table 6.1 for
approximate n values of various muds.
A Drill pipe
B Hole wall
Table 6.1. Approximate n values of standard
field muds.
n value
Approximate
Mud type
PV/YP
1
0/0
0.7–0.8
30/15
0.6–0.7
25/20
0.5–0.6
20/20
0.4–0.5
10/20
0.2–0.3
5/20
Water
Weighed, dispersed
bentonite mud containing a high proportion
of drilled solids
Low-weight, dispersed bentonite mud
containing few drilled
solids
Non-dispersed bentonite/polymer mud
Non-dispersed polymer mud
Water/xanthum gum
6-21
Horizontal Directional Drilling Training Program
K index. K, the Consistency Index, is a
function of the quantity and type of solids
present in the mud (control of K is similar
to the control of PV). K is expressed as the
viscosity of the drilling fluid at a shear rate
of 1 sec-1. It is found graphically by extrapolating the tangent of the rheological curve
until it intercepts the shear stress axis of the
graph.
If the graph Ss vs. KSrn is prepared on logarithmic paper, it will be a straight line with
the slope of the line being n and the intercept on the Ss axis (with Sr = 1) being K
(Fig. 6.16). The higher the K factor, the
higher the shear stress will be. Consequently, the higher the viscosity will be,
thereby exerting a greater retarding force in
the annulus on the particles attempting to
settle through the liquid.
Circulating pressure losses, viscosity at the
bit, and hole-cleaning ability are all
affected by the K value of the mud.
To minimize the viscosity at the bit and the
equivalent circulating density, K should be
maintained as low as possible (as long as
hole cleaning is not adversely affected).
With regard to PV, an increase in inert solids content will raise the K value (with little
or no effect on n). In addition, K may be
reduced by diluting with new mud or by
using the solids control equipment effectively to remove solids. Adding XC
Polymer will increase K while (at most
concentrations) reducing n.
Ss
1
Fig. 6.16. Power Law on loglog paper.
n
K
Log Sr
300
600
Modified Power Law model
One shortcoming of the standard Power
Law model is that it does not allow for yield
stress; i.e., the initial resistance encountered in a fluid before flow is established.
In the Modified Power Law, yield stress is
included and is expressed as follows:
Ss = Ys + KSrn
Equation 6
where Ys is yield stress.
The yield stress is calculated from the readings of a Fann VGM rotating at 300 rotary
speed; i.e., the 10-sec gel reading.
6-22
Of the three models discussed, the Modified Power Law most closely represents the
characteristics of the majority of drilling
muds over the whole range of shear rates.
Slip velocity. Slip velocity is the rate at
which cuttings settle in a stationary fluid. It
follows that as cuttings are being transported up the annulus, the mean velocity of
the particles or cuttings will be the difference between the mud annular velocity and
the slip velocity, expressed as:
Vp = Va - Vs
Equation 7
Mud: Rheology
The slip velocity can be estimated using the
following equation:
Vs = 113.4 x (PD(pp - p)/Kfp)1/2
Equation 8
For a particle Reynolds number above
2000, Kf is a constant at 1.5. For particle
Reynolds numbers below 2000 (i.e., for
most routine solutions):
Vs = 175 PD(pp - p)0.667/(pµ)0.333
Equation 9
Equation 11
The average velocity of mud inside the drill
pipe is given by:
V = 24.5Q/(ID)2
The pressure loss in the drill pipe with mud
in turbulent flow is:
Pp = 7.7 105 p0.8 Q1.8 (PV)0.2 L/(ID)4.8
Equation 11b
Annular flow.
where
µ = ((2.4Va/(Dh - Dp)) x ((2n + 1)/3n))n
x 200K(Dh - Dp)/Va Equation 10
In the Power Law equation where n = 1, the
velocity profile across the annulus is a parabolic curve, as shown in Fig. 6.15, clearly
illustrating that the velocity varies with the
distance from the side of the hole and from
the outside of the drill pipe. It follows that
there will be points where the annular
velocity is greater than, equal to, or less
than the slip velocity. The result is that
some cuttings are not efficiently transported to the surface, and in extreme cases
are recycled in the annulus. The lower the n
value, the flatter the velocity profile
becomes, and the more efficient the transportation of cuttings. The flat part of the
velocity profile is known as plug flow and
only occurs with non-Newtonian fluids.
Critical velocity. The critical velocity (Vc)
of a fluid is that velocity at which there is a
transition from one flow pattern to another.
If V < Vc, then the fluid is in laminar
flow
If V > Vc, then the fluid is in turbulent
flow.
Flow inside the drill pipes.
Vc
((3n + 1)/4n))(n/(2-n))
= (5.82104 K/P)(1/(2-n)) x ((1.6/ID) x
Vc=(3.878 104 K/p)1/(2-n) x
((2.4/(Dh - Dp))x(2n + 1)/3n)n/(2-n)
Equation 12
The above equation assumes the flow pattern changes from laminar to turbulent at a
Reynolds number of 3000. The average
velocity of mud in the annulus is given by
v, where:
V = 24.5 Q/(Dh2 - Dp2)
Equation 13
The pressure losses in the annulus due to
mud in laminar flow are:
Power Law:
PA = (2.4V/(Dh - Dp) x
(2n + 1)/3n)n x KL/(300(Dh - Dp))
Equation 13b
Bingham:
PA = (PV)VL/(60000(Dh - Dp)2) +
(YP)L/(200(Dh - Dp))
Equation 13c
The pressure loss in the annulus due to
mud in turbulent flow (assuming Bingham
model) is given by:
PA = 7.5 105 p0.8Q1.8(PV)0.2/
((Dh - Dp)3(Dh + Dp)1.8)
Equation 14
6-23
Horizontal Directional Drilling Training Program
Reynolds number
The normally accepted flow patterns for
various Reynolds numbers are as follows:
Nr < 2000—laminar flow
2000 < Nr < 3000—transition from
laminar to turbulent flow
The pressure losses in turbulent flow are
directly proportional to the Fanning friction
factor, f, (a dimensionless number), which
is in turn related to the Reynolds number
(also dimensionless) given by the following
equation.
Nr > 3000—turbulent flow.
It should be noted that Equations 11, 11b,
12, and 14 were developed assuming that
the mud flow pattern changes from laminar
to turbulent at a Reynolds number of 3000.
If this assumption is not correct, a new set
of equations needs to be developed for
pressure losses in turbulent flow for both
the annulus and inside the drill pipe (the
pressure loss equations for laminar flow are
unchanged).
(Annulus) NR = 15.47(Dh - Dp)pVa/µ
Equation 15
where µ is given by Equation 10.
f is then found (usually graphically) and the
annular pressure losses are calculated using
the following formula:
PA = pVa2Lf/(93000 (Dh-Dp))
Equation 16
Filtration
Normally, the hydrostatic pressure exerted
by the mud in the borehole is maintained
above that of the formation pressure to prevent the formation fluids from passing into
the borehole. This positive differential
pressure from the borehole to the formation
will, in a newly exposed section of borehole, cause an initial spurt of mud into the
formation if it is porous and permeable.
into the formation is called filtrate, and the
loss of filtrate from the mud is called fluid
loss or filtration.
Assuming that the distribution of particle
sizes in the drilling fluid is such that the
pores in the formation can be bridged by
suitably sized particles, the bridge will then
build up by additional particles, forming
the porous layer of filter cake. (If the formation is impermeable to the passage of
drilling fluid, then no filter cake can form.)
The fluid that passes through the filter cake
•
unnecessarily thick filter cake, leading
to potential stuck pipe and swab and
surge problems during trips
•
loss of fluid and expensive chemicals
into the formation
•
unstable wellbore with the possibility
of cave-ins.
Controlling fluid loss and building a tough,
thin filter cake are vital when drilling a
well. Some problems that can occur as a
result of excessive fluid losses are:
Conditions affecting filtration
There are two types of filtration encountered when drilling a well: static filtration
and dynamic filtration. Static filtration is the
filtration that occurs when the mud is not
moving. This type of filtration normally
results in an increased rate of filter cake
deposition.
6-24
Dynamic filtration is the filtration that
occurs when the mud is flowing. Due to the
erosive effect of the moving mud, less filter
cake is deposited under dynamic conditions
than during static conditions. A state of balance is reached when the rate of filter cake
deposition and the effects of erosion are
Mud: Filtration
equal, resulting in a uniform cake thickness
and a steady fluid loss.
Other parameters that affect the rate of filter cake deposition are time and the mud
composition (pressure and temperature are
also factors, but not applicable to HDD).
After the initial spurt of mud has filtered
into the formation, the volume of filtrate Q
passing through the filter cake is directly
proportional to the square root of the time t
in seconds. By using the following formula
on observed laboratory tests, you can predict fluid losses:
t1 = time interval for fluid loss Q1
in min
Time
t
Q 2 = Q 1 ---2
t1
where:
Q1 = measured fluid loss over time t1
in cm3
Q2 = calculated fluid loss over time t2
in cm3
t2 = time interval for fluid loss Q2
in min
For example, if the fluid loss is 4 cm3 after
7.5 min, the calculated fluid loss Q2 after
30 min will be:
30
Q 2 = 4 ------7.5
Q2 = 4 x 2 = 8 cm3
In an ideal situation, the laboratory test
could be carried out over a 7.5-min period
and the result multiplied by 2 to give the
approximate fluid loss (Q2) over a 30-min
period. This is not an accurate approximation with some muds, and it should be
noted that the standard API test requires
fluid losses to be measured over a 30-min
period.
Control of filter cake permeability
Permeability of the filter cake is largely a
function of the size, shape, and distribution
of solid particles. Larger spherical particles
tend to compact and create incompressible
filter cakes. Colloidal particles below 2 µ
give a better control of permeability. The
best results are obtained with bentonite
because of its colloidal, platelet-like struc-
ture. Under compression, these platelets are
progressively spread within the filter cake,
thereby reducing its permeability.
If a mud is flocculated, it will be necessary
to adequately disperse it to achieve a thin,
compressible filter cake. Filtrate can easily
pass around flocculated groups of particles.
Filtration control additives
Clays. The fundamental fluid loss control
agent for most water-based drilling fluids is
bentonite with a wide distribution of particle sizes down to less than 1 µ. The
colloidal, platelet-like structure is perfectly adapted to the production of a
compressible filter cake, and is further
assisted by the water of hydration surrounding each molecule.
Regular bentonite treatments are necessary
when solids control equipment is being
used, because some smaller particle sizes
are removed with the larger drilled solids.
Starch. Starch is a very popular mud additive that reduces fluid loss. In warm water,
the starch expands and absorbs some of the
water, forming small, amorphous masses
that plug the passages in the filter cake.
6-25
Horizontal Directional Drilling Training Program
Dispersants. Adding dispersants to the
mud helps form a resilient, thin, compressible filter cake by preventing flocculated
particles from aggregating, and promoting
an even distribution of particle sizes. Adequate mud dispersion allows more
bentonite than normal to be used while still
maintaining a low viscosity.
Some dispersants with a colloidal nature,
such as lignosulphonates and lignites,
assist fluid loss control by bridging formation pores.
CMC. CMC is a long-chain polymer that
can reduce fluid loss, depending on the
application. Different types of CMC are
available, depending on whether the mud is
plain bentonite, or bentonite with salt
water.
Measuring fluid loss by the various tests
available is not a precise criterion by which
to judge what is happening downhole—it is
only an indication. Factors such as depth,
formation, pressure, and temperature can
significantly alter the acceptable fluid loss
values. It is the responsibility of the mud
engineer to establish what is an acceptable
fluid loss figure for the job, and to make
any necessary adjustments with the most
suitable fluid loss control agents.
Solids Control
Introduction
Controlling and removing drilled cuttings
from the circulating mud is very important
in all drilling operations. A correctly
designed system must be able to process
the full flow of mud from the hole at all
times. Since the particles sizes can vary
from colloidal clays of less than 2 µ up to
rocks weighing a few pounds, a range of
specialized equipment is necessary to meet
this requirement.
The primary objective of any solids control
program is to remove all the cuttings on the
first circulation. If this is not achieved and
cuttings are recycled, they will be ground
by the drill bit into progressively smaller
particles until they cannot be effectively
removed by the solids control equipment.
When these fine solids below 2 µ accumulate in the mud, they give rise to high
viscosity, poor filtration, and increased
chemical treatment and dilution costs. The
condition is particularly exacerbated when
6-26
drilling reactive shales containing Namontmorillonite, because as the particles
hydrate, disperse, and then flocculate, there
is a significant increase in viscosity.
Some mud systems display a better tolerance to solids content than others, as
illustrated in Fig. 6.9. Mud A has a constant
viscosity with an increasing solids content
until the critical point is reached, after
which, for a small increase in solids content, there is a disproportionately large
increase in viscosity. Mud D displays similar characteristics, but because it has a
greater solids tolerance, the increase in viscosity due to increased solids content is
delayed relative to Mud A.
All muds will follow this characteristic
curve, and unless the solids content is
reduced by removal or dilution, they will
reach their own critical point and become
unpumpable.
Mud: Solids Control
Monitoring solids content
solids content, and suitable for use on a
weighted mud, is by solids retort. This
method produces results that are approximate at best, since this instrument was
designed to measure oil and not solids. The
solids measured in this way include soluble
salts, barite, commercial chemicals, and the
drilled solids.
The first indication of a solids problem will
often be an increase in flow line viscosity.
There are two methods of estimating the
solids content of a mud. The first is with a
nomograph, as shown in Fig. 6.17. However, remember that this nomograph is not
suitable when the mud is weighted with
barite. The second method of measuring
25 000
50 000
75 000
100 000
125 000
220
200
180
160
140
120
100
80
60
40
20
0
24
22
20
18
16
14
12
10
8
6
4
2
0
(Volume %)
120
(lb/bbl)
0
150 000
175 000
115
110
105
100
95
90
85
te
ud
M
sc
lid
So
w
on
t(
en
co
Ch
lo
rid
e
e
(lb ig
/g ht
al
)
nt
)
pp
de
In
nt
il
O
(v
80
m
x
c
ol on
um te
e nt
%
)
200 000
Fig. 6.17. Solids content of low-weight muds.
It is standard practice for mud engineers to
record total solids unless the operator specifically requests otherwise. You can
calculate the amount of drilled solids
present, but remember that the large potential error present when using the retort
appears proportionally larger in the final
drilled solids calculation. A more realistic
interpretation of the potential solids problem can be obtained by the PV and
Methylene Blue Test (MBT) results.
PV should be maintained as low as possible, as it does not contribute to good, stable
mud properties. Any increase in the drilled
solids retained in the mud will be shown by
an increased PV. The MBT will show an
increase only if the solids contain reactive
clays. Viewed together, the PV and MBT
results provide a more meaningful and
accurate presentation of drilled solids content than a solids retort result on its own.
6-27
Horizontal Directional Drilling Training Program
Fig. 6.18 shows mud weight vs. percent
solids content and indicates the range of
percent solids content that can be present
for a given mud weight. For example, with
a mud weight of 12 lb/gal, the solids content can vary from 13 to 27.5%. The ideal
operating zone is in the shaded area.
60
Percent solids
50
40
Fig. 6.18. Mud weight vs.
solids content.
30
20
10
0
9
10
11
12
13
14
15
16
17
18
19
Mud weight (ppg)
The solids removal system
Fig. 6.19 shows a possible solids size distribution in a mud prior to being processed
by solids control equipment. The effective
operating range of each of the commonly
available separating devices is shown. The
solids removal system can be compared to
a chain composed of numerous links. Since
any chain is as strong as its weakest link, it
is essential that each separating device
operate efficiently at full flow conditions.
Failure to meet this requirement will result
in increased mud costs because of the additional dilution required to maintain mud
properties.
5
100
4
80
Fig. 6.19. Particle size
distribution.
Percent solids
3
60
1 = Desilter
2 = Centrifuge
40
3 = Desander
2
0
6-28
4 = Screens
1
20
5 = Screens
0
2
20
50
100 200
500
Particle size (µ)
1000
Mud: Solids Control
Table 6.2 illustrates the range of cuttings
that are typically encountered, their classi-
fication, and the equipment best suited for
their removal.
Table 6.2. Cuttings classification and recommended removal equipment.
Solids size range
Greater than 2000 µ
2000–250 µ
250–74 µ
44–74 µ
2–44 µ
Less than 2 µ
Solids classification
Large cuttings, cavings
Medium cuttings
API sand
Silt
Barite
Colloids to clay
The standard used for measuring particle
size is the micron, which is a thousandth of
a millimeter or 1/25,400 of an inch. The
level of mechanical separation equipment
Removed by
10-mesh screens
10–80-mesh screens
Desander, desilter, mud cleaner
Desilter, settling tank
Clay ejector, centrifuge
Centrifuge
required on a typical onshore or offshore
drilling rig is covered in the following
sections.
Shale shakers
This is the first and most important solids
control device that the return mud encounters. Normally, you will have two or three
shale shakers onsite and they should be
capable of handling at least 1300 gal/min
of weighted drilling mud through 20- or
30-mesh screens. Shakers are classified by
screen arrangement, location of vibrator,
capacity, and screen type.
Screen arrangement. For most soft-rock
drilling, the multiple deck arrangement of
parallel screens is preferred. This allows
you to use very coarse 12-, 20-, or 30-mesh
screens on top to remove the larger cuttings, cavings or mud balls. This reduces
the load on the fine screens below, which
improves separation efficiency and
increases screen life.
In more hostile offshore environments,
older styles of shakers installed on floating
rigs have proved to be very inefficient, and
large volumes of mud have been lost
because of the rig pitching during bad
weather. The screens of these older-design
shakers were prone to binding with larger
cuttings and mud balls, thus impeding sep-
aration, reducing screen life, and increasing
mud losses.
Position of vibrator. The vibrator on multiple deck shakers is generally balanced at
the center of gravity, thus imparting a circular vibratory motion. This greatly
improves cuttings transport down the
screen. In the case of a vibrator located
above the screen, the motion is less regular
and this aggravates the buildup of cuttings
on the discharge end of the screen.
Screen type. The type of screen support is
another important feature to consider when
selecting shale shakers. The bottom-supported system used on most rig shakers is
stronger than the top-supported system. If
you use fine mesh screens, you will also
need a backup screen of coarse plastic or
stainless steel mesh. The shaker screens
made to API specifications have square
openings, although rectangular-shaped
openings permit the use of heavier gauge
wire with resulting improvements in screen
life. A slight decrease in separation efficiency will be experienced with rectangular
screens, but this is offset by the increased
fluid capacity of these screens.
6-29
Horizontal Directional Drilling Training Program
Screen selection is largely a matter of experience. A good guideline is to use the
finest-mesh screen that will give minimum
mud losses. See Table 6.3 for commonly
available mesh sizes.
Table 6.3. Mesh size and equivalent US
screen grade.
Mesh size
(µ)
US screen
grade
762
541
381
234
177
104
74
44
20
30
40
60
80
150
200
325
Sand traps
Sand traps or settling pits are included in
this section because of their vital importance in the chain of solids control
equipment. Anyone who has struggled to
dump several feet of accumulated silt and
sand from these traps will appreciate their
importance.
Sand traps should have as large an area as
possible and should not be used as suction
compartments, as this disturbs the settling
action of the solids. The base of the tanks
should be angled at about 45˚ toward a
large dump valve. These tanks should not
be dumped during connections unless it is
unavoidable, as difficulties can occur when
trying to close the dump valve with an
accumulation of sand on the seat. Drilling
is not paused when the mud engineer clears
this blockage and, consequently, large
quantities of clean mud can be lost when
circulation is prematurely resumed. Ideally,
you should clean out these tanks during a
round trip when more time is available.
During periods of high penetration, check
the tanks more frequently and dump as
required to avoid solids contamination of
the mud. In this case, you should stop all
drilling and circulation and do not resume
until the dump gates are properly sealed.
Desander
Removing solids by gravity settling has
long been an accepted practice in the industry. The methods vary from normal gravity
settling pits or ponds, to cone-type
mechanical equipment where higher gravitational forces are developed to improve
settling (Fig. 6.20). Whatever method is
6-30
used, the principle remains the same and is
governed by Stoke’s Law, which states that
the settling rate of a solid above clay size is
a function of the acceleration due to gravity, particle size, specific gravity of the
particle, specific gravity of the liquid
phase, and viscosity of the liquid phase.
Mud: Solids Control
4
3
2
5
1
6
7
8
9
10
11
Fig. 6.20. Desander.
mud mixture enters
1 Pressurized
tangentially here
2 Feed in
3 Feed chamber
4 Liquid discharge
5 Vortex finder
moves inward and upward
6 Liquid
as a spiraling vortex
rotation develops centrifugal forces in
7 Slurry
cyclone
are driven to the wall and moved
8 Solids
downward in an accelerating spiral
9 Trinut for adjusting apex size
10 Apex
11 Solids discharge
6-31
Horizontal Directional Drilling Training Program
For any given mud, one of the parameters
that can be changed to increase the settling
rate is the acceleration due to gravity in
mechanical cone-type equipment:
Vs = 2GD2(Pc - Pm)/92.6µ
where:
Vs = settling velocity (ft/sec)
G = acceleration due to gravity
(ft/sec2)
D = largest cutting diameter (in.)
Pc = density of cuttings (lb/ft3)
Pm = density of mud (lb/ft3)
µ = viscosity of mud
(0.000673 x viscosity cp).
G is increased by injecting the mud tangentially and at high pressure into the top of
the cone (Fig. 6.20). The resulting circular
motion produces a centrifugal force and a
consequent separation of solids and liquids.
The speed at which the mud swirls at a
constant pump pressure is a function of
cone size. The smaller the cone, the faster
the mud swirls. For this reason, desanders,
which remove large particles, generally
have 6- or 8-in. diameter cones.
Desilters, which remove smaller particles
down to colloidal size, have 4-in. cones; 2or 3-in. diameter cones can be used to
either discard colloidal material or recover
barite.
The whirling stream of mud entering near
the top of the cone is directed downward
toward the apex of the cone (and underflow) by a vortex finder extending into the
cone body from the top. The larger and
heavier particles settle to the outside by
centrifugal force and migrate down the
cone to the underflow, where they are discarded. The smaller, lighter particles and
the liquid fraction reverse their direction,
moving up the vortex finder pipe and back
into the mud system.
For the solids removal equipment to match
a circulating rate, usually more than one
cone must be used. A number of cones are
manifolded together in parallel to increase
their capacity. Desanding cones have the
advantage of being able to handle large volumes of mud (up to 1000 gal/min), but
have the disadvantage of making coarser
particle size cuts (from about 80 µ
upward), and therefore do not discharge the
finer particle size solids. To obtain the best
results from a desander, you should install
it with its own centrifugal pump that feeds
it at a steady pressure. Direct the overflow
into another pit or compartment that is
downstream from the desander pump suction. You can check whether the
hydrocyclone is operating properly by
placing a finger in the bottom discharge of
the cone. When operating correctly, the solids will be discharged as a fine spray and
you will feel a slight suction in the orifice.
Desilter
Generally, a 4-in. cone is used for desilting.
It is important to link the cones in parallel
so that their capacity can match the volume
of mud being circulated.
In a well-designed 4-in. cone, the median
cut is about 40 µ. It is very important in
desilting not to get a cut low enough to
remove the finer clays, which contribute to
good wall-building characteristics in the
mud.
Some important advantages to the proper
desilting of drilling fluids are:
6-32
•
thinner filter cake in water-based drilling fluids, minimizing the possibility
of differential wall sticking
•
reduced drill pipe torque due to better
filter cake characteristics
•
reduced amount of water dilution
required for solids control, minimizing
the amount of chemical additions,
especially where low weights and fluid
loss control are important
•
minimum mud weights with less liquid
loss than is possible by discarding
whole mud
Mud: Solids Control
•
longer bit life obtained by removing
abrasive drilled solids and sand
•
increased penetration rates
•
increased parts life on mud pumps and
related equipment.
Mud cleaner
Mud cleaners are of particular value when
drilling large-diameter holes with weighted
drilling muds. The desilter will perform an
efficient job in removing the sand- and siltsized particles that pass through the primary shale shaker. However, the desilter
may discharge large amounts of the
coarsely ground fraction of barite and liquid mud, so using it may get expensive.
The mud cleaner passes the underflow
from the cones through a vibrating screen.
All of the liquid is returned to the active
mud system, while the drilled solids are
discharged. The median particle size cut is
determined by the grade of screen mesh
used. If screen life is acceptable, the
200-mesh screen is preferred.
The mud cleaners are an excellent solids
control tool and will result in considerable
savings if you give careful attention to their
installation and continued operation. A
capacity of 800 to 900 gal/min is required
of any mud cleaner to be effective. However, like all other hydrocyclone equipment, they are susceptible to alternations in
the feed pressure to the cones.
If the shakers are bypassed for any reason,
the accumulation of large cuttings will rapidly plug the cones and render them
inoperative. This must be avoided. You
should pay particular attention to ensure
that the shakers are not bypassed.
Centrifuges
The decanting centrifuge also works on the
same principle as the hydrocyclone, except
that the cone is installed in the horizontal
plane and rotates at high speed (Fig. 6.21).
Inside the cone, a screw conveyor mounted
on a hollow spindle is installed. The conveyor rotates in the same direction as the
outer cone but at a slightly lower speed.
Mud is injected through the hollow spindle
of the conveyor, where it is thrown outward
into the annular ring of mud called the
pond. The level of the pond is determined
by the height of the discharge ports at the
larger flanged end of the cone. As solids
settle against the inner wall of the cone
because of centrifugal force, the action of
the screw conveyor pushes them along the
cone toward the smaller end. They are discharged at the small end as dried particles,
while the liquid is discharged at the larger
flanged end through the discharge port.
It is important when operating the centrifuge to dilute the mud with water at a
predetermined rate to reduce the viscosity
and maintain the separation efficiency of
the machine.
You should use a centrifuge on a weighted
mud system when you observe increases in
viscosity and gel strength. However, if the
fine particles are removed by the centrifuge, you will have problems with fluid
loss control and will need to add fresh
chemicals. In certain mud systems, you
need to compensate for this loss to maintain mud parameters, and add bentonite to
restore the wall-building quality of the
mud.
The dilution water added at the centrifuge
is discharged with the rest of the effluent,
but treatment will be required to maintain
the original balance of the system.
The operation of the centrifuge can be
changed such that in the case of an
unweighted mud, or an inhibitive or oilbased mud where the liquid phase is very
expensive, the liquid discharge can be
saved and the underflow discarded. In this
case, the only liquid loss is that adhered to
the underflow solids.
6-33
Horizontal Directional Drilling Training Program
2
3
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1
5
4
Fig. 6.21. Centrifuge.
1 Feed in
2 Bowl rotates, creating high centrifugal force
rotates same direction as bowl, but at slightly
3 Conveyor
lower speed to convey coarse solids
4 Coarse solids discharge (underflow)
5 Clay liquid discharge (effluent)
A secondary application of the decanting
centrifuge is in processing the underflow
from the desilting hydrocyclones. As the
hydrocyclones are designed to process the
full flow of a mud system, the centrifuge
can successfully handle the partial flow of
the underflow, drying out the solids dis-
6-34
charged by the desilter. This type of
operation is particularly advantageous
when the liquid phase of the mud is very
expensive. A further justification for this
operation is where environmental controls
dictate complete recovery of the liquid
phase.
Appendix A: Units and Abbreviations
2-D
3-D
AC
Al
ANSI
API
AWG
Az
b, bbl
BHA
bpf
C
Ca
Cl
cm
CMC
cp
cum
°C
°F
DC
Dh
two-dimensional
three-dimensional
alternating current
aluminum
American National Standards
Institute
American Petroleum Institute
American Wire Gauge
azimuth
barrel
bottomhole assembly
blows per foot
carbon
calcium
chlorine
centimeter
carboxyl methylcellulose
centipoise
cumulative
degrees Centigrade
degrees Fahrenheit
direct current
hole diameter (in.)
F
ft
gal
H
HDD
HDPE
HPb
outside diameter of drill pipe
(in.)
Young’s modulus; modulus of
elasticity
Fanning friction factor (dimensionless)
force
feet
gallon
hydrogen
horizontal directional drilling
high-density polyethylene pipe
hydraulic horsepower at the bit
hr
ID
IF
IFb
hour
inside diameter of drill pipe (in.)
interfering force
impact force at the bit (lb)
in.
K
inch
consistency index, Power Law
model
frictional drag coefficient
Dp
E
f
Kf
kg
km
Kpa
l
L
lb
LW
µ
m
ma
MBT
mg
Mg
min
mm
Mpa
MSL
n
Na
Nr
Pa
Pa
kilogram
kilometer
kiloPascal
liter
length of annulus (ft)
pound
long wave
mud viscosity (cp)
meter
milliangstrom
Methylene Blue Test
milligram
magnesium
minute
millimeter
megaPascal
mean sea level
exponent in Power Law Model
sodium
Reynolds number (dimensionless)
oxygen
outside diameter of drill pipe
(in.)
pressure loss for any section of
length L (psi)
Pascal
annular pressure drop (psi)
Pb
pressure loss through the bit (psi)
Pc
sum of circulating pressure
losses, excluding losses at the bit
(psi)
polycrystalline diamond compact
particle diameter (in.)
O
OD
P
PDC
Pd
Pg
Pp
surface pressure required
break gel (psi)
drill pipe pressure drop (psi)
ppg
ppm
Ps
parts per gallon
parts per million
surge pressure (psi)
Psp
stand pipe pressure (psi)
PV
Q
plastic viscosity (cp)
circulation rate (gal/min)
to
Horizontal Directional Drilling Training Program
R
S
SDR
sec
Si
SMYS
Sr
Ss
SW
θ
t
T
TCI
TVD
UHF
A-2
radius of a drill pipe (in.)
sulfur
standard dimension ratio
second
silica
Specified
Minimum
Yield
Strength
shear rate
shear stress
short wave
Viscom readings (lb/100 ft2)
thickness
tension
tungsten carbide insert
true vertical depth
ultra-high frequency
v
V
Va
Poisson’s ratio
average fluid velocity (ft/min)
average annular mud velocity
(ft/min)
Va(max) maximum annular fluid velocity
(ft/min)
critical velocity of mud (ft/min)
Vc
VHF
VLF
Vn
very high frequency
very low frequency
velocity through nozzles (ft/sec)
VOM
Vp
Vs
voltage output meter
average velocity of particles
(ft/min)
slip velocity of particles (ft/min)
YP
yield point (lb/100 ft2)
Appendix B: Glossary
A
accuracy
aggregation
angular target
anion
annular velocity
apparent viscosity
as-built
atom
atomic weight
attapulgite
azimuth
quality or state of being exact or precise
process of clay particle association by face-to-face
arrangement
building or holding inclination to a particular number
atom that has acquired a negative charge by gaining an
electron
fluid velocity in the borehole annulus
value of viscosity at any given shear rate
drawing depicting the final location of an installed
pipeline
smallest particle of an element, exhibiting all the chemical properties of that element
measure of the number of protons and neutrons contained
in an element’s nucleus and, to a lesser extent, the number of electrons
chain-structure clay of hydrous magnesium aluminum
silicate
angle between the horizontal component of the borehole
at a specified point measured clockwise from magnetic
north
B
back reaming
ball up
Barlow formula
barrel reamer
beam
bentonite
Bingham plastic model
bottom limit
bottom’s up
breakover
bullet-nose reamer
enlarging the hole from the exit side of the crossing
clay material filling all the areas between the reamer teeth
or cutter blades, so that the inserts make no contact with
the formation
formula used for calculating hoop stress
reamer with a center shaft mounted concentrically in a
cylinder of pipe with a wide range of diameters and
lengths
solid with a length at least five times its height
sodium montmorillonite; expandable clay material that
can absorb large quantities of water
mathematical model to express plastic flow
horizontal line denoting the base of the maximum allowable ground cover above a pipeline
measure of the time required to displace a known quantity of fluid from the bottom of a hole to the surface
bend through which the pipe must pass from its horizontal position on the rollers to its alignment with the hole
(also: overbend)
same as a barrel reamer, only with weld cap ends
Horizontal Directional Drilling Training Program
C
catenary
cation
centralizer
chisel teeth
Class Location
colloid
compound
compressive stress
Construction Type
conventional hole opener
core buster
cradle
critical velocity
cutter sets
cuttings
path that the pipe must follow to limit the stresses in the
pipe and load on the cranes or sidebooms
atom that has acquired a positive charge by losing an
electron
tool run in front of the primary cutter to hold the cutting
assembly up in the center of the hole
used when encountering cobbles or boulders embedded
in normal soils
class of a pipeline section as per applicable code
particle 2 m or less in size
material made up of two or more different kinds of atoms
measure of the maximum compression of a material
before it experiences failure
type of construction for a pipeline section
cast hole opener designed for use in rock; has a center
shaft with three to six arms onto which are mounted
roller cones
set of blades in front of the hole opener designed to keep
rock pieces from accumulating in the hole opener, and to
centralize the hole opener
pipeline roller attached to lifting equipment
velocity of a fluid at which there is a transition from one
flow pattern to another
numbered teeth sets that are fitted onto hole openers
formation materials removed from the hole and suspended in the drilling fluid
D
dead man
decanting centrifuge
deflocculation
desander
design pressure
desilter
dip poles
direction
dispersion
dissociation
dogleg severity
dynamic filtration
B-2
anchorage for the rig to oppose pull/thrust forces
solids control device used with weighted mud systems
process of breaking up clay particles by neutralizing the
charges on the platelets via a chemical catalyst
solids control device that removes sand-sized particles
from a fluid
value of the pressure used for pipeline design.
solids control device that removes silt- to colloidal-sized
particles from a fluid
magnetic north and magnetic south poles
borehole direction referenced to magnetic north
process of breaking up clay particles; opposite of
aggregation
process of separating a molecule into ions by dissolving
the material in a solvent
total 3-D change of angle between two given points
filtration that occurs when the mud is flowing
Glossary
E
elastic instability
elastic limit
electron
element
entry angle
entry point
entry side
equivalent weight
exclusion area
exit angle
exit point
collapse of a body even though the load applied to the
body does not create stresses in excess of yield
maximum stress under which a specimen may be subjected and return to its original length upon load release
part of an atom with a negative electrical charge
material made up of a single atom, or atoms of only one
kind
angle of entry of drilling tool into the ground; maximum
of 18° and minimum of 6°
point where the drill pipe enters the ground in front of the
rig
side where drilling tool enters the ground
an atom’s atomic weight divided by the charge of the ion
it forms during dissociation
area delimited by vertical lines from the banks and the
lowest of river bottom, scour level and dredging area,
plus minimum pipeline cover
angle of pipeline exit from the ground; maximum of 12°
and minimum of 4°
target expressed in distance from entry, elevation, and a
position left or right or directly on a centerline
F
Fann Viscom
filter cake
filtrate
filtration
fishing
floater
flocculation
fly cutter
forward reaming
fragile gel
device used to measure fluid viscosity (also: Fann VGM)
lining on the wall of the bored pathway
fluid that passes through the filter cake into the formation
loss of filtrate from the mud (also: fluid loss)
retrieving tools from the hole following a tool failure
blunt-nosed assembly on the end of the drill string; used
to push the assembly through a pre-reamed pathway
without sidetracking
process of clay particle association, arranged either edgeto-edge or edge-to-face
reaming device that has a center shaft with three or four
spokes
enlarging a hole from the entry side
gel with a small difference in readings between the 10sec and 10-min gel strengths; desirable gel condition
G
gauge
gel strength
scale of measurement of a bit, reamer, hole opener, or
wire
measure of the electrochemical attractive forces present
in a static liquid
B-3
Horizontal Directional Drilling Training Program
gravel shield reamer
ground pressure
G-Total
unconventional bottomhole assembly used for rock and
gravel crossings
weight of the ground on top of the pipeline
accelerometer reading that detects movement of the
probe during forward and reverse current applications
H
hoop stress
horizontal plan
H-Total
stress caused by internal pressure in the pipeline during
testing or operations
projection in plan view of the left or right position of the
bore against a planned centerline
magnitude of the earth’s magnetic field
I
inclination
inside diameter
ion
angle between the vertical and the axis of the borehole at
a chosen distance from entry
internal diameter of a pipe
atom having given up or gained an electron that is no
longer at zero potential
K
Kennemetal teeth
cutting teeth used on cutters and reamers
L
lost circulation
failure of pumped drilling fluid to recirculate to the mud
return pit
M
Marsh Funnel
maximum bending stress
maximum operating pressure
maximum pipeline length
maximum pipeline size
measured distance
mill tooth cutters
minimum pipeline cover
mixture
molecules
monel
B-4
device used to measure fluid viscosity
measure of the compression on the “outside fiber” and
“inside fiber” of a pipe
value of the maximum pressure in the pipeline during
operation
between 5000 and 6000 ft (1500 and 1800 m)
48 in. (1.2 m)
total length of the drill pipe and that part of the BHA up
to the probe’s sensor, measured from the entry point
bladed teeth used in soft rock formations
minimum soil height above the pipe to ensure that it does
not rise toward the surface when empty
combination of two or more components in varying proportions that retain their own properties
compounds consisting of groups of atoms
non-magnetic drill string
Glossary
montmorillonite
mud cleaner
sheet-like clay that can absorb water; key component of
bentonite
solids control device, used in conjunction with desanders
and desilters
N
neutron
Newtonian fluids
nominal diameter
non-Newtonian fluids
north, geographic
north, magnetic
north, map
nucleus
part of an atom with a mass nearly equal to that of a proton and having no electrical charge
fluids in which shear stress is proportional to shear rate
inside diameter of standard wall thickness pipe, up to 12
in.
fluids that lack constant viscosity over a range of shear
stress/shear rate ratios
direction from any point on the Earth’s surface toward the
geographic north pole (also: true north)
uncorrected compass north; differs from geographic
north by the amount of magnetic declination at any given
point
Lambert north
part of an atom that contains most of the mass and consists of protons and neutrons
O
operating pressure
outside diameter
overbend
value of the pressure during pipeline operation
external diameter of a pipe
see breakover
P
PDC teeth
pH
pipe length
pipe side
plastic limit
plastic region
Poisson’s ratio
position target
pre-reaming
profile
progressive gel
manmade polycrystalline diamond compact teeth; used in
shales
measure of the hydrogen ion concentration of a fluid,
reported on a logarithmic scale from 1 to 14
distance measured along the course of the borehole from
the entry point
exit point; side where the pipeline exits the ground
ratio of fine solids in the drilling fluid relative to the
amount it can carry (also: plastic viscosity)
region where a material is strained beyond the elastic
limit, causing permanent deformation
ratio of lateral strain to longitudinal strain
subjective target (e.g., “straight ahead”)
enlarging the hole before pulling the pipeline
projection of the vertical position of the bore against a
planned vertical profile
gel with a large difference in readings between the 10-sec
and 10-min gel strengths; undesirable gel condition
B-5
Horizontal Directional Drilling Training Program
proportional limit
proton
pullback
punchout
on a strain vs. stress curve, the point at which the plot is
no longer linear
part of an atom with high mass and a positive electrical
charge
pipeline installation
point at which the drill string exits the ground
R
radial angle mismatch
radial angle
radial intensity mismatch
radial intensity
radius
reaming
reaming and pulling
repeatability
restrained pipeline stress
Reynold s number
rheology
difference between actual and theoretical measurements
indicator of improper coil connections to the Tru Tracker
control box
difference between actual and theoretical measurements
indicator of the current strength measured by
magnetometers
expression defining the exact curvature of a line,
expressed in feet or meters
enlarging a hole from one size to another size of greater
diameter
reaming the hole simultaneously as the pipe is pulled
ability to produce the same result again and again
stress in one direction that creates a stress of the same
sign in the perpendicular direction if the material is
restrained from expanding or contracting in that direction
numerical quantity used to characterize the type of flow
in a hydraulic structure in which the resistance to flow
depends on the viscosity of the liquid and inertia
science of flow and deformation of fluids
S
sand trap
sepiolite
shale shaker
shear rate
shear stress
shear thinning
slip velocity
solids retort
stabilizer
standard dimension ratio
B-6
solids control device that collects sand-sized particles
from the drilling fluid
rod-structure clay similar to attapulgite
solids control device that filters large cuttings from the
drilling fluid
rate at which one layer moves relative to an adjoining
layer
force required to move a unit area of a layer of liquid
with respect to an adjacent layer
pseudoplastic characteristic of a fluid that leads to lower
viscosity at the bit
rate at which cuttings settle in a stationary fluid
method of measuring solids content of a fluid
tool run behind the primary cutter for stabilization and to
keep the primary cutter from bouncing and tilting
ratio of the pipe outside diameter to the minimum pipe
wall thickness
Glossary
static equilibrium
static filtration
Stoke’s Law
strain
stress
when, at any point x, the moment of all forces applied to
a beam, either at the right or left of that point x, values
are equal
filtration that occurs when the mud is not flowing
states that the settling rate of a solid above clay size is a
function of the acceleration due to gravity, particle size,
specific gravity of the solids particle, specific gravity of
the liquid phase, and viscosity of the liquid phase
amount by which a dimension of a body changes when
the body is submitted to a load, divided by the original
value of the dimension
force per unit area
T
temperature stress
tensile stress
test pressure
thixotropy
tool face
traction stress
tripping in
tripping out
tungsten carbide inserts
stress caused by a temperature change
measure of the maximum stretch of a material before it
experiences failure
value of the pressure used for pipeline testing
property of a mud that allows it to change from a gel to a
liquid when shaken, but to increase in strength upon
standing; helps manage cuttings in suspension
measurement of the position of the bias of a bottomhole
assembly perpendicular to the axis of the borehole
longitudinal stress
entering the borehole with the drill pipe
removing the drill pipe from the borehole
cutting teeth on the roller cones of hole openers that cut
or break the rock
U
ultimate strength
point at which a material is strained beyond the plastic
region, causing material failure
V
valence
vertical depth
vertical section
viscosity
viscous flow
the number of hydrogen atoms with which an atom can
combine
vertical distance from the surface reference elevation
datum to the probe’s sensor
mathematical calculation to express 3-D positions in two
dimensions
measure of a fluid’s resistance to flow
occurs when a linear relationship is established between
shear rate and shear stress
B-7
Horizontal Directional Drilling Training Program
W
water-based mud
wireline leak
wireline open
wireline short
mud made up with water as the continuous liquid phase
electrical drain not yet large enough to stop probe
operation
zero continuity between the interface and the probe
electrical spike causing the amp needle to move to maximum or blow the power fuse
Y
yield
yield point
yield stress
Young’s modulus
(of a clay): the number of barrels of 15-cp mud that can
be produced from 1 ton of dry clay by adding fresh water
measure of the electrochemical resistance to flow as a
result of the electrical interaction between the surface of
adjacent particles
initial resistance encountered in a fluid before flow is
established
modulus of elasticity; ratio of unit stress to unit strain
within the proportional limit
Z
Z axis interference
B-8
magnetic interference