Casing Setting Depths and Sizes
Casing Setting Depths and Sizes The principal purpose of casing
is to ensure the integrity of the well during drilling and
production. The selection of casing setting depths is critical for
casing off troublesome formations, containing pressure, or
protecting fresh water formations. Casing design evolves from
completion requirements, as the completion equipment dictates the
size of the production casing or liner. Casing sizes at necessary
depths uphole escalate as needed for clearance. Tubular strengths
are selected as the well conditions dictate, and materials are
selected to resist corrosion. Wellhead and blowout-prevention
systems must be compatible with the tubulars in pressure rating and
material.
Prior to designing casing strings, the engineer must study
pressure requirements and prepare a mud-density schedule. A plot of
fracture gradient versus depth should be prepared, although in some
instances knowledge of the fracture gradients at the casing depths
under study is sufficient. Leakoff data on new wells is
particularly valuable. Hole problems must be thoroughly identified
and the need to design for acid gases or other corrosion problems
evaluated. Conductor Casing
Setting depth is usually shallow (80 to 150 ft) and selected so
that drilling fluid may be circulated to the mud pits while
drilling the surface hole. The casing seat must be in an
impermeable formation with sufficient fracturing resistance to
allow fluid to circulate to the surface. With subsea wellheads, no
attempt is made to circulate through the conductor string to the
surface. It is set deep enough to assist in stabilizing a guide
base to which guide lines are attached.
Large sizes (usually 16 to 30 in.) are required as necessary to
accommodate subsequently required strings.
Surface Casing
Setting depth should be in an impermeable section below
fresh-water formations. In some instances, near-surface gravel or
shallow gas may need to be cased off. The depth should be great
enough to provide a fracture gradient sufficient to allow drilling
to the next casing setting point and to provide reasonable
assurance that broaching to the surface does not occur in event of
closure on a kick.
In hard-rock areas the string may be relatively shallow (300 to
800 ft), but in soft-rock areas deeper strings are necessary.
Surface casing setting depths are often specified by government
regulatory bodies to protect fresh-water sands.
Intermediate or Protective String
A protective string may be necessary to case off lost
circulation, salt beds, or sloughing shales. In cases of pressure
reversals with depth, protective casing may be set to allow
reduction of mud density. The most predominant use is to protect
normally pressured formations from the effects of increased mud
density needed in deeper drilling.
When a transition zone is penetrated and mud density increased,
the normal pressure interval below surface pipe is subjected to two
detrimental effects:
The fracture gradient may be exceeded by the mud gradient,
particularly if it becomes necessary to close in on a kick. The
result is loss of circulation and possibly an underground
blowout;
The differential between mud column pressure and formation
pressure is increased, which increases the risk of stuck pipe.A
practical "rule of thumb" is to set the intermediate casing when
the mud density is approximately 12.5 to 13.0 ppg, which limits
both of the detrimental effects described. However, even these mud
weights may be excessive in certain areas. Attempts to drill to
higher mud-weight requirements are sometimes successful, but many
holes have been lost by attempts to extend the protective string
setting depth beyond that indicated by the above rule. Either kicks
occurred causing loss of circulation and possibly an underground
blowout, the pipe became differentially stuck, or sloughing of the
high-pressure zone caused stuck pipe.
Significantly, in soft-rock areas the fracture gradient
increases relatively slowly as depth of the surface casing string
is changed, but the pressure gradient in the transition zone
usually changes rapidly. Emphasis is often placed on setting
surface casing to an acceptable fracture gradient. It should be
noted that greater control of potential conditions at the surface
casing seat exists in the protective casing setting depth
decision.
It is often tempting to "drill a little deeper" without setting
pipe in exploratory wells. When pressure gradients are not
increasing this can be a reasonably acceptable decision, but with
increasing gradient the risk is great and should be carefully
evaluated.
To ensure the integrity of the surface casing seat, leakoff
tests should be specified in the Drilling Procedures section of the
well plan.
It is sometimes necessary to alter the setting depth of the
intermediate casing during drilling if:
hole problems prohibit continued drilling;
pore pressure changes occur substantially shallower or deeper
than originally calculated or estimated.For this reason the well
plan should state the pore-pressure requirement at which casing
should be set in a transition zone.
Liner
A liner is often economically attractive in deep wells as
opposed to setting a full casing string. This decision must be
carefully considered because the intermediate string must be
designed with a burst requirement suitable for the depth of the
liner. This increases the cost of the intermediate string. Also,
the possibility of continuing wear of the intermediate string must
be evaluated. If there is to be a production liner, then either the
production liner or the drilling liner should be tied back to the
surface as production casing. If the drilling liner is to be tied
back it is usually best to do so before drilling hole for the
production liner. By doing so, the intermediate casing can be
designed for a lower burst requirement, resulting in considerable
savings. Also, any wear in the intermediate string is covered up
prior to drilling the production interval.
If increased mud density will be required while drilling hole
for the drilling liner, then leakoff tests should be specified
under Drilling Procedures for the intermediate casing shoe. The
fracture gradient at the shoe may limit the depth of the drilling
liner. In Figure 1 the fracture gradient at the intermediate casing
shoe is indicated to be 17.3 ppg.
Figure 1
This would limit drilling to 14,000 ft, where the mud weight
requirement is 17.3 ppg. Leaving in a 0.5-ppg kick margin would
limit drilling to about 13,500 feet. At this depth the fracture
gradient would be approximately 18.6 ppg for further drilling below
the drilling liner.
The conditions described are in a commonly found range, but the
depth decisions depend on the accuracy of the fracture gradient
calculations, which can have significant error. In areas where
experience cannot be drawn upon for accurate fracture gradients,
leakoff tests should be specified, and setting depths altered if
necessary.
Production String
Whether production casing or liner is set, the depth is
determined by the geological objective. Depths may have to be
altered accordingly if the well runs higher or lower than the
geologic prognosis. The objective and method of identifying the
correct depth should be stated.
Casing and Hole Sizes
Generally, standard bit sizes should be run, but thick casing
walls may be necessary in deep wells for sufficient strength. The
designer can sometimes solve this problem by specifying special
drift casing. This allows the use of bits with diameters
approaching the inside diameter of the casing, rather than being
limited by drift (tolerance) diameter. Manufacturers make oversize
casing in several sizes providing strength comparable to APT sizes,
but with clearance for standard bit sizes.
Tubular and Wellhead Design
Following the development of mud weight requirements and
selection of casing setting depths, the first consideration in
casing design is determination of design loads. These vary for
surface casing, intermediate casing, and drilling liners as
compared to production casing and production liners.
Surface and intermediate String Design
Collapse: Collapse load (or collapse pressure) is the point at
which the hydrostatic pressure of the fluid column in the annulus
exceeds the casing pressure, causing the casing to collapse. Cooke
et al. 1982, 1983 have shown that after a cementing job, the
annular pressure gradually reduces to formation pressure in both
the drilling fluid and the cement. Usually, however, the
hydrostatic pressure at the time of cementing is used in
calculating the casing pressure required to prevent collapse, thus
providing some safety margin.
Considerable cost savings result from basing design loads on the
assumption that surface and intermediate strings will not be
completely emptiedfor example, that the string will not be more
than 15% empty. This might vary with the area to some extent, but
has been used by some companies for years.
The lower end of casing is in compression due to hydrostatic
pressure on the end of the pipe. Where the pipe is in axial tension
the effect of tension on collapse rating should be considered.
Two special conditions should be carefully considered on a
different assumed-load basis:
When strings are cemented through salt, particularly deep, thick
salt at elevated temperature, there is usually a collapse load that
is unidirectional and design load may need to be 1 psi/foot of
depth. In some severe cases it has been necessary to set
overlapping strings through the salt with cement between;
When cementing structural or surface strings through drillpipe,
the collapse loads may be high due to the difference in hydrostatic
pressure of the cement column in the casing/openhole annulus and
the mud column in the drillpipe/casing annulus. Large casing having
low collapse strength could collapse during cementing.Burst: The
maximum burst load occurs if the string is emptied and the well is
closed in on dry gas. The maximum load is at the surface. The
maximum pressure at the casing seat is the formation pressure in
the gas zone less the hydrostatic pressure of the gas back to the
casing seat, or the fracture pressure at the casing seat, whichever
is the lowest. The surface pressure is the maximum pressure at the
casing seat less the hydrostatic pressure of the gas to the
surface.
If oil is known to be the only hydrocarbon present, the
hydrostatic pressure is taken as that of the oil column, but in
exploratory drilling a gas column is usually assumed. Burst loads
at the surface also dictate the wellhead and blowout prevention
equipment ratings.
The burst load at the casing seat, or at any depth uphole, is
the pressure inside the casing minus the formation pressure at that
depth.
The above describes realistic maximum burst load conditions.
However, the strings so designed are expensive and sometimes
require high-strength casing, which is more prone to failure than
more common grades. In very deep, high-pressure wells, 15,000+ psi
surface pressures may occur if the well is emptied and closed in.
Provision of adequate strength for the design basis described
becomes more difficult. Sometimes either very high strength,
brittle pipe must be used, or the assumed design load decreased. If
hydrogen sulfide is expected, a lower-strength pipe, resistant to
sulfide embrittlement, may need to be used.
In cases where surface pressures could exceed 20,000 psi,
blowout preventers of sufficient rating are not available. It would
be impossible to contain the maximum possible pressure.
Many companies design on the basis that less than maximum
possible loads will occur. The U.S. Mineral Management Service only
requires that casing be designed to withstand "anticipated
pressure." Various assumptions are often made by different
companiese.g., that the hole can always be kept full of sea water,
that only a kick of a certain size and intensity will occur, or
that maximum pressure will not exceed a certain amount.
Tension: The maximum tension load on a joint of casing usually
occurs while it is hanging in the elevators because the tension
decreases as the joint is run into the hole. This is due to the
increasing hydrostatic pressure on the end of the pipe as it is run
into the hole. Therefore, the tension load can be reasonably
calculated at the top of a section as the buoyed weight of the pipe
below. When the section is downhole the tensile stress is reduced,
increasing the safety factor in tension above the calculated value.
However, this effect is usually accepted and ignored in design.
Some companies design using air weight and others using buoyed
weight. Often those who use buoyed weight use a higher design
safety factor so that the resulting casing design may be nearly
equal in tensile strength.
Two special conditions may warrant consideration of increased
design load:
When pipe is set through a dogleg there will be a bending load,
or, in an equivalent sense, a reduction in tensile strength;
In order to reciprocate pipe during cementing, drag and
increased weight of cement inside casing will increase tension.In
well planning, the first item is best handled by instructions in
the drilling procedure to wipe out doglegs as they occur. The
maximum permissible dogleg for each string should be calculated and
included in the well plan.
The second can be handled by specifying a safe hook load
(allowable pull) that will not reduce the tension safety factor
below a preselected, safe value. When this is done, pipe often can
be reciprocated during cementing; otherwise it may have seemed
stuck, and movement would have stopped.
Presentation: Both the loads used in design and the strength of
pipe are difficult to visualize from tabulated pipe and associated
safety factors. A graphical design or supplementary graphical
presentation such as shown schematically in Figure 2 is of
considerable help in understanding the design.
Figure 2
In this illustration, the collapse and burst design loads (loads
multiplied by a safety factor) are shown along with the strength of
pipe used. Tensional designs can be shown graphically also. Usually
the strength of pipe required in collapse and burst is high enough
that tension strength automatically gives a design safety factor in
excess of that stated as minimum.
Design: After the depths and sizes of casing and the loads have
been determined, the next step is to select the most economical
weights and grades of pipe that will satisfy the requirements. The
designer must also determine if there is a need to select pipe
resistant to sulfide stress cracking, and, if so, be familiar with
suitable materials.
Change-over depths are easily determined graphically as shown in
Figure 2 . The most economical weight and grade of pipe satisfying
the collapse requirement at bottom is found and plotted on the
graph as a vertical line. A second, more economical weight and
grade is selected and plotted. The intersection with the load line
determines the bottom of the second segment and the top of the
first. Other, more economical segments are determined as
necessary.
Burst (internal yield) ratings are graphed, along with collapse
ratings. Toward the top of the hole the collapse strength greatly
exceeds the collapse load, but the burst strength of the pipe may
be less than the design load. An intersection of the burst strength
line with the burst load design line determines the top of the
segment and the bottom of a stronger segment needed to satisfy the
higher burst loads nearer the surface.
When change-over depths are determined by calculation rather
than graphically, a graph showing the loads and change-over depths
is not essential. However, it can still be helpful in visualizing
the design, particularly for review purposes.
The collapse strength of casing decreases with tension and burst
strength increases with tension. Biaxial ellipse curves ( Figure 3
) can be used to determine such changes when designing strings, but
more recently triaxial stress calculations (Stair et al., 1983)
have been used.
Figure 3
Triaxial stress calculations account for axial load and bending
stress as well as internal and external pressures.
The strength of casing joints may be less (low efficiency), as
high, or higher (high efficiency) than pipe body yield. The usable
load (strength of pipe or joint divided by minimum safety factor)
is often determined for both pipe and joint, and the lesser used
for the maximum load to be hung on that kind of pipe. Approximately
80% of pipe problems appear to be with joints, particularly in
tensional failures. Joint strengths are based on pullout force or
minimum ultimate strength of the minimum cross section, and so are
likely to fail at the published rating. The rating of the pipe body
is based on minimum yield strength and the actual yield strength is
normally higher. Although stretching pipe is not desirable, the
pipe body would not part until the still higher ultimate strength
is reached. This is 1.1 to 1.75 times as high as the yield
strength. Thus, there is effectively a built-in safety factor in
pipe body ratings compared to joint ratings.
Some companies take advantage of this situation by using a
lesser safety factor for pipe body than for joint strengthe.g., 1.3
versus 1.75.
Makeup torque for the joint should be specified in the well
plan.
When the number of segments in the design is small or a segment
is short, consideration might be given to eliminating a weaker
segment by extending a stronger segment. In some wells only one
weight and grade might be used. This avoids making crossover joints
and lessens the possibility of errors in running the segments in
order. In deep wells, however, the use of a single weight and grade
can be prohibitively expensive.
Allowable Pull: In emergency conditions it is necessary to know
the maximum pull that can safely be exerted on casing. The
advantage of an allowable pull calculation when reciprocating
casing during cementing has already been explained. For this
calculation a smaller safety factor (e.g., 1.3 versus 1.75) may be
used.
Design Presentation: A form with blanks prompting inclusion of
all relevant casing design items is helpful to the designer as a
reminder of necessary calculations and as a step-by-step guide
while making the design. It is also a vehicle for presenting in the
well plan a condensed summary of the safety factors, sizes, weights
and grades, joints, and lengths to be ordered and run, including
screwage. It also calls for such important accessory design
information as mud weight, fracture gradient, allowable pull,
minimum ID and designer's identification. Blanks can also be
included for triaxial stress safety factors and makeup torques.
Landing: Casing strings should be landed at least with hanging
weight at time of cementing or according to calculated pick-up or
slack-off loads to avoid casing buckling with increases in
temperature and mud weight during deeper drilling. This should be
clearly specified in the drilling procedures section of the well
plan.
Holding the surface string in tension until the cement sets is
critical. Any slack-off can create misalignment in the surface
string and all subsequent strings, making the top joints subject to
excessive wear, even though a drilling bushing is used.
Production Strings and Liners
Collapse: At some time during the history of the well there is a
probability that the production string or liner will be emptied and
maximum possible collapse load applied. Although the pressure in
the annulus may reduce to formation pressure, the hydrostatic
pressure at the time of cementing is usually used as the design
load. Design on this basis results in an added safety factor above
the calculated value, as does the strengthening of pipe in collapse
by a cemented annulus and the effect of hydrostatically induced
compression in the lower part of the string. The latter increases
collapse strength above API rating. This uncalculated safety margin
tends to counter corrosion that could weaken pipe in later
years.
Burst: Burst loads are usually taken as the pressure that would
result from a tubing leak at the surface. If lesser design loads
are used, a pressure relief system for tubing-casing annulus would
be necessary.
If the packer fluid has the same density as the backup fluid (or
formation pressure if that basis is used), then the burst load is
the same as tubing pressure from surface to packer for a full
string. If the packer fluid has a higher density than the backup
fluid, then burst load on the production casing increases with
depth.
If the well is to be fracture-treated down casing, the surface
pressure during the fracturing job must be known to the designer
and incorporated into the casing design load.
Tension: Tension design loads are usually handled as for
intermediate strings. Makeup torque for the joints should be
specified.
Landing: Casing strings should be landed at least with hanging
weight at time of cementing or according to calculated pick-up or
slack-off loads to avoid buckling of the casing with temperature
increases during production. This should be clearly specified in
the Drilling Procedures section of the well plan.
Tubing Design
Joint strength of tubing is almost always greater than pipe-body
yield, so design is usually on a pipe-body-yield basis.
Conventionally, design is on an air-weight basis, since this
provides considerable overpull in the event tubing is stuck in
packer or mud.
On this design basis, the setting depth of tubing is determined
by grade of pipe, regardless of size. Where deeper settings are
required, a tapered string can be designed. If this is done, the
same safety margin (strength less usable load) should be used for
both sections after determining the usable load (pipe-body
strength/safety factor) for the lower section.
Where lower-strength, sulfide stress cracking-resistant pipe
must be used, setting depths can be extended by a tapered string
design, use of a downhole tubing hanger, or a production liner with
a polished bore receptacle through which production flows to the
tubing string.
Burst design should be based on maximum expected surface tubing
pressure unless the well is to be fractured, in which case the
burst design should be based on the maximum expected surface
pressure during fracturing.
Tubing for high-pressure wells should be pressure-tested to the
rated value divided by the burst design safety factor. Mill test
pressures are considerably lower than this value. The well designer
may wish to specify mill tests to this value.
Industry experience in general indicates that the use of a
teflon seal ring in joints is of considerable assistance in
providing leak resistance. These are often used in high-pressure
gas wells. Many premium connections are available that offer
gas-tight sealing with or without a teflon seal ring.
Collapse safety factors are generally at least 1.0 as the
strings may be swabbed, plugged, or used for formation tests, in
which case internal pressure may drop to low levels.
Materials selection in deep, high-temperature wells with carbon
dioxide and/or hydrogen sulfide can be affected by the decision as
to how corrosion will be handled. Treatment methods may be by batch
inhibition, continuous inhibitor injection, or use of high-alloy
materials.
Landing nipples for bottomhole pressure gauges or plugs should
be specified.
The type of packer or polished bore receptacle should be stated
with the tubing design. The necessary slack-off or tension should
be specified. Tubing landing practices and makeup procedures need
to be fully described in the Completion Procedures section of the
well plan.
Makeup: Makeup torque should be shown on the casing design
summary. If the torque-turn method is to be used, it should also be
designated and mentioned in the drilling procedure.
Mill test pressures are specified in APT Specification 5ST and
are low compared to burst rating. These are not intended to be the
basis for design. The test durations are short, usually about five
seconds. Unless pressure tests to internal yield rating are
specified, there is no assurance that the tubes will withstand
rated pressure. When a 1.1 safety factor is used, the test might be
90% of rating. Joints may be tested at the mill in coupling
made-up, hand-tight, or plain-tube condition. Couplings may be
supplied by someone other than the tube manufacturer. Magnetic
particle, ultrasonic, or electromagnetic inspection at the mill is
often done only by the purchaser s request. All this indicates the
unreliability of mill tests, even if inspected by a company
representative at the time of manufacture. (In some instances,
where pipe manufacture must be carefully controlled to ensure low
hardness for sulfide use, mill inspectors may be necessary.) Even
if pipe withstands mill tests, it can be damaged during shipment.
In consideration of all these factors, field inspection of pipe is
strongly recommended.
Field inspection is expensive and often is omitted in
noncritical wells, but to ensure integrity of the pipe it should be
field inspected by electromagnetic or ultrasonic testing methods.
Threads (pipe and couplings) should be inspected by magnetic
particle inspection or by Accu-Thread inspection.
Normally, tubing should be tested internally with water pressure
equal to anticipated running pressure. These tests are brief,
however, and leaks can still occur during actual use. Care in
selection and makeup is the best insurance. Test pressures and
inspection methods should be stated in the Drilling and Completion
Procedures of the well plan.
Buckling
Increases in mud density, average temperature, and internally
applied pressure tend to cause casing to buckle (corkscrew) .
Tubular doglegs created by buckling become more severe in intervals
of hole washout, resulting in high incidence of wear during
continued drilling.
With tubing, a number of severe problems can occur:
Seals may move out of the packer, allowing treating pressures to
burst casing;
Seal movement during production may wear out seals;
Seal movement during treating may be sufficient to permanently
corkscrew tubing;
Excessive buckling of tubing may prevent tools from going to
bottom;
Tubing may part in tension during treating;
Excessive rod wear may occur in buckled tubing.These can be
avoided by prior analysis.
In severe circumstances, pressure may be held until cement sets
and casing is landed to prevent severe buckling. Added tension may
be pulled before landing to limit the buckling tendency and
possible pipe movement in wellhead seals.
Service companies that do treating have computer programs that
make tubing buckling analyses, or these may be done by the
designer. In deep wells, such analyses are essential.
As a preventive measure, some designers run three joints of
higher-grade pipe just above the packer to avoid permanent
corkscrewing during treating or production. The necessary seals for
treating conditions must be specified with a safe excess. Set-down
weight to prevent tubing movement during production must be
specified, and any increased loads due to treating must be
incorporated in the tubing design.
Wellheads Casing spools and valves must have pressure ratings
equal to or greater than the casing pressure rating. Considerable
savings in nipple-up time can be realized by using spools in which
two or more strings can be hung. This practice also avoids the
necessary but unsafe procedure of removing blowout preventers in
order to nipple up on casing conventionally. However, it tends to
complicate pipe reciprocation during cementing.
Tubing heads must have provisions for removable tubing head
plugs. Stainless trim or stainless heads are necessary for
high-temperature, corrosive conditions. Metal-to-metal seals are
preferred for severe conditions. A schematic drawing of the
wellhead with an inventory and price list should be included in the
well plan.
The entire tension loads of subsequent strings will be
transferred to the surface string. The landing head on the surface
pipe must be capable of supporting this load, as must the casing
joints. In general, the compressive strength of casing is
approximately equal to tensile strength if casing is well supported
laterally, but there are exceptions.
Drilling Fluid Program Mud program design involves two stages.
First, a data-gathering exercise is undertaken to accumulate
information from as many sources as possible. Second, this data is
used as background information to prepare the mud program for the
upcoming well. The proposed mud program may be similar to past mud
programs in the area or may be entirely different. The mud-program
designers should feel free to make any changes, provided they will
result in a more efficient drilling operation.
Information Gathering
Sources of In formation: Usually, the most accessible sources of
information are the IADC drilling reports, mud recaps, and bit
records for offset wells. Wireline and mud logs, which are
sometimes more difficult to obtain, contain very valuable
information. Consultations with personnel who have worked in the
area can be very important. If the well to be drilled is in an
entirely new area the geophysical and/or seismic data may be the
only information available; in such cases, a discussion with the
geophysicists may be helpful.
Data: One of the most important pieces of information is the
pore pressure. Using the pore pressure, the mud weights required to
drill the well safely can be estimated. The required mud weight
sometimes affects the mud-type selection.
The casing program, usually submitted by the operator's drilling
engineer, is another very important piece of data. A properly
designed casing program cases off abnormal pressure zones and
troublesome formations. Once the casing program has been approved,
the mud program is then designed for maximum performance relative
to borehole stability for each interval. This could require a
complete change of mud types for different hole intervals. If at
all possible the mud program should be designed so that one mud
type, with progressive changes, can be used throughout the well,
thus drastically reducing mud cost.
A review of the available mud recaps gives insight into the mud
programs used previously in the area. Some important information on
the mud recap is the mud type, type makeup water, mud weight
requirements, mud-related problems, type of solids control
equipment used, total days to drill the well, and mud cost. Careful
attention should be given to the mud-related problems such as drag,
torque, differential sticking, bridging, fill after trips, and lost
circulation.
The available bit records, hydraulic programs, deviation
program, and IADC drilling report should be reviewed for additional
information. Downhole temperatures also affect the mud-type
selection.
Mud Program Design
Having compiled and studied all the available information, the
mud engineer is ready to begin planning the mud program for the
upcoming well. The required casing program will have been submitted
by the operator's drilling engineer to the person designing the mud
program.
Mud Weight: From the pore pressure, the estimated mud weights
for each interval are calculated along with fracture gradient.
Factors directly affecting the mud weight program are abnormal
pressure, lost circulation, water flows, gas intrusion, and
borehole stability. Each of these parameters must be considered for
each hole interval.
Mud Type Selection: Mud-type selection is based on numerous
factors which must be considered for each interval drilled. One
important factor is cost-effectiveness. Borehole stability is also
an important parameter but must not overshadow economics.
Trade-offs are sometimes necessary due to other factors such as
available makeup water, bottomhole temperature, material
availability, environmental constraints, solids-control equipment
availability, logistics, and safety. In determining the most
cost-effective system, all of the above factors play a role and
must be considered together to obtain the most economical mud
system.
Rheology and Fluid Loss: The rheological properties and fluid
loss (API low-pressure and high-temperature/high-pressure) should
be specified for each interval. Mud viscosity should be maintained
as low as practical to improve penetration rate and assist in
solids-control efficiency. Prior to weighting a mud, the API fluid
loss should be reduced if differential sticking is a possibility.
High-temperature/high-pressure fluid loss should never be specified
at a temperature higher than the true bottomhole temperature of the
well.
Problems and Contingencies: A thorough discussion of anticipated
problems along with contingency plans should be provided. If lost
circulation is prevalent in the area, a supply of materials should
be maintained on location for preparing a lost-circulation
treatment. If the possibility of differential sticking exists,
materials for preparing a stuck pipe treatment should be maintained
on location at all times, since freeing stuck pipe is time
dependent (i.e., the sooner the treatment is spotted, the more
likely the pipe will be freed) .
Corrosion Control: The possibility of corrosion should be
assessed for the mud type being used. If the mud system may be
corrosive, a corrosion monitoring program should be instituted. If
necessary, a cost-effective chemical treatment program should be
implemented to keep corrosion within acceptable limits.
Mud Products: A thorough discussion of mud products (their
purpose and limitations) should be provided. Handling and mixing
procedures should be specified for additives, especially hazardous
materials. Drilling fluid additives of low quality should not be
used, since the net result will probably be a more expensive mud
system. Usually materials classified "API Approved" meet certain
quality specifications, whereas materials not so designated may
need to be checked for quality. Not all mud additives have API
specifications, so testing may be required to determine
quality.
An estimate of the materials necessary to complete the job
should be furnished. This estimate is extremely important where
product availability is a problem or where mud materials may be
delivered only once or twice during the drilling of the well.
Solids-Control Equipment
Effective solids-control equipment is essential to running a
cost-effective mud system. Solids-control equipment should be
specified for each interval and a detailed discussion provided on
its proper use. This discussion should include methods for
determining the efficiency of each piece of mechanical equipment in
use. If rental equipment is necessary to enhance solids removal,
the cost can be justified by comparing its performance to rig
equipment performance. A maintenance program for the solids-control
equipment, whether rental or rig equipment, should be specified and
executed.
The primary shaker is the most important piece of solids-removal
equipment. It is essential for this piece of equipment to be
working at maximum efficiency at all times.
In designing a solids-removal program, the fluid-handling
capacity of the secondary solids-control equipment, with the
exception of the centrifuge, should always be greater than the flow
rate of the drilling fluid through the wellbore. It should not be
assumed that contractors arrange mud pits and solids-control
equipment to provide maximum solids removal. In remote drilling
locations, mechanical solids-control equipment should be selected
for ease of maintenance.
It is becoming increasingly important, especially in
environmentally sensitive areas, to use solids-control equipment
that discharges a relatively dry solid.
Cementing Program The primary purposes of cement are to seal the
annulus between casing and formation, and to support the casing
strings. The slurry selections and placement techniques vary
widely, depending on the types of formation, well temperatures,
hole and casing sizes, hole enlargement, formation pressures, and
depths and loads of the casing strings.
The well planner must determine all of the conditions and
requirements, select slurries that are appropriate, and prescribe
placement and evaluation techniques that ensure effective
results.
All this should be presented in the cement program in a concise
manner, and appropriate instructions should be included in the
drilling procedures section.
There is a large body of cementing technology with which the
well planner should be familiar. Cementing company handbooks are
the most readily available source illustrating the many variations
in slurry compositions available for special conditions.
Manufacturers catalogues are the most ready source of equipment
choices. Cementing technology cannot be covered in depth here, but
the principal concerns of the well planner are discussed.
Requirements and Considerations
The casing, hole sizes, depths, and the mud weight and type
determined previously are the basic data for cement design.
Surface strings that support subsequent strings should be
cemented to the surface with an excess of cement to ensure
uncontaminated cement at the surface. Top fill with strong cement
is necessary if the primary cement falls back. This is sometimes
advisable even after circulation to the surface in order to place
strong, uncontaminated cement at the top of the string. Top filling
is done through 1-in. pipe lowered alongside the casing.
For subsequent strings, the desired height of the cement column
must be determined and calculated with annular volume to determine
cement volume requirements. Caliper logs should be used and some
excess (usually 10 to 20%) specified, based on area experience, to
ensure cement fill to the desired height. In some cases, only bit
gauge is known, and a larger excess (usually 50%) should be
specified to compensate for washout. This, too, depends on area
experience.
The following are other considerations that affect volume
requirements:
The cement height should be sufficient to minimize casing
buckling during subsequent drilling;
The upper portion of a cement job often shows poor bonding as a
result of insufficient contact time (the time that a given depth is
flushed by cement) . All intervals that must be securely cemented
need a minimum (recommended) contact time of ten minutes;
Potential lost-circulation problems often require the use of a
light, scouring, lead slurry nearly matching the mud density,
followed by denser, strong (neat) cement through potential
producing intervals, or for the lower part of surface and
intermediate string annuli. This is also more economical than using
all neat cement;
Two-stage cementing may be used with separate volume
calculations for each stage;
Liners should be cemented with an excess to be left inside
casing. This provides less contaminated cement at the liner
top.
Slurries
The best, most accessible sources of slurry choices are the
cementing company handbooks. Usually, the cementing company
selected is called upon for recommendations.
The following are common considerations in slurry selection and
some comments:
Low-density slurries are often made with gel and pozzolan, but a
good fill cement for low-temperature, near-surface conditions is
Class A plus 16% gel plus 3% salt. These have sufficient strength
for all but completion intervals at densities down to 12.2 ppg. For
lower densities with adequate strength, more expensive Spherlite or
gilsonite slurries can be used. In cases of severe lost
circulation, foam cements may be employed. Foam cement slurries can
be mixed at densities as low as 3 to 4 ppg; however, they are not
impermeable at densities less than 7 ppg. A normally accepted
minimum compressive strength is 500 psi in 24 hours at well
temperature;
Gel cements should not be used at temperatures above 250 F.
Pozzolanic materials or silica flour should be used at temperatures
above 230 F to prevent strength retrogression;
Low-filtration slurries should be used where annular clearances
are small, such as with liners;
Fresh water or sea water can be used to prepare slurries. Sea
water is convenient and cheaper to use offshore;
Saturated salt water cement should be used when cementing
through salt;
Cements with salt usually bind well with shale formations;
Lost-circulation materials can be added to slurries if lost
circulation is a problem;
Accelerated cements can be used in shallow applications to speed
thickening;
Sulfate resistance may be needed for corrosion protection if the
formation water contains sulfate;
Normally, Class G or H cements are used with appropriate
additives, but retarded cements (Classes D, E, and F) are sometimes
used in deep wells with high bottom temperature.
Slurry Design: The slurry must be designed to give adequate
thickening time (placement time plus at least one hour) and set in
a reasonable time. It also must be pumpable, but not so thin that
free water separates when the cement sets, as this would leave
water pockets or high-side channels in the hole.
Retarders are added to slurries to give required pumping time,
but these can alter minimum and maximum water requirements or
over-retard. Slurries retarded for high bottomhole temperatures may
not set at surface conditions.
Various brands of cement of the same class have different
pumping times and even the same brand varies from manufacturer's
batch to batch. Different water sources alter pumping times, as do
different batches of additives and retarders.
All this indicates that except in shallow or very standard
conditions, the well planner should specify laboratory testing of
slurries for pumping time and strength, using the mix water,
batches of cement, and additives that will be used in the well.
This should be done well before each string is cemented to give
adequate time for any necessary adjustments.
API Spec 10 gives procedures for testing oilwell cements. It
includes schedules for applying pressure and temperature to
slurries being tested for pumping time, based on a maximum
circulating temperature derived from formation bottomhole
temperature (BHT) . These schedules are also shown in cement
company handbooks. Strength development is determined under BHT
conditions. The BHT is usually obtained from maximum-recording
thermometers run with electric logs. The temperature from
comparable wells, if possible, should be determined and provided to
the cement laboratory. Otherwise, the bottomhole temperature may be
provided by area temperature charts. The estimated temperature
should be listed in the well plan. Should logging indicate a
significant change from estimated temperature, it may be necessary
to rerun the tests, even at the expense of delay.
Slurries should be designed to provide rheological properties
that allow turbulence. The advantages of placing slurries in
turbulent flow are discussed later in the manual.
Field Mixing
Unless slurries are mixed in the field at the same water/cement
ratio as the laboratory tests, the pumping time will be altered and
free water may occur. Cement density measurements are usually taken
just downstream of the hopper during mixing. As a result, the
cement often contains considerable air, even if defoamers are used.
If air-cut cement is mixed to the specified density, the slurry at
downhole conditions will have excessive density and possibly
shorter pumping time.
Density should be checked continuously when cement is mixed on
the fly, and mixed carefully to required density when batch-mixed.
Pressurized cement balances that measure the density of air-cut
cement should always be specified and used. Also, densiometers can
be provided that give a continuous record of slurry density and
better control of mixing. These, too, should be specified.
Cement blending is not a precise science. When offshore bins
filled with blended cements are tested, there may be considerable
variation in pumping time between blends. For this reason, it is
advisable to specify testing of blended mixtures in the field prior
to critical jobs. Batch mixing should be specified whenever
practical, as it affords better control and consistency of slurry
component concentrations.
Dry samples of blended cement should be taken in the first,
middle, and last stages of the cement job. If difficulties are
encountered during the job, these samples should be laboratory
tested using the field water. Wet samples are often taken and
observed for set, but the setting time during such tests is likely
to be different from downhole set time. The Procedures section of
the well plan should specify the equipment to be used, the mix
water requirement, the spacer, and the sample-catching method.
Placement
The greatest difficulty in cementing is the adequate
displacement of mud and mud cake by cement. Many slurry
compositions are adequate if adequately placed. The following are
well-known significant factors in mud removal:
Borehole Specs A gauge hole is desirable;
Contact Time Sufficient cement should be pumped across the
critical formation to adequately flush the interval. (A minimum of
10 minutes is suggested.);
Centralization All holes wander enough so that pipe is against
the side of the hole for most of its length. Cement cannot be
placed behind pipe in such conditions;
Pipe Movement This helps break up gels and creates some lateral
movement that helps cement flow behind pipe;
Wipers or Scratchers These help remove mud in washouts even
though they may not touch the wall;
Low-Viscosity Spacers These dilute the mud, making it easier to
remove, and establish a favorable mobility ratio with the cement,
thus improving displacement;
Turbulent Flow Turbulence displaces mud much more effectively
than plug or laminar flow. Excessive pressures and flow rates are
not required when the slurry is thinned;
Density The density of the slurry should be 1 to 2 ppg heavier
than the mud whenever practical. Density difference aids mud
displacement;
Mill Varnish Removal of mill varnish increases cement bonding to
pipe.
The Cementing section of the well plan should include provision
for the above, excepting Item 1, which is affected by the mud and
hydraulics programs.
Other Considerations
The following are additional considerations that should be
included in the Cementing sect ion of the well plan.
Centralizers: These should always meet or exceed APT
specifications. In vertical holes, casing can be centralized
adequately with 90-ft spacing. In directional holes, spacing should
be calculated based on angle, pipe weight, and centralizer
strength. Centralizers should be placed over collars or stop rings
so that they are "pulled" into the hole. Closer spacing is needed
on the bottom joints.
Wipers or Scratchers: These should be spaced (often at 15 ft)
and pipe movement specified to overlap wiper or scratcher travel
from bottom through productive intervals. Rotating scratchers or
wipers should be continuous across producing intervals.
Pipe Movement: Pipe movement should begin during circulation and
continue until the plug bumps. Plugs should be dropped without
stopping pipe movement. When cement reaches the shoe, pipe should
be lowered to bottom to flush out mud, and then pipe movement
continued above. Rotation produces more cleaning than
reciprocation, but is more limited in depth of use.
Allowable Pull: A safe allowable pull should be specified in the
Casing Design and Drilling Procedures sections of the well plan.
Casing is more likely to be reciprocated if this guide is used,
particularly in directional holes.
Plugs: Two plugs should be used, because one plug behind cement
picks up excessive mud film and forces it into the cement. Plugs
should always be placed in cement, not in spacers. The front plug
should be inserted after the spacer. When the top plug is ready to
be dropped, the lines should be broken at the cementing head and
flushed, then the spacer pumped behind the plug.
Accurate displacement of the top plug is essential. Even small
amounts of over-displacement harm cement jobs. Therefore,
displacement should be measured from cement tanks to avoid
over-displacement in case a plug fails or is inadvertently left in
the cementing head. Over-displacement volume should be limited to a
maximum of one or two barrels over calculated value, depending on
casing size. Displacement should be measured using measuring tanks
on the cementing unit rather than barrel counters or pump
strokes.
Float Shoes and Collars: Two check valves are often run, as one
might fail. With occasional filling of pipe being run, float
equipment failure can cause a blowout as annular fluid level drops
due to U-tubing into the partially filled casing. The float collar
should always be at least one joint above the shoe in order to
prevent cement contaminated by mud film from circulating into the
annulus. Epoxy cementing of collars and bottom joints should be
specified in the Drilling Procedures section of the well plan.
Waiting on Cement: Time for cement to set is usually short as
far as adequate support of pipe is concerned. However, slurries
retarded for use in deep, high-temperature wells and circulated up
the hole may have extended setting times. In these circumstances
the cement company should be consulted and simulated tests run if
needed.
Liners: Cement should be circulated well above liner tops (300
to 500 ft) to provide adequate flush, and left to be drilled out,
rather than reversed out. Cementing at an excessive rate is a
common mistake, causing excessive annular pressure and loss of
circulation. A suitable rate should be specified in the well
plan.
Evaluation
In routine jobs, the cement height is often not determined. But
where circulation is lost, and in deep wells, either a temperature
log or bond log (CBL) should be run to determine cement height.
Bond logs are controversial, but can be of value in determining the
adequacy of a cement job. These are necessary in unusual conditions
and in critical wells.
The Drilling Procedures and Logging Program should list the
surveys. Block squeezing of producing intervals is normally not
necessary when the interval is reasonably near bottom, unless the
bond log so indicates. However, contamination of cement placed
uphole may require squeezing, and the bond log is the only tool
available for evaluation.
Gas flow in the cemented annulus can be detected by noise logs,
which should be run if this problem is suspected.
Annular Gas Flow
Tinsley, et al.(1979) and Cooke (1982) have shown that cement
hydrostatic pressure tends to drop to formation fluid pressure when
initial set begins. This can result in flow through the cement to
the surface with surface strings, flow at liner tops, or interzonal
flow through cement. These flows seem to be relatively small, but
troublesome. Various solutions have been suggested, including
holding pressure and pumping into the annulus during set.
Much research has been done recently regarding annular gas flow.
Cementing companies have recommended solutions as diverse as
thixotropic cements, and cements blended with aluminum powder. The
aluminum powder reacts with the cement to generate small quantities
of hydrogen gas, which maintains pressure in the cement column
until the cement sets completely. There is not any clearly
effective, direct solution, and such situations require special
study.
Bit Program Designing a bit program involves much more than
simply selecting a bit type. The objective is to employ a bit
program and associated drilling practices that will minimize
drilling cost per foot. The various bit company catalogues and
manuals illustrate the large variety of bit types available, but
admit that selecting the best bit to match the formation involves
some trial and error. The well planner needs to be thoroughly
familiar with such manuals, and with the proper application of rock
bits and other bit types, as well as alternate drilling
techniques.
The principal choices of bit type are:
Roller Cone Bits
- Mill tooth (commonly called "rock" bits)
- Tungsten carbide insert (commonly called "button"
bits)Variations
- Standard or extended jet nozzles
- Soft to hard formation designs
- Roller or journal bearings
- Gauge protection
- Small to large diameters
Fixed Cutter Bits
- Polycrystalline diamond compact (PDC)
- Thermally stable PDC (TSP)
- Natural diamondVariations
- Soft to hard formation designs
- Parabolic, cone, or step bit crown profiles
- Nozzle, radial flow, or feeder/collector hydraulic flow
patterns
- Gauge protection
- Small to large diameters
- Angle, shape, size, and density of cutters
- Steel body or tungsten carbide matrix body
- Hybrid combinations of cutter types
- Size and number of Junk slotsAll of these have design
variations for use with downhole motors,
There are variations in both mill-tooth and tungsten carbide
insert bit design for soft to hard formation types. The softest
formations, particularly where bit balling is a problem, are
usually drilled best with mill-toothed bits. Generally, these
provide faster drilling rate and shorter tooth life than tungsten
carbide insert designs for comparable hardness.
Rock-bit life may be limited by tooth wear, bearing wear, or
loss of gauge protection, all of which are affected not only by the
type of formation drilled, but also by the drilling fluid used,
hydraulics, and drilling mechanics. Even the most appropriate bit
for a formation can give poor results if these factors are not
handled properly. A bit designed for softer formations almost
always drills a given formation faster than would a bit designed
for harder formations, The same bit type in a smaller size has
smaller bearings and teeth, and consequently less penetration rate
with the same drilling mechanics, and also has a shorter bearing
life.
Sealed journal bearing bits tend to have a limitation on the
maximum combination of weight (W) and rotary speed (N) that can be
run and still afford satisfactory bearing life. Bit manufacturers
publish recommended ranges of weight and rotary speed for each bit
type in their catalogues. Except for cases where tooth penetration
is so great that the cones ride on the formation (and this can be
helped by hydraulics), higher bit weights and rotary speeds result
in faster drilling. Consequently, if there are no other
limitations, maximum WN values ( weight multiplied by rotary speed
) usually provide the most economical bit runs.
Even so, relative emphasis should be placed on higher rotary
speed in soft formations and higher bit weight in hard formations.
High rotary speeds accelerate tooth and bearing wear in harder
formations and create vibrations leading to drillstring and bit
failure. High bit weights tend to cause bit balling in soft
formations..
PDC Bits: Compared to roller cone bits, PDC bits employ low
weight-on-bit and high rotary speed. These bits may be limited in
shallow drilling by bit balling (controllable to some extent by
high hydraulics) and in harder formations by the effects of heat
generated on the diamond cutter. Thermally stable PDC bits provide
much better performance in this area.
PDC bits cost more than rock bits, particularly in large sizes
(10-5/8 in. or larger) . The higher cost can be offset, however, by
higher penetration rates and longer bit life.
Bit Selection: There is a strong tendency among field personnel
to simplify the problem of bit selection based on hours run or
footage made, but this often provides wrong answers. Bits are run
for effective drilling, not to be conserved.
On exploratory wells there may be no offset bit records on which
to base selection, but there are often records of wells drilling
the same formation some distance away. Usually there are one or
more bit records that can be studied and used judiciously.
The first step in bit comparison is to calculate the cost per
foot for bits run in offset wells. These values are then plotted
against depth ( Figure 1 ) . Sometimes the depths need to be
adjusted to make comparisons on the basis of formation tops or
measured depth, but this gives a far clearer indication of cost
effectiveness than can be obtained by simple examination of bit
records.
Figure 1
Notably, one of two bit runs in offset wells may be cheaper than
the other, but the comparison can be reversed if the runs are
started at different depths or the rig rate is changed equally for
both rigs.
The tool on which comparisons of effectiveness should be based
is the cost-per-foot for a bit run formula, which we may express as
follows:
[ C/D ] = [ Cbit + Crig ( t + T ) ] /DWhere: C/D = cost per foot
t = trip time, hours
Cbit = bit cost T = rotating time, hours
Crig = equivalent hourly rig costD = footage drilled
The principal applications of the cost-per-foot calculation are
to (1) determine the cost per foot at intervals during a bit run,
and (2) to make economic comparisons of bit runs or drilling
techniques. The application relates principally to mill-tooth bits,
whose drilling rate slows (and cost per foot increases) as their
teeth become dull, indicating that the bit should be pulled. The
second application allows comparison of subsequent bit run costs,
offset well bit run comparison; and if suitable input is made, can
compare such variations as using a downhole motor, air or mist
drilling, etc.
In plotting comparisons ( Figure 1 ), it is best to use the
equivalent hourly rig rate for the well to be drilled rather than
for the rig actually used. The trip time factor should also be that
anticipated for the well to be drilled. Otherwise, the comparison
may be distorted or even reversed.
Even after calculation and plotting, selecting the bit and
rotary practices is a matter of judgment selection based on low
cost-per-foot could actually result in an expensive bit run if the
bit gauge wears out and the hole must be reamed. High costs might
also result from pulling a "green" bit, poor hydraulics practices,
using excessive mud weight, or maintaining too low a bit weight or
rotary speed.
Presentation: The bit program should list the bits to be run,
the expected intervals of use, approximate weight and rpm, and
discuss any appropriate special considerations.
Hydraulics The hydraulics program should provide for:
minimum annular velocities and flow rates;
maximum annular velocities and flow rates;
jet bit and other bit hydraulics design;
minimum pump and pump output horsepower.The objectives are to
ensure adequate hole cleaning., minimize hole enlargement in some
instances., ensure maximum drilling rate as related to hydraulics.,
and specify minimum pump horsepower.
Annular Velocity and Flow Rate
Hole cleaning is affected by a number of interdependent factors.
These are drilling rate, bit size, pipe size, mud effective
viscosity and density, circulating rate, annular velocity, flow
regime., hole enlargement., sloughing rate., pipe rotation.,
cuttings and sloughings shape, mud type, and balling tendency. No
expressions combining all these factors are available, although
some semiquantitative expressions or estimates have been
published.
Reasonably., the annular velocity should be as high in large
diameter holes as it is in more common-sized holes, but this is
seldom seen because available rig pumps do not have this
capability. The lower annular velocities in larger holes are
acceptable because of at least three effects. When drilling with
water in hard rock., bit cuttings tend to break easily into fines
and are more readily removed. Also., drill rate tends to be slow,
so removal rates can be low. With drilling with mud, the low shear
rates in large holes result in high effective viscosities that
compensate for lower annular velocities. In soft rock, where
drilling rates in large diameter holes are fast, the cuttings tend
to disperse and make fine particles that are easily removed. Even
so, drilling rates can be too fast, resulting in burying the bit
and/or balling. In some instances maximum drilling rates may need
to be specified.
One commonly stated axiom is that cuttings volume should not
exceed 5% of mud volume. Undoubtedly, a mass of cuttings can
accumulate., often in washouts where annular velocity is greatly
reduced., and this can fall back when pumping stops for a
connection. However, calculating slip velocity as a basis for
setting minimum annular velocity is a very uncertain procedure. In
laminar flow (Williams and Bruce, 1951), flat particles are subject
to random turning and sliding downhole., but are better removed
when pipe is rotated. More-rounded particles ride the center of the
flow profile and can rise faster than the average flow rate. All
this makes calculation of the cuttings removal rate very uncertain,
hence the rule that flow rates maintain less than 5% cuttings.
As a practical matter, minimum circulating rates are usually
selected based on area experience for the hole and pipe sizes under
consideration. If fill on trips occurs or circulation tends to be
restricted after connections, adjustments can be made in viscosity
to improve hole cleaning. Density is sometimes increased to stop
sloughing. When drilling with water or low-viscosity muds, pills or
sweeps of high viscosity are sometimes used. If these procedures
are anticipated, appropriate comments should be made in the Hole
Problems and Mud Program sections of the well plan.
In special cases provisions may be necessary to ensure adequate
hole cleaning in enlarged sections above liner tops or in
risers.
The following are suggested minimum velocity guidelines:
Bit size (in.)DP OD (in.)gpmfpm
4-3/42-7/8100170
63-1/2150150
8-1/24-1/2250120
9-7/84-1/2 - 5350 - 330110
12-1/44-1/2 - 5530 - 510100
154-1/2 - 5585 - 57070
17-1/24-1/2 - 5700 - 69060
These may vary considerably, depending on specific conditions.,
and local practice should be checked before setting the minimum
velocity and flow rate. Except in the lower part of the hole.,
circulation is usually at rates considerably above minimum. If
unusual conditions exist, these should be stated in the well
plan.
Larger hole sizes often require two large pumps to provide
minimum annular velocity.
Maximum flow rate is usually the maximum flow rate of the pump.,
unless hole erosion is a consideration.
At any level of pump pressure on which a jet-bit program is
based, pumping at less than the maximum rate (or, when the bit is
deep enough., reducing the rate below the optimum rate) reduces bit
hydraulics and sacrifices drilling rate. Therefore, flow rates
should not drop below those inherent in a properly designed jet-bit
program unless there is an overriding reason.
One such reason is hole erosion. In this case., maximum rates
should be established and stated in the well plan. In order to
avoid turbulent flow around drill collars or drillpipe, annular
velocities are sometimes limited to less than critical velocity.,
calculated from a Reynolds number of 2000.
Borehole erosion due to excessive annular velocity is largely
self-correcting. Small enlargements rapidly reduce annular velocity
and there is a concurrent increase in effective viscosity that also
reduces Reynolds number. Except in instances where excessive flow
rates are known to cause a problem, maximum flow rates should be
specified as indicated by jet-bit program design.
Jet-Bit Hydraulics Program
The hydraulics program must be designed with due regard to hole
cleaning, mud-density requirements, hole geometry, drillstring
sizes., and pumps to be used.
Industry opinion is divided as to whether jet-bit programs
should be designed to provide maximum bit hydraulic horsepower or
impact force. Optimum flow rates can be reduced by 25 to 30% at a
given standpipe pressure by designing programs for maximum
hydraulic horsepower rather than jet impact force. This results in
decreased pump input horsepower requirement and decreased fuel
consumption.
With either criterion., the most significant factor is that
hydraulic energy is transmitted to the bit with less loss at high
pressure. Therefore, the pump liner to be used is the smallest
(with the highest pressure rating) that will provide minimum
annular velocity. To improve the life of pump parts, programs are
generally designed and run at less-than-rated liner pressure.
However, a small reduction in surface pressure results in a much
larger reduction in bit hydraulic horsepower or impact force.
Demonstrably, increasing bit hydraulic horsepower or impact
force increases drilling rate at constant bit weight. Often,
increased bit hydraulics allows a higher maximum effective bit
weight, which can further increase drilling rate. These effects
lessen in hard rock, but are still present. The objective for the
well plan is to specify a jet-bit program that ensures maximum
drilling rate.
If rig equipment, mud-density requirements, and pump efficiency
are accurately known, then a workable jet-bit program can be
planned. However, the mud density is only approximately known and
subject to unexpected variations. Actual pump efficiency varies
from estimated values, and the use of viscosity-building and
filtration-control polymers often varies the friction loss of muds
so as to change the apparent pump efficiency. The drillstring
design is subject to variation, and the exact pump liner size is
not known until the rig has been selected.
Thus, a detailed hydraulics program planned for a well has to be
modified as the well is drilled, and can be only approximate and
illustrative. Where computer, calculator, or offset well programs
are available., an illustrative program is sometimes worth
including in the well plan, but is not mandatory.
The rules for designing jet-bit programs for maximum bit
hydraulic horsepower or impact force (Kendall and Goins, 1960) can
be applied to field data to determine the next bit nozzles. This
avoids the unanticipated variations inherent in a completely
preplanned program. Hydraulics programs should be based on maximum
practical surface pressure, and allow for any anticipated mud
density increase during the bit run. A procedure (Coins and Flak,
1984), based on the graphical technique used by Hughes Tool Company
in their Practical Hydraulics text, provides for increases in pump
pressure and/or mud density.
Design procedures must recognize minimum annular velocity
limitations and maximum flow rate of the pump liner used. When
maximum annular velocity is selected to avoid excessive hole
erosion, the maximum flow rate must be recognized. With these
considerations in mind, the following items should be specified in
the well plan for each hole size:
minimum annular velocity and flow rate;
use of smallest liner that will provide minimum annular
velocity;
maximum flow rateeither maximum pump rate or maximum flow rate
based on limiting hole erosion;
nozzle selection for next bit run based on field data using
calculation or graphical techniques allowing an increase in pump
pressure and/or mud density.Hydraulic program design for PDC bits
appears to be best done as for toothed jet bits. However., minimum
flow-rate restrictions may be based on bit cooling rather than hole
cleaning. The minimum flow rate is often specified by the bit
manufacturer.
Pump Horsepower
Pump requirements should be based on maintaining minimum annular
velocity at a preselected, maximum surface pressure. Horsepower
requirements are high in large holes and decrease as hole size
decreases. Horsepower requirements also decrease with depth in a
given hole size.
Figure 1 illustrates how pump horsepower requirements vary with
hole size and drillpipe size at selected surface pressure.
Figure 1
This illustration is based on 120 ft/min minimum annular
velocity. Note that pump horsepower to provide maximum impact force
or bit horsepower decreases with depth. Horsepower requirement is
obtained by calculating flow rate to provide minimum annular
velocity in the hole and drillpipe annulus., and multiplying by
surface pressure divided by the appropriate constant; i.e., PHP =
Q(gpm) X P(psi)/1714.
This must be done in the larger hole sizes using minimum annular
velocities selected. The highest horsepower requirement should be
increased assuming 90% hydraulic efficiency. Also, it is necessary
to specify minimum mechanical horsepower input assuming 85%
mechanical efficiency. In many cases, rigs cannot provide enough
horsepower to run pumps at rated values. Horsepower requirements
should be specified in the Rig Requirements section of the well
plan.
Hole Deviation Unintentional hole deviation often results in a
variety of serious (and occasionally disastrous) problems.
Deviation is measured and expressed in degrees. In "vertical" hole
sections, it is usually measured with either a plumb bob or
gyroscopic instrument. Instruments can be run on slickline or
dropped inside the drillstring. Except at deviation angles above 45
F, absolute deviation rarely causes problems of any consequence.
Rather, it is rate of change of angle, known as dogleg severity
(expressed as degrees change per hundred feet of hole), that causes
problems. In shallow wells deviation is usually measured assuming
direction does not change, but as depth increases, directional
measurements are generally included. This is helpful both for
maintaining a fix on the position of the hole in case of a blowout,
and to obtain a more accurate measurement of dogleg severity.
Dogleg severity is the direct cause of a number of well problems.
These include drillpipe and casing wear, drillpipe fatigue, rod and
tubing wear, key seats, high drillstring drag and torque, failure
to get logs and casing to bottom, excessive loads on casing, and
other problems related to or resulting from those listed here. In
general, shallower doglegs cause more severe problems due to
greater tension in the drillstring. Casing wear can result in
failures which, in turn, lead to either lost circulation or
blowouts.
Little is known about precisely which rock characteristics cause
holes to deviate. It is known, however, that deviation generally
becomes harder to control as rocks become harder. This is due to
the nature of the rocks and the necessity for applying higher bit
weights for penetration. Several authors (e.g., Milheim l979) have
described the effects of added bit weight on deviation.
Experience in many areas shows that deviation problems are much
more severe in some intervals that others. Problems in a particular
interval may extend basinwide., or may be more localized. Problems
are often related to geologic structure., hole size., and
bottomhole drilling assembly clearances.
In soft to medium-hard rocks, deviation is often the result of
sidewise rather than frontal drilling by the bit. Changes in rock
strength., erosion of the borehole wall., and perhaps other effects
tend to cause rather abrupt changes in hole deviation. These
changes may or may not be observed on deviation surveys., but they
often result in an effective hole diameter considerably less than
bit size. Degree of offset and consequent reduction in effective
hole diameter is dependent upon the relation of drill collar or
stabilizer size to bit size (Qilaon., 1976) .
The need to bottom a well at a fixed location varies
considerably. Lease boundaries or geologic considerations sometimes
necessitate restriction of hole deviation. At other times., wells
could be allowed to drift almost without limit. Since restrictions
of deviation almost universally increase well cost., the maximum
practical limits should be allowed. When deviation is severe and
the direction of drift is predictable., it is often economically
desirable to displace the surface location to such a point that
normal drift will place the bottomhole at the desired location.
The large majority of wells tend to drift updip. In harder
rocks., the tendency exceeds 95%. It is always desirable to plan
deviation limitations to allow the maximum tolerable displacement.
If the dip direction is known., deviation limitations can be
relaxed or tightened accordingly to allow maximum penetration
rates.
From a well-operation point of view., hole displacement in
itself is of little consequence. Restrictions are required because
of dogleg severity and hole angle.
Dogleg severity is the primary concern among deviation problems.
For the reasons mentioned above., limits must be enforced to
prevent severe problems. Much work has been done to establish
maximum allowable dogleg severity (Lubinski, 1960; Williamson.,
1981) and as long as recommended limits are observed, few problems
occur.
Hole angle becomes important at higher values primarily for
three reasons. First, as the lateral component of drillstring load
increases., the likelihood of wall sticking increases. Second.,
carrying capacity of drilling fluid is decreased., allowing
accumulation of cuttings in the borehole. Third., as the lateral
component of drillstring load increases., both rotating torques and
longitudinal drag are increased due to friction. The solution to
all of these problems involves special attention to drilling
fluids., hydraulics design., and drillstring design.
Hole deviation and dogleg severity are controlled by bottomhole
assembly configuration and drilling rate parameters, or by
directional drilling methods. The ideal condition for deviation
control would be to run an infinitely stiff bottomhole assembly
with zero clearance to the well bore. Since that condition is
unattainable., the practical solution is to run the
maximum-fishable-diameter drill collars to get maximum stiffness.,
and to run the minimum number of stabilizers that will keep
deviation within tolerable limits while drilling at an acceptable
penetration rate.
Bottomhole assembly selection is largely empirical. The relative
ability of various assemblies to build., hold., or drop angle has
been fairly well established (Milheim., l979) . However., the
selection of the assembly for use in a particular well must still
be based on experience. Records from similar wells, whether offsets
or merely in a similar basin., often provide the best guide for
selection of bottomhole assemblies.
The well plan should include the following items concerning
deviation control:
a description of any anticipated problems;
the bottomhole assemblies to be used;
the method and frequency of surveys;
the limits of hole angle as a function of depth, if
applicable;
a stipulation that doglegs above 3 degrees/100 ft be wiped out
with string reamers.
In many instances, modern directional drilling techniques have
replaced traditional methods of deviation control. Depending on the
potential for deviation-related problems and the importance of
maintaining a specified well trajectory, such equipment as downhole
motors may be used even in "straight hole" applications.
Logging The drilling engineer can use several controls to
maximize openhole log accuracy. The main control often is the mud
program. Severe hole washout can ruin log quality. If this is a
regional problem, the drilling engineer can specify a more
inhibitive mud system to reduce hole erosion. If turbulent flow is
causing hole enlargement in the region, then the hydraulics program
can address the problem. The logging tools most affected by hole
enlargement (in order of effect) are dipmeter, microlog, BHC sonic,
neutron porosity, density porosity, and resistivity/ induction
logs.
Excessive filtration into a producing zone can make fluid
content evaluation from resistivity logs very difficult. The log
analyst should provide the drilling engineer with the depths of
possible production zones and practical fluid-loss limits.
Coring
The drilling engineer should be provided a coring program for
well planning and cost estimation. Coring operations are expensive
and time-consuming. Failure to include coring costs in an estimate
could result in cost over runs.
Coring costs can be reduced if the drilling engineer is given
some warning while preparing the well plan. PDC core heads can be
used to core at substantially higher rates than natural diamond
core heads in the right application. PDC core heads also reduce
core barrel jamming, which allows much longer (90- to l20-ft) core
barrels to be used.
Many times the drilling engineer is not informed of the need for
core preservation and quick evaluation by the coring program
initiators. If a representative core is required., the engineer
should be instructed in pressure coring and "native state" coring
techniques.
The sidewall coring (SWC) program should also be transmitted to
the drilling engineer. The practicality of SWC on an intermediate
log run should be evaluated carefully. If drilling is to proceed.,
the SWC barrels left in the hole will need to be fished out at
additional cost. Again, the well plan should reflect the need for
proper core preservation and quick evaluation.
Testing
A properly run and interpreted drillstem test (DST) probably
yields more valuable information for its cost than any other
evaluation tool. A DST can be defined as a temporary well
completion in open or cased hole, which is designed to sample
formation fluid and establish the probability of commercial
production. Open hole DSTs are typically run in hard-rock areas.,
such as the Permian Basin of West Texas and in the midcontinental
region of the United States.
The drilling engineer must be given every possible detail of the
proposed DST when planning the well and estimating costs. Area
knowledge may indicate that running a DST is impractical, or may
suggest a particular DST technique to gain the most information. A
well-run DST yields information about reservoir fluid composition,
static reservoir pressure, and productivity. Transient pressure
evaluation of recorded pressures yields information about flow
capacity (KH product) and skin effect. This information can then be
used by the drilling, completion, and reservoir engineers to
determine the prospect commerciality, fluid composition., required
tubing size, perforation density, and reservoir characteristics.
Additionally., this information aids in the planning of effective
well treatments and the development of a comprehensive production
testing program after pipe is set. The Drilling Procedures section
of the well plan should fully describe the DST procedure planned
for the well. The reservoir engineering group should provide an
on-site engineer during the test to evaluate the test data.
The completion procedure should fully describe any required
cased hole production tests. This information should be summarized
and included in the logging, coring, and testing section.
The completion procedure should accurately describe what would
actually occur in the field. In this way, the well is "tested on
paper" prior to the actual job. Deficiencies in the procedure can
then be recognized and corrected.
If some basic assumptions can be made prior to drilling the
well, the drilling/completion engineer can make some preliminary
calculations to better estimate the required length of the test and
the required test equipment capacity, and determine the best test
technique.
The reservoir engineer, who depends on good, representative test
data to make various evaluations, should be on location during
testing to act as a quality-control inspector of the test data.
This should be mentioned in the well plan.