1. International majors make waves in the Browse Basin.
MARCH 2015
■ AOG 2015: Who Has The Goods?
■ An Australian Pipe Dream
■ Why Midcaps Will Drive Growth
■ AOG 2015: Who Has The Goods?
■ An Australian Pipe Dream
■ Why Midcaps Will Drive Growth
991-994_Covers_0315_991-994_Covers_0315 2/17/15 5:44 PM Page 991

2. D
rilling technology advance-
ments over the past several
decades have been leveraged
in recent years to transform our in-
dustry and fuel the“Unconventional
Revolution.”These incremental devel-
opments in drilling technology
evolved gradually since the OPEC oil
embargo in 1973 and the subsequent
oil shock in 1979.These events and
other geopolitical developments
drove an explosion in global drilling
activity,especially for highly complex
offshore development projects that
required huge,upfront capital invest-
ments and pushed the limits of exist-
ing technology.
Thus,this“new age”of drilling
technology has led to more sophisti-
cated directional,then extended
reach,and now horizontal well
drilling programs throughout the
world,but especially in North Amer-
ica in unconventional resource plays.
Over and over again,technology bar-
riers have given way to allow today’s
advanced,highly demanding horizon-
tal well programs that commonly use
“manufacturing mode”processes for
achieving results never before antici-
pated or even believed possible.
Even with these incredible advance-
ments,the industry continues to inno-
vate and develop new drilling systems
for achieving faster and faster drilling
rates.But now,with these astonishing
Lessons learned from the horizontal drilling boom in North
America can be applied to onshore drilling in Australia.
A Path to Better
Horizontal Drilling
BY KC OREN,
Horizontal Solutions International
OGIAustralia.com | March 2015 HartEnergy.com68
Technology
68-73 TECH_Horizontal Drilling_68-73 TECH_Horizontal Drilling 2/17/15 5:42 PM Page 68

3. gains,the industry is hitting other
boundaries and facing conflicting limi-
tations due to interdependencies in
closed-loop drilling systems.The ques-
tion then becomes,can essential geo-
logical and drilling data needed to
support the evaluation of the targeted
strata keep up with rapid drilling rates?
If not,as a result,a new dilemma has
emerged for the integrated drilling,
geosciences and production engineer-
ing team.
Conundrum
Both drilling and geologic data for true
drilling-time decision support is essen-
tial,but when data is limited by
MWD/LWD data transmission speeds
for receiving the multitudes of varied
measurements topside,other issues
emerge as critical and limiting ele-
ments.Acquiring downhole data and
sending it uphole via binary data
transmission for informed decisions
by the team is an incredibly complex
operation,but skillfully and reliably
carried off by our drilling service com-
panies every day.
However,downhole data transmis-
sion speeds have not kept pace with
improved drilling rates,creating an
information“log jam”by limiting criti-
cal data flow from the subsurface.This
bottleneck further hinders the team’s
ability to make timely data assess-
ments for evaluation and then execu-
tion by the integrated asset team.
One challenge is low bandwidth
inherent to MWD/LWD transmission
systems—both from the multitude
of desirable petrophysical measure-
ments such as natural gamma ray and
azimuthal resistivity competing for the
binary data channel capacity (mud col-
umn pulses) and drilling data such as
azimuth,inclination,tool face orienta-
tion,bit vibration,downhole torque
and drag and continuous inclination.
The combination of petrophysical and
drilling data is essential to basic geo-
navigation principles and,ultimately,
in application of that analysis for
geosteering decisions for drilling
optimum horizontal wells.
But to make matters even worse,
geoscience and drilling disciplines’
competition for data channels is exac-
erbated by the real-world challenges
of binary data transmission rates
and signal attenuation through the
fluid (mud) column—this problem
becomes even more acute as we
achieve deeper drilling depths and
ever-increasing lateral lengths—thus
reducing achievable and useful data
rates even further.
Another factor is the applied
measurement system’s sonde position
well behind the bit,delaying the time
that the various sensors actually
measure their respective physical
properties downhole in relative posi-
tion to the drilling system,even
before they are processed and sent
uphole,further delaying the timeli-
ness of the information topside.
So,each of these noted individual
difficulties become worse when
combined collectively.And they are
even more severe as competition and
inherent tradeoffs between disciplines
create new challenges for the asset
team members as operators continue
to leverage technology to drill even
faster,deeper and further in their hor-
izontal well applications.
Exploring the tradeoffs
What’s not to like about these advance-
ments for drilling faster?As enviable as
this situation would have been in the
1980s or even the last decade,achiev-
ing the goal of optimising production
by leveraging drilling technology with
multimillion-dollar horizontal well-
bores is being questioned.
Are we possibly applying too much
technology,too soon,in our quest to
meet short-term departmental goals of
faster drilling rates (ROP) with less
non-productive time (NPT),while
missing the immediate objective of
high initial production (IP),and ulti-
mately,maximising estimated ultimate
recovery and achieving greatest possi-
ble rate of return on investment (ROI)?
March 2015 | OGIAustralia.com 69HartEnergy.com
Magnitude of error for well-maintained
survey instrumentation (MWD systems):
Azimuth: 0.75º to 2.0º
And human-introduced errors
can far exceed the survey tool’s intrinsic error!
Inclination: 0.25° to 0.75°Greater error in azimuth
Used by Permission - based upon
SPE 79917 Stockbausen and Lesso
TVD: +/-2 to 4' per 1000'
E/W: +/-3' per 1000'
N/S: +/-6' per 1000'
FIGURE 1: ELLIPSES OF UNCERTAINTY–SYSTEMATIC ERRORS
The magnitude of error of an MWD surveying system in Stockhausen’s and Lesso’s
research is demonstrated. (Source: Society of Petroleum Engineers)
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4. OGIAustralia.com | March 2015 HartEnergy.com70
Wellbore position
uncertainty
Problems with determining the
wellbore’s true pathway and precise
location at any given time is well un-
derstood and documented.Yet,many
companies do not fully consider this
issue when making critical decisions
in both the planning and execution
phases of drilling horizontal wells.
As has been documented in the
Society of Petroleum Engineers
paper by Stockhausen and Lesso
(SPE79917),the magnitude of error
of an MWD surveying system in their
research has been demonstrated and
is illustrated in Figure 1.
Fortunately,industry guidelines
for quantifying both systematic and
random errors are readily available in
the public domain for understanding
and managing the impact of these
inaccuracies and sometimes flawed
procedures.Stockhausen and Lesso’s
research cited these problems com-
mon to MWD systems,and raise the
possibility of further human-induced
errors and other drilling industry
“best practices”that have become
commonplace in achieving faster-
and-faster drilling rates,especially
for horizontal wells.
Current drilling practices
Figure 2 illustrates two common
drilling“best practices”that introduce
systematic error into the wellbore posi-
tion uncertainty formula.Drilling long,
course length intervals between survey
stations is one element leading to well
position modeling errors:surveys are
typically taken either every 10m or
30m depending upon the drilling inter-
val in the curve.
A second drilling practice further
introducing systematic error is sliding
after each connection (survey station)
and then rotating out the remaining
drilling interval until reaching the next
connection point where another survey
is then taken.The net of those two
common drilling practices is com-
pounding both errors (long survey
intervals and calculation errors in the
calculation model.)
This problem is shown in Figure 3,
with an exaggerated illustration using
the radius of curvature calculation
model.The resulting error is that the
calculated position is deeper than
the actual wellbore position in this
case.Once again,these errors are
compounding over the course of the
well and poor decisions may be possi-
bly based upon an inaccurate wellbore
location versus the true well path.
Furthermore,Stockhausen and
Lesso highlight that survey calculation
model assumptions,along with these
common survey interval and drilling
practices,are all sources contributing
to systematic error resulting in greater
and greater uncertainty.
Theminimumcurvaturesurveycal-
culationmodelshowninFigure4clearly
illustratesthatanyvector-basedcalcula-
tionmodelhasinherentlimitations
whenfittingasmoothradiusof curva-
ture.Inthiscase,asphericalcalculation
model (minimum curvature method)
acrossanundulatingwellborecourse
willyieldsubsurfacepositionalerrorsin
TVD(X),aswellasnorthing(Y)and
easting(X)positions.Thiserroris
cumulativeandmayrendersignificant
errorsasthewellisdrilledaheadtoTD.
One more procedure for reducing
wellbore position uncertainty for con-
sideration,and an opportunity to
improve confidence,is the recom-
mended best practice of taking more
surveys on shorter intervals.Unfortu-
nately,this requires drilling to stop,cir-
culate off-bottom and taking a full
directional survey more often as a
means to more precisely measure,cal-
culate and“track”a truer course of the
wellbore.Naturally,the mere mention
of“stop drilling”is frowned upon by
the drilling team—increasing NPT
and lowering ROP—key metrics that
will raise ire of any driller when these
benchmarks are negatively impacted.
But perhaps less impactful to the
drilling team is to at least apply this
practice (more surveys) at the end of
any drilling transition point between
“drilling states.”That is,a status-change
from either a rotary drilling (rotating)
to sliding (oriented TF) mode or from a
sliding to rotational drilling interval.
More frequent survey stations improve
the accuracy of tracking the position of
the wellbore,thereby increasing the
level of wellbore position certainty.
So,while taking more frequent sur-
veys has been documented and pro-
moted to improve definition of a
calculated wellbore path,it is still con-
flictive to achieving positive drilling
marks and,as a consequence,it is
greatly objectionable to the drilling
team,and is rarely followed.
A possible compromise is yet
another less impactful procedure that
calls for“rotating out”of a survey sta-
tion (after a drill pipe connection)
and once again rotating out after the
slide interval (curved section) before
Technology
Systematic survey practices
- 30' surveys in the curve
- 90' surveys in the lateral
Systematic drilling practices
- Survey, Slide, Rotate
Slide
Rotate
Result:
Compounding both errors
- Yielding measurement bias
and calcutated TVD error
FIGURE 2: SYSTEMATIC SURVEYS AND INDUSTRY “BEST PRACTICES”
There are two common drilling“best practices”that introduce systematic error into the
wellbore position uncertainty formula.(Source:Ryan Directional Services,a Nabors company)
Even with these
incredible
advancements,
the industry
continues to
innovate and
develop new
drilling
systems for
achieving
faster and
faster drilling
rates.
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5. HartEnergy.com March 2015 | OGIAustralia.com 71
making another connection.Simply
put,this process calls for“rotate-slide-
rotate”intervals between survey sta-
tions (connections).The amount of
sliding required depends upon the
amount of course correction or“steer-
ing”that is necessary.This simple
change in procedure as recommended
by Stockhausen and Lesso renders a
better survey calculation model result.
Thus yielding a more accurate repre-
sentation of the actual well path and
projected bit position while drilling.
Continuous inclination
While using these recommended
drilling best practices can be employed
to mitigate some of the wellbore path
uncertainty challenges,there is an even
better option:continuous survey data.
The goal of continuous survey mon-
itoring is similar.That is to overcome
the lack of directional survey data
(inclination and azimuth) between
survey stations,thereby reducing
uncertainty and more closely tracking
your true course along the way.
As Figure 5 illustrates,when contin-
uous inclination is tracked regularly
(shown in red),the constant inclina-
tion values relative to the survey station
measured inclination (blue line) are
markedly different in most cases.
The net result is then calculated
and dramatically confirms the
impact on drilling ahead “blindly”
without tracking inclination
changes at least intermittently.
Memory data improves
earth model
If continuous inclination is not a viable
option while drilling—perhaps due to
the service cost of this advanced sensor
package or simply the tradeoffs of
sharing desirable data channel band-
width due to drilling depths or other
factors—then,at a minimum,it is rec-
ommended that the memory data from
the MWD system be used to produce a
post-trip survey data file for comput-
ing a more accurate representation of
the well’s course.Simply,the inclination
data can be used to provide more fre-
quent survey stations and to update the
drilling path more accurately than oth-
erwise possible.
Likewise,petrophysical data gaps
due to slow transmission speeds,band-
width competition and fast drilling
rates can be overcome by infilling with
memory data from the LWD system
after it is brought to the surface.
TSP to the rescue
Fortunately,while these downhole
measurements are essential for
understanding the drilling formation
properties and a well’s physical posi-
tion in the subsurface while drilling,
these shortcomings can be at least par-
tially overcome in true drilling time.
By applying good geo-navigation tech-
niques for determining TSP of the
drilling system,the goal of“staying in
zone”can be mostly achieved.
Many directional drillers will argue
that they must have directional surveys
and an accurate wellbore position to
plot where they are in the subsurface
relative to a well plan and then for
making good drilling decisions relative
to a target line.While the former may
be true,if the ultimate goal is to stay
within a geologic window or targeted
formation zone,then the actual
position of the wellbore relative to a
geologic marker is the key geo-naviga-
tion parameter.
Inother words,pinpointing the well’s
truestratigraphicposition(TSP)and
drilling dip angle are reallythe critical
informationrequiredbythegeosteering
team.Thatis,theoperationsgeologist
inconcertwiththedrillingdataand
otherdrillingpersonnel’sprimary
objectiveistoknowthewellbore’s
Survey
Position
Model 1
Calculated Path
A slide section with a short radius of curvature followed by a rotary
section (no curvature). The actual wellbore
position will be shallower than calculated. Used with permission
(SPE 79917 Stockhausen and Lesso)
CalculatedRadiusofCurvature
Actual
Well
Path
Slide Radius of Curvature
Slide
FIGURE 3: SURVEY POSITIONED AT START OF THE SLIDE SECTION
The net of those two common drilling practices is compounding of both errors (long
survey intervals and calculation errors in the calculation model.) (Source: Society of
Petroleum Engineers)
A1
A2
I1
W E
N
DL
But the actual wellbore
is not a constant arc
Minimum Curvature Survey Calculation Method
assumes a constant arc between survey points
TVD error
builds with
depth
S
I2
VERT
EAST
NORTH
MD
DL
2 DL
2
FIGURE 4: ERROR BUILDS WITH DEPTH REGARDLESS
OF MODEL USED
This minimum curvature survey calculation model illustrates that any vector-based
calculation model has inherent limitations when fitting a smooth radius of curvature.
(Source: Ryan Directional Services,a Nabors company)
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6. OGIAustralia.com | March 2015 HartEnergy.com72
Technology
precisestratigraphicpositionand
drillingattituderelativetotheapparent
formationdipatanygivenmoment—
aprocessreferredtoasgeo-navigation.
The TSP modeling technique
employed by geo-navigation special-
ists is used to determine the relative
position of the logging sensor —typi-
cally a gamma ray detector housed
within the LWD system—in the sub-
surface by using log correlation tech-
niques within specialised software
that also provides the expert geo-nav-
igator with a means to swiftly deter-
mine apparent formation dip angle.
Using these data (TSP and apparent
dip),targeting decisions and recom-
mended borehole course corrections
may then be made; these steps are
collectively known as geosteering.
Still,these geo-navigation data
measurements (both petrophysical and
positional) as noted earlier are critical
for relating TSP back to the earth’s geo-
model for making sound,timely
geosteering decisions and keeping the
horizontal path in the optimal,targeted
production zone.Of course sound
industry geosteering best practices,
including recommended targeting
methodology,consider the many trade-
offs so as to not unnecessarily“chase”
formation changes and avoiding the
creation of new,potentially serious,
drilling and completion problems as a
consequence of an undulating and por-
poising wellbore.
Recommended targeting
best practice
The recommended methodology is
“vector-based”targeting.This tech-
nique uses TSP modeling results
along with the resulting apparent dip
calculations relative to current
drilling inclination.
Very simply,the current TSP and
apparent dip angles are compared
with the drilling orientation to deter-
mine an optimal target vector.The
result is a“zero vertical section”(VS0)
position at a specific TVD location
with a desired new inclination angle
for use by the DD.This gradual change
will occur over whatever course length
is required to softly“land”on the pre-
scribedVS0 at a given true vertical
depth (TVDy1) with the prescribed
vector line angle (inclination1).
Subsequently,as needed,the target
vector can then be easily updated as
needed.Again,over time,the DD will
again bring the well path onto a new
“landing vector”and well trajectory.
Right tools for the job
As is certainly the case for conventional
resource developments,not every
unconventional resource play is the
same.Every play has its own challenges
and inherent risk due to so many vari-
ables.Geologic risk may be due to
sparse data and little well control.Geo-
logic complexities that need to be con-
sidered are regional,local and even
well-specific structure,faulting and the
potential for changes in facies and other
formation unconformities.And there
are so many more challenges created by
insufficient and unavailable data to fur-
ther understand the uniqueness of each
unconventional resource play.
And over time these elements can
change in importance as play delin-
eation provides new geologic and
reservoir insight and other new data
that is brought to bear to provide a bet-
ter understanding of the resource in
place and evolving best practices that
may become available.
Ultimately, this new knowledge
can be leveraged for attaining
optimal economic and key corpo-
rate objectives for each of the stake-
holders.As such, the technology
deployed at the start of a project
could (should?) be different as the
play evolves. Be sure to deploy solu-
tions that can be scaled up or down
as new challenges arise or are met
with new information and technol-
ogy is put into play.
And very importantly is your
asset team’s organisation itself. The
group should operate like a well-
oiled machine that is in-sync with
each other’s goals at all times. This
is especially true “after hours,”
on nights and weekends, when
problems seem most likely to come
up.A clear definition of what are
appropriate responses to a given
situation during planning and exe-
cution of a program that meets
each of the most important criteria
of each discipline in the lineup
should include your service compa-
nies, as well as the reservoir and
production team members.
Be sure to scale your services solu-
tions and your asset team’s skills to
meet the demands and complexity of
each project.■
8800 9000 9200 9400 9600 9800 10000
Inclination
Measured Depth
Cont. Inclination
Survey Inclination
94
93
92
91
90
89
88
87
FIGURE 5: CONTINUOUS INCLINATION ENHANCES GEO-NAVIGATION
When continuous inclination is tracked regularly,the constant inclination values relative to the survey station measured inclination is
markedly different in most cases. (Source: Ryan Directional Services,a Nabors company)
Benefits Include:
• Never “blind” to true
inclination while
drilling ahead
• Better, more reliable
predictions at the bit
• More timely geo-
navigation and
geosteering DS
• Earlier directional
course corrections
• Reduced wellbore
tortuosity
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