OGJ - Eight Steps Ensure Successful Cement Jobs
OGJ - Eight Steps Ensure Successful Cement Jobs
OGJ - Eight Steps Ensure Successful Cement Jobs
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In completion of oil and gas wells, cement isolates the wellbore, prevents casing failure,
and keeps wellbore fluids from contaminating freshwater aquifers.
The basic factors engineers and operators must consider for successful cementing jobs
have not changed in more than 50 years. These factors are summarized in eight basic
ideas:
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The industry has conducted numerous projects over the years to validate the importance
of these factors.1-3 The projects have also provided quantitative data for more precisely
defining the recipe for good zone isolation.
Drilling fluid
The drilling fluid condition is the most important variable in achieving good displacement
during a cement job.
As rig crews pull drill pipe, run casing, and prepare for cementing operations, the drilling
fluid in the wellbore essentially remains static and becomes gelled. Pockets of gelled mud,
which commonly exist after a wellbore is drilled, make displacement difficult. One must
ensure the pockets of gelled fluid are broken up.
Regaining and maintaining good fluid mobility after running the casing is key. Drilling fluids
with low gel strengths and low fluid loss are the easiest to displace.
To condition the drilling fluid in preparation for a cement job, operators are encouraged to
follow these measures:
Determine the hole volume that can be circulated. Also, evaluate the percentage of
wellbore that is actually being circulated.
Good fluid returns at surface do not reliably indicate the mobility of fluid in the annular
space. For best results, use a fluid caliper or material balance to determine downhole fluid
mobility and check for annular fluid that is not moving.
Circulate the drilling fluid to help break the gel structure of the fluid. Condition the
drilling fluid until equilibrium is achieved. After the casing is on bottom and before the
displacement begins, circulating the mud decreases its viscosity and increases its
mobility.
Never allow the drilling fluid to set static for extended periods, especially at elevated
temperatures. When the drilling fluid is well conditioned (the mud properties coming
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out of the well are the same as the mud pumped in), continue circulating until the
displacement program begins.
Modify the flow properties of the drilling fluid to optimize mobility and drill cuttings
removal.
Examine the mud gel strength profile, during the job planning stage and just before
the cement job. Measure gel strengths at 10 sec, 10 min, 30 min, and 4 hr. An
optimum drilling fluid will have flat, nonprogressive gel strengths. For example, it will
have 6-rpm gel strength values of 1, 3, and 7-lbf/100 sq ft on a Fann 35 viscometer
at 10 sec, 10 min, and 30 min, respectively.
Measure the gel strength development during the job planning stage, at downhole
temperature and pressure. Drilling fluid left in the well at elevated temperatures and
pressures can gel to a consistency that prohibits removal. These increased gel
strengths are not detectable at surface conditions.
Deviated wellbores usually require higher-viscosity drilling fluids to prevent solids from
settling on the low side of the hole. Larger drill cuttings in the system also require that
higher-viscosity fluids be used. Optimum use of higher-viscosity fluids should be driven by
wellbore conditions and inclination.
Spacers, flushes
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Pump the spacer fluid at an optimized rate or as fast as possible without breaking
down the formation.
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Provide spacer contact time and volume to remove the greatest possible amount of
mud.
Make sure the viscosity, yield point, and density of both the spacer and the cement
slurry, are at least the same as the drilling fluid.
Design the spacer package to water-wet the surface of the pipe and formation
thoroughly, when using oil-based or synthetic-based drilling fluids.
Water-wetting the pipe and formation after use of oil-based mud is essential to ensure
strong cement bonding. One should test the spacer system using a new API apparent
wettability testing technique.1 The technique allows the spacer-surfactant package to be
customized, ensuring optimal water-wetting performance.
Flushes are used for thinning and dispersing drilling-fluid particles. These fluids go into
turbulence at low rates, helping to clean drilling fluid from the annulus. Flushes generally
have densities close to water and may not provide proper well control.
Some chemical flushes such as oxidizers and sodium silicate-based fluids, aggressively
attack specific drilling muds, breaking them down and further enhancing drilling fluid
removal.
Move the pipe
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Some liner hangers and mechanical devices prevent casing movement, which must be
considered during cement displacement program design.
Centralize
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Centralizing casing with mechanical centralizers across the intervals to be isolated helps
optimize drilling-fluid displacement. In poorly centralized casing, cement bypasses drilling
fluid by following the path of least resistance. Cement travels down the wide side of the
annulus, leaving drilling fluid in the narrow side (Fig. 4).
Good pipe standoff helps ensure uniform flow patterns around the casing. Equalizing the
friction loss or force that flowing cement exerts around the annular clearance increases
drilling-fluid removal.
Standoff is even more critical in deviated wellbores to prevent solids from accumulating in
a bed on the low side of the annulus. Operators are encouraged to use computer modeling
to develop preferred standoff, which should vary with well conditions.
The best mud displacement at optimum rate is achieved when annular clearances are
1-1.5 in. Centralizing smaller annuli is difficult. Pipe movement and displacement rates are
severely restricted. Larger annuli require extreme displacement rates to generate enough
flow energy to remove the drilling fluid and cuttings.
Centralizers and other mechanical cementing aids, commonly used in the industry, also
serve as inline laminar flow mixers. They change fluid flow patterns and promote better
mud displacement and removal.
Displacement rate
High-energy flow in the annulus is most effective to ensure good mud displacement.
Turbulent flow around the full casing circumference is desirable, but not absolutely
essential.
When turbulent flow is not a viable option for the formation or wellbore configuration, use
the highest pump rate that is feasible.
The best cementing results are obtained when the spacer and cement are pumped at
maximum energy, the spacer is appropriately designed to remove the mud, and good
competent cement is used.
Proper temperature
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Operators can optimize slurry design if they know the actual temperature the cement will
encounter. Bottomhole cementing temperatures affect slurry thickening time, rheology, set
time, and compressive-strength development.
Industry wide, operators tend to overestimate the amount of material required to keep
cement in a fluid state for pumping.
Also, there is a tendency to overestimate the pumping time required for a job, which
results in unnecessary cost and well-control problems. Most cement jobs are completed in
less than 90 min.
One can optimize cost and displacement efficiency by following these guidelines:
Design the job on the basis of actual wellbore circulating temperatures, obtained
from a downhole temperature sub recorder.
Estimate the bottomhole circulating temperature (BHCT) using the API
Recommended Practice for Testing Well Cementing, if actual measurement is not
possible.6
Use the actual downhole temperatures measured. Do not exceed the amount of
dispersants and retarders recommended for the wellbore temperature. When
determining the amount of retarder required consider the rate at which the slurry will
be heated.
Include surface mixing time when estimating job time, especially if the job is batchmixed. Calculate the actual job time, using the slurry volume and average
displacement rate. Limit the amount of trouble time to 1-1.5 hr. To calculate the
approximate thickening time for slurry design, add 1-1.5 hr to the job time.
Cement composition
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Operators are encouraged to design a cement slurry for its specific application, with good
properties to allow placement in a normal time period.
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Well depth.
BHCT.
Bottomhole static temperature (BHST).
Drilling fluid hydrostatic pressure.
Drilling fluid type.
Slurry density.
Lost circulation.
Gas migration potential.
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Pumping time.
Quality of mix water.
Fluid-loss control.
Flow regime.
Settling and free water.
Quality of cement.
Dry or liquid additives.
Strength development.
Quality of the cement testing laboratory and equipment.
Before the job, one should check the cement reaction and actual location mix water to
ensure the formulation will perform as expected. Contaminants in the mix water can
produce large variances in thickening time and compressive strength.
Organic materials and dissolved salts in mix water can affect slurry setting time. Organic
materials generally retard the cement. Inorganic materials generally accelerate cement
thickening.
Raw materials and plant processing methods vary widely and can cause cement quality to
vary.
Cement dehydration from the loss of filtrate to permeable formations can cause bridging
and increased friction pressure, viscosity, and density. Pump pressures can increase.
Additives can be used to provide fluid-loss control when necessary to compensate for
dehydration.
Cementing system selection
Operators select cement systems on the basis of job objectives and well requirements.
Cement is basically inelastic. Cementing systems are similar in many ways. These
systems vary, however, in their capability to provide good zone isolation in changing
environments. The traditional approach to cement selection has been on the basis that
higher compressive strengths result in higher cement sheath quality.
Today, research has proven that the ability of cement to provide good zonal isolation is
better defined by other mechanical properties. Good isolation does not necessarily require
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high compressive strength. The real competence test is whether the cement system in
place can provide zone isolation for the life of the well.
Field studies and laboratory research have shown that a cement sheath can lose its
capability to provide isolation because of inelasticity. Annular fluid movement between
zones and abnormally high annulus pressures indicate failure.
Cement failure can be observed in any area of excess flowing temperatures at the surface
of wellbores in which excessive internal casing test pressures are used.
Applications in which cement sheath failure is a concern require the use of systems that
can withstand wellbore stresses. Some cement additives impart ductile properties to
cement and improve stress tolerances.
One of the most versatile systems to apply is foam cement, which produces a more ductile
and resilient cement and withstands the stress associated with casing expansion and
contraction.
Researchers discovered that cement with approximately 25% foam quality can have the
ductility and resiliency to expand and contract with the casing.
Special considerations
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Because of the complexity of deepwater designs, often it is impossible to employ all of the
cementing practices noted in this article.
This puts additional emphasis on proper slurry design, having a good grasp on
temperatures and paying close attention to the additional challenges of deepwater
cementing.
ISO is in the final stages of developing a deepwater cementing document that addresses
many of the issues in deep water cementing.
Although the basic factors engineers must consider for successful cementing have
changed little in the past 50 years, taking advantage of the experience and technological
advances that have occurred greatly benefits the petroleum industry today.
References
1. Clark, C.R., and Carter, L.G., "Mud Displacement with Cementing Slurries,"
presented to the SPE Annual Meeting, San Antonio, Oct. 8-11, 1972.
2. Haut, R.C., and Crook, R.J., "Primary Cementing: The Mud Displacement Process,"
presented at the SPE Annual Technical Conference and Exhibition, Las Vegas, Sept.
23-26, 1979.
3. Hartog, J.J., Davies, D.R., and Stewart, R.B., "An Integrated Approach for
Successful Primary Cementations," JPT, September 1983.
4. Haut, R.C., and Crook, R.J., "Laboratory Investigation of Lightweight, Low-Viscosity
Cementing Spacer Fluids," presented at the SPE Annual Technical Conference and
Exhibition, San Antonio, Oct. 5-7, 1981.
5. Smith, T.R., and Crook, R.J., "Investigation of Cement Preflushes for a KCl-Polymer
Mud," presented at the 33rd Annual Technical Meeting of the Petroleum Society of
CIM, Calgary, June 6-9, 1982.
6. RP 10B, Recommended Practice for Testing Well Cementing, 22nd edition, API
(December 1997; Addendum 2, November 2000).
The authors
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Ronald J. Crook is a senior technical advisor in the Zonal Isolation Cementing Group at
Halliburton's Duncan Technology Center. He coordinates requests for joint research
projects and is a point of contact for technology exchange between various organizations.
Crook holds a BS degree in chemical engineering from Oklahoma State University. He has
published several technical papers and holds patents in cementing materials and
procedures. Crook, a member of SPE, is currently serving on the program committee of
SPE/IADC. He also serves on API Committee 10 as chair of publications.
Click here to enlarge image
Ronnie Faul is a technical professional for Halliburton's new global Deepwater Solutions
Team in Houston specializing in deepwater cementing. He has worked 27 years with
Halliburton in South Louisiana, South Texas, and the Gulf Coast. He is a 1973 graduate of
McNeese State University with a degree in electrical engineering and a member of SPE
and AADE.
Click here to enlarge image
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In 2000, the MMS received 672 departure requests for casing annuli pressure problems, of
which it processed 632.
Of these requests, MMS allowed 217 wells to continue operation with specific monitoring
requirements for a fixed time period, after which a new departure request is required.
Another 238 wells had casing pressures less than 20% of the minimum internal yield
pressure of the affected casing. Also, the pressure could be bled to zero and MMS allowed
those to continue producing with no further reporting.
MMS allowed continued operation of 30 wells in which the casing pressure was attributed
to thermal expansion of annuli fluids.
The MMS denied 112 of the requests, preventing normal well operation and requiring the
operator to perform remedial work to resolve the problem. Operators withdrew 35
departure requests.
Currently, the API is working to establish recommended practices specifically for offshore
operations, to be issued in three phases.
The first phase is for cementing in deepwater applications. The recommended cementing
practice will address the problem of shallow (below mud line) water flow in wells drilled at
water depths in excess of 1,000 ft.
The second phase will address cementing applications in water depths less than 1,000 ft,
and cover cementing of shallow conductor casing strings. Most reported casing annuli
pressure problems involve surface casing strings.
The third phase will address sustained pressures in all casing annuli. The highest reported
casing pressures normally are in the production casing strings.
The MMS plans to reference the recommended practices for cementing in their rules and
regulations, once they are established, if they meet MMS needs. The effort began in
August 2000. The API reportedly is in its third draft. The expectation is that all three
phases will be finalized within the next 2 years.
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Annular gas migration and sustained casing pressure problems are not restricted to wells
in the Gulf of Mexico. It is a problem that can develop in any petroleum basin, worldwide.
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