Petroleum & Natural Gas Engineering: September 2009

Wireline MWD logs in formation Evaluation

Monday, September 21, 2009 by ShoXee - Leave a comment

Basic Logging Parametres , Spontaneous potential , Sp log ,gamma ray , density log , acoustic log , sonic log ,shale volume ,porosity log combination , complex lithology plots , gamma ray curves , micro resistivity curve ,short spaced resistivity curve , formation boundries

Some Important Oil & Gas Definitions

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Artisian Flow , Bubble Point , Coning , Critical Point , Deeper Pool test , Development well , dew point , Extension Test well , Fair way , Formation Volume Factor , Gas Oil Ratio , Gross Pay , Hydrates , Hydrocarbon Play , Migration , mili darcy , net pay ,new field wildcat , new pool wildcat , pool , pore throat , porosity , Recovery , resourse , reservoir , Saturation Condition , Seal , Sedimantary Basin , Service Well , shallower Pool Test , Stratigraphic Test well ,Trap , Under saturated Conditon.

Reservoir Maps , Isochron Maps , Depth Structure Maps , Isopach Maps , ISochore mAps

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natural Drive Mechanisms , Gas Drives ,Water Drives , Combination Drive

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Traps , Types Of Traps

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Fault Trap

Stratigrtaphic Trap

Growth Faults

Horst

Fan FOlds

Domino Faulting

Normal Fault

Footwall

Hanging Wall

Synthetic Fault

Anthetitic Fault

Anticilinal Traps

Fault Traps

Classification of reservoir Fluids

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wet gas

Dry gas

Gas Condensate

Black oil

Volatile Oil

MWD - Measurement While Drilling

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Measurement-While-Drilling (MWD)

Although many measurements are taken while drilling, the term MWD is
more commonly used to refer to measurements taken downhole with an
electromechanical device located in the bottomhole assembly (BHA).
Normally, the capability of sending the acquired information to the surface
while drilling continues is included in the broad definition of MWD. Telemetry
methods had difficulty in coping with the large volumes of downhole data, so
the definition of MWD was again broadened to include data that was stored
in tool memory and recovered when the tool was returned to the surface. All
MWD systems typically have three major subcomponents of varying
configurations: a power system, a directional sensor, and a telemetry
system.

Power Systems

Power systems in MWD may be generally classified as two types: battery
and turbine. Both types of power systems have inherent advantages and
liabilities. In many MWD systems, a combination of these two types of power
systems is used to provide power to the toolstring with or without drilling
fluid flow or during intermittent drilling fluid flow conditions.
Batteries can provide tool power without drilling-fluid circulation, and they
are necessary if logging will occur during tripping in or out of the hole.
Lithium-thionyl chloride batteries are commonly used in MWD systems
because of their excellent combination of high-energy density and superior
performance at LWD service temperatures. They provide a stable voltage
source until very near the end of their service life, and they do not require
complex electronics to condition the supply. These batteries, however, have
limited instantaneous energy output, and they may be unsuitable for
applications that require a high current drain. Although these batteries are
safe at lower temperatures, if heated above 180°C, they can undergo a
violent, accelerated reaction and explode with a significant force. As a result,
there are restrictions on shipping lithium-thionyl chloride batteries in
passenger aircraft. Even though these batteries are very efficient over their
service life, they are not rechargeable, and their disposal is subject to strict
environmental regulations.

The second source of abundant power generation, turbine power, uses what
is available in the rig's drilling-fluid flow. A rotor is placed in the fluid stream,
and circulating drilling fluid is directed onto the rotor blades by a stator.
Rotational force is transmitted from the rotor to an alternator through a
common shaft. The power generated by the alternator is not normally in an
immediately usable form, since it is a three-phase alternating current of
variable frequency. Electronic circuitry is required to rectify the alternating
current (AC) to usable direct current (DC). Turbine rotors for this equipment

must accept a wide range of flow rates so that multiple sets of equipment
will not be required to accommodate all possible mud pumping conditions.
Similarly, rotors must be capable of tolerating considerable debris and lost-
circulation material (LCM) entrained in the drilling fluid. Surface screens are
often recommended to filter the incoming fluid.

Telemetry Systems

Although several different approaches have been taken to transmit data to
the surface, mud-pulse telemetry is the standard method in commercial
MWD and LWD systems. Acoustic systems that transmit up the drillpipe
suffer an attenuation of approximately 150 dB per 1000 m in drilling fluid
(Spinnler and Stone, 1978). Advances in coiled tubing promise new
development opportunities for acoustic or electric-line telemetry. Several
attempts have been made to construct special drillpipe with an integral
hardwire. Although it offers exceptionally high data rates, the integral
hardwire telemetry method requires expensive special drillpipe, special
Low-frequency electromagnetic transmission is in limited commercial use in
MWD and LWD systems. It is sometimes used when air or foam are used as
drilling fluid. The depth from which electromagnetic telemetry can be
transmitted is limited by the conductivity and thickness of the overlying
formations. Some authorities suggest that repeaters or signal boosters
positioned in the drillstring extend the depth from which electromagnetic
systems can reliably transmit.
Three mud-pulse telemetry systems are available: positive-pulse, negative-
pulse, and continuous-wave systems. These systems are named for the way
their pulse is propagated in the mud volume.

Negative-pulse systems create a pressure pulse lower than that of the mud
volume by venting a small amount of high-pressure drillstring mud from the
drillpipe to the annulus. Positive-pulse systems create a momentary flow
restriction (higher pressure than the drilling mud volume) in the drillpipe.
Continuous-wave systems create a carrier frequency that is transmitted
through the mud and encode data using phase shifts of the carrier. Positive-
pulse systems are more commonly used in current MWD and LWD systems.
This may be because the generation of a significant-sized negative pulse
requires a significant pressure drop across the BHA, which reduces the hole-
cleaning capacity of the drilling fluid system. Drilling engineers can find this
pressure drop difficult to deliver, particularly in the extended-reach wells for
which the technology is best suited. Many different data coding systems are
used, which are often designed to optimize the life and reliability of the
pulser, since it must survive direct contact from the abrasive, high-pressure
mud flow.
Telemetry signal detection is performed by one or more transducers located
on the rig standpipe, and data is extracted from the signals by surface
computer equipment housed either in a skid unit or on the drill floor. Real-
time detection of data while drilling is crucial to the successful application of
MWD in most circumstances. Successful data decoding is highly dependent
on the signal-to-noise ratio.

A close correlation exists between the signal size and telemetry data rate;
the higher the data rate, the smaller the pulse size becomes. Most modern
systems have the ability to reprogram the tool's telemetry parameters and
slow down data transmission speed without tripping out of the hole;
however, slowing data rate adversely affects log-data density.
The sources of noise in the drilling-fluid pressure trace are numerous. Most
notable are the mud pumps, which often create a relatively high-frequency
noise. Interference among pump frequencies leads to harmonics, but these
background noises can be filtered out using analog techniques. Pump speed
sensors can be a very effective method of identifying and removing pump
noise from the raw telemetry signal.
Lower-frequency noise in the mud volume is often generated by drilling
motors. As the driller applies weight to the bit, standpipe pressure increases;
as the weight is drilled off, standpipe pressure is reduced. The problem is
exacerbated when a polycrystalline diamond-compact (PDC) bit is being
used. Sometimes, the noise becomes so great that even at the lowest data
rates, successful transmission can only occur when bit contact is halted and
mud flow is circulated off-bottom. Well depth and mud type also affect the
received signal amplitude and width. In general, oil-based muds (OBMs) and
pseudo-oil-based muds (POBM) are more compressible than water-based
muds; therefore they result in the greatest signal losses. This effect can be
particularly severe in long-reach wells where OBM and POBM are commonly
used for their improved lubricity. Nevertheless, signals have been retrieved
without significant problems from depths of almost 9144 m (30,000 ft) in
compressible fluids.

handling, and hundreds of electrical connections that must all remain reliable
in harsh conditions

Directional Drilling

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Introduction

Directional drilling began with the use of devices such as whipstocks or
techniques such as jetting to kick off, rotary assemblies to control inclination
in tangent sections, and wireline steering tools to orient and survey. These
tools possessed limited directional control capabilities, required frequent
tripping of the drillstring, and made directional drilling an expensive,
difficult, and sometimes risky proposition. Directional well planning was
more an art than a science, and capabilities and boundaries were based
largely on empirical observations and historical tool performance.
Recently, technological advances have contributed to a significant increase in
the use and scale of directional drilling. Perhaps the technologies with the
highest impact have been steerable mud motors, measurement-while-drilling
(MWD) tools, and logging-while-drilling (LWD) tools. These tools in
combination have provided the ability to follow complex, 3D well profiles
without changing bottomhole assemblies (BHAs), and to measure where the
bit has drilled without having to run a wireline to survey or log. Equally
important, engineering models have provided the fundamental tools for
evaluating drillstrings, hydraulics, BHAs, and the drilled formations
themselves. These advances have enabled the drilling of extended-reach,
horizontal, and multiple-target well profiles once thought impractical,
uneconomical, or impossible.
Most books currently available either discuss deviation control—the attempt
to keep vertical wells truly vertical—or discuss older directional-drilling
practices, such as whipstocks, jetting, or the use of straight mud motors
with bent subs. These practices, while still in use, are now the exception
rather than the rule. This chapter, then, primarily discusses directional
drilling as it is performed today. Emphasis will be placed on identifying the
principles and mechanics that define the capabilities and limitations of
current directional-drilling technology.

Well Planning

Planning even the simplest vertical well is a task that involves multiple
disciplines. A casual observer might think that planning a directional well
would require only a few geometry calculations in addition to the usual
tasks. On the contrary, almost every aspect of well planning is affected when
a directional well is planned. Various software systems are available to assist
in these engineering efforts, but effective application of such software
requires a good understanding of the underlying engineering principles. The
fundamental variables that dictate the planned wellpath are the surface
location for the rig and wellhead and the location(s) of the target(s)
downhole. However, many other variables also impact the final wellpath
chosen.

Well Profiles and Terminology

A simple build/hold/drop well profile, known as an "S" well, is shown in
Figure 2-1. The kickoff point (KOP) is the beginning of the build section. A
build section is frequently designed at a constant buildup rate (BUR) until
the desired hole angle or end-of-build (EOB) target location is achieved. BUR
is normally expressed in terms of degrees per hundred feet (°/100 ft), which
is simply the measured change in angle divided by the measured depth (MD)
drilled.

Hole angle, or inclination, is always expressed in terms of the angle of the
wellbore from vertical. The direction, or azimuth of the well is expressed
with respect to some reference plane, usually true north. The location of a
point in the well is generally expressed in Cartesian coordinates with the
wellhead or the rig's rotary kelly bushing (RKB) as the reference location.
True vertical depth (TVD) is usually expressed as the vertical distance below
RKB. Departure is the distance between two survey points as projected onto
the horizontal plane. The EOB is defined in terms of its location in space as
expressed by coordinates and TVD. The EOB specification also contains
another important requirement, which is the angle and direction of the well
at that point. The correct angle and direction are critical in allowing the next
target to be achieved; also, it may be necessary to penetrate the payzone at
some optimum angle for production purposes.
A tangent section is shown after the build section. The purpose of the
tangent is to maintain angle and direction until the next target is reached. In
the example well, a drop section is shown at the end of the tangent. The
purpose of a drop is usually to place the wellbore in the reservoir in the
optimum orientation with respect to formation permeability or in-situ
formation stress; alternatively, a horizontal extension may be the preferred
orientation in the case of a payzone that contains multiple vertical fractures
or that has potential for gas or water coning.

Factors in Wellpath Design
Completion and reservoir drainage considerations are key factors in wellpath
design. For fracturing, gravel-packing, completion in weak formations, or
depletion-induced compaction, it may be desirable to limit the inclination of
the well through the reservoir or even to require a vertical or near-vertical
trajectory. These conditions are also true in laminated or layered reservoirs.
Often, it may be desirable for the wellpath in the reservoir to be horizontal
to provide as much reservoir drainage and production rate as possible. In
horizontal wells, correct TVD placement will minimize gas coning or water
production. In vertically fractured formations in which the fractures may aid
in the flow of hydrocarbons, the direction of the wellpath in the reservoir
may be chosen to intersect multiple fractures. Alternatively, it may be
desirable to place the wellbore in a given direction to avoid faults that are
expected to allow water migration. Optimal placement of the wellbore in the
reservoir will result in maximum production and should actually be the
starting point for wellpath design.

Additional considerations will influence the design of the trajectory from the
surface location to the reservoir-target entry point. Some shallow formations
in sedimentary geologies are weak, and, as a result, building inclination is
difficult because of the lack of reactive forces against the BHA. If this
condition is anticipated, the KOP should be designed deeper, where
Frmations are more competent.

The interrelationship of the wellpath design and the casing/hole program
must also be recognized. The casing/hole program for the well is generally
designed on the basis of the desired completion, the pore pressure regimes
for the well, the presence of trouble zones, and regulatory requirements.
The casing program influences the planned trajectory in several ways. For a
given casing design, the trajectory plan should be optimized for operational
efficiency. For example, required builds and turns should be executed fully
within a single hole section. When this method is used, the well will be "lined
out" towards the reservoir target, and the remaining hole section can be
drilled as a straight tangent section without additional directional work.
Likewise, in troublesome zones, such as underpressured sands or reactive
shales that can increase the risk of stuck pipe, it may be desirable to avoid
directional work that requires sliding (drilling without rotating the drillstring).
Thus, the design of a build section may need to include a short tangent
through the troublesome section that will allow it to be rotary-drilled as
rapidly as possible.
When the various constraints are considered, a feasible and optimized
directional trajectory plan should result. An optimized wellpath often cannot
be described by the simplest geometry that can be conceived to connect a
series of targets. Even with a simple build-and-hold profile, additional
wellpath optimization is possible. For example, drilling experience in an area
should allow for the definition of the typical walk rate (the tendency of the
BHA to turn slightly in the azimuthal direction) for certain BHAs in that area.
With walk rates defined, the well can and should be "led," or initially directed
away from the target in the direction opposite to the anticipated walk. If the
well is properly led, steering will not be required in this interval, since the
natural walk tendency will gradually bring the well into the target. If the
wellpath had been designed as a straight line from one target to the next,
frequent steering would be required throughout the interval to counteract
the natural walk tendency.
Modeling the Wellpath
In addition to refining the trajectory plan to account for drilling tendencies
such as walk, trajectory planning in development projects must also account
for the location of existing wells and the requirement that the planned well
safely bypasses all existing wellbores. This aspect of planning, known as
"collision avoidance," must account for the uncertainty associated with the
ability to survey the well.
Wellbore trajectory calculation methods use data points called survey
stations, each of which consists of inclination, azimuth, and measured depth.
Directional measurements are normally provided by MWD sensors, and
measured depth is provided by traveling block sensors or by pipe tally. Many
survey models are available (Bourgoyne et al., 1991; Craig and Randall,
1976), and each is based on different assumptions on the shape of the
wellbore between survey stations. Except for the tangent method, most
models provide virtually identical results. The most commonly used survey
calculation method is the minimum curvature method (Figure 2-3).