WHAT IS TECHNICAL HOLE DEVIATION (THD)?
Deviation (THD) mathematically quantifies spatial
differences between actual and planned well paths. THD provides significant insight regarding three important
directional drilling issues: control, monitoring, and post-evaluation. More specifically, technical
hole deviation provides:
- Support information for real-time rationalization of directional tool
settings. A THD well log significantly augments the
visual tools available to the directional driller to rationalize control
decisions, especially for 3D/complex wellbores and non-linear hole
- Information for daily progress monitoring of directional control performance.
Many relevant wellbore details cannot be determined from
directional vertical section and plan view plots.
For example from these standard plots alone, it
is impossible to determine dogleg-severity (DLS), wellbore inclination, and wellbore azimuth,
and (more importantly) how they are changing relative to the planned
trajectory. THD logs present all of this information and much more. A glance
at the THD logs for a well, quickly conveys how directional control is progressing, on a
scale that doesn't mask the true details.
- Basis upon which to
evaluate overall directional control performance of a directional driller, service
company, or directional drilling system. With THD, directional control
performance can be quantified with various metrics. Three such examples are
Average Absolute Vertical Deviation, Average Absolute Inclinational
Deviation, and Excess Measured Depth.
Technical Hole Deviation (THD) is calculated at each
survey station. THD may be fully presented with two well
logs. Computing THD only requires a mathematical understanding of the
well path, and directional survey data. Employing THD technology doesn't
require more "steering"; rather, it's an enhanced
use of standard information to make more-informed directional control decisions at the same or less steering
Technical Hole Deviation
- directly applicable to all types of directional drilling
(ultra-short, short, medium, and long radii of curvature; slant; horizontal,
relevant to every type of directional drilling
system (rotary, PDM, rotary steerable) and all
industries (oil & gas, utilities/HDD, in-seam
coal bed methane (CBM), in-seam coal mine methane
- mathematically valid as
defined, with any planned well path profile (2D/3D circular arc, line,
catenary, double circle, spline-in-tension, 3D
StratBlock, earth model marker bed grid, "plan" defined by survey of offset
well for relief well drilling, etc.)
Of critical importance to
almost any system is how its state is changing. Actual directional well paths
are "noisy". From an engineering/mathematical point of view,
differentiating "noisy" data is useless. In effect, THD smoothes the data by
associating the actual well path to the planned well path. The smoothed profile
is then differentiated (differenced) to determine how it is changing
relative to lineal and angular target path properties. This process provides the foundation for
future well path deviations,
without explicitly assuming a model of directional drilling.
This document contains the following sections.
OF TECHNICAL HOLE DEVIATION
change in vertical deviation
change in inclinational deviation
change in horizontal deviation
change in azimuthal deviation
The planned well path defines the preferred location of the wellbore in 3D space. Every directional well has a planned path. In some cases as
information is acquired while drilling, the planned path changes
via geosteering. However, there is always a planned path in force at each
Technical hole deviation is defined with properties of the
nearest point between "current TD" and the "current" planned path. Given the current actual location of the wellbore, there is one point along the planned path that minimizes the 3D distance
between where the bottomhole location actually is, and where it is preferred.
This point along the planned path is called MD* ("measured
depth star"). Associated with MD* is N*, E*, TVD*, Inc*, and Azi*, respectively,
planned values North, East, True Vertical Depth, Inclination, and Azimuth. With
a directional survey and a mathematical understanding of the planned path, MD*
is found iteratively. (* always denotes a planned value)
Eight components collectively define technical hole deviation. They
are based on lineal and angular differences—and the relative changes
thereof—between the actual and planned well paths. Four THD components address hole deviation in the "vertical"
sense, and four THD components address hole deviation in the "horizontal" sense.
Other variables of interest include:
INC - actual
wellbore inclination angle; (deg)
INC* - planned
wellbore inclination angle; (deg)
DLS - actual
wellbore dogleg-severity; (deg/100ft or deg/30m)
DLS* - planned
wellbore dogleg-severity; (deg/100ft or deg/30m)
AZI - actual
wellbore azimuth; (deg)
AZI* - planned
wellbore azimuth; (deg)
DL - difference in MD* between two consecutive survey stations
b - subscript with reference to current wellbore total depth
A description and mathematical definition of each THD component follows.
msVD/msHD (1st Order, Lineal Deviation)
and Horizontal Deviation, msHD, are
the two most easily-visualized components of technical hole deviation. They
the wellbore exists in space, relative to the (current) preferred location.
By design, their definitions are such that being High or
Low, and Left or Right, match common directional-driller sense. The terminology and equations
apply to ALL curvilinear and linear well plans (i.e., not just circular-arc).
In the mind's eye, if you were to "walk"
along the planned path at MD* as the well is drilled and point to the current
wellbore TD, the components of that pointing vector, relative to the high
side of the planned hole, would be msVD and msHD.
The relevancy of industry's "vertical section"
deteriorates when the current planned azimuth is different from the
vertical section azimuth. In other words, projecting well path
departure onto a single
vertical plane (i.e.,
to compute vertical section) can
sometimes have little meaning over thousands of feet of hole. EVERY well with
"turn" built into the plan, to some degree, suffers from this fact.
It's not an issue with msVD and msHD.
RCVD/RCHD (2nd Order, Lineal Deviation)
The Relative Change in Vertical Deviation, RCVD, and the Relative Change in Horizontal
Deviation, RCHD, are less intuitive than are msVD and msHD. However, they contain much information, including
"predictive" qualities. We say predictive because, for example,
RCVD leads msVD (or conversely msVD lags RCVD).
*Note: For metric, use 304.8 in place of 1000 in the
Consider two examples of
technical hole deviation in the vertical
sense, as sketched below.
Current msVD is identical in both cases, that is, the
wellbore is low of the
plan by the same amount. Current
RCVD is positive in both cases but the magnitude of RCVD for Case B is
clearly higher. Thus, the plan is being approached more quickly in Case B
than in Case A, which may have significant influence on the next directional
tool setting decision.
RCVD provides insight as to how msVD is changing. RCHD
provides insight as to how msHD is changing. The signs and magnitudes of RCVD
and RCHD are important for real-time tool-setting purposes. For example, if the
wellbore is high, then RCVD must be
made negative before the wellbore will begin to approach the plan.
Typically, this will happen long before the planned path is approached or
intersected, hence, the "predictive" quality as mentioned above. RCVD
and RCHD are also used for projecting msVD and msHD.
msID/msAD (1st Order, Angular Deviation)
Inclinational Deviation, msID,
and Azimuthal Deviation, msAD, are
differences in actual and preferred wellbore angles. For example, if the
current wellbore inclination is 91.6 degrees while the plan is horizontal, msID = 1.6 degrees.
Visualizing msID or msAD in space is not simple.
Nevertheless, both their signs and magnitudes contain important directional
control information, especially when
combined with other technical hole deviation components and while considering
the task at hand. In all cases,
controlling msID (or msAD) is easier to accomplish than controlling msVD (or msHD), because sooner or later msVD depends on msID.
While drilling the upper hole section of a directional well,
maintaining msID and msAD close to zero is usually more important than
minimizing msVD and msHD. Why? Because it means the
wellbore is headed in the
planned directions and drilling is taking place at the planned DLS. For example,
you may be drilling that 45 degree tangent section 35 feet low, but you're
drilling it at 45 degrees, which may be perfect in the practical sense.
landing and drilling the payzone "perfectly"
requires minimization of all 8 components of hole deviation. In the vertical
sense, this includes, msVD, RCVD, msID, and RCID. In the horizontal sense, this
includes, msHD, RCHD, msAD, and RCAD. Typically, "being on depth",
that is, minimizing hole deviation in the vertical sense is most important.
entirely possible for msVD ~ 0, RCVD ~ 0, and msID be significantly greater-than or less-than 0. In other
words, even though you're currently on-depth, msVD won't stay zero for long and
the wellbore will soon be either high or low. Collectively analyzing technical hole deviation in the vertical sense can help eliminate the foregoing situation.
RCID/RCAD (2nd Order, Angular Deviation)
The Relative Change in Inclinational Deviation, RCID, and the Relative Change in
Azimuthal Deviation, RCAD, are similar in design to
RCVD and RCHD. They quantify how msID and msAD are changing as the hole is
*Note: For metric, use 30.48 in place of 100 in the
As was the case with 2nd order lineal deviation, both the signs and magnitudes of RCID
(or RCAD) have relevancy and insight into controlling msID and msVD (or msAD and msHD).
Most directional drillers
employ some sort of forecasting scheme to assist in determining their
directional tool-setting control actions. Some methods are quantitative (e.g.,
linear projection, path projection, etc.), while others are purely
qualitative and include simply "mental processing" of numeric and/or
graphed information. No method is perfect, since what lies ahead of the bit and
how it will affect drilling direction is unknown beforehand.
Technical hole deviation
provides a superior foundation upon which to form opinions about hole deviations
and thus, directional tool-setting control actions. THD projections forecast
msVD and msHD and are model-free. Furthermore, when viewed on a THD
well log, THD projections significantly compliment the other graphed
information that is "mentally processed" by the directional driller.
The equations for projecting
THD in the vertical sense (msVD) and in the horizontal sense (msHD) are provided
below. In either case, delMD represents a projection length (e.g., 100 feet
measured depth) beyond the current known values (i.e., at the deepest survey
*Note: For metric, use 304.8 in place of 1000 in the
Although the THD projection
equations are linear, it does not mean the planned or actual well paths
are assumed linear, circular, or of any specific shape. What is assumed is
that the relative change in deviation is constant over delMD;
over short distances this assumption is often completely
valid. Obviously, forecasting and subsequent visual interpretation influences
the tool-setting control actions taken by the directional driller, which will
affect the actual well path and thus, the actual THD profiles that unfold.
MAP SHOWS TRUE COMPLEXITY OF DRILLING DIRECTION
spite of numerous
attempts (& millions of dollars) to develop mathematical models that could directly assist directional
drillers in how to steer--particularly in the 1970's and
direction cannot be predicted with significant certainty. The core picture that
captures the complexity of drilling direction is conveyed in the cognitive map,
pictured above. A
cognitive map draws a causal picture of the
association of components within a complex dynamic system. All that may
be directly controlled while drilling (e.g., hookload, rotary speed, pump rate,
directional tool settings/orientations, mud characteristics) rests in the node
Even with a complex
model that attempts to address the drilling system as a whole, the effort can't help for
live practical purposes because there are too
many significant unknowns. While drilling, the 3D circumferential shape of the
wellbore or the true dynamic hole diameter profile with depth is unknown, along
with multiple other factors that directly or indirectly affect drilling
direction! This is one of many reasons why directional
drillers have never required a simulator to do their job. The system is too
complex to be modeled with any relevancy, and what lies ahead of the bit is even
more uncertain. Instead, directional
drillers make real-time decisions regarding steering with quantitative
information that is accessible. Such information is predominantly
one or more of the sub-system nodes in the cognitive map alters drilling direction,
significance is manifested empirically via Technical Hole Deviation. Thus, knowing the
precise cause of changed drilling
direction—a change in the compressive strength of the formation being drilled
or hole enlargement, for
examples—is of hindsight value for real-time operations.
A planned drilling trajectory exists for a
reason. While tolerances vary by application and within application, having the ability to control the
drilling direction is important to the oil and gas industry.
While it is true that drilling direction cannot be
predicted, that doesn't mean to say it can't be controlled (i.e., steered). A similar analogy is
that you can't predict the precise path your vehicle will travel while driving
down a street, however, you still manage to steer your vehicle to its
destination by continually acting, reacting,
and processing many forms of information. In general, steering for humans is a relatively
simple task. Just consider driving a car, playing a video game, or
watching a 3 year old on a tricycle. Placing our human steering logic into a
computer system, however, is a challenge.
TECH HOLE DEVIATION?
Automation is coming to
drilling. The context to which this statement refers is similar to when cars
began to have cruise controls and aircraft began to
have auto-pilot mode. One of the first steps in designing a control
algorithm/methodology for a directional drilling control system is to identify observables and
controllables. Relevant observables are metrics (inputs) that quantify the current state of the system,
while controllables represent--as one may easily guess--that which may be directly controlled.
For example, wellbore inclination is an observable, while effective directional tool
magnitude and orientation (TFMO)
is a controllable for rotary steerable directional drilling systems.
Fuzzy-Logic-based controller for
auto/guided directional drilling and for general
steering guidance at surface. In its infancy in 1996,
the project began with identifying the system
observables of directional drilling trajectory
control. This work led to what is now called Technical
Hole Deviation. Since Technical Hole Deviation is
important "input" to an auto/guided directional
drilling control system, we feel THD has significant
potential to assist the directional drilling industry
in general by directly assisting directional drillers
and conveying information to operators. A more-informed
human (or system) is more likely to make better decisions.
Discovering new technology from "standard data" is
a welcomed occurrence. Numerically defining geometric hole deviation extracts
an abundance of information, simply from directional survey data and a planned well path.
The details of directional control performance are no longer hidden. THD well
logs convey the actual and planned well path properties in a manner far superior
than path projections onto static vertical and horizontal planes and tables of numbers
Directional drilling trajectory control requires
at least 4 x 2 = 8 dimensions. This helps to convey its complexity. Minimizing 8
variables is not simple for man or machine. Much value exists in simply
identifying what needs minimized! It is our opinion that the THD state variables
msVD, msID, msHD, msAD, and
the respective THD state-transition variables RCVD, RCID,
RCHD, and RCAD, collectively and sufficiently quantify how a directional well path differs from its