**9-21-04 Draft RP-65-P2**

**API RP-65 Part 2**

**\"****Isolating Potential Flow Zones in Well Drilling and Cementing
Operations\"**

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**Isolating Potential Flow Zones in Well Drilling and Cementing
Operations**

**1.0 Scope**

This document contains best drilling practices and primary cementing
design recommendations for inhibiting annular fluid flow by barriers
including hydrostatic pressure, mechanical seals, or cement.

**1.1 Background**

On August 16th of 2000, the MMS (Minerals Management Service) of the U.
S. Department of the Interior presented safety concerns on uncontrolled
annular flows to a new API Work Group comprised of government and
industry representatives of several organizations including API
Washington staff, API Executive Committee on Drilling and Production
Operations, API Subcommittee 10 on Well Cements, International Standards
Organization, International Association of Drilling Contractors,
Drilling Engineering Association, the MMS, and other interested parties.
Issues related to sustained casing-head pressure (SCP) were also
discussed. The API Work Group on Annular Flow Prevention and Remediation
agreed to prepare "best practices" to improve zonal isolation, reduce
the occurrence of SCP, and help prevent annular flow incidents prior to,
during, and after cementing operations. Studies of all available
information on flow event causes and prevention helped the Work Group
write best practice documents for publication as API Recommended
Practices. The MMS is considering the incorporation of these API
publications into new regulations for well construction in federally
regulated areas. The API Work Group is responsible for the following API
Recommended Practice publications:

a)  RP-65 Part One titled \"Cementing Shallow Water Flow Zones in Deep
    Water Wells.\"

b)  RP-65 Part Two titled "Isolating Potential Flow Zones in Well
    Drilling and Cementing Operations."

c)  RP-65 Part Three titled "Zone Isolation to Prevent and Remediate
    Sustained Casing Pressure."

**1.2 General**

The failure of an annular cement column to isolate the wellbore is the
root cause for many of the loss of well control incidents experienced in
offshore drilling operations. Loss of well control events can occur at
any point in the well construction process, from soon after spudding the
well to drilling the well at total depth.

A number of factors are common to loss of well control events
experienced while drilling the top-hole section. From a pressure
maintenance standpoint, many wells are drilled in a near-balanced
condition. As such there often are times when only a minimal pressure
margin exists between formation pore pressures and circulating
hydrostatic pressures of the drilling fluid. Typically the well is being
drilled with simple spud muds with minimal fluid loss control. The
cement slurries employed are lightweight, extended lead cement systems
with a tail cement of higher density placed in the lower section of the
cemented interval. In common practice, both lead and tail cement systems
would be designed without any gas control capabilities. Further, certain
lightweight cement systems are prone to gel quickly, thereby
accelerating the loss of hydrostatic pressure exerted on the column of
tail cement below.

**[*It should be noted that in the Gulf* *of Mexico the majority of loss
of control events occur after tophole cementing operations. Conventional
cement designs typically employed in the shallow section of the wellbore
possess no ability to mitigate flow, and as such, must not be used for
the purpose of controlling annular flow in the wellbore.*]{.underline}**

Achieving zonal isolation in the presence of a potential annular flow
requires not only the modification of the cement properties to
facilitate control of migrating formation fluids but also several other
actions including:

-   A stable wellbore -- no losses or gains

-   Adequate annular circulating flow clearances

-   Proper mud conditioning

-   Spacer design

-   Casing centralization

-   Tripping requirements

-   Drilling techniques

-   Well monitoring

This document is a compilation of best-demonstrated practices,
engineering considerations and cement property requirements to be
applied to assist in the prevention of annular flows and to establish
zonal isolation of the wellbore. This task entails, at its most
fundamental level, the removal of mud from the wellbore and replacement
of mud with cement capable of achieving and maintaining annular
isolation.

**1.3 Conditions of Applicability**

The guidance from this document will cover two main areas: (1)
Recommended drilling practices and cement design recommendations to
mitigate annular fluid flow as a result of a pre-spud hazard assessment
and (2), required actions to mitigate flow as a result of events
experienced while the well is being drilled.

Pre-spud information gathered from offsetting well(s) and /or from high
resolution seismic surveys can be used to define the degree of flow
potential (Low, Medium, High) for a particular drilling prospect. Any
relevant information should be communicated to the appropriate service
provider for incorporation into the basis of design for a particular
fluid (mud or cement) and for relevant engineering and operations
procedures.

If any subsurface anomaly with a potential flow is identified by seismic
or offsetting well information, the following recommendations are made:

1.  When possible, the surface location should be relocated outside the
    anomaly to a location with less risk.

2.  When relocation of the wellsite is not possible, the drilling plan
    for the effected section of the wellbore should be modified to
    mitigate the risk of flow. The next section on well planning details
    the recommended action steps.

**2.0 Well Planning and Drilling Plan Considerations**

***2.1 Evaluate Well For Flow Potential***

Before drilling a well, the operator should attempt to identify and
analyze potential flow zones. A variety of techniques are available to
do this, three of which are discussed below. The success of these
techniques in identifying and successfully dealing with flow zones is
related to the quality of the available data, a company's experience in
a specific geographical area, and the quality of personnel.

***2.1.1 Site Selection***

Prior to drilling, the operator can minimize encounters with potential
flow zones by carefully selecting a site that achieves target depth
while minimizing the risk of encountering a flow. This is primarily
accomplished through accurate review and analysis of available shallow
and deep hazards data, proper interpretation of this information, and
assimilation of this information into the drilling program.

When available, offset well information should be evaluated to determine
if flow zones were encountered, the magnitude of any flow events, and
the methods used to mitigate the effects of these flows. If possible,
this information should be incorporated into the current drilling
program.

Cementing Shallow Water Flow Zones in Deep Water Wells, API Recommended
Practice (RP) 65, First Edition, September, 2002, Section 4, addresses
site selection for minimizing shallow flows in deep water wells. Many of
the same principles discussed in this Section apply to operations for
all water depths and well depths. Refer to RP 65 for further
information.

***2.1.2 Shallow Hazards***

Identification and evaluation of shallow hazards through the use of
seismic surveys can aid the operator in proper site selection. If
available, shallow seismic data from offset wells or adjacent fields
should be analyzed to verify the analysis. If hazards are identified,
they should be avoided if possible. The operator is cautioned that
shallow hazards analysis is not a conclusive method of prediction, so
precautions to minimize the chances of a flow should still be
implemented when drilling the shallow portions of the well.

If the decision is made to drill a well in an area that is likely to
encounter shallow hazards, consideration should be given to drilling the
shallow portions of the well with a small diameter pilot hole. If a
shallow flow zone is encountered during pilot hole drilling, a kill
operation will be easier to achieve.

***2.1.3 Deeper Hazards***

Potential sources of deeper drilling hazards include abnormal pressure,
drawn-down zones, faults, tectonics, salt flows, and areas of lost
circulation. Such hazards can often be identified through seismic
interpretation and/or analysis of offset wells or fields. Identification
of hazards that could be encountered during drilling operations will aid
in proper well planning and in minimizing risk. If available, deep
seismic data from offset wells or adjacent fields should also be
analyzed to aid in the prediction of flow zones.

***2.2 Planning the Well*** -- introductory verbiage from DPP

***2.2.1 Pore Pressure / Fracture Gradient / Mud Weight*** -- The well
planner must understand the anticipated pore pressures, fracture
gradients, and mud weights that will be encountered while drilling the
well. This information is generally presented as a graph, as shown in
Figure 1.

> **INSERT FIGURE 1**

General guidelines for the construction of this graph are given below:

-   Plot the predicted pore pressure vs. depth, expressed as an
    equivalent mud weight (EMW). It may also be helpful to note
    lithological information, if it is available.

-   Similarly, plot the predicted fracture gradient profile. Draw a
    design fracture gradient profile that is offset to the left of the
    predicted curve by a prescribed amount to roughly account for kick
    tolerance and the increased ECD during drilling and cementing
    operations. Typical offset values range from 0.2 ppg to 0.5 ppg.

-   Draw the mud weight profile based on the pore pressure and fracture
    gradient data. In general, the mud weight profile is offset to the
    right of the pore pressure curve to provide a sufficient overbalance
    for trips. Typical offset values range from 0.3 ppg to 0.5 ppg.

> If mud weight and leak-off test (LOT) information is available from
> offset wells, include it on the graph for reference. If large
> disparities exist between the offset well information and the
> predicted values, further investigation may be warranted. This graph
> will become the design basis for the well.

***2.2.2 Casing Plan*** -- The appropriate selection of shoe depths and
consequently, the required number of strings is critical to the well
design. General guidelines are given here for the selection of shoe
depths. Local practices and experience should also be used to fine-tune
this process.

![](media/image1.wmf){width="5.748611111111111in"
height="3.8854166666666665in"}

**Figure 2 - Casing Shoe Selection Graph**

> The initial shoe depth determination is made as follows (see Figure
> 2):

-   Starting at the mud weight at the well TD (point A), draw a vertical
    line upwards until it intersects the design fracture gradient curve
    (point B). This is the approximate shoe depth of an intermediate
    casing.

-   Draw a horizontal line from point B leftwards until it intersects
    the mud weight curve (point C) and then upward until it intersects
    the design fracture gradient curve (point D). This represents the
    approximate shoe depth of the next casing string.

-   Repeat this process until all shoe depths dictated by mud weight and
    fracture gradient constraints have been established.

After the preliminary shoe depths have been established, an additional
check should be made based on kick tolerance. The kick tolerance is the
maximum size kick of a specified intensity that can be circulated out of
the hole without causing the formation to fracture in the open hole
section (often near the shoe). It may be necessary to adjust casing shoe
depths to conform to kick tolerance limits.

In some higher pressure wells with a small margin between the mud weight
and the fracture pressure, the recommended kick tolerance is nearly
impossible to achieve. This is particularly true for many wells drilled
in the Gulf of Mexico.

There are numerous other factors that affect the design of shoe depths.
These factors include:

-   Regulatory requirements. Applicable local regulations should always
    be obtained before beginning the design. For the Offshore U.S., MMS
    regulations can be found in CFR 30 part 250.

-   Hole stability. This can be a function of mud weight, deviation and
    stress at the wellbore wall, or it can be chemical. Hole stability
    problems often exhibit time dependent behavior (making shoe
    selection a function of penetration rate). The plastic flowing
    behavior of salt zones should also be considered.

-   Differential sticking. The probability of becoming differentially
    stuck increases with increasing differential pressure between the
    wellbore and formation, increasing permeability of the formation,
    and increasing fluid loss of the drilling fluid (i.e., thicker mud
    cake).

-   Zonal isolation. Shallow fresh water sands need to be isolated to
    prevent contamination. Lost circulation zones should be isolated
    before a higher-pressure formation is penetrated.

-   Directional drilling concerns. A casing string is often run after an
    angle-building section has been drilled. This avoids keyseating
    problems in the curved portion of the wellbore due to the increased
    normal force between the wall and the drill pipe.

-   Uncertainty in predicted formation properties. Exploration wells
    often require additional strings to compensate for the uncertainty
    in the pore pressure and fracture gradient predictions.

> ***Hole and Pipe Diameters*** - The selection of pipe diameters has
> the largest impact on well costs in both design base and detailed
> casing design. In general, hole and pipe diameters should be designed
> to be the smallest possible, which meet all design requirements, well
> objectives, and safety and environmental requirements. In exploratory
> wells, hole diameters may be larger to allow for contingency casing
> string (s). The final hole or casing diameter is generally determined
> by evaluation, completion, and production requirements. Because of
> this, casing sizes should be determined from the inside outward.
>
> Hole and casing diameters are based on the following requirements:

-   *Drilling* - minimum bit diameter for adequate directional control
    and drilling performance, available downhole equipment, rig
    specifications, and available BOP equipment.

-   *Cementing* -- See next Section 2.2.3 below under Hole Size and
    Shape and Section 5.5 for more information.

-   *Production* - production equipment requirements including tubing,
    subsurface safety valve, submersible pump and gas lift mandrel size,
    completion requirements (e.g., gravel packing), and weighing the
    benefits of increased tubing performance of larger tubing against
    the higher cost of larger casing over the life of the well.

-   *Evaluation* - logging requirements and tool diameters.

***2.2.3 Cementing Plan*** -- Short and long term isolation of potential
flow zones requires proper cementing planning and execution. Several
aspects of well planning may affect the success of primary cementing
operations:

-   ***Hole Size and Shape*** - Hole size and shape affects the
    available annular space, fluid velocities, displacement mechanics,
    centralizer effectiveness, and cement volumes. Fluid systems and
    bottom hole assemblies (BHA) that provide a smooth, non-spiraling
    wellbore will improve displacement mechanics and ultimately cement
    placement. A non-spiraling hole shape can minimize casing
    eccentricity, improve uniform centralization by centralizers, and
    optimize mud displacement. In many wells, the available hole size
    coupled with needed casing size substantially restricts the annular
    flow area and virtually eliminates the ability to circulate cement
    in the well. The bypass flow area across tools such as liner hangers
    and liner packers should be maximized to help reduce flow
    restrictions and the associated high equivalent circulating
    densities (ECD) that can cause lost circulation, channeling, and
    poor cement placement. The ability to properly circulate the well
    with casing on bottom is key to successful placement. Section 5.5
    has for more information.

    -   ***Mud Conditioning*** - Conditioning of the mud before
        cementing will improve hole conditions. Mud circulation will
        break gelled mud and place conditioned mud in the annulus. Care
        must be exercised to assure proper well control while
        conditioning the mud, and to assure that the well is stable (no
        mud losses or formation fluid influx or crossflows). If a well
        is flowing during cementing operations, there is a high risk of
        not getting a seal with the cement.

    -   ***Spacers*** - Spacers are used for separation of the mud and
        cement and are also responsible for the bulk removal of mud from
        the well. Spacers should be selected for compatibility with the
        mud and cement, and used in sufficient quantity to obtain the
        bulk removal of the mud. Spacer volume should be based on the
        actual hole volume in the same manner that cement volumes are
        determined. Well control calculations should include the
        hydrostatic pressure effect of the column of spacer in the
        annulus.

    -   ***Pump Rates*** - Pump rate control affects ECD, mud
        displacement efficiencies, job time, and ultimately cement
        slurry design. Consideration should be given not only to the
        displacement rate of the job, but to the mixing rate of the
        cement and its effect on the ECD and displacement efficiencies.
        Cement mixing rates should not be designed so high as to prevent
        good density control.

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-   ***Centralization*** -- In zones where an annular seal is critical,
    casing centralization can be a key to successful cementing. Cement
    can not be placed completely around casing in places where the
    casing is laying against a formation. Casing centralization will
    raise the casing off the formation and allow cement to completely
    surround the pipe. Centralizer selection will depend on hole
    size/shape and casing size, and the directional profile of the well.
    The use of a 3-D centralizer placement program that determines
    lateral loads on the centralizer, drag forces while running in the
    hole, and casing stand off is highly recommended.

-   ***Testing/Evaluation Plan*** - Determining successful placement of
    cement can take many forms, from running of complex cement
    evaluation logs, temperature logs or simple pressure testing. For
    most primary cementing operations, pressure testing is used to
    evaluate the effectiveness of the cement seal at the shoe of the
    casing. Well planning should take into account how this test will be
    performed, and what type of testing is necessary. The plan should
    state whether the casing shoe test will be taken to leak off, or if
    the test will be stopped at a predetermined pressure. Depending on
    drilling requirements, it may be appropriate to evaluate the need
    for open hole leak off or integrity tests. These tests can be run
    after reaching the planned hole section depth to confirm that the
    open hole's pressure containment integrity will hold the designed
    maximum cementing job ECD. If the test indicates a lack of adequate
    integrity, the cementing job design may be modified accordingly. For
    example in some cases, a lower cement slurry density may be designed
    to lower the cementing ECD. More information on testing and
    evaluation is in Sections 6 and 7.

***2.2.4** **Drilling Fluids Plan *** **-- missing most of this
section**

***2.2.4.1 Mud Weight vs. Pore Presure***

**Missing**

***2.2.4.2 Mud Stability***

**Missing Drilling Fluid Stability (settling, sag, etc.)**

***Hydrate Prevention*** - Gas hydrates are simple crystalline chemical
compounds composed of water molecules surrounding a single free-floating
natural gas (methane) molecule. The crystal is arranged in a compressed
latticework, appearing very similar to ice formed from water. Unlike
ice, however, hydrates can form at temperatures above the freezing point
when system pressures are elevated. Hydrate formation has led to
plugging of wellbores, flowlines, and wellhead and well control
equipment, and has jeopardized operators' abilities to maintain positive
control of pressures in the wellbore. The prevention of gas hydrates is
thus a critical concern in all deepwater wells.

Pre-emptive measures should be taken to insure that hydrates do not form
and do not become a safety/well control problem. The key to hydrate
prevention is to inhibit the formation of hydrates through the proper
selection and design of the drilling/completion fluid. Low dosage gas
hydrate inhibitors (anti-agglomerants) and a combination of
anti-agglomerants/kinetic polymeric inhibitors have been successfully
tested for the prevention of hydrate formation. Other methods including
the use of solvents such as methanol, maintaining the proper drilling
fluid salinity and the use of non-aqueous base fluids can also reduce
the likelihood of hydrate formation. Computer models that predict the
formation of hydrates under various conditions are available to the
operator from a variety of sources.

**Combine above with section below?**

### *Gas Hydrates*

*Gas hydrates can cause severe well control problems by forming a plug
in valves or chokes completely blocking flow. Upstream pressure then
increases which compounds the problem. For this reason, a frequent
practice is to suppress the formation of hydrates by injecting
inhibitors into the drilling fluid. On the other hand, in many
situations it might be desirable to avoid dissociating hydrates
occurring in-situ. Recent experiments have shown that these conflicting
requirements can be achieved by using a special mud additive known as
polyvinylcaprolactam (PVCap) which is capable of suppressing both
hydrate formation and dissociation.*

*Hydrates are easier to prevent than to remove once they have formed in
a flow system. Prevention measures include*

-   *good well control practices to minimize gas coming from the
    formation*

-   *reduce free water by using oil-based mud or maximizing the chloride
    content of a water-based mud.*

-   *maintaining the temperature as high as possible*

-   *injecting methanol or glycol at a rate of 0.5-1 gallon per minute
    on the upstream side of a choke or line*

*If hydrates do form and plug off a choke or line consider circulating
hot brine solution.*

***2.2.4.3 Mud Type***

**Missing section.**

Also see Section 5.3 for more information on drilling fluid type.

***2.2.4.4 Packer Fluid Stability* --** Packer fluids are fluids that
are left in the annulus of the wellbore when the well is completed and
put on production or temporarily abandoned. The purpose of a packer
fluid is to provide hydrostatic pressure control in the tubing/casing
annulus and provide for corrosion protection of the tubulars in the
well.

A properly designed and placed packer fluid should provide:

-   *Suspension* - Suspension of weighting material such as barite,
    hematite or illmenite to prevent solids settling around packers or
    downhole equipment. Settling of weight material can also lead to an
    unbalanced fluid column, which can lead to well control problems.

-   *Corrosion protection* - Protection of downhole tubulars from
    corrosion is essential. Pretreatment of the packer fluid with
    scavengers and film-forming compounds is essential for brines and
    water based fluids. Non-aqueous (NAF) packer fluids normally provide
    adequate corrosion protection if the fluid alkalinity is in the
    desired range when the fluid is placed.

-   *Pump-ability* - The fluid should be fluid enough to be pumped into
    place, yet viscous enough to provide the desired suspension of
    weighting agents. Properly conditioned packer fluids should be shear
    thinning so as to allow proper placement without exceeding the
    desire pumping/placement pressure.

***2.2.5 Hydraulics - ECD***

***2.2.5.1 Equivalent Circulating Density (ECD) Management***

A plan should be developed to monitor and control static and dynamic
fluid pressures of the mud column such that ECD is maintained within
appropriate limits. Static fluid pressure should be sufficient to
contain maximum openhole formation pressure and minimize wellbore
stability problems, while dynamic fluid pressure should be held below
the minimum breakdown (fracturing) pressure of any exposed formation.
Hole size, casing size, BHA and drill pipe size selection must be
balanced with the fluid properties and surface equipment ratings to
ensure ECD can be maintained within the desired range. Offset well files
should be reviewed for indications of lost circulation, stuck pipe,
significant borehole washout, etc., and the ECD management plan should
be modified to mitigate these problems. ECD increase in high-angle and
horizontal wellbore sections must be addressed in the plan, as the
formation fracture gradient will remain constant in the horizontal
section of the well.

Numerous well design parameters can impact ECD, including the use of
casing strings with increased annular clearances, use of liners rather
than full casing strings, selecting fluids that reduce frictional
losses, expandable tubulars to preserve hole size, and controlling ROP
to avoid overloading the annulus with cuttings. Critical circulating and
swab pressure should be documented in the plan. A wellbore hydraulics
simulator should be used on each well.

***2.2.5.2 Wellbore Cleaning***

Cuttings transport to the surface is primarily controlled by annular
velocity and fluid rheology, so care must be taken when selecting
components that impact these parameters. Surface drilling equipment (mud
pumps, flow lines, and shakers) must be sized to accommodate the maximum
rate of cuttings generated. Hole deviation must be considered when
designing higher annular velocities for proper hole cleaning. Ensure
chemical compatibility of the formation and the mud system to avoid
swelling problems. The bit nozzle selection should be based on
optimizing ROP, bit cleaning, and annular velocity for transport of
solids to the surface. It is recommended that a wellbore hydraulics/hole
cleaning simulation model be run on each well to determine minimum and
maximum flow rates. Maximum pipe-tripping speed should be controlled to
avoid creation of excess swab pressure. Wells drilled from floating
vessels should consider the use of a booster line when high solids
loading is expected in the riser.

Conventional hole cleaning tactics may have to be supplemented with hole
cleaning pills under certain conditions. Viscous pills and high weight
pills can be effective at removing cuttings. However, the use of pills
should be minimized where possible, as they can contaminate the mud
system.

***2.2.6 Well Center Planning***

The well center design (i.e. wellhead, BOPE, riser, etc.) should include
a minimum of two barriers, available during any wellbore operation, to
prevent uncontrolled flow from the well to the atmosphere. The barrier
design will incorporate the following elements:

-   Ability to withstand the maximum anticipated wellbore pressure

-   Ability to be tested (leak & functional)

-   Failure of a single barrier will not result in uncontrolled flow
    from the well

-   Field operating environment is within the design specifications of
    the barrier element

In addition, one of the barriers should have the capability to:

-   Shear any device that passes through the barrier and seal the
    wellbore after having sheared the tool. If this is not possible, an
    alternative pressure control plan shall be created.

-   Seal the wellbore with any size device that penetrates the well
    barrier. If this is not possible, an alternative pressure control
    plan shall be created.

***2.2.7 Barrier Plan***

The ultimate goal of any well is to provide sufficient barriers between
formations and between those formations and the surface. A barrier plan
includes maintaining well control with fluids that exceed pore pressure
in the well, selection and use of well control equipment, and ultimately
the placement of cement or other mechanical barriers in the well.
Evaluation of these barriers must be considered in the planning process.
Plans must address well control issues each time a barrier is removed or
replaced. Following a cement job, the BOP system is typically removed to
install wellhead components. At these times, the barriers in the well
have changed from fluids and the BOP stack to fluids and cement. The
plan should address when it is safe to make that change.

Plans for testing of well barriers should be part of each well design.
Barrier plans should address pressure integrity through pressure
testing, but may also require negative testing of a liner top prior to
changing out the wellbore fluid.

See relevant Sections below for more information on designing the
different types of barriers.

***2.2.8 Contingency Planning*** - **\[Section "h" still being
edited**\]

Unintended transfers of fluids or solids between the wellbore and the
formation can occur with minimal warning and can have devastating
effects. The potential for such problems should be identified in
pre-drill analyses. Contingency plans should be developed specifying the
procedures, equipment, and personnel needed to avoid adverse situations
or to suppress incipient dangers before they become unmanageable.
Planning should consider events that fall into three categories: fluid
influxes, lost circulation, and formation failure.

## *[2.2.8.1 Well Control Planning for Fluid Influxes]{.smallcaps}* 

## 

## *Kicks* - The following equipment and materials should be available to handle a kick:

-   A minimum of 300 barrels of heavy mud must be ready in the reserve
    pit (mud weighting 2 ppg more than the active mud is normally
    recommended). However caution must be exercised to ensure that this
    mudweight will not lead to rupturing of the formation

-   A diverter where shallow gas hazards exist

-   Properly selected and well maintained blowout preventers, chokes,
    choke manifolds, mud-gas separators, degassers, mud monitoring
    equipment and other well control related equipment

Safety and well control procedures must be implemented if a kick occurs.

Well control procedures vary depending upon whether the kick occurs
while tripping, drilling, or the bit is out of the hole, and whether
surface or subsea BOP\'s are employed. However in general they include:

-   The use of kill mud

-   Diverting shallow gas

-   Temporarily shutting in the well

-   Plugging the borehole with barite or cement plugs leading to partial
    or complete abandonment of the well

If the well is shut in, use a well control method that keeps the bottom
hole pressure constant while allowing the kick to migrate through the
flow system.

## *Shallow Water Flows* - Shallow water flows are best managed by drilling the interval with weighted fluid. For cementing, foamed cement is recommended since unlike conventional cement, it continues to transmit the mud pressure throughout the thickening process. More information on controlling shallow water flows can be found in API RP-65 Part 1 titled "Cementing Shallow Water Flow Zones in Deep Water Wells" published in September 2002.

## 

## *2.2.8.2 Planning for Lost Circulation Control*

## 

## There are generally three categories of losses: seepage losses, partial losses, and complete losses. The two most common (and most avoidable) causes of lost circulation are excessive downhole pressures and improper selection of intermediate (protection) casing seats. Rigsite operations should be directed toward avoiding wellbore pressures that can break down the hole. Downhole pressure can be divided into three types: hydrostatic, frictional (circulating), and inertial (surge/swab).

Hydrostatic pressure is controlled by using the minimum reasonable mud
density, by maintaining adequate hole cleaning, and by controlling ROP
as required. Drilling with the minimum reasonable mud density is
obviously the first consideration. Reducing the mud density not only
lowers the hydrostatic pressure, it also lowers the surge/swab pressures
and usually the rheological properties that affect circulating
pressures. Other recommendations include the following:

-   Avoid surging the pumps, avoid sudden starts, and break circulation
    cautiously after engaging the rotary while slowly pulling up on the
    drillstring. Engaging the rotary before breaking circulation
    eliminates the effects of downhole gelation. Slowly pulling up on
    the drillstring while breaking circulation offsets the inertial
    surge pressure.

-   Avoid sudden starts and stops of the drillstring and control maximum
    pipe running speeds, especially in deep and small-diameter holes.

-   Try drilling, not spudding, all bridges.

-   During casing and cementing operations, care should be exercised to
    ensure that surge effects do not cause mud losses.

If losses occur, use the correct blend of loss control materials (LCM)
depending upon mud type and the severity of the problem. It is important
to understand the relationship of particle sizes required to plug
various fracture widths and to ascertain whether the loss is into
formation matrix or a fracture. In most cases, continuing
lost-circulation problems exist as a result of fractures.

In cases of losses to large vugs or caverns, about all that can be done
is to continue drilling ahead without returns to surface (drilling
blind). In some cases it may be desirable to pump large volumes of water
down the annulus while drilling ahead blind. Sometimes it is possible to
fill the voids with drilled cuttings to regain circulation if the void
is small enough, but this is usually not the case. In most cases, the
recommended practice is to drill blind to some point below the loss zone
where a satisfactory casing seat can be attained. At that point, run
casing and cement to the loss zone to seal it off.

Wellbore breathing or ballooning is often an indication of imminent lost
circulation. The following responses should be adopted:

-   Review system hydraulics in an effort to reduce ECD. Consider
    reducing the mudweight if possible

-   Monitor flowback while making connections. Record the volume and
    duration of flow.

-   Do not weight up and risk loss of returns

-   Apply an LCM pill

-   When a kick and breathing both occur it is time to set casing

## *2.2.8.3 Formation Failure* 

## 

## Formation failure caused by mechanical or chemical instability results in hole enlargement, an influx of cavings into the wellbore, and potentially severe consequences for drilling, logging, and cementing operations. Procedures for avoiding or managing formation failure vary depending upon the type of formation, the nature of the instability, and the availability of time and resources. However in general the following practices should be observed:

-   Maintain the ECD within planned boundaries

-   Use an appropriate mud type that promotes the formation of
    filtercake, cuttings transport, and inhibits chemical reactions with
    the formation

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-   Avoid surging or swabbing the formation and reduce tripping speeds
    when the BHA is opposite problem formations

-   Plan frequent reaming or wiper trips in mobile formations

-   Minimize the exposure time in areas where rock deformation or
    failure is time dependent (e.g. in salt)

-   Perform adequate circulation to clean the hole before drilling ahead

-   Drill problem formations with smaller hole sizes as this reduces
    hole cleaning problems and increases the mechanical stability of
    hole. Alternatively use a larger drillpipe to improve cuttings
    transport

-   Use reciprocation and rotation of the drillstring to assist hole
    cleaning particularly when mud flow alone is unable to clean the
    wellbore

-   ROP should be controlled in upper section to avoid overloading the
    annulus

Good hole cleaning is especially important in deviated wells where
cuttings beds can accumulate and avalanche down the low side of the
wellbore packing off the drillstring. In the event of a packoff, the
following measures should be applied in order of appearance until the
drillstring is freed:

-   Turn off the pumps and bleed down the standpipe pressure

-   Apply maximum make-up torque

-   Working the pipe up and down

-   Increase the standpipe pressure and continue to apply torque and
    work the pipe

-   As a last resort, commence jarring in the direction opposite to the
    last pipe movement

***2.2.9 Regulatory Issues***

One component of proper well planning includes appropriate regulatory
review. Typically, the regulatory agency with jurisdiction for the well
will need to review the well plan before operations begin. Well plan
submittal documents tend to have the following features in common: a
description of drilling objectives, planned casing and cementing
program, drilling fluid program, equipment testing policies and
procedures, borehole evaluation and directional survey programs, and
estimates of pore pressures and fracture gradient. Depending on the type
of regulatory system in effect, the agency may or may not approve the
well plan in its entirety, or it may require certain changes to the plan
to meet regulatory requirements.

***2.2.10 Communications Plan***

A key feature of good well design is effective communication of the plan
to the personnel that will execute that plan. The well design should be
communicated through a written plan and through personnel meetings. For
complicated wells, holding a meeting to \"drill the well on paper\" can
often highlight areas of risk and concern, and gives an opportunity for
all parties to understand their role in executing the well program. A
discussion of human factors, required training and experience of
personnel should be highlighted.

Pre-spud meetings should take the final well plan and highlight any
areas of concern. The meeting should review the full well plan in
detail, highlight and review with the personnel the need for safety, and
address topics related to annular flow prevention. The prevention of
annular flow does not rest solely with the cementing operation and well
control equipment. It is a process that involves wellhead equipment,
directional control, wellbore quality, drilling fluid management and
cementing operations.

***3.0 Drilling the Well***

***3.1 General Practices While Drilling***

The following practices should help maintain efficient drilling results
and provide hole quality conditions suitable for primary cementing:

-   Using a drilling fluid of sufficient density to contain formation
    fluids

-   Use of high viscosity sweeps to reduce potential for annular pack
    off or excessive gumbo deposition

-   Control mud losses using LCM as needed

-   Minimize static gelled mud with flat gel strength mud rheology

-   Prevent excessive mud cake buildup with low fluid loss muds

-   Prevent balling on the BHA due to gumbo

-   Rotate pipe while breaking circulation to reduce lost circulation
    potential on connections

-   While on diverter, the rig should pump out of the open hole and
    assess trip fill by monitoring each stand while circulating through
    the trip tank

-   Control ROP to prevent overloading the wellbore with cuttings and
    minimizing the opportunity for gumbo accumulation

-   Monitor mud gas content and volume to verify flow potential.

***3.2 Monitoring and Maintaining Wellbore Stability***

Having a stable wellbore prior to, during, and after the cement job
execution is crucial to cement job success. If losses or gains occur
during a cementing operation the possibility of obtaining a successful
cement job is greatly diminished. Corrective action should be taken to
stabilize wellbores prior to the cementing operation. Certain corrective
measures are best applied prior to running the casing or liner string
into the well. The following indicators are used to identify potential
flows and losses, contributing to wellbore instability:

-   Changes in pit volume -- monitor trend

-   Changes in flow rate -- monitor trend

-   Changes in Pump Pressure

-   ROP -- monitor trend

-   Torque and Drag

-   Changes in WOB (weight on bit) -- monitor trend

-   PWD (pressure while drilling) data

-   ECD

-   Fracture Gradient via shoe and open hole LOT data

-   Cuttings size and shape

-   Variation in "d" and "dxc" exponent

-   Monitor Gas -- background, connection, and trip

-   Flow-line temperature

-   Mud properties; look for mud cut density, change in salinity, oil in
    retort, etc.

-   Shale density

-   Formation changes from LWD/MWD data

-   Presence of geologic anomalies

    -   Fractures

    -   Faults

    -   Non-conformities

Many of these indicators are precursors to wellbore losses or kicks
which can result in an unstable wellbore.

***3.3 Curing and Preventing Lost Circulation***

Detailed well planning and accurate hydraulic modelling is extremely
important in minimizing lost circulation. Lost circulation is one of the
most common and expensive problems that are encountered while drilling
or while running casing. Loss of circulation can lead to loss of well
control and a multitude of associated problems. The financial
consideration is of concern with any type of drilling fluid but the
importance is the greatest when using non-aqueous fluids (NAF). Loss of
circulation can lead to well bore instability and well control problems
that can drastically affect the outcome of drilling and cementing of the
well. Loss of circulation occurs when either of the following conditions
are met:

-   The pressure exerted by the mud column either while static or during
    circulation (surge is considered as circulating) must exceed the
    formation fracture or pore pressure.

-   The porosity and permeability of the formation or the fissure or
    fracture is large enough to permit the passage of whole mud thus
    preventing the sealing effect of the filter cake.

Loss zones can be categorized into two types: natural and induced
losses.

***3.2.1 Natural Losses***

-   Loss through rock permeability -- for whole mud to be lost, the
    formation openings are larger than the largest particles contained
    in the drilling fluid. These types of formations are usually
    characterized by seepage losses occurring in highly porous
    formations which are usually encountered at shallow depths.
    Typically these formations are sands and gravel.

-   Formations containing natural fractures.

-   Cavernous and vugular formations -- formations such as limestone or
    dolomites that have been dissolved by ground water that can lead to
    vugs or caverns.

***3.2.2 Induced Losses***

Losses due to a mechanical disturbance of the well bore can create
fractures not normally present in the formation. The hydrostatic
pressure thus created in the well bore exceeds the formation break down
pressure and mechanically fractures the rock. These types of losses are
different than what is seen in natural fractures since the fracture
network is not interconnected. Some of the causes of induced fractures
are affected by the following:

-   Fluid density and/or equivalent circulating density (ECD).

-   Additional hydrostatic due to length of riser.

-   Insufficient hole cleaning.

-   Rate of penetration (ROP)

-   Pump rates

-   Drilling fluid rheological properties

-   Movement speed of the drill string or casing.

-   Wellbore geometry

-   Restricted annulus from pack offs or bottom hole assembly (BHA)
    balling.

***3.2.3 Loss Rate Categories:***

Losses of mud to the formation have been arbitrarily defined in the
following categories:

1.  Seepage losses = 1 - 20 bbl/hr.

2.  Partial Losses = 20 - 50 bbl/hr.

3.  Severe Losses = \>50 bbl/hr but the hole will remain full with the
    pumps off.

4.  Complete losses = No returns while pumping or the hole will not
    remain full

with the pumps off.

#### *3.2.4 Preventing Losses*

# *Drilling Fluid Properties*

The following should be done to optimize the drilling fluid for
preventing losses:

-   Proper solids control management.

-   Keep the fluid density as low as possible.

-   ­Maintain gel strengths and yield point at the lowest levels that
    will effectively clean the hole and effectively suspend barite and
    cuttings.

-   Prevent excessive filter cake build‑up by controlling fluid loss.

-   Utilize hydraulic prediction software to predict ECD and determine
    optimum fluid properties.

***Minimizing Surge Pressures***

Surge pressures can be minimized by:

-   Staging in the hole to prevent excessive circulating pressures.

-   Rotating the pipe before turning on the pumps and bringing the pumps
    up slowly.

-   Monitor and control pipe running speeds.

-   Utilize available hydraulics modeling software for predicting surge
    pressure.

## *Downhole Equipment*

The following downhole equipment practices will help reduce ECD to limit
losses:

-   Utilize down hole pressure measurements to monitor and manage ECD's
    in real time

-   Utilize tools with maximum annular flow paths across the tools.

-   Auto fill and various enhanced flow by-pass equipment could be used
    to minimize surges while running casing.

-   Use down hole tools that allow for high concentrations of loss
    circulation material (LCM).

> ***3.2.5 Identifying the Loss Zone***

Quickly identifying where the loss zone is located will greatly enhance
the performance of the treatment used to counter the lost circulation.
Temperature logs, spinner surveys, noise logs, logging while drilling
(LWD) data analysis and stress modeling, connection flow monitoring
analysis, lost circulation computer model simulations, and offset well
mud loss data are a few of the techniques used to identify where the
suspected loss zone may be located. If a NAF is used, the suspected loss
zone could be identified during a short trip by very high resistivity
readings in an otherwise non-productive zone.

***3.2.6 Lost Circulation Materials and Systems***

There are a wide variety of lost circulation materials available to deal
with the most severe types of lost circulation. There is no generic
treatment available that is universal to all types of lost circulation
encountered. These can range from fine to coarse particulate materials,
fibers, cements, reactant pills and acid soluble particulates. The type
of material to use should be matched with the severity of the lost
circulation encountered.

***Seepage Losses***

The most common type of lost circulation materials for this type of
losses are the fine cellulosic fibers and fine granular types of
additives. The most commonly used granular material is calcium
carbonate. Another widely used technique is to pump the fine seepage
loss additives as a sweep while drilling the seepage loss zone.

***Partial Losses***

The most commonly used materials for this type of loss circulation are
granular and flake types of products that have particles sizes larger
than those used to deal with seepage losses. These can include mica, nut
shells, and medium to coarse calcium carbonates, graphitic materials and
coarse cellulosic fibers. Special graphitic products are also effective
in dealing with these types of losses. Generally, the graphitic type of
additives has a particle size larger than the cellulosic fibers and fine
granular type (calcium carbonate). These additives can be added to the
mud system as a continuous treatment or can be spotted as a sweep across
the suspected loss zone.

***Severe Losses***

The most commonly used materials for severe losses are the granular and
flake type products that have larger particle sizes than those used to
deal with partial losses. As the severity of the loss is greater than
the preceding two types of losses, coarser types of the same additives
should be used as well as including some of the fine sized materials.
Special graphitic products are also effective in dealing with these
types of losses. Generally, the graphitic type of additives has a
particle size larger than the cellulosic fibers and fine granular type
(calcium carbonate). These additives can be added to the mud system as a
continuous treatment or can be spotted as a sweep across the suspected
loss zone.

***Complete or Total Losses***

The types of additives used to deal with total losses are generally a
different class than is required for the preceding types of lost
circulation. These types of losses generally occur in formations with
leak off flow paths larger than the diameter of some types of bridging
particles. Large fracture openings and vugs usually account for these
massive losses of drilling fluid. These openings are not effectively
sealed with the cellulosic and granular type of products described
above. Reactive pills and agglomerating type LCM materials are used
under these circumstances. Some of these are as follows:

-   High filtration squeezes allowing for rapid loss of the carrier
    fluid resulting in a solid plug forming in the formation opening.

-   Hydration type systems where a very active material such as powdered
    clay or mixtures of clays and polymers in an inert carrier reacts
    with the drilling fluid to form a rubbery type of plug.

-   Chemical type systems where special resins or polymers and catalysts
    react to form a semi-solid type of plug can be used.

-   Mixtures of the above systems with cement to create highly viscous
    and hard setting plugs may also work.

-   These types of losses also respond well to cement plugs to cure the
    lost circulation.

-   Large cavern loss zones may need large volumes of the above systems
    or special squeeze cements such as foam cement.

***3.2.7 Planning and Operations Considerations***

1.  Pre-well planning for all phases (drilling, running casing/liners, &
    cementing)

    a.  Drilling

        i.  Pore pressures and fracture gradients

        ii. Fluid selection -- NAF vs water based mud (WBM)

        iii. Minimizing flow properties

        iv. ECD control, annular pressure measurements

        v.  Controlled ROP and hole cleaning

        vi. Caliper logs

        vii. Lost circulation, stress cage, and ECD computer modeling

    b.  Running casing and liners

        i.  Swab and surge pressure modeling

        ii. Insure the hole is clean and free of cuttings

        iii. Casing hardware selection

        iv. Pre-treat the drilling fluids to reduce pressures

        v.  Breaking circulation

    c.  Cementing

        i.  ECD modeling

        ii. Utilize good cementing practices

        iii. LCM in the cement slurries

        iv. Spacer considerations -- flushes, Spacer design (hydraulics)

        v.  Use proper cement densities and cement volumes.

2.  Pre-treating the mud

    a.  Drilling

        i.  Pre-treat with various particle size distribution (PSD)
            materials

    b.  Running casing

        i.  If possible cure the lost circulation prior to running
            casing.

        ii. Spot LCM in the open hole prior to running casing

    c.  Lost circulation and stress cage computer modeling

***4.0 Mechanical Barriers and Operational Considerations***

***4.1 Introduction and Flow Incident Cases***

***Objective***

The objective of this guideline is two fold. The first is to prevent and
/ or control flow after cementing on casing strings through surface
pipe. These incidents of loss of well control are a very serious problem
threatens the safety of offshore personnel, the rigs themselves, and
pollution of the environment. The second objective is the elimination of
sustained casing pressure (SCP) which is also a serious industry
problem.

***Background***

The data presented primarily by the MMS obtained from industry, strongly
suggest that the "Incidents of loss of well control", particularly when
cementing or after cementing shallow strings, is a serious problem and
blemish to the drilling industry. Events like this are a threat to human
life, a source of pollution, expensive, and affect the industries
ability to obtain leases in some areas because we are considered unsafe,
and the potential for a pollution event like those presented is a real
concern. Since anything and everything can happen on a cement job, even
when it has been properly designed, other means of preventing these
"incidents of loss of well control" need to be employed when there is a
risk of hydrocarbon flow involved.

MMS regulation 30 CFR 250.422 (b) requires that if you plan to nipple
down the diverter or BOP stack during the 8 hour or 12 hour WOC time you
must determine before nippling down when it will be safe to do so. Your
decision must be based on your knowledge of the formation, cement
composition, effects of nippling down, potential drilling hazards, well
conditions, and past experience. Even though we have this regulation,
more specific guidance is needed since we are still having well control
incidents. This is unacceptable and it effects out entire industry.

***Flow Incident Examples from MMS Records.***

The following are examples taken from actual situations to emphasize the
potential consequences of annular flow events that took place during or
after cementing operations on OCS (outer continental shelf). Some of the
similarities that reoccur most often are:

1.  Most events took place during or after cementing of surface casing.

2.  Most wells used a mudline hanger / suspension system.

3.  Frequently the surface x conductor annulus was washed out after
    cementing.

4.  Washing out of the annulus resulted in a small but possibly very
    significant changes in hydrostatic pressure.

***Flow Incident Example 1.***

  ----------------------------------- -----------------------------------
  Safety Alert No. 199\               Contact: Buddy Stewart\
  November 15, 2001                   337-289-5108

  ----------------------------------- -----------------------------------

**Blowout and Fire**

After a slip-on wellhead (SOW) had been set on a 10¾-inch surface
casing, and during the welding of the inside of the SOW, gas and liquid
were observed escaping from the +10 valve. The +10 valve was closed and
8.6-ppg seawater was added to the annulus through a ½-inch gap between
the wellhead's 24-inch base plate and the 10¾-inch casing, in an attempt
to kill the well. It should be noted that a 16-inch scab liner was hung
from the drive pipe. The well continued to flow, so the fluid was
weighted up to 9.2-ppg mud, and then later increased to 16-ppg mud. It
became more difficult to maintain a steady rate and quantity of mud flow
because of the mud's density and the size of the opening between the
base plate and the surface casing. As the gas flow increased, the +10
valve was opened in order to allow the 16-ppg mud to displace the
lighter fluid in the 24-inch x 10¾-inch annulus. With gas flow still
increasing, the decision was made to evacuate the rig. The +10 valve was
left opened in an effort to divert the flow of gas away from the
platform and rig. Approximately a day later, fire erupted on the
platform from an unknown source and caused extensive damage to the
platform and drilling rig.

The MMS investigation of the accident revealed in part that, while the
source of the blowout, namely shallow gas, was identified through well
log data, the cement program was not properly designed for the presence
of shallow gas. The failure of the operator to communicate the presence
of shallow gas to the contract cement service company resulted in the
improper design of the cement. It was further revealed that a pre-spud
meeting, in which the presence of known shallow gas could have been
communicated to all parties involved in the drilling operation, was not
conducted.

It is therefore recommended that operators:

1.  Review their current specific strategies regarding the prevention of
    gas migration into the cement column.

2.  Review their method of communication with contract cement companies
    regarding shallow-gas hazards.

3.  Review their procedures by which well log information indicating
    shallow gas is used in the proper design of their cement program.

***Flow Incident Example 2***

Notice No. 165

April 3, 1995

**Shallow Gas Flows While Cementing Surface Casing**

A well recently blew out while waiting on cement after surface casing
was set. After the wiper plug was bumped, the casing was pressure-tested
and sugar water was spotted on top of the mud line hanger. The well was
static for four hours, and the operator commenced to nipple down the
diverter system. Two hours later, the well started flowing gas and
cement out the open diverter. The diverter was closed, and the loosened
bolts that attach the diverter to the conductor casinghead were
reinstalled. Efforts were unsuccessful to stem the flow by pumping
saltwater through the conductor casing valve while allowing the well to
unload out both 10-inch diverter lines. Approximately one-half hour
after the well started unloading, flow began coming from the annulus
between the drive pipe and the conductor, and the rig was evacuated.

Several unsuccessful attempts were made to control the flow. Six days
after the flow began, the flow rate decreased and the rig was able to
move off location. Four days later, the drive pipe, conductor, and
surface casings fell to the seafloor and the flow ceased. The next day,
a subsea inspection by a remote operated vehicle (ROV) revealed a
25-foot crater at the base of the drive pipe with no bubbles or flow
observed. Five months later, another rig moved on location and
successfully completed abandonment of the well. There were no injuries
or fatalities as a result of this blowout.

A similar incident occurred in July 1994 while spotting water mixed with
lignosulfonate (ligno water) after washing the annulus through wash
ports on the mud line hanger. After the 20-inch surface casing was
cemented, the annulus was washed by circulating through ports on the mud
line hanger, and ligno water was spotted. After a gyro survey was run, a
diverter line was opened to check for flow. Flow was noticed on the
annulus and the diverter line was closed. The annulus pressure was
alternately bled off and allowed to build up during the next day. During
the next two days, unsuccessful attempts were made to place heavy mud
into the annulus by injection and by circulating through the mud line
hanger. The well was finally killed by placing 3/4-inch tubing into the
annulus and circulating heavy mud. Operations were resumed some three
days after the flow began. There were no injuries or fatalities
associated with this incident.

In another, less serious incident, a shallow gas flow also occurred
after the surface casing was cemented. Nippling down of the diverter was
begun seven hours after the plug was bumped and the float valves were
checked. The diverter and diverter lines were rapidly reinstalled when
flow first began. The well was shut in with a surface pressure of 50
psi, and was killed by lubricating mud into the annulus between the
conductor and the surface casings. The annulus was then successfully
grouted, and normal drilling operations were resumed 5 3/4 days after
the flow first began. There were no injuries or fatalities as a result
of this incident.

In still another incident, nipple down of the diverter system and
installation of the casing slips were completed two hours after the plug
on the surface casing was bumped. A slight gas flow was ignited by a
welder making a rough cut on the surface casing one-half hour later. The
gas was flowing from a casing valve that was open so that the annulus
could be monitored. The flame was extinguished with no damage or
injuries when the casing valve was closed. However, when the valve was
later reopened, mud and gas flowed from the well. The valve was closed
and the diverter was reinstalled on the wellhead. At this point, the
seal on the casing slips failed, and 15-20 bbls of mud and gas were
discharged through the diverter line. When fluid slowed to a very small
stream, a line was connected to the casing valve, and 3 3/4 bbls of mud
was pumped between the 13 3/8-inch and 20-inch casings. The well was
monitored for 16 hours and 6.9 bbls of mud were recovered. Final flow
rate was 2 1/2 gallons per hour, and at this point, the crew prepared to
resume normal operations. The lead cement had thixotropic properties
typical of slurries used for this application.

All four cases were caused by formation fluids migrating into the
annulus as the cement went through a transition before compressive
strength was developed. Sixteen similar well-control incidents have been
reported since 1973.

The best way to avoid these problems is to select, on the basis of the
shallow hazards survey, a surface location that is not directly above a
seismically visible shallow gas accumulation. However, if well
objectives require drilling from a location in a shallow gas area, or if
it is likely that gas sands will be penetrated in the surface hole,
appropriate consideration as to how to handle any shallow gas related
problem that might arise should be developed when the well is planned.
This consideration is particularly important where the hydrostatic head
is to be reduced by activities such as washing mud or cement from the
upper annulus with water to facilitate future abandonment.

Items to be considered in shallow gas areas may include the following:

1\. Improving cement properties to minimize chances of shallow gas flow,
including density, fluid loss, transition time, compressibility, etc.

2\. Planning for optimum cement column length (within guidelines
established in [30 CFR
250.54](../../../../../../../../i:%5Cfopolicy%5Cmacroreg%5C54.wcm)).

3\. It may be desirable to hold slight back pressure on the annulus
after cement is in place, and to consider shut-in of the well rather
than diverting the well. In these cases, leakoff testing of the
conductor casing shoe is recommended to better predict the surface
pressures that could later be withstood without fracturing. Based on
results of the leakoff test, the amount of back pressure that could
safely be applied until cement has achieved compressive strength should
be calculated. Any applied back pressure should not be enough to cause
the formation at the conductor shoe to break down, and the annulus
should be bled as required to avoid breakdown.

The considerations made regarding shallow gas should also seriously
address whether or not the parameters associated with a particular well
suggest diversion after cement is in place as a viable option. These
parameters include leakoff test data and various depths at which gas
sands may be drilled in the surface hole. The mindset that \"diversion
is the best option because a diverter system is in place\" may need to
be reexamined. In many cases, the planned shut in of a well may provide
for a safer means of well control than diverting the well, especially
after cement is in place.

Current regulations require waiting on cement for 12 hours before
drilling out all casing strings other than the conductor casing, and
that cement have a minimum of 500-psi compressive strength in the bottom
500 feet. This waiting time does not specifically apply to the nippling
down of the diverters. In 3 of the above 4 cases, diverters had been
partly nippled down in substantially less time than 12 hours after the
plug was bumped. It was fortunate for the rig crews that the diverters
were able to be reconnected before the flow became prohibitive. The
proper amount of time to leave the diverter system in place is dependent
upon the time required for the cement to develop adequate strength to
prevent gas flow. (Flows began in an average time of 4.5 hours and a
maximum time of 10.5 hours after the plug was bumped in 13 of the
incidents for which information was available.)

A better determination of the time required for waiting on cement would
be based on lab tests of the cement properties rather than time alone.
The Minerals Management Service plans to investigate the issue of
waiting on cement. The goal is to better understand well bore cement
properties, particularly compressive strength, and how they can be used
to establish an acceptable criterion for waiting on cement. This could
lead to a regulatory change that better recognizes cement performance
criteria and the importance of when well control equipment is nippled
down in lieu of the rigid waiting on cement time prior to drilling out
of casing in our current regulations.

***Flow Incident Example 3***

Safety Alert No. 210 Contact: Lee Fowler

January 8, 2003 979-266-1004

# 

# Blowout After Cementing Surface Casing

While drilling a well, an operator noted a slight gas flow coming from
the annulus between the surface and conductor casing shortly after
cementing the surface casing. The diverter was closed and pressure
started increasing on the annulus. Attempts to bleed off the pressure
were unsuccessful. Two days later, gas belched from the drive pipe of an
adjacent well. Soon thereafter, gas bubbles were noticed coming from
other wells at the water line. The platform was safely evacuated, and
the flow eventually ceased.

The subsequent MMS investigation of the incident noted the following
conditions encountered by the operator while performing the surface
casing cement procedure: a delay in initiating the cement job because of
a top drive electrical problem, a temporary loss of returns while
pumping cement, and premature cement returns while pumping the cement.

It has been concluded in part by the MMS investigation of this event
that the well control problem was probably caused by the \***regression
of the cement density to a seawater gradient\*** and/or the formation of
a channel because of the delay in pumping cement. MMS stresses the
importance of and recommends pumping cement as soon as possible after
landing casing and circulating at least one casing volume.

Other aspects of this incident are currently being studied by the MMS.

**\* Note:**

**Scientific evidence in the form of downhole annular pressure
measurements**

**inside the cement column shows that "cement density" or the
equivalent**

**hydrostatic pressure may decrease to values below the seawater
gradient.**

***4.2 Mechanical Barriers***

***4.2.1 Definition***

A mechanical barrier is defined here as "A verifiable seal between two
casing strings or a casing string and the annulus that isolates all
hydrocarbon-bearing zones below the BOP or diverter achieved by
mechanical means". This seal must be installed, energized, tested and/or
verified prior to nippling down (ND) the BOP or diverter. The term
verified or verifiable refers to those unique circumstances where the
seal can not be tested (such as an ECP packer in open hole). In this
case you would have to rely on surface and down hole indications that it
is set and in place.

***4.2.2 Characteristics and Capabilities***

Many annular flows occur while BOPs or diverters are nippled down just
after cementing shallow casing strings. This results from: 1) loss of
hydrostatic pressure as the cement column begins to develop gel strength
and support its own weight, 2) reduced fluid density in the annulus
during cement washout operations, 3) gas migration within the unset
cement column, and/or 4) a combination of these.

Mechanical barriers can significantly increase the odds of preventing
flow after cementing and can also save significant rig time by allowing
the operator to move straight into nippling down the BOPs without
waiting on cement (WOC). This may serve as an incentive for using a
mechanical barrier. Mechanical barriers are still not intended to
replace the primary control, a properly designed and well executed
cement job coupled with adequate time for the cement to cure. Rather,
they serve as a secondary barrier to keep the well from flowing after
the cement is in place. A properly designed cement job is extremely
important, but there are many factors that can prevent even a
well-designed cement job from being properly executed in the field.
Examples of these are lost returns, shut downs caused by equipment
malfunction during the cementing operations thus preventing uniform and
timely placement of cement, getting cement from the wrong tank, etc.
Even if there is a mechanical barrier in place, there is still no
guarantee that flow around the outside of the shallow set casing shoe to
the surface could not occur, but the odds of a flow shutoff between
strings are much better.

The industry has successfully used for many years liner top packer to
eliminate / reduce flow after cementing on deeper strings as well as
squeeze work on liner tops. The liner top packer is a proven product.
Devices similar to this or that functionally serve the same purpose
(mechanical barriers) can be used on shallower strings. Mechanical
barriers will keep the well from flowing, which will allow the cement
column to hydrate and cure in a static condition enhancing the
probability of zonal isolation. In addition, a mechanical barrier may
prevent flow up between the casing string and the BOPs making the job
safer.

If the well was static before the cement job, then holding the fluids in
place provides the best opportunity for preventing gas from migrating
up, and ultimately breaking down the shoe and broaching to the surface.
Experience has shown that not having a mechanical barrier in place can
result in flow after cementing.

If washing out between strings is required for a given well plan and the
probability that hydrocarbons will flow (i.e., the well contains
hydrocarbon bearing zones behind the pipe) then a mechanical barrier may
be recommended since the effectiveness of the BOPs is negated by the
tubulars run inside the BOP or diverter to wash the cement. If a
mechanical barrier cannot be used in this situation, then the operator
would not be able to wash out.

***4.2.3 Subsurface Mechanical Barriers***

Some mechanical barriers can be run downhole to isolate an annulus. The
positioning of these devices depends on both purpose and design. To
avoid exposing potential trapped pressure, the subsurface mechanical
barrier should be placed deep enough below the mudline so that it
remains in place when the well is plugged and abandoned. The following
are examples of items / tools that can be used as subsurface mechanical
barriers:

1.  Inflatable External Casing Packers (ECPs) are packers that have
    inflatable elements mounted on mandrels that are equivalent to the
    liner or casing string. The advantages of ECPs include the ability
    to run through reduced IDs and seal in larger ID sections of casing
    or irregular open hole. If the ECP is set directly above the problem
    zone in open hole then all casings above the zone are protected.
    Elements can be designed for specific applications but the minimum
    OD is generally 1" greater than casing OD. The wellhead and BOP
    stack must be selected with a minimum ID sufficient to accommodate
    the ECP. The differential pressure capability of a liquid filled ECP
    is a function of element design and the ID of the casing or open
    hole that it is set in. Inflation with fluid that is inside the
    casing at the time of the primary cement job is a simple operation
    that requires only that a differential pressure be applied to the
    ECP valve system. If the element is inflated with cement then the
    differential pressure capability is limited only by the casing or
    open-hole strength. Cement inflation is recommended for many
    applications. In conventional casing cementing operations spacer
    fluids are used to locate cement inside the ECP at the time of plug
    bump and pressure is applied to inflate the ECP with cement. In all
    applications planning is critical, and analysis of temperature and
    pressure changes during the life of the well must be included in the
    ECP design.

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2.  Another mechanical device is the external mechanical casing (EMC)
    packer and collar combination. Basically a sub is run in the
    previous casing string with a load shoulder built into it which is
    fluted for fluid by-pass. This load shoulder will reduce the ID of
    the casing string which will alter normal bit selection when
    drilling out of this outer casing string. The EMC packer is run
    externally on the inner casing string. The inner string must be
    planned to set off bottom (rat hole below the casing string).
    Mudline suspension cannot be used with this system because the pipe
    must be landed off bottom, as well. At the completion of the cement
    job, weight is slacked off energizing the EMC pack-off on the inner
    string and creating a seal between the strings. The pack-off should
    then be tested. This device is not applicable for all casing
    configurations. It should be sized for the diameters of the tubulars
    involved and the differential pressure across the annular area. Past
    performance shows that this tool is effective in preventing annular
    flow and Sustained Casing Pressure (SCP).

3.  Mudline Casing Suspension Systems (MCSS) can also be used if cement
    removal in the annulus to a point below the mudline is desired. This
    equipment allows for removal of cement without disabling the BOPs.
    Removal of the cement can be accomplished by opening the wash ports
    provided at the disconnect point and circulating the cement from the
    annulus. This is not a strictly mechanical barrier, however. MCSS
    provide for a means to support the casing string weight at or near
    the mudline and provide for a means to disconnect the casing strings
    above that point for the purpose of temporary abandonment. The
    suspension/disconnect point is often positioned sufficiently below
    the mudline to accommodate any requirement of the appropriate
    regulatory agency to remove the casing below the mudline for
    permanent abandonment. To ensure the ability to disconnect the
    casing for temporary abandonment, cement should be washed out of the
    casing annulus above the disconnect point. If water is used, the
    hydrostatic pressure above the MCSS could be reduced enough to
    permit the well to flow, and a shut-in would be required.
    Consideration should be given to the use of heavier fluids to wash
    out. Shut-in time would also be required prior to nippling down to
    prevent flow if there is no mechanical barrier used in conjunction
    with the MCSS.

***4.2.4 Surface Mechanical Barriers***

Other items can be installed at or near the surface that can serve as
mechanical barriers. These devices also seal the annulus, but in the
wellhead area rather than downhole. Examples of these are:

1.  A Multibowl wellhead system provides several casing suspension and
    sealing positions in a single wellhead housing. This allows the
    landing and sealing of more than one casing string without the need
    to remove the BOP after cementing to add an additional well head. A
    "Multibowl System" can also serve as a mechanical device to seal the
    annulus and allow the BOPs to be nippled down without waiting on
    cement for long time periods. The Multibowl head can be installed on
    top of the drive pipe and used to seal the annulus between the
    surface casing or conductor casing. Since the inner string is landed
    off bottom with only the drive pipe to support it the possibility
    exist for the entire assembly to fall due to the weight of the
    surface or conductor. In this case; drive pipe should be driven to
    refusal or into a competent formation. Alternatively, the Multibowl
    can also be installed on the conductor and rest on the drive pipe
    for additional support. The Multibowl system may have a retractable
    load shoulder to land the casing on via a fluted hanger, but there
    are other types that do not require retractable load shoulders. The
    pipe is cemented, and then the hanger and packoff are landed through
    the BOPs sealing the annulus. The BOPs could be safely nippled down
    after this seal is tested. All strings must be landed off bottom,
    which precludes the use of a MCSS.

2.  Conventional wellhead equipment requires that the BOPs must be
    disconnected and lifted to install the slip and seal assembly around
    the casing just cemented. Unfortunately, in most cases, this
    requires several hours during which the cement column begins to
    develop gel structure, reducing its ability to transmit hydrostatic
    pressure to the formation and allowing the possibility of an influx
    of fluid or gas from the formation. Review of past incidents of flow
    after cementing revealed that the earliest flow after cement was in
    place was 2 ½ hours. If the slip and seal installation along with
    the BOP nipple down could be performed during the time the cement
    column is still completely fluid, conventional wellhead equipment
    could be installed with reduced risk. . There is specialized
    equipment that can facilitate completing this operation in less than
    two hours. An example is a "Fastlock Connector". This device does
    not require studs and nuts (the removal and re-installation of which
    requires significant time). If the well begins to flow, the BOPs can
    be lowered and the connection to the wellhead restored quickly. A
    conventional studs and bolts nipple down would be difficult to
    execute in the time required. In the event the well began flowing
    prior to setting the slip and seal assembly, the stabbing and
    securing of studs would also be a high risk operation.

***4.2.5 Alternate Methods***

Several other mechanical methods and materials can be employed to reduce
WOC time by preventing annular flows. The following are examples of
these:

1.  Scab liners can be run and cemented inside previous casing (drive
    pipe or surface casing) to save the cost of a wellhead and to save
    nippling up / nippling down (NU / ND) time associated with the BOP
    and diverter. In many cases this liner is simply set on bottom
    inside the drive pipe after cementing in place to seal the annulus.
    To be effective, cement must come up between the liner and the host
    string of casing and should be verified with a test. If cement or a
    seal is not verified and a kick is taken on the following hole
    section, then the host shoe would see the pressure and could
    ultimately break down and flow to surface on the outside of the
    drive pipe ( host string). One scab liner system incorporates a
    shoulder and seal area welded into the drive pipe that accepts the
    seals and hanger for the scab liner. The scab liner would be set off
    bottom. This annulus must be tested 150 psi above the frac gradient
    at the drive pipe shoe to verify the seal is effective before
    drilling ahead. This could also be an application for an ECP run on
    the scab liner and set inside the drive pipe.

2.  Chemical sealants have been effective in stopping some minor annular
    flows. One example is a product that uses a pressure-activated
    polymer designed to seal leaks in wells and severe environment
    hydraulic systems. The polymer crosslinks only at the point of
    differential pressure at the leak site. Otherwise, it remains a
    pumpable liquid. Product like this have been successfully used to
    seal micro-annulus gas leaks in cement jobs between casing strings
    by injecting it from the surface.

***4.2.6 WOC Decision Tree for Surface Stacks***

***4.2.6.1 Waiting Time Guidelines Prior to Nippling Down***

This WOC Decision Tree and guidelines for surface stacks is an excellent
tool to use in making a decision on when and under what conditions it
would be safe to proceed ahead with ND the BOP or Diverter system. This
document is to be referenced whenever there are hydrocarbon bearing
zones or the possibility of hydrocarbon of hydrocarbon bearing zones in
the drilled section or if it is unknown. Deviations from this guideline
are permissible only with the approval of the proper regulatory body
such as the MMS.

There may be other downhole conditions that could modify the guideline.
It is extremely important that your plan be modified toward a
conservative approach to avoid loss of well control. Examples of this
are as follows:

1.  Complete loss of returns while pumping cement.

2.  Delays in getting cement in place, such as pump problems or getting
    cement out of tanks that could lead to channeling and poor cement
    jobs.

3.  Premature returns of cement to surface.

4.  High gas units in the drilling mud prior to cementing

In these cases confidence in the cement job would decrease and waiting
on cement for 10 hours before nippling down is deemed prudent.

This guideline is based on the best information and technology to date
and will be updated as new technology and information become available.
In can not be overemphasized the importance of planning for this
contingency well in advance of the drilling of these hole sections.
These discussions should include all parties involved in doing the work
and specifically should include the operator, drilling contractor,
cement contractor and the contractor providing the mechanical barrier if
applicable.

***4.2.6.2 Elaboration on Circumstances***

In instances where a hydrocarbon bearing sand is expected to exist in
the zones through surface pipe, the operator is required to submit a
plan for mitigating the possibility of the zone flowing before, during,
or after cementing. If the existence of, or potential for, hydrocarbon
zones is unknown or found unexpectedly, a plan on how it will be handled
is required and must be approved in progress. Plans can vary depending
on a given situation, but should cover the drilling, cementing, and
after cementing time frames.

The casing strings that are of primary concern are the drive pipe
(example 36" or 30") and conductor annulus (example 20", 16" or if
conductor has been eliminated it could be 13 3/8" or 10 ¾" for example).
The second annulus of primary concern is the conductor by surface pipe
annulus (20" x 13 3/8" or 16" x 10 ¾" are examples of common sizes used
in the GOM). Usually, you are going from a large annular / diverter
system to the 13 5/8" high pressure BOPs which requires the removal of
one to install the other BOP or to install a wellhead. The greatest
concern in both of these cases is the untimely removal or disabling of
the BOPs just after the cement job which is the most dangerous time due
to the potential loss of hydrostatic which results as part of the cement
curing process. Some people may consider this a safe time since a cement
heavier than the drill mud has been pumped into place, but this is just
untrue. During the curing process, the equivalent hydrostatic pressure
previously created by the cement weight can fall far enough to create an
under balance and allow hydrocarbons to enter the well bore which could
lead to a disaster if the BOPs are partially disabled by tubulars run
along side the casing or BOPs not in place at the right time to prevent
fluid movement.

There are other equipment issues. One is the use of mudline hanger
systems (MHS) which aid in the abandonment and or a future tieback when
the well is temporarily plugged and abandoned. Removing the cement can
be done by exposing ports on the inner string at the MHS hanger and
circulating out the cement above, spotting sugar water to inhibit the
cement from setting up, and then closing the ports and displacing
(bullheading) the sugar watered mud below the MHS a safe distance. If
you are not using a MHS, then to clear the desired annulus is
accomplished in many cases with tubing strings run in the hole just
after the cement job through the annular / diverter system to the
desired depth below the mudline and then displacing the annular fluid
and cement to the surface as soon as the cement is in place. The problem
here is that the BOPs are disabled in the event the well flows after
cementing and you have a potential disaster on your hands if you needed
to shut them in. If there is an exposed hydrocarbon bearing sand, then
this practice must be avoided unless there is a mechanical seal between
the strings (such as an external casing packer) that could prevent a
flow. In any case, when there is a hydrocarbon bearing sand, nippling
down without a mechanical seal between strings must be delayed until the
cement is past the critical phases in curing where the equivalent
hydrostatic could drop allowing the well to flow. Even when it is past
this stage, Nipple down through nipple up of the new well head and BOP
must proceed as efficiently as possible and with a plan to minimize the
exposure time and plan for the unexpected.

***4.2.6.3 WOC Decision Tree Procedures***

The WOC Decision Tree defines minimum waiting times prior to beginning
Nipple down operations of the BOP or Diverter system. In ALL cases, the
operator and contractor must have a plan to minimize the time from the
start of ND the BOP to securing the exposed annulus with slip and seals.
No other activities should take precedence over securing this annulus.
As previously stated Waiting time can be reduced or avoided if the
operator has a "mechanical barrier" in place and tested prior to ND the
BOP. A mechanical barrier is defined here as "A verifiable seal between
2 casing strings or a casing string and the annulus that isolates all
hydrocarbon bearing zones". This seal must be installed, energized,
tested and / or verified prior to BOP or diverter removal or BOP
impairment.

**Step 1:**

Determine whether hydrocarbon zones exist in the open hole section of
the wellbore.

If it is **KNOWN** by using MWD/LWD/wireline logging tools that no
hydrocarbon zones

exist in the open hole, or that the zones identified have low
permeability with little to no flow potential, it is not necessary to
wait-on-cement after bumping the plug. In this case, go to **Step 4.**

If the presence of hydrocarbon zones cannot be determined within the
open hole section of the wellbore, or have been found but with unknown
flow potential, go to **Step 2**.

**Step 2:**

Once cement pumping is complete and the plug has been bumped,
waiting-on-cement time required prior to nippling down BOPs is
determined as follows (See **Note 1**. If this is the case, go to **Step
4**):

**1st Level Decision :**

Is there a mechanical barrier in place to contain a potential flow
between the string or in the form of a special wellhead? If the answer
is yes and this seal has been verified or tested, go to **Step 4.**

**2nd Level or Primary Cementing Decision (Use if the 50-psi compressive
strength data is known):**

This method for determining waiting-on-cement time is when the in-place
cement reaches 50-psi compressive strength (See Notes 2 and 3). This WOC
time value exceeds the time for obtaining a 500-lb/100-ft2 gel strength,
therefore erring on the safe side. Go to **Step 3**.

**3rd Level or secondary Decision (Use if compressive strength data is
unknown):**

If unable to obtain compressive strength data for the proposed cement
slurry or if

unable to confirm **NO** hydrocarbon zones in the open hole section of
the wellbore, wait-on cement time is to be 10 hours plus 2 hours for
each 1000' below 5000'. (See **Note 4**). Go to **Step 3.**

**In all cases above the WOC time assumes that the cement job went as
planned. That is there was no lost circulation, the cement was mixed as
designed within a reasonable time, no pump failures causing delays in
placement, etc. If not, the operator will wait THE MAXIMUM time before
beginning ND operations.**

**C**

**Step 3:**

Once the wait-on-cement time in hours is obtained for the specific
cement slurry, you **MUST** wait-on-cement for that amount of time prior
to removing or disabling the BOP equipment, or have a mechanical barrier
seal in place and tested or verified on that annulus.

**Step 4:**

After making sure the annulus is full, proceed according to the planned
procedures of the

Operator (may include nippling down the stack).

**Notes:**

1\) Nippling down when waiting-on-cement becomes a non-issue when the
well head or casing annulus can be and has been sealed off and tested.
Obviously the rig time involved is expensive and sealing the annulus
after cementing would allow the operator to proceed immediately to
nippling down the BOPs. Examples of this are:

\- Running the string as a liner with a liner packer and setting it
after the cement job

\- External Casing Packer (ECP) run between pipe strings.

\- EMC packer collar with landing seat on previous casing string

\- Multi- bowl system NU on drive pipe or conductor allows casing to be
landed and

packed off without nippling down larger diverter / BOPs.

Since 3 of the above require the casing to be set off bottom, mudline
suspension systems (MLS), used to facilitate temporary P&A, needs to be
thought out carefully because it could preclude the use of any of the 3.
The only one that would work on bottom would be the ECP. The pack-off
that is run between strings, needs to be run deep enough that
abandonment does not remove it; otherwise we might suddenly be exposed
to a flow.

Advanced planning is a must between the operator, drilling contractor,
and cementing company, and mechanical barrier company if that route is
selected.

2\) The primary decision information should have been requested from the
cementing company long before the cement job commences, preferably at
the pre-spud meeting or before. It may be possible for the operator to
modify the slurry mixture and have it re-tested to minimize the WOC
time.

3\) The cement companies report that once the cement reaches 50-psi
compressive strength, gas generally can no longer migrate through the
cement slurry. This 50-psi compressive strength value is therefore
conservative and should take into account variables that can not be
reproduced in the laboratory. However, the reported compressive strength
times may be in significant error if the temperature used for testing
differs significantly from the zone of interest actual temperature.
Higher testing temperatures reduce the reported compressive strength set
times. This situation may lead to nippling down early and should be
questioned.

4\) This value was chosen based on thousands of cementing tests
conducted in the laboratory by one of the primary cement suppliers. Test
results indicate that the vast majority of cement slurries reach 50-psi
compressive strength well within the 10 hour time frame. As can be seen,
it is much better to obtain the proper cementing information and
**KNOW** when the cement slurry reaches the appropriate WOC value rather
than resorting to a rule of thumb measurement.

**C**

***4.2.6.4 Nitrogen Aerated Cement (Foam Cement)***

Special considerations will be taken when utilizing foam cement on
Jackups.

1\) Operators and contractors are required to do a complete risk
assessment prior to utilizing foam cement on jackups, and will make sure
that the results of this assessment are communicated in the cementing
plan.

2\) Operators and contractors are prohibited from the running of tubing
in the annulus between the casing and the diverter, or BOP, prior to
completion of cementing operations and determining that the well has no
potential for flow. Any deviation from this will be on a case by case
basis by MMS approval

3\) The operator will verify that hydrostatic pressure calculations are
performed to ensure

sufficient hydrostatic head throughout the well prior to washing out to
the mud line

suspension hanger (MLSH). As previously discussed, if there is potential
for flow, then washout can not be done without a mechanical seal in
place, or the proper time has elapsed to insure the cement has gained
sufficient strength to preclude flow after cementing.

***4.2.6.5 WOC Decision Tree***

***5.0 Cementing Practices and Factors Affecting Cementing Success***

***5.1 Introduction***

This section summarizes many of the key drilling issues that affect the
quality of a primary cementing operation. This section is not
exhaustive, nor does it provide the reader with a comprehensive set of
detailed recommendations for well construction. The intent is to
highlight the salient aspects that should be considered and summarize
the interrelationship between drilling operations and cementing success.
All topics discussed are covered in detail in various API, ISO, and
industry publications.

***5.2 Hole Geometry***

Hole geometry affects many aspects of the cementing operation. Among
these are centralizer/centralization requirements, casing running
conditions and ability to move pipe, mud removal, and equivalent
circulating density (ECD) while circulating and cementing.

The relationship between hole size and casing size should, from a
cementing perspective, always strive to achieve the best balance between
displacement efficiency and equivalent circulating density. Past studies
have indicated that 0.5 inches to 0.75 inches are generally recommended
***minimum*** clearances (hole size 1 to 1.5 inches \> than pipe size).
However, modern fluid systems and fluid mechanics modeling allow more
precise matching between hole geometry and fluid properties. Maximum
recommended clearances between casing and the wellbore should be
determined by desired minimum annular velocity and fluid friction
pressure profiles versus available hydraulic horsepower and/or maximum
pump rates as determined by surface equipment and open hole fracture
gradients. Minimum annular clearance is determined by drilling and
completion objectives, how much annular coverage is desired, formation
limitations (fracture versus pore pressure), and logging considerations.
Cement sheaths less than 0.5 inches thick are difficult to evaluate with
CBL.

Drilling and fluid management practices should strive to minimize hole
washout via proper bit hydraulics and shale inhibition. Weight on bit
and rate of penetration should be controlled to minimize unintentional
doglegs and/or trajectory changes. Under-reaming practices and
bi-centered bit use should concentrate on minimizing double-helix hole
geometries that interfere with mud removal and pipe movement during
cementing operations. The directional survey, complete with azimuth,
should be included in centralization, torque & drag, and displacement
modeling, especially when wellbore spiraling cannot be avoided.

***5.3 Drilling Fluid Type***

Drilling fluid (mud) selection and maintenance play a key role in
cementing success. Drilling fluid performance affects hole condition
(washouts), mud filter cake thickness and gel strength, mud mobility,
fluid and formation compatibility, and bonding of cement to formation.

Drilling fluid selection is generally dictated by anticipated formation
types and drilling conditions, penetration rate and differential
sticking and environmental, disposal and logistical considerations.
While drilling fluid selection does impacts subsequent cementing
operations, that impact is not often considered in the selection
process. Unfortunately, the ideal drilling fluid is not necessarily that
best suited for cementing operations.

Drilling fluid performance is controlled by many factors. Low-gravity or
active solids should be adequately controlled, and adequate shale
inhibition should be provided for aqueous mud systems. HTHP filter cakes
should exhibit thin, low permeability characteristics. Static gel
strength and low shear rheology at HTHP conditions should be low and
nonprogressive, but not at the sacrifice of drill cuttings or barite
support.

Achieving good cementing success through effective mud displacement
requires proper preplanning. Computer modeling of cement placement or
mud displacement requires careful evaluation of fluid properties and
placement processes.

Rheological properties of the drilling fluid should be obtained at
anticipated wellbore temperatures and pressures for proper displacement
modeling. The rheological properties of some drilling fluids, and
synthetic--based fluids in particular, can vary widely with changes in
pressure and/or rheology. Drilling fluid samples representative of the
drilling fluid at the time of cementing should be tested with cementing
fluids for rheological and chemical compatibility. Laboratory-prepared
samples of drilling fluids are generally not sufficiently representative
of actual well fluid for this evaluation. Samples collected at the rig
as near to casing set point as logistics permit should be used for these
evaluations. In the case of nonaqueous drilling fluids, the ability of
the cementing spacers and/or preflushes to fully water-wet pipe and
wellbore should be evaluated as detailed in API RP 10B and ISO 10426-2.

***5.4 Casing Hardware***

Casing hardware and auxiliary downhole equipment may be used to enhance
the cementing operation. This includes centralizers, float equipment,
stage collars, external casing packers, liner hangers and liner top
packers and expandable casing.

Centralization of the casing is of paramount importance to successful
zonal isolation. Computer simulators are highly recommended for
determining the best centralization design for a given application.
Caliper logs are highly recommended since they can be used to improve
the accuracy of centralizer and cementing simulations, and evaluate hole
condition and drilling performance. Two-arm calipers are acceptable, but
four-arm caliper logs are preferred.

Casing centralizers exist in many models and designs and are generally
categorized as either bow-spring or rigid models. Auxiliary
functionality such as flow diversion and mechanical friction-reducing
methods are also available on both types. Minimum performance
specifications for bow-spring centralizers are provided in API
Specification 10D and ISO 10427-1. However, it is recommended to use the
actual standoff performance specifications for each specific model as
provided by the manufacturer. Custom-built centralizers are available
for either slimhole or extremely large annular clearances.

Centralizers can be installed such that they are allowed to slide
between casing collars or clamped in place via either limit clamps or
set screws on the centralizer itself. Such holding devices must be of
adequate construction to withstand the forces of running casing and pipe
movement during cementing. Centralizers installed on flush joint casing
must be equipped with stationary holding devices.

Float equipment is used to prevent the cement from flowing back into the
casing when pumping is stopped and/or pressure released. Test procedures
for various classes of float equipment and associated mechanical
components are provided in API RP. Float equipment choice should always
be matched to anticipated bottom hole temperatures and the back-pressure
expected at the end of the cement job. Specialized float equipment
including auto-fill, side-ported, and custom-profiled is also available
to address the functionalities of surge-reduction and collapse
protection, improved hole cleaning, and ease of running casing,
respectively. Float collars are also available that lock and hold the
wiper plugs to prevent rotation during drillout. A float collar and a
float shoe can be used together to provide redundant back-pressure
control as well as a trap for contaminated cement slurry. Some
lost-circulation materials (LCM) in the drilling fluid and/or cementing
fluids may preclude or hamper the use of certain float equipment valves
designs.

Casing and liner wiper plugs, whether conventional surface release or
subsea release (SSR) provide the function of mechanically separating
cementing fluids from the drilling fluid, wiping the ID of the tubulars,
and providing a positive indication of the end of displacement. Wiper
plugs should be matched to the anticipated bottom hole temperatures,
pressures, depths and mud type (aqueous or nonaqueous). Not all wiper
plugs and associated operating systems (releasing darts) are compatible
with all types and manufactures of float equipment and/or stage tools,
liner hanger tools, and liner top packers. Tapered casing strings may
require customized wiper plug systems. Wiper plugs and associated
operating systems should be matched to the casing size and weight and
all other casing hardware components to ensure compatibility.

Cementing plug containers and head assemblies provide the means by which
conventional casing wiper plugs can be launched from the surface without
substantial interruption in pumping operations. All types and
manufactures of cementing heads have their own specific capabilities in
terms of pressure ratings, mechanical operation, load-carrying capacity,
and auxiliary capabilities such as allowing rotation or remote
operation. Not all casing wiper plugs are compatible with all models of
cementing heads and float equipment. Cementing heads and plug sets
should always be checked for compatibility. Plug containers equipped
with remotely-operated plug releasing mechanisms reduce risk to
personnel and may minimize shut-down time.

Cementing heads should always be in good working order and be
pressure-tested on a regular basis. Various components that should be
examined and tested on a regular basis are the cap, coupler, seals,
O-rings, extensions, threads, lift swivels, hoist rings, manifolds,
along with any associated swages. Magnetic particle inspection should be
performed on a periodic basis, or if a component is suspect.
Type-Certification is available from the service provider in many
instances. A Type-Certified Plug Container is one that has fully
traceable components with material mechanical properties verified by
laboratory tests. In addition, a Certification of Design Strength
Approval for the design is issued by Lloyd's Register.

***5.5 Close Tolerance Considerations***

Close tolerances are encountered in pipe-to-pipe annuli, liner tops,
expandable casings, and between the inner diameter of outer tubulars and
some tools such as liner top packers, stage tools, external casing
packers (ECP's), and expandable tubulars. Close mechanical tolerances
should be examined for mechanical (drift) compatibility with all
components involved in the cementing operations including wiper plugs
and associated operating components. Minimum and average cross-sectional
area and length of the restricted flow path should be examined for
compatibility with drilling and cementing fluid properties and/or
material components such as LCM. Circulating pressure calculations
should include any flow restrictions associated with close tolerances,
particularly those of significant length such as liner laps and tieback
sleeves.

***5.6 Engineering Design***

Cementing objectives determine the cement designs to be used, extent of
cement coverage with each, and performance requirements of each.
Performance requirements include gas control, fluid loss, free fluid,
thickening time, and compressive strength. Tensile strength and
elasticity may also be considerations.

*Zonal coverage determination*. It is important to evaluate which
zone(s) have potential for flow in order to plan the cement job to
achieve suitable zonal isolation. Ideally, such zones should be covered
with a cement slurry designed to prevent flow after cementing and the
cement placement mechanics should be designed to maximize mud removal.
Zones left uncemented may not flow in the short term if pore pressure is
balanced by mud hydrostatic head. However, phenomena such as barite sag
and mud dehydration may lead to longer-term sustained casing pressure.

Cement top selection is influenced by the location of the problem zones,
regulatory requirements and pore pressure/fracture gradient
considerations. Higher density tail slurries may be more easily designed
to be "gas tight" than lighter weight lead systems.

If the potential problem zone is to be covered by tail cement, the tail
slurry should have a shorter zero gel period than the lead slurry so gel
strength development in the lead slurry does not reduce the hydrostatic
head exerted on the zone before the tail slurry goes through transition.

*Pore pressure/frac gradient.* Accurate knowledge of pore pressure and
fracture gradient profiles is necessary for a successful cement job.
Pore pressure is one piece of information needed to assess flow
potential. The pore pressure and fracture gradient profiles are two of
many input values used in computer simulation programs used to evaluate
static and dynamic well security.

*Temperature (Thermal modeling and/or measurement or offset)*
Temperature is the single greatest influence on cement slurry
performance. Accurate estimates of cementing temperatures (both static
and circulating) are essential to the success of the cement job. For
many wells, API temperature schedules provide adequate estimates of
circulating temperatures. However, these schedules are based on data
collected in wells in shallow water with little deviation (*API Report
10TR3 - Technical Report on Temperatures for API Cement Operating
Thickening Time Tests -- 1993 Report from the API Task Group on
Cementing Temperature Schedules)*. The API schedules should not be used
for wells that vary greatly from these conditions (e.g. deepwater).

For such "non-standard" wells, circulating temperature information can
be obtained using temperature recording devices that are made up in the
drill string or dropped into the drill string and run on clean-up trips.
These devices measure the maximum temperature encountered as well as
changes in temperature as the well is circulated. The measurements are
taken with a geometry (drillpipe) different than what will be present in
the well during the actual cement job (casing) so the measured values
may deviate from values during cementing. Also, because the devices are
run after the hole section has been drilled, little time is available
for extensive slurry modifications. Finally, temperature measurements
are more commonly considered in production hole sections than in
shallower strings, although the affects of temperature on cement
performance are just as important in the shallower strings, especially
if there is potential for flow.

Computer-based thermal modeling programs may be used to develop
cementing temperatures. Such programs are not simple and require a
relatively large amount of input information including static
temperature, formation and well fluid thermal characteristics and
estimated job volumes and pump rates.

Temperature information may be obtained from measurement-while-drilling
(MWD) tools as the hole is drilled. Temperatures from MWD devices tend
to be higher than those derived from models or sensors used on cleanup
trips. Several things account for this including an elevated mud suction
temperature while drilling compared to initial slurry temperature while
cementing. Some bottomhole assemblies and formation types have been
demonstrated to give very elevated MWD readings.

In summary, there are many sources of temperature information. All
temperature information should be considered. Rather than a single,
"correct" answer, the engineer will likely be presented with a range of
likely temperature values. The slurry design must perform acceptably
over the anticipated range.

*Mud removal design.* Proper slurry design is only part of a successful
cement job. The other part involves efficiently removing the drilling
fluid from the well and replacing it with cement slurry. Computer based
placement simulators allow the engineer to tailor the cement job to a
particular well's conditions rather than relying on "rules of thumb".
Factors to include in planning for efficient mud removal include:

Pump rate. Higher pump rates introduce more energy into the system
allowing more efficient removal of gelled drilling fluid. However, tight
annular clearances in some wellbore configurations limit how fast the
job can be pumped without causing lost returns. Depending on fluid
rheology and degree of centralization, pumping too fast may actually
lead to uneven flow between the narrow and wide sides of the annulus.
Computer simulators allow us to consider many factors when determining
optimum pump rates.

Fluid types. The types of fluids used during drilling and cementing
operations affect the cement job. A drilling fluid conducive to wellbore
stability benefits the cement job by producing a uniform, near-gauge
hole with minimal hole washouts.

In addition, all fluids used in the cementing operation must be
compatible. Compatible fluids are fluids that are "capable of forming a
mixture that does not undergo undesirable chemical and/or physical
reactions". Mixtures which become viscous when mixed are difficult to
displace efficiently and may cause lost circulation due to excessive
friction pressure. If non-aqueous drilling fluids are used, a spacer
containing surfactants that water wet downhole surfaces will be
necessary (compatibility and wettability test procedures are found in
API RP10B)

Rheology and density. As a general statement, mud removal is more
efficient when the displacing fluid is "thicker" and heavier than the
fluid being displaced. Various guidelines have been used to decide how
much heavier and thicker each step should be in this density and
rheology hierarchy. Narrow pore pressure/fracture gradient windows in
some wells may limit application of density and rheology hierarchies.

Mud compressibility (affect on density and rheology). Unlike water-based
muds, nonaqueous drilling fluids are compressible. Depending on the
pressure, the fluid density may be increased by as much as 0.5 lbm/gal
due to compressibility. Compressibility may dramatically increase fluid
rheology as well. Commonly available viscometers used at the rig take
measurements at atmospheric pressure and thus will not show the effects
of compressibility. For more accurate cement computer displacement
simulations, mud samples should be sent to a laboratory for testing
under higher, more realistic confining pressure.

Spacer design. The purpose of a spacer is to aid in bulk mud removal by
avoiding incompatible mixtures of cement slurry and drilling fluid. When
non aqueous drilling fluids are used, the spacer also serves to strip
away the oily mud film and water-wetting the downhole surfaces.
Procedures for testing spacer compatibility are found in API RP10B. Some
computer simulators can help optimize the volume of spacers to be pumped
for mud removal.

Pipe movement. One of the best aids to achieving effective mud removal
is pipe movement; either rotation or reciprocation.

Centralization. If casing is not centralized, it will lay near or
against the borehole wall. Mud, washes, spacers and cement slurry flow
most easily on the wide, less restricted side of the annulus. It is
difficult, if not impossible to displace mud efficiently from the narrow
side of the annulus. This results in bypassed mud channels and loss of
zonal isolation. Centralization is necessary to improve flow all around
the pipe and aid in mud removal.

Computer Simulations (displacement efficiency, fluid hydraulics, well
security and control). As is true with many areas of study, computers
have greatly improved the design process for well cementing. Using
computer simulators, the engineer can tailor the cementing process to
account for an individual well's unique conditions. It is no longer
necessary to rely on general "rules of thumb". Each cementing service
company has its own simulator. Simulators are also available from 3^rd^
party vendors. These simulators vary in their capabilities and
strengths. Typical capabilities include:

-   U-tube calculations to predict whether the cement job can be
    performed within the pore pressure/frac gradient window, considering
    ECD

-   Displacement efficiency

-   Foamed cementing calculations

-   Circulating and post cementing temperature profiles

-   Swab and Surge Pressure

As with any computer program, the quality of a cementing simulator's
output depends on the degree to which the input variables are known. It
is not likely that a simulator can give you a single "right" answer.
However, by bracketing variables, the engineer can gain insight that
will assist in achieving zonal isolation.

***5.7 Slurry Design and Testing***

Cement must be placed in the wellbore and provide good contact with the
casing and borehole wall, prevent the formation of channels within the
cement and prevent the invasion and propagation of fluid through the
cement as it sets. The cement should maintain its integrity throughout
the operation of the well and after.

Cement properties necessary to meet these objectives include

-   rheological properties that aid mud displacement,

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-   hydrostatic pressure control,

-   fluid loss control as appropriate,

-   free fluid and sedimentation control,

-   control of gel strength development,

-   resistance to invasion of gas or fluid,

-   rapid set and adequate short term and ultimate strength,

-   long-term sealing (bonding/flexibility);

Test methods for determining the performance of cement are described in
API RP 10B (ISO 10426-2), ISO 10426-3, ISO 10426-4, and ISO 10426-5.
These methods should be modified, as closely as possible, to the
conditions to which the cement will be exposed during placement across
the potential flowing zones requiring isolation. Temperature/pressure
schedules should be devised for conditioning and curing the cement for
these tests. The use of thermal wellbore simulators is discussed
previously.

***Lead and Tail Cement*** -- Lead and tail cements are routinely placed
in the annulus during primary casing cementing. Lead cements are cement
slurries that are designed with lower densities by extending the cement
with low cost components, either water or readily available low-cost
materials. In addition to the cost consideration, low density lead
cements are used to lower the hydrostatic pressures to avoid or minimize
losses of the cement to the formations. Tail cements are cements mixed
without extending components and are thus more costly.

The design of the cement which will cover the potential flowing
formations must be considered carefully. Lead cements, although not
normally "designed" to cover formations which might flow, can be
designed to control flows. Doing so may require special formulations. In
most cases, potentially productive formations which have the potential
for flow after cementing are covered by "tail" slurries. Such slurries
are frequently designed with special properties and/or additives to
control the flow. Lead slurries which are placed across "non-productive"
formations having the potential to flow should be designed with the same
criteria as slurries placed across the pay zones.

***Density*** - Density plays a key role in the design of cement
slurries. In cases with potential for flow, there are two primary
considerations for selecting the density: preventing losses to the
formation and preventing flow from permeable formations. This implies
the density must fall between that necessary to provide enough
hydrostatic pressure to control flow from the permeable formations and
that which will fracture the weak formations (see previous discussion of
pore pressure/frac gradient under Engineering Design).

Other considerations related to the density of the slurry are the
performance related to strength development, and slurry stability (see
subsequent discussion). Meeting the requirements of strength and slurry
stability may make the use of special slurry formulations necessary to
achieve the required density.

The density under placement conditions (temperature and pressure) must
be considered in the design. Some slurries are compressed by pressure
while others have components which are deformed by pressure. Either of
these can lead to higher densities after placement downhole than the
density at which the slurry was mixed at surface.

***Thickening Time*** -- The thickening time is the time that a slurry
is judged to be pumpable. Testing should be under conditions simulating
those downhole during placement. Slurries should be designed for the
specific set of conditions found in the well and for the designed
pumping schedule (rates) to be employed during the cementing operation.
Wellbore temperature simulators are used to model anticipated well
temperatures while cementing and can be used to develop schedules for
conducting tests.

The use of excessive safety factors in thickening time design should be
avoided. Excessive safety factors can cause delayed setting, long
periods of gelation and increased likelihood of solids segregation.
These factors may present a higher potential for flow from the formation
before the cement has adequate strength to prevent it.

Thickening times should be designed so that slurries set from the bottom
to the top of the well. Gel strength development progression should also
be from bottom to top.

***Fluid Loss*** -- Control of fluid loss plays a key role in preventing
flow. Loss of fluid after cement placement is a contributing factor in
the loss of the overbalance pressure controlling flow. The rate of fluid
loss is dependent on the overbalance pressure, the permeability of the
formation, the condition of the mud cake (including its permeability),
and the fluid loss characteristics of the cement. Testing should be done
after conditioning the slurry at conditions similar to those in the
wellbore. Fluid loss test temperature should be that which the slurry
will experience across the potentially flowing zones. It is not possible
to make a precise rule about the required level of fluid loss; it
depends on many factors, but lower fluid loss is always better where
there is potential for flow.

***Slurry Stability; Sedimentation, Free Fluid*** -- Stability of the
slurry is an important property in preventing annular flow. Free fluid
and sedimentation may occur simultaneously or one may occur without the
other.

Free fluid can result in a channel or a void in the cement into and
through which formation fluid or gas can easily flow. It may also result
in a severely underbalanced condition (through the water channel)
initiating the flow. Control of free fluid is imperative in situations
where there is the potential for flow.

Not only is the presence of a channel and the resulting underbalanced
condition critical, but the condition of the remaining slurry is key as
well. When water is lost from the slurry (by free fluid separation), the
solids concentration is increased. This can result in uncontrolled
gelation, changing other properties of the cement (such as ability to
transmit hydrostatic pressure).

Additionally, sedimentation (which results in concentration of solid
particles in lower sections and reduced concentrations in upper sections
of the well) must be controlled. The properties of the slurry will be
changed by sedimentation, leading to greater gelation where the solids
are concentrated and low strength and high permeability where they are
reduced.

Slurries should be conditioned at temperatures encountered during
placement and free fluid and sedimentation tests conducted at the
temperatures to be encountered while static in the annulus.

***Rheology*** -- The rheology of the cement slurry is important for two
reasons; the displacement of fluids ahead of it and the friction
pressure generated during placement. Design should take these into
account.

Rheology has a secondary effect on the slurry stability. Gel strength
development may also be affected by components of the cement which are
used to control rheology. All of these effects must be considered
together. Rheology is tested at atmospheric pressure at temperatures up
to 189^o^F (87^0^C). To avoid burns, care must be taken when such
testing is conducted at high temperatures.

***Gel Strength*** -- Gel strength affects the ability of slurries to
suspend their solids. It also contributes to decay of hydrostatic
pressure as the gelled fluid interacts with the casing and the borehole
wall. Thus, the gel strength of cement slurries should be designed to be
adequate to support the solids and yet, not be excessive. One method to
evaluate gel strength development is to measure the "critical gel
strength period."

There are two approaches to the control of gel strength for annular flow
control; low gel strength until just before setting and rapid gel
strength development to 500 lbf/100 ft^2^.

The [Critical Gel Strength Period]{.underline} is the time between the
development of critical static gel strength (CSGS) and 500 lb/100 ft^2^.

The CSGS is the gel strength of the cement that results in decay of
hydrostatic pressure to the point that the pressure is balanced (equals
pore pressure) across the potential flowing formation(s).

The CSGS is computed by:

> CSGS = (OBP)(300)/(L/D~eff~), where
>
> OBP = overbalance pressure (psi)
>
> 300 = conversion factor (lb/in.)
>
> L = length of the cement column (ft)
>
> D~eff~ = effective diameter (in.) = D~c~ - D~OH~
>
> D~c~ = diameter of the casing (in.)
>
> D~OH~ = diameter of the open hole (in.)

The critical static gel strength should not develop before mixing and
pumping stoppages (such as dropping a wiper plug) have been completed.

Gel strength is intimately related to the hydration of the cement, the
chemical reaction between the powdered cement and water to produce a
solid matrix. These reactions and the gel strength depend on
temperature, the chemical and physical nature of the cement being used
and materials added to the cement to control its properties (e.g.,
thickening time, fluid loss, etc.). Gel strength can be controlled by
the use of additives. Additives for controlling other properties of the
cement should be selected with control of gel strength in mind.

There are no standardized tests for gel strength determination. Service
companies have developed methods for determining gel strength at
temperature and pressure to simulate wellbore conditions. The gel
strength can be measured using a device that allows measurement under
pseudostatic conditions \[at a rotation of 0.2^o^/minute (or at shear
rate of 10^-3^ sec^-1^) or less\] on an apparatus designed to make this
measurement under simulated downhole conditions. The gel strength may
also be determined using special rheometers designed to measure gel
strength, pressure drop measurements or ultrasonic correlations. It
cannot be determined using a consistometer or a standard rheometer.

[Critical Gel Strength Period]{.underline} **--** The critical gel
strength period should be minimized to the extent possible, preferably
less than 45 minutes (measured at the temperature of the potentially
flowing zone).

***Strength*** -- The development of strength is a primary consideration
in continued operations following a primary cementing job. Early work^1^
has shown that 8 psi tensile strength (or about 100 psi compressive
strength; compressive strength is about 8-12 times tensile strength for
most cements) is adequate to support the casing. Waiting on cement (WOC)
time is normally until laboratory testing has shown the cement around
the casing shoe to develop 500 psi compressive strength. The allowable
activity after cementing should depend on the strength development
profile of the cement (see additional discussion of WOC under "Post
Cementing Operations" and "WOC Tree" under Mechanical Barriers).

There has been a tendency in the past to maximize compressive strength.
For the short term, this may seem appropriate, but for later well
operation, high strength may be contrary to good well integrity (see
discussion under Mechanical Properties).

***Compatibility*** -- Any fluid being displaced should be compatible
with the fluid displacing it. Fluid compatibility has been discussed
previously under Engineering Design: Mud Removal. Compatibility between
cement slurries in not normally a problem, but with certain types of
slurries it can be. This is especially true for latex-containing
slurries in contact with extended slurries. Compatibility between
slurries should be tested to ensure that rheological behavior,
thickening time, fluid loss and slurry stability are not compromised.
Procedures described in API RP 10B, Section 16 can be adapted to test
cement slurries for which there is concern about compatibility between
the slurries. Rheological behavior, thickening time, fluid loss and
slurry stability should be evaluated.

***Mechanical Properties*** -- Besides compressive and tensile strength,
Young's Modulus and Poisson's ratio play a key role in the integrity of
the cement during the operation of the well. Stresses placed on the
cement by changing pressures (including pressure testing, hydraulic
fracturing, etc.) and temperatures in the well or changes due to
reservoir pressure can cause a microannulus to form between and the
casing or can cause radial cracking of the cement sheath, or both. These
conditions can lead to fluid leakage through the cement sheath,
sometimes to surface. Pressure at the surface caused by such leaks is
commonly known as sustained casing pressure.

High strength cement is brittle and subject to failure under stress.
More flexible cement can better withstand stress without failing. Such
more flexible cements often exhibit lower, but adequate, compressive
strength. Lower Young's modulus cements are more flexible than those
with high Young's modulus.

Wellbore simulation software can be used to determine the proper
combination of strength and flexibility for a specific well within its
operation conditions.

There are no standardized tests for determining Young's Modulus and
Poisson's ratio for cement under wellbore conditions. Tests have been
adapted from other disciplines for testing oil and gas well cement
formulations.

***Flow Control*** -- Proprietary slurries are available for cementing
where there is risk of annular flow. Service company design criteria
should be met for use of these slurries.

***Expansion/Shrinkage*** -- Cement may shrink under certain conditions
encountered in the wellbore. Such shrinkage may lead to loss of seal,
leading to leakage through or around the cement. Expansive agents may be
employed to counteract the effects of this shrinkage.

Test methods for determination of shrinkage or expansion of well cement
are under development (ISO 10426-5, Petroleum and natural gas industries
-- Cements and materials for well cementing -- Part 5: Test methods for
determination of shrinkage and expansion of well cement formulations at
atmospheric pressure).

***Foamed Cement*** -- Foamed cement is sometimes used for control of
annular flow due to the ability of its compressible phase to maintain
pressure in spite of gel strength development. An additional benefit of
foamed cement is the greater flexibility of the set foamed cement. Many
of the same criteria for design of unfoamed cement are key in designing
foamed cement for oil and gas well operations. Thickening time, slurry
stability, fluid loss and strength development should be designed for
the conditions of the well. High permeability foamed cements should be
avoided. In addition, the effects of pressure on the compression of the
gas phase and consequently the density must be considered.

An operational benefit of foamed cement is the ability to easily change
slurry density by adjustments in the gas ratio. Care must be exercised
when making such adjustments to ensure that other design criteria are
not compromised (strength, permeability, etc.)

Foamed cement requires special testing methods. Due to the compressible
nature of foamed cement, standard well cement testing methods cannot be
used for the foamed cement itself. Tests on the foamed cement are made
at atmospheric pressure only, unless special equipment is used.
Atmospheric pressure testing standards are being developed for foamed
cement (ISO 10426-4, Petroleum and natural gas industries -- Cements and
materials for well cementing -- Part 4: Preparation and testing of
foamed cement slurries). In addition to procedures for generating the
foamed cement, methods for testing foam stability, compressive strength
and permeability are described in that standard. Determination of the
thickening time, fluid loss and rheological properties are determined
for the base cement slurry.

***5.8 Wellbore preparation and conditioning***

Every effort should be made to minimize the time between completion of
the hole interval and cementing when flow hazards exist. With the
cementing process in mind, the fluids used to drill should be designed
for ease of removal. Conditions should be maintained to minimize changes
in hole conditions which would lead to difficulty achieving a seal
during the cementing operation.

## *5.8.1 Well Preparation*

Well preparation, particularly circulating and conditioning fluids in
the wellbore, is essential for successful cementing. Many primary
cementing failures are the result of fluids that are difficult to
displace and/or inadequate wellbore conditioning. Particular attention
should be placed on low fluid loss (thin, tough filter cake) and
rheological properties that provide low, flat gel strengths.

Even when good well preparation is planned, contingencies in the
cementing operation should be provided in case well conditions prevent
the planned well conditioning program from being performed.

Well preparation includes:

-   Determining hole size,

-   Adjusting drilling fluid rheological properties to aid in its
    removal during cementing,

-   Ensuring the well is dead ,

-   Curing losses,

-   Conditioning of fluids prior to cementing to ensure that gel
    strength is broken, that cuttings and gas are removed and that the
    well is cooled for cementing.

> The precementing considerations that are included in this summary are
> based on sound cementing best practices that are known to enhance the
> probability of success. Primary cement job failures are predominately
> due to a breakdown in the \"displacement process\" which leads to
> channeling of the cement through the drilling fluid. These guidelines
> when applied in conjunction with a simulation software program will
> enhance the displacement process and improve the probability of
> successful primary cementing. Simulation software can be used to help
> determine the optimum displacement parameters and safe operating ECD.

1)  ***Caliper*:** A caliper is a necessary part of any cementing
    design. The whole size must be known to allow proper calculations of
    friction pressure, both during the cementing operation and when
    running casing. It is also necessary to calculate the centralizer
    requirements and from centralizer calculations, to calculate flow
    regimes and rates required for effective mud removal. The caliper
    must be of sufficient quality to make the necessary calculations.

2)  ***Control Lost Circulation*:** Before cementing casing or liner,
    lost-circulation should be eliminated or significantly reduced. This
    is best done prior to cementing. If this is not possible, or if
    losses are anticipated during the primary cementing job, there are
    several options. The first is to maintain the downhole circulating
    pressures below the pressure at which losses occur by reducing the
    density of the cement slurry, minimizing the height of the cement
    column and limiting friction pressure during the cementing
    operation. Other options are to pump a plugging material as a spacer
    in front of the cement slurry and add lost circulation materials to
    the cement slurry itself. In practice, these techniques are usually
    used in combination.

3)  ***Wiper Trip; Conditioning the Drilling fluid:*** After logging and
    prior to cementing, a wiper trip should be made to help stabilize
    the wellbore and remove any remaining cuttings. The mud should be
    conditioned in preparation for cementing. The condition of the
    drilling fluid is one of the most important variables in achieving
    good displacement during a cement job. Regaining and maintaining
    good mobility of the mud is key. Drilling fluids with low gel
    strength, low rheology and low fluid loss are more easily displaced.
    Pockets of gelled fluid, which commonly exist following drilling,
    make displacement difficult and must be broken up. Conditioning
    should include adjusting the mud properties to those which will be
    favorable for mud removal during cementing.

4)  ***Flow Rate:*** Flow rate is dependent on well geometry, fluid
    densities and rheologies. Turbulent flow conditions are desirable,
    but are not required. Some modeling indicates using high energy
    displacement rates can allow fluid to be bypassed if the flow is
    greater than the maximum allowable. A computer simulation should be
    used to determine the optimum pump rates to obtain the best flow
    regime and safe ECD\'s.

To condition the drilling fluid in preparation for a cement job, perform
the following:

a.  Modify the flow properties of the drilling fluid to optimize
    drilling fluid mobility and removal of drill cuttings. Yield point
    (YP) and gel strengths should be maintained as low as possible
    without causing settling of solids from the fluid. These variables
    must be evaluated for the specific well conditions. In deviated
    wellbores a higher-viscosity drilling fluid may be required to help
    prevent solids from settling on the low side of the wellbore. The
    presence of large drill cuttings may also necessitate higher
    viscosity fluids. The higher-viscosity fluid needs to be optimized
    based on wellbore conditions and inclination. After removal of
    cuttings, consideration should be given to lowering viscosity of the
    drilling fluid to aid in its removal.

b.  Measure gel strengths at 10 seconds, 10 minutes, 30 minutes, and 4
    hours to examine the gel strength profile of the drilling fluid. In
    addition, a longer term gel strength test should be run at the
    bottom hole temperature and pressure. If gel strength profile is not
    flat after 4 hours, continue to test to match the maximum planned
    static time for operations such as tripping, logging, or running
    casing or liner. This testing would typically be performed during
    the job planning stage. During conditioning just prior to the job,
    readings taken at 10 seconds, 10 minutes, and 30 minutes are
    typically sufficient. Well-conditioned mud should have a 10 second
    gel strength that is \< 15 lbf/100 ft^2^ and the 10 minute gel
    should be no more than 1.5 times the 10 second gel or the 10 minute
    gel strength should be \< 15 lbf/100 ft^2^.

c.  Decreasing the filtrate loss into a permeable zone enhances the
    creation of a thin filter cake. A high fluid loss creates a thick or
    high viscosity, drilling fluid layer immediately adjacent to the
    formation wall that is difficult to displace prior to or during
    cementing. The fluid loss required is dependent on the hole section
    being drilled. In the surface section the fluid loss (API) is
    generally not controlled or reduced to \<20 cc prior to running
    casing, while in deeper sections the fluid loss is reduced further.
    Fluid loss control should be maintained while conditioning the hole
    and running casing and cementing. Note that a thick, gelled filter
    cake deposited while drilling using high fluid loss mud cannot be
    repaired by later lowering the fluid loss of the mud

***5.8.2 Running Casing***

The surge effect of running casing can result in fracturing or wellbore
damage. When casing is run into the hole, a piston effect is caused by
the friction pressure of the gelled mud flowing past the casing as it is
run. The mud flow rate (and the friction pressure) is proportional to
the casing running speed. Running casing with a closed end (normal float
equipment) causes the mud to flow faster up the annulus, whereas when
run open-ended or with automatic fill float equipment, the fluid
velocity (and friction pressure) in the annulus is reduced since part of
the mud fills the casing.

As the well has been static since the wiper trip, the mud will be
gelled. This also increases the surge pressure.

***a. Surge mitigation tools/procedures***

With sensitive or weak formations, the surge pressure must be minimized.
Surge pressures can be reduced by reducing running speed and by the use
of floats that allow mud to flow into the casing while it is run. Surge
pressures can also be reduced by reducing the rheology and gel strength
of the drilling fluid prior to running casing.

Surge effects can also be reduced by pausing while running casing to
circulate mud, removing the gelled mud from the well and replacing it
with well-conditioned mud from the pits.

Casing speeds should be evaluated prior to the job by using surge
calculation software to determine maximum running speeds without
damaging the formation or losing mud. Surge simulation software can also
show the effects of lowering mud viscosity or gel strength and may be
used for input to the fluid engineer for use in conditioning the mud
during the wiper trip.

b.  *Centralizer program*

Centralizing the casing across the intervals to be isolated helps
optimize drilling fluid displacement. In poorly centralized casing,
cement will follow the path of least resistance; as a result, the cement
flows on the wide side of the annulus, leaving drilling fluid in the
narrow side. In a deviated wellbore, standoff is even more critical to
prevent a solids bed from accumulating on the low side of the annulus.
The required standoff should be determined from computer modeling of mud
removal and will vary with well conditions.

Centralizers should be run according to an engineering design for
optimum cementing results.

***5.8.3 Conditioning After Casing is Landed***

When the casing is on bottom and before cementing, circulate the
drilling fluid to break its gel strength, decrease its viscosity and
increase its mobility. Condition the drilling fluid until equilibrium is
achieved.

Determine the volume of the circulatable hole and calculate the
percentage of the openhole annular section that is being circulated.
Good fluid returns at the surface do not reliably indicate the mobility
of fluid in the annular space. For best results, use a fluid caliper to
determine downhole fluid mobility.

A fluid caliper is a small volume of fluid which is easily identifiable
when it returns to the pits after circulation. Knowing the time between
injection and recovery, and the pump rate, the volume of fluid which is
flowing in the well can be calculated. A fluid caliper pumped through
the well in a full circulation helps perform several functions:

-   Measure the openhole circulating volume by subtracting casing
    capacity and pipe-in-pipe annular volume from the trip volume.

-   Measure hole cleaning performance (gelled mud/cake/cuttings removal)
    of various methods/materials.

-   Validate cement volumes predicted by wireline caliper logs.

If less than 95% of the openhole volume is circulating, various methods
and materials should be used to clean the hole to achieve at least 95%
circulation in the open hole annulus prior to cementing. Hole cleaning
methods include higher circulating rates, pipe movement, and the use of
high/low viscosity pills to remove any partially dehydrated \"gelled\"
mud, wall cake, and cuttings that can impair mud displacement during
cementing. More information can found in the following technical papers:

1.  Smith, T.R.: "Cementing Displacement Practices: Application in the
    Field," SPE/IADC paper 18617 presented at the 1989 SPE/IADC Drilling
    Conference in New Orleans, La. on February 28 - March 3.

2.  Griffith, J.E. & Ravi, K.M,:"Monitoring Circulatable Hole with
    Real-Time Correction: Case Histories", SPE 29470 presented at the
    1995 SPE Production Operations Symposium, Oklahoma City, April 2-4.

At a minimum, condition the hole for cementing by circulating 1.5
annular volumes or one casing volume, whichever is greater.

When the drilling fluid is well conditioned (drilling fluid properties
in equals properties at the outlet), continue circulating the drilling
fluid until spacer and cementing fluids are pumped. Minimize shutdown
time between conditioning and cementing by installing the cement head
and pressure testing lines BEFORE conditioning the well. Minimize time
to drop plug by proper planning. It is best to land casing close to the
floor to allow easy access to pins and valves on the cementing head
necessary to drop the plug (and to minimize hazards).

***5.9 Cement Job Execution***

# *5.9.1 Bulk Plant QA/QC* 

Accurate cement blends are extremely important to the success of any
cement job. Care must be taken to ensure that the blend matches the
blend tested in the laboratory.

All cement blends must be blended in accordance with the written
procedures established by the Service Company providing the cement
blend. In addition, the personnel blending and/or loading the cement
must be properly trained and/or certified bulk plant operators.

The cement blenders and all associated equipment should be regularly
maintained and inspected to ensure there are no leaking valves or any
equipment malfunction that could cause improper additive and/or cement
concentrations or contamination. Equipment to be inspected includes
check valves, pressure relief valves, interior blender surfaces,
additive hoppers, and aeration devices. Appropriate actions, including
purging discharge lines and blending systems with neat cement, should be
taken to ensure no contamination is possible whenever blends are loaded.

Bulk plant scales should be accurate and in proper working order. These
scales should be part of a regularly scheduled calibration program.
Copies of the calibration certification should be retained at the bulk
plant. A certified calibration technician must perform all calibrations.

Bulk plants should be equipped with proper sampling devices to ensure
that multiple samples are taken throughout each blend. The sampling
device should be located in an area on the discharge line that ensures
that excess moisture cannot enter the sample containers.

# *5.9.2 Cement and Additive Lot Numbers*

The Service Company providing the cement and/or cement blend must follow
all established documented company procedures to ensure that all
received neat cement is within acceptable specifications upon arrival at
the bulk plant. In addition, the lot numbers of all additives used must
be documented for each cement blend. This information should be
contained in the paperwork associated with the particular job for which
the blend is loaded. A minimum of two samples of at least one gallon
each of neat cement or blend shall be documented, labeled, and retained.
One of these samples should be retained at the bulk plant and the other
sent to the lab for verification testing (if required). If verification
testing is required, testing should be conducted with representative
samples of location water.

# *5.9.3 Transportation/Storage*

All cement blends must be stored in properly maintained bulk storage
tanks. This includes physical inspection of the pads and interior
surfaces of the tanks prior to loading/bulk transfer. Tanks should be
physically swept out after a cement blend is stored in the tank. This
will ensure that no contamination is present in the storage tank(s). In
addition, discharge, fill, inspection port, and vent valves must be
checked in order to determine that no valves are malfunctioning.

Cement volumes to be loaded must take into account any bulk transfer
losses that may occur. This is particularly important in an offshore
environment where losses in the bulk tanks of a boat and in transfer to
the rig may be significant. Boat tanks must also be physically inspected
and, if necessary, swept out prior to loading.

# *5.9.4 Mixing and Pumping*

The cement spacer(s) and slurries should be mixed at the planned
densities. The spacer and slurry should be batch mixed if possible. If
batch mixing is not possible, all attempts should be made to ensure that
the slurry density is within the acceptable range. Computer aided
density control systems are recommended to ensure that the slurry is
mixed at the proper density.

Slurry density fluctuations can have adverse affects on slurry
properties including: reduced or extended thickening times, free fluid,
retarded compressive strength development, extended slurry transition
time, and reduced fluid loss control. Additionally, density fluctuations
can result in increased ECD, fracturing of weak formations, and the
potential loss of well control.

# *5.9.5 Following the Job Design*

The pumping of the cement job should be according to planned rates and
volumes. The planned rates should be obtained from the output of a
computer simulation. The computer simulation should determine maximum
pumping rates allowable and mud removal efficiency at planned pumping
rates. The information entered into the computer simulation should be as
accurate as possible. This information should include actual mud,
spacer, and slurry rheologies, actual caliper log information (if
possible), actual tubular configuration, actual fracture and pore
pressures, and actual hardware configuration. Required hardware
configuration data includes actual centralizer data, hanger systems,
liner packer data, etc. Having accurate input data ensures that the
simulation output will be accurate and feasible. Deviating from planned
job design can result in poor zonal isolation due to formation
fracturing or mud channeling. Due to this, it is recommended that
discussions be held with all pertinent parties prior to a deviation from
planned procedure.

# *5.9.6 Pipe Movement*

Pipe reciprocation and rotation can assist in effective mud removal.
Pipe movement assists in mud removal by altering the flow path of the
mud and/cement spacer(s) and slurry. Pipe movement can also help to
break the gel strengths of mud that may otherwise be bypassed by the
spacer and slurry. Reciprocation must be done slowly to ensure that
surge pressures are minimized and losses are not induced due to
fracturing of formations. Computer surge programs can supply the maximum
reciprocation rate during a cement job.

Proper equipment must be utilized anytime pipe movement is planned. When
reciprocating, ensure that enough treating iron has been utilized from
the rig floor to the cementing plug container. Pipe rotation
necessitates the use of equipment designed to rotate without creating
stress on the plug container and treating iron.

# *5.9.7 Computer Collection of Data*

All pertinent job data should be monitored and recorded by computerized
data acquisition equipment. The data to be recorded should include
density of all fluids pumped, rate at which they were pumped, and
surface treating pressure. Pressure should be recorded during the entire
displacement, regardless if the rig mud pumps are utilized to displace
the plug. If possible, return rates should also be recorded. The
recorded job data discussed in this section is necessary as a quality
control record and for post job analysis and reporting. It can also
supply valuable information in the event that the job can not be pumped
as planned.

# *5.9.8 Lost Circulation Contingency Plans*

Lost circulation contingency plans should be discussed prior to job
execution. These plans can include increasing or decreasing cement
volumes, altering cement thickening times, altering fluid loss control
of the slurry, and increasing or decreasing slurry pumping and
displacement rates. Computer aids such as surge analysis programs and
ECD programs can minimize the risk of lost circulation. In addition,
there are several float equipment designs that can be utilized to help
reduce the risk of fracturing formations while running the casing into
the wellbore.

# *5.9.9 Spacers*

Cement spacers are one of the most critical components in obtaining
successful zonal isolation. Spacers serve several functions including:
removing gelled mud ahead of cement slurries, water wetting cement
contact surfaces, and providing a barrier between the cement slurry and
drilling fluid in the wellbore. Cement spacers should be tested for
compatibility with a representative sample of the drilling mud. Improper
spacer selection may result in poor mud removal and excessive viscosity
at the spacer/mud interface.

Multiple spacers may be required if compatibility does not exist with a
single spacer. The first spacer may aid in mud removal, while the second
spacer water wets downhole contact surfaces and provides a barrier
between the slurry and drilling mud.

There should be a fluid density hierarchy in which each successive fluid
pumped into a wellbore is at least 10% heavier than the fluid preceding
it. There may be times when this is not possible or practical, although
this is generally preferred.

Turbulent flow spacers are generally recommended if a single spacer
system is to precede a cement slurry. Turbulent flow may not be possible
due to wellbore eccentricity, enlarged wellbore sections due to
washouts, and pumping/displacement rate restrictions due to ECD
constraints.

Adequate spacer volume is critical to the success of a primary cement
job. Spacer contact time and/or annular fill should be discussed during
job planning sessions. The spacer volume should be the greater of 5
minutes contact time (minimum) or 1,000' of linear fill. Some mud
systems require that these values be greatly increased or doubled.

# *5.9.10 Displacement*

Displacing of cement slurries should take place at planned rates, unless
lost circulation is encountered and the contingency plans initiated. The
cement unit should displace all squeeze jobs, liner jobs, stab-in jobs,
and plug jobs. The rig mud pumps can be used to displace large casing
jobs, though the cement unit should monitor and record the displacement
pressures. Displacement rates should also be recorded if possible, and
thoroughly documented if recording is not possible.

Over-displacing if the plug does not bump should be discussed prior to
job execution. Volumes in excess of 50% of the capacity of the float
tract should not be exceeded when pumping additional fluid over
calculated displacement volume.

# *5.9.11 Multiple Plugs*

Top and bottom wiper plugs are recommended for all casing jobs, with the
exception of stab-in casing jobs. On stab-in casing jobs, a drill pipe
wiper dart or ball should be dropped behind the cement slurry. The
spacer ahead of the cement slurry should be pumped ahead of the bottom
wiper plug. This ensures that the cement is uncontaminated in the
casing. In addition, double plug containers are recommended where
possible. The wiper plug container should have a system indicating the
launch of the wiper plug.

Trained personnel should follow established procedures when operating a
cement wiper plug container. The top wiper plug should be launched as
slowly as practical. Plugs should never be launched "on the fly".
Careful attention should be paid to when the wiper plug actually leaves,
due to the potential for fluid bypass in some plug containers prior to
plug launch. It is recommended to launch the top plug with spacer
whenever non-aqueous fluids are used to displace.

# *5.9.12 Holding Pressure Inside Casing*

The casing floats should be tested after the displacement is complete.
Once it has been determined that the floats are holding properly, ensure
that no pressure is trapped inside the casing due to closed valves on
the cement head. The valves on the cement head must remain open as the
fluid inside the casing will expand due to heating and thermal expansion
of the displacement fluid. If the valves on the cement head are closed,
the casing will expand with the fluid inside. This can create a
microannulus, which could result in poor zonal isolation and sustained
casinghead pressure. The only time it is permissible to trap pressure
inside the cemented casing is in the event that the floats have
malfunctioned and are not holding pressure.

***5.10 Post Cementing Operations***

***Maintain Full Hole*** -- In order to maintain maximum overbalance
pressure, the fluid level must be maintained in the annulus. In addition
to maintaining the overbalance pressure, a full hole will give an
earlier warning if the well begins flowing and allows for tracking
losses.

***WOC*** -- Operations on the well following cementing must be done in
such a way that they will not disturb the cement and damage the seal or
the set cement.

Any pipe movement to complete hanging the casing and activating seals
should be finished before significant gel strength has developed. If
done after the cement has developed significant gel strength, the
movement could cause a microannulus. There is also danger of initiating
flow if the pipe is moved in such as way as to swab the well.

If hanging the casing must be performed after cement strength is
developed, as when intentionally increasing or decreasing the landed
tension in the casing, this should be performed after the compressive
strength at the top of the cement is at least 100 psi.

Likewise, pressure testing casing should be done preferably before
significant gel strength has developed. Pressure testing can be done
after the cement has set but this can result in microannulus formation
or damage to the cement sheath. The pressure should be held on the
casing for the shortest length of time required to accomplish the test.
The effect of pressure testing will depend on the properties of the
cement, the pressure at which the casing is tested (and consequently the
amount of enlargement of the casing) and the properties of the formation
around the cement. Mechanical stress modeling can assist in determining
the best time to conduct the pressure tests.

Normally, a minimum compressive strength of 500 psi is recommended
before drilling out the shoe of the cemented casing.

See additional discussion of waiting on cement under Mechanical
Barriers.

***Top Job*** -- A top cement job (that is, one conducted to fill in the
annulus when cement did not reach the desired depth for the top of
cement) can be conducted immediately after bumping the top wiper plug or
can be done after the cement has set.

Consideration must be given to the probable poor displacement when a top
job is performed. Because of this, it is unlikely that a top job will
achieve isolation. Every effort should be made to ensure that the
primary job circulates cement to surface, when required, and a top job
be done only as a last resort.

If done immediately after bumping the wiper plug, formations deeper in
the well may be broken down. The formations which might be broken down
and the impact on the integrity of the well and the annular seal should
be considered when using this method.

If the top job is done after the cement has set, consideration must be
given to the method of placement, whether it is to be bullheaded or
grouted. Bullheading will result in breaking down a formation. If the
cement has set and there is not a channel in the cemented annulus, the
formation will break down between the top of the set cement and the shoe
of the previous casing. If the top of set cement is above the shoe of
the previous casing, this method cannot be used. In such a case, the
cement will have to be placed by grouting with a small diameter pipe run
into the annulus.

[]{.mark}

# *6.0 Leak Off Tests*

***6.1 Introduction***

# 

Limit Tests (LT, also known as jug tests or formation integrity tests
(FIT)) and Leak-Off Tests (LOT, also known as pressure-integrity tests
or pump-in tests (PIT)) are carried out during the drilling phase after
a string of casing has been cemented and before a new section of hole is
drilled. In these types of casing shoe tests, the cement at the casing
shoe is drilled out and a section of new hole (typically 10-20 ft) is
drilled, the BOP is closed around the drill-pipe, and the well is slowly
pressured up using mud. Casing shoe tests serve the following purposes:

1.  To confirm the strength of the cement bond around the casing shoe
    and to ensure that no flow path exists to formations above the
    casing shoe or to the previous annulus. If such a flow path exist,
    the casing shoe may have to be repaired, e.g. by cement squeeze.

2.  To investigate the capability of the wellbore to withstand
    additional pressure below the shoe, such that the well is competent
    to handle an influx of formation fluid or gas without the formation
    breaking down.

3.  To collect data on formation strength and in-situ stress that can be
    used for geo-mechanical analyses and modeling (e.g., wellbore
    stability and lost circulation prediction).

Most governmental regulatory organizations maintain criteria regarding
verification of casing shoe integrity. The US federal regulations that
apply for offshore wells in the Gulf of Mexico are given by the Code of
Federal Regulations, 30, Chapter II, §250.54 (7-1-'93 edition).
Paragraphs (5) and (6) state:

***(5)** If there are indications of inadequate cementing (such as lost
returns, cement channeling, or mechanical failure of equipment), the
lessee shall evaluate the adequacy of the cement (...). If the
evaluations indicates inadequate cementing, the lessee shall re-cement
(...).*

***(6)** A pressure-integrity test shall be run below the surface
casing, the intermediate casing(s), and liner(s) used as intermediate
casing(s). The District Supervisor may require a pressure-integrity test
to be run at the conductor casing shoe (...).These tests shall be
conducted either by testing to formation leak-off or by testing to a
predetermined equivalent mud weight as specified in the approved APD. A
safe margin, as approved by the District Supervisor, shall be maintained
between the mud weight in use and the equivalent mud weight at the
casing shoe as determined in the pressure-integrity test. Drilling
operations shall be suspended when the safe drilling margin is not
maintained (...).*

Limit tests are carried out until a pre-determined test pressure is
reached, confirming that the formation at the casing shoe can sustain
this pressure. The test is characterized by a linear response of
downhole pressure vs. volume pumped (or time if the flowrate during the
test is constant). These tests are frequently used on production wells
in mature fields, where fracture gradients are already well-understood.
The limit test is used to confirm the necessary and available margin to
drill the next hole section, without leaving a fracture (= potential
point-of-weakness) at the previous casing shoe.

LOT tests are carried out at higher pressures to characterize the
phenomenon of "leak-off" into the formation at the casing shoe. Leak-off
is characterized by a deviation from linearity on the pressure vs.
volume curve. It is associated with the initiation of a fracture at the
casing shoe. Pumping beyond the leak-off point will extend the fracture.
A shut-in period is normally maintained after pumping to monitor the
behavior of downhole pressure. During an extended leak-off test,
backflow of drilling mud after shut-in is monitored in order to
characterize in-situ stress values. Both limit and LOT tests may be
repeated to verify the results of -- or assess the changes induced by --
earlier tests, drilling operations, and/or remedial squeeze jobs.

Note that if deviations from a linear response are observed in the
pressure vs volume curve during casing shoe testing, the following main
factors should be considered: (1) leaks on the surface (e.g., chicksan
connections, pump plungers); (2) fluid flow around the casing and cement
caused by poor cement bonding and channeling; (3) fluid seepage into
formation in the open hole section; (4) trapped air/gas or void space in
the mud column that has not been properly filled with mud; (5)
non-linear deformation of rock being exposed to mud pressure in the
open-hole; (6) fracture initiation and growth in the formation.

***6.2 Pressure Integrity Test Procedures***

1.  Perform casing integrity test per applicable regulations.

2.  Prepare the operator-specified PIT/LOT form. Note the anticipated
    LOT on the form and/or a maximum test pressure if specified. Use a
    scale that will best utilize the entire plotting area of the form to
    help identify the break-over points. Plot only the portion of the
    casing integrity test data to fit this scale.

3.  Drill out casing shoe, clean out rat-hole, and drill 10 ft. of new
    hole.

4.  Circulate bottom up to condition mud and stabilize properties,
    especially density. Be sure mud is free of air bubbles.

5.  Pull up into casing a few feet. General industry practice is to
    **not** pump a slug of heavier mud or LCM prior to the test.

6.  Rig up pumping unit, pump mud through test lines to purge air from
    the system and pressure test surface lines checking for leaks. Use
    same pump that was used for the casing test.

7.  Close the BOP.

8.  Pump down the drill pipe at ¼ or ½ barrel per minute (bpm) or other
    designated rate. MAINTAIN THE CONSTANT PUMP RATE ASSIGNED.

9.  During the test, record and plot cumulative volume pumped vs. drill
    pipe pressure for every ¼ bbl pumped, regardless of the pump rate.

10. Permeability in the open hole may cause pressure build-up to be
    non-linear (i.e., the plot curves and does not follow the trend of
    the casing test). If this occurs, stop the test, bleed pressure to
    zero and retest at a pump rate that is ¼ to ½ bpm higher than the
    previous test.

11. Continue pumping until the predetermined maximum pressure is reached
    or until leak-off is confirmed.

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a.  If pressure decreases sharply while pumping, stop pumping
    immediately. Check surface lines and valves for leaks (make any
    needed repairs) and attempt to retest.

b.  If pressure levels off far below required pressure or leak-off, pump
    additional volume (typically 1--2 bbl) to see if a pressure increase
    will resume.

c.  If performing a Limit Test (a.k.a. Formation Integrity Test (FIT) or
    Jug Test), do not exceed maximum pressure required.

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12. When leak-off is confirmed, or maximum pressure is reached, stop
    pumping and close the shut-in valve.

13. Observe and record shut-in pressure vs. time. Check surface lines
    and valves for leaks during this period. If any are found, repair
    and retest.

14. Release pressure and record volume of fluid bled back.

***6.3 Pressure Integrity Test Guidelines***

# *[Rig Up]{.smallcaps}*

**A. *Pump***

Use a low-volume high-pressure pump, (e.g., cementing unit). Do not
assume that the mechanical barrel counter on the pump is accurate. Pump
strokes are more reliable volume indicators if the pump is in
calibration. The displacement tanks can also be used to monitor volume
if properly marked in ¼-bbl increments.

**B. *Shut-In Valve***

Use a shut-in valve between the pump and the pressure gauge. Use the
shut-in valve rather than relying on the pump to prevent back flow.

**C. *Pressure Gauge***

A good quality calibrated pressure gauge is required. Use an electronic
gauge or a mechanical gauge with the following features: liquid filled,
4" or larger, range 25%-50% greater than maximum anticipated test
pressure (the lower the better), 10-50 psi increments (the smaller the
better), and isolated from pump vibrations and pressure surges.

**D. *Purge Valve - Optional***

If testing without a top drive, install a purge valve on the pump-in sub
and use to purge air from the test lines before initiating test.

**E. *Bleed Valve -- Optional***

If possible, install a bleed valve on a tee between the pump and the
shut-in valve. Open valve during shut-in period to see if the shut-in
valve is leaking.

## F. Pressure Test System Before PIT

# *[Recorded Test Data]{.smallcaps}*

The following items are generally recorded for each PIT:

+-----------------------------------+----------------------------------+
| -   Well Identification           | -   Test Date                    |
+-----------------------------------+----------------------------------+
| -   Casing Shoe Depth (TVD/MD)    | -   Test Type (casing/FIT/LOT,   |
|                                   |     etc.)                        |
+-----------------------------------+----------------------------------+
| -   Hole Depth (TVD/MD)           | -   Pump Rate                    |
+-----------------------------------+----------------------------------+
| -   Casing Size                   | -   Predicted Leak-off or        |
|                                   |     Pressure Limit               |
+-----------------------------------+----------------------------------+
| -   Hole Size                     | -   Fluid Bled Back              |
+-----------------------------------+----------------------------------+
| -   Mud Weight at Surface         | -   Water Depth (offshore)       |
+-----------------------------------+----------------------------------+
| -   Mud Type                      | -   Air Gap (offshore)           |
+-----------------------------------+----------------------------------+
| -   Pressure vs. Volume (or Time) |                                  |
+-----------------------------------+----------------------------------+

As a minimum, pumping data (pressure vs. volume or time), casing shoe
depth and mud weight are necessary for even a rudimentary interpretation
of the test. Other data listed above are also useful in interpretation
and comparison of tests.

# *[Drilling Fluid]{.smallcaps}*

Before pulling into the casing shoe for the test, circulate and
condition the mud to stabilize properties and clean the hole of all
fill. Circulate and condition for the shoe test. Insure that the mud
weight out equals the mud weight in (± 0.1 ppg). Different mud types and
formulations (e.g., water vs. water base mud vs. non-aqueous mud) can
produce different PIT results. Interpretation of repeat tests is
simplified if drilling fluid types and properties are consistent with
the first test.

***[Pumping Guidelines]{.smallcaps}***

Pump rates of ¼ to ½ bpm are typical for initial PITs. Larger volume
tests may require higher pump rates. Pump rate should be constant
throughout the test. Fluctuating pump rates can complicate test
interpretation.

***[Shut-In Guidelines]{.smallcaps}***

**A. *Use the Shut-In Valve***

Using this valve rather than the pump will eliminate the possibility of
fluid leaking past the pump during shut-in. As further insurance,
monitor the shut-in valve (by means of the bleed valve) and other
surface equipment for leaks.

**B. *Monitor Pressure Decline***

Monitor the shut in pressure in 1 minute intervals until the pressure
levels off or can be reasonably extrapolated to a level-off point. A
10-15 minute shut-in is usually sufficient. If the pressure does not
level-off after 15 minutes it is worth the time (for interpretation
purposes) to wait until it does level off or declines to zero.

# *7.0 Post Cement Job Analysis and Evaluation*

## *7.1 Material Inventory*

One important aspect of the post job analysis is material inventory
after cementing operations are complete. A final inventory of material
should be completed and compared to the pre-job inventory as described
in the cementing execution section. The material mass balance will
ensure that the correct amount of cement and additives were utilized
during job execution.

## *7.2 Job Data*

To further evaluate the cementing operations, the real time data can
confirm fluid volumes, densities and rates in accordance with the
initial design. Using computer aided design software, the acquired
versus predicted can be compared to obtain pressure matching, equivalent
circulating densities and confirm well security. When problems occur
during the cementing operations, this information can be useful when
investigating job failures.

The information collected from the job should be compared to the
predicted job design. Prior to the cementing operation, a checklist can
be prepared from the job design to ensure all requirements have been
achieved after execution is complete. The checklist should include all
critical job information such as rates, volumes, densities, pressures,
etc.

All job data should be collected for a complete analysis and can serve
as a reference for future wells drilled in the same or similar areas.
Capturing the knowledge and sharing information with other operators
could drastically reduce the number of flowing wells after cementing in
the Gulf of Mexico.

## *7.3 Cement Evaluation*

Formation integrity and cement placement and strength are important
parameters to be evaluated before drilling the next hole section. There
are two methods commonly used to pressure test the formation below the
casing shoe to determine the strength. The two methods are Leak-off Test
(LOT) and the Formation Integrity Test (FIT). Each test requires the
operator to pump fluids at low rates and small volumes until a change in
slope occurs in the pressure versus cumulative volume plot. The pressure
recorded at the change in slope is used to calculate fracture initiation
pressure and gradient.

When the LOT or the FIT results are inadequate, the operator can perform
a cement squeeze or chemical treatments such as formation consolidation
or fracture sealant squeezes to enhance the formation's pressure
containment integrity or to seal a leaking cement sheath in the annulus.
A repeat LOT or FIT may then confirm the squeeze or treatment results in
increasing the interval's wellbore pressure containment. If the cemented
annulus is not leaking, the other option is to drill ahead with the
existing wellbore pressure containment limitations of the formation
until a more competent formation is reached. For weak formation
intervals of a few hundred feet or less, one chemical treatment may then
be applied to increase the integrity of the entire weak zone instead of
repeat treatments for shorter intervals. When drilling longer intervals,
setting a contingency string in a competent formation may be a viable
option to achieve the desired LOT/FIT.

A more detailed discussion pertaining to formation integrity test
procedures can be found in Section 6.0.

In order to effectively evaluate a cement job, one must ensure the
objectives of the job have been achieved. The most obvious is supporting
the pipe but other objectives will vary depending on the nature of the
cement job. Some of these objectives include isolation to prevent
erosion caused by annular flow of fluids, seal off and protect water
formations, integrity to support deeper strings and to ensure zonal
isolation. Based on the required objectives, multiple techniques are
available which include temperature, noise and acoustic and ultrasonic
cement logs.

***7.4 Cementing Matrix***

[]{.mark}

[Add discussion about the cementing matrix and its use.]{.mark}

This matrix is to be used to evaluate the potential impact of elements
of the cementing process on its success. The sheet should be completed
by the operator during the planning of the well to highlight areas
needing improvement. At the conclusion of each string on which it is
used, the scores for each parameter should be evaluated again and used
as a post job evaluation. The sheet can be printed at each of these
stages and placed in the well file. The scores, both by major category
and the total can be compiled in a database and, with evaluation of
flow, used for process improvement.

The Cementing Matrix and Instructions are in Table One in Appendix Two.

***Appendix One -- Reference List***

^1^ Bearden, W.G., and Lane, R.D.; "You Can Engineer Cementing
Operations to Eliminate Wasteful WOC Time," *The Oil and Gas Journal*,
July 3, 1961.

***Appendix Two -- Cementing Matrix and Instructions***

**See separate Excel file.**