SPE/IADC 103967
Drilling Performance and Environmental Compliance—Resolution of Both With a
Unique Water-Based Fluid
Steven Young and Gamal Ramses, M-I Swaco
Copyright 2006, SPE/IADC Indian Drilling Technology Conference and Exhibition
This paper was prepared for presentation at the 2006 SPE/IADC Indian Drilling Technology
Conference and Exhibition held in Mumbai, India, 16–18 October 2006.
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Abstract
In an industry where the technical demands on a drilling fluid
are ever increasing, the use of invert emulsion fluids has been
seen as a necessity to meet required drilling performance
criteria. At the same time there is increasing pressure to
comply, and even exceed, the tightening environmental
demands on our industry which has made the use and
associated waste treatment of these invert fluids complex and
costly. A drilling fluid, which has the drilling performance
characteristics of an invert emulsion fluid, but can exhibit the
benign environmental characteristics of a simple water-based
fluid, has long been the goal of fluids development.
This paper describes the development and application of a
unique water-based fluid that utilizes a triple inhibition
approach to delivering invert emulsion-like drilling
performance. Each component of the fluid system has also
been designed to ensure compliance with some of the world’s
most demanding environmental requirements. The resulting
fluid is flexible in formulation such that it can be utilized in
freshwater on land wells to meet chloride discharge
requirements, can be formulated in seawater for shelf wells to
meet low toxicity and logistics requirements, and can be
formulated in saturated salt water to meet toxicity and
performance requirements for deepwater environments.
The applications of this fluid on a global basis will be
evaluated, comparing the drilling performance and economics
to offset wells which have utilized both conventional waterbased fluids and invert emulsion fluids.
Introduction
Invert emulsion drilling fluids, also known as “oil-based
muds” (OBM) and synthetic-based muds (SBM), have
traditionally always been the fluids of choice when drilling
demanding wells that required a fluid that ensured a high
degree of wellbore stability, was capable of insuring high rate
of penetration (ROP), gave good lubricity and demonstrated
the lowest potential for stuck pipe. The development of a
water-based drilling fluid which could exhibit similar drilling
characteristics tod an invert emulsion drilling fluid has long
been seen as the ultimate goal of drilling fluids research and
development.
Invert emulsion drilling fluids (OBM) are universally
recognized as being the most efficient fluids to drill with due
to the absence of contact between the drilled formations and
water, and due to the inherent oil wetting and lubricity
characteristics of these fluids. The advantages of invert
emulsion drilling fluids have been well documented. The
major advantages are:
a) Improved wellbore stability
b) High degree of contamination tolerance
c) Improved rate of penetration
d) Low coefficient of friction
e) Thin, lubricated filter cake
f) Low dilution rates and ease of engineering
g) High degree of re-usability
The disadvantages of invert emulsion drilling fluids are
typically outweighed by the advantages and have similarly
been well documented. The major disadvantages are:
a) Poor environmental characteristics
b) Poor fracture sealing behavior (higher losses)
c) Density sensitive to temperature/pressure
d) Gas solubility
e) High unit cost
f) Logistical issues with bulk fluid transfers
Several water-based drilling fluid systems have been
developed over the past decade that have began to close in on
the goal of OBM-like drilling performance.1-9 A few of the
more successful WBMs have been:
a) Potassium/salt/glycol fluids
b) Silicate gluids
c) CaCl2/polymer fluids
d) Cationic fluids
Despite these successes, however, the approaches taken
with these fluids have not been completely successful in
inhibiting the hydration of highly water sensitive clays and
have various limitations. Potassium/salt/glycol and
CaCl2/polymer fluids cannot reach the inhibition levels of an
OBM, thus in highly water-sensitive shales, bit balling,
accretion, wellbore instability and poor ROP can result.
Silicate fluids exhibit highly inhibitive properties but have
2
problems related to logistics and mud formulation limitations.
Cationic polymer systems can be almost as inhibitive as an
OBM; however, the cost of running the system, toxicity of
cationic polymers, and their incompatibility with other anionic
drilling fluid additives has resulted in only limited success in
the field.
In addition to these generalized system developments,
there have been a number of individual product developments
that have allowed the performance of such systems to be
pushed closer to that of an OBM. Effective lubricants, ROP
enhancers, and more efficient filtration-control polymers are
some examples.
These developments have all resulted in various inhibitive
water-based fluids which are relatively finely tuned to perform
in certain areas whilst drilling through specific shale types.
However the flexibility of an OBM in a multitude of drilling
environments is one of the areas in which current WBM have
not yet reached the level of OBM performance.
Research and Development
A research and development initiative was undertaken to
evaluate the potential for improving upon existing highperformance
water-based
drilling
fluid
(HPWBM)
technologies, or developing a new HPWBM technology.
Giving the overall goal of the development project – to find a
WBM that would give similar performance characteristics to
that of an IEM – it was determined that development of
individual products, which could enhance existing systems,
would be insufficient to achieve the goal. With this in mind, a
complete system approach was taken.
Learning from previously developed and utilized
HPWBM, it was deemed critical that throughout the
development focus should be maintained on the entire
performance spectrum of an IEM, and not limited to only one
aspect of IEM performance. The following were determined to
be the key development criteria:
• High degree of inhibitive response across a wide
range of shale types
• Significant reduction in clay dispersion and hydration
compared to existing inhibitive systems
• Lower degree of accretion and cuttings
agglomeration related problems
• Environmentally acceptable on a global basis
• Highly flexible in formulation – easily controllable
filtration and rheology profiles, and usable with
various base brines
• Highly solids and contamination tolerant
• Economical in both make-up and maintenance
• High degree of engineering control possible
The test matrix involved testing novel system components
in four different base fluids (freshwater, seawater, 10% KCl,
and 20% NaCl). Testing was conducted on four differing
shale substrates (from highly swelling to highly dispersive),
and used a variety of inhibition test methods (shale dispersion,
bentonite tolerance, shale swelling, shale hardness, shale
accretion) which are described more fully in a previous
publication.10 In addition to these inhibition performance
tests, the novel formulated fluids were also subject to fluids
performance testing (lubricity, filtration, rheology,
SPE/IADC 103967
contamination tolerance, thermal stability, etc.) to evaluate
their overall performance. The test results achieved were
compared to three baselines of a mineral oil-based fluid, a
NaCl/polymer water-based fluid, and a silicate highperformance, water-based fluid. Generalized formulations for
the novel HPWBM, and formulations for the three baseline
fluids are shown in Tables 1a-d.
The final result of this research and development project
was a new water-based drilling fluid which exhibited
laboratory performance characteristics which were in the
realm of those achieved by OBM and far exceeded those
exhibited by other water-based fluids. This fluid was then
taken to the field test stage.
New Fluid Formulation
From the final results of our extensive matrix of testing, a final
novel HPWBM emerged consisting of four synergistic basic
products; a brief description of these key components follows.
Typical formulations for this fluid for a Gulf of Mexico
deepwater well, a South China Sea shelf well and a Western
USA land well are given in Table 2.
Hydration Suppressant. The optimum product developed is a
multi-functional, complex, slightly cationic, polyamine-based
material of specific molecular weight, which is fully watersoluble. The compound is compatible with other common
drilling fluid additives used in WBM, exhibits a pH buffering
effect, and has no hydrolyzable functionality. The unique
molecular structure of this material has been shown by
molecular modeling techniques to provide a perfect fit
between clay platelets, tending to collapse the clays hydrated
structure and greatly reduce the clay’s natural tendency to take
up water.
The material requires minimal ionicity for
maximum functionality, and is equally stable in high salinity
and hardness environments. In addition to its ideal inhibitive
function, the material has been designed to exhibit minimal
toxicity, to be biodegradable, and to be safe to handle.
Dispersion Suppressant. The optimum product developed is a
low-molecular-weight, mildly cationic, fully water-soluble
copolymer that exhibits good biodegradability and low marine
toxicity. The polymeric material is designed to have a
molecular weight and charge density that promotes superior
inhibition by limiting water penetration into the clays and
binding clay platelets together. The molecular weight and
charge of the polymer allows rheological flexibility over a
wide range of fluid densities while tolerating high salinity and
hardness. The compound has the characteristics of controlling
both dispersion and accretion of water-sensitive clays.
Rheology Controller. Xanthan gum was chosen as the
optimum rheology control agent for the fluid, based on the
high efficiency of the polymer and its function across a broad
range of salinities and to hardness. The high low-shear-rate
viscosity (LSRV) and efficient carrying capacity of the
polymer optimizes rheological control and improves fluid
performance in extended reach and deepwater environments
by allowing optimization of hydraulics and hole cleaning.
In complex, deepwater wells, an alternate rheology
control, based on an optimized synergistic biopolymer
SPE/IADC 103967
combination, can be used to achieve a flatter rheology profile
(minimal effect of temperature on yield point and gel strength)
which allows further optimization of hydraulics and hole
cleaning in these operational environments
Filtration Controller. A low viscosity, highly modified,
polysaccharide polymer was chosen as the optimal filtrationcontrol agent for the system. This polymer is stable in low to
high salinities, and at high hardness levels. The low-viscosity
contribution of the polymer allows for optimal filtration
control, to be achieved even at high solids loading (high mud
weights). The low contribution to viscosity from this polymer
also allows for increased rheological optimization to improve
system drilling performance.
Accretion Suppressant. The optimum product developed is a
unique blend of coating agents, surfactants and lubricants
designed to coat drill cuttings and metal surfaces to reduce the
accretion tendency of hydrated cuttings on the surface of
metals and with each other. This blended material is designed
to exhibit stability across a wide range of salinities and be
compatible with highly solids-laden (high mud weight) fluids.
The accretion suppressant aids in preventing any buildup of
drill solids below the bit, allowing the cutters good contact
with new formation for improved rate of penetration. The
component also lowers torque and drag by reducing the
coefficient of friction and by thinning out and lubricating the
filter cake.
The development and selection of each of these
components were coordinated, optimizing upon the synergies
between the chemistry and performance the materials. This
resulted in an improvement in the flexibility of the overall
system design. The net result of this development process is a
high-performance, water-based fluid which has the capability
of both performing in a wide variety of base fluids, and over a
wide density and temperature range.
New Fluid Performance
From initial results of laboratory testing (Figures 1-5), it can
be seen that these newly developed components of this novel
HPWBM individually exhibit performance characteristics that
exceed those previously seen from modern water-based
drilling fluid additives.
The hydration suppressant shows a high degree of
recovery of shale pieces exposed to the inhibitor in a variety of
brines, and shows little softening of shales on exposure. The
product also shows a tendency to prevent shale swelling. The
Optimum concentration range for this product lies at 2-3% by
volume.
The dispersion suppressant shows a high level of
resistance to shale dispersion and contributes towards a
reduction in shale accretion. The optimum concentration range
for this product lies at 2-3 lbm/bbl.
The accretion suppressant shows high efficiency at
preventing shale cuttings from adhering to metal surfaces, and
also contributes towards a lower friction coefficient. The
optimum concentration range for this product lies at 1-3% by
volume.
Bringing all of the components together into a final
HPWBM formulation readily demonstrated the synergistic
3
benefits obtained and demonstrated the true performance that
can be achieved with such a design of water-based fluid.
Summaries of a few of the laboratory test results are shown as
Figures 6 to 12. This testing was carried out on four outcrop
shale substrates which were used in their native state:
• Raw Bentonite –Wyoming bentonite ore, which is
predominantly sodium montmorillonite and has high
swelling characteristics. The moisture content is low
at ~2%.
• Foss Eikeland Shale – an outcrop shale from Norway
which has ~15% sodium montmorillonite, and
exhibits high tendency to dispersion and accretion.
This shale has moderate moisture content at ~12%.
• Oxford Clay – an outcrop shale from Great Britain
which has ~10% sodium montmorillonite, and shows
a tendency to both swell and disperse. This shale has
moderate moisture content at ~14%.
• Arne Clay – an outcrop clay from Great Britain
composed predominantly of kaolinite. The material
is fragile and has a very high tendency to disperse
and accrete. This shale has low moisture content at
~6%.
Four drilling fluid systems are compared in these test results
shown:
1. OBM – conventional mineral-oil-based fluid, 80/20
O/W ratio, YP = 15, ESV= ~1000 v, and density 12
lbm/gal.
2. NaCl/polymer – a WBM typically used in US GOM,
with 20% wt NaCl and 1-lb/bbl PHPA polymer. YP =
15, weighted to 12 lbm/gal with barite.
3. KCl/silicate – one of the most inhibitive WBM with
10% KCl and 8% sodium silicate. YP = 15, weighted
to 12 lbm/gal with barite.
4. HPWBM – newly formulated high-performance
water-based drilling fluid, which was weighted to 12
lbm/gal and YP = 15. The formulation is given in
Table 1.
Figure 6 shows the comparative shale inhibition results
using the slake durability test method.
Figures 7a-d show comparative shale inhibition using the
cuttings hardness test method.
Figure 8 shows the comparative performance of the fluids
with respect to cuttings accretion using the rolling bar test
method.
Figure 9 shows the comparative lubricity measured using
the Fann metal/metal lubricity test at two different loadings.
Figure 10 shows the comparative effect of solids loading
using OCMA bentonite as the contaminant.
From these tests, it can be seen that the HPWBM
significantly outperformed both the NaCl/polymer and the
KCl/silicate water based fluids and could be compared directly
with the performance of the OBM.
Figure 11 shows the inhibition characteristics of the new
water-based fluid using different base fluids of seawater, 10%
KCl brine, and 20% NaCl brine. In all of these tests the fluids
were formulated with 3% hydration suppressant, 2-lb/bbl
dispersion suppressant, and 1.5% accretion suppressant. This
4
demonstrates the flexibility of the fluid that was desirable and
was part of the design criteria.
Based on these, and many other test results, the new
water-based drilling fluid was considered, from a laboratory
standpoint, to be a significant improvement over existing
water-based fluids and to show great promise as a true
performance equivalent to invert emulsion drilling fluids.
In addition to the above, more complex testing such as
molecular modeling of inhibitor chemical behavior in shale
substrates, shale membrane testing, and large-scale accretion
and ROP testing was conducted prior to the newly formulated
fluid being considered for field trial.
Environmental Performance
Given the potential scope of use of this newly developed
HPWBM, a rigorous series of environmental tests were
performed to ensure that the fluid would have minimal impact
on the external environment on discharge. In addition a series
of engineering guidelines were developed with respect to
measurement and control of the fluid with the desire to
optimize product additions and minimize whole drilling fluid
dilution requirements.
Initial marine toxicity testing was carried out according to
the United States EPA guidelines, using the marine shrimp
species mysidopsis bahia. Each of the components of the
system were tested individually, at the uppermost
recommended concentration level, in a standardized test fluid
(Generic Mud #7) to determine the LC50. In addition to the
component testing, a number of whole drilling fluid
formulations were tested using the same EPA test protocol and
species. Seawater and 20% sodium chloride-based fluids were
tested both with and without drill solids contamination. Test
results obtained are shown in Table 3. Achieving shale
inhibitive performance without using a potassium ion is an
important benefit of the new HPWBM. A number of marine
test species used globally (e.g. US Gulf of Mexico, Offshore
Brazil, Offshore India) are sensitive to high potassium
contents.
Further marine toxicity testing was carried out on each of
the chemical components of the materials of the system
according to the North Sea (PARCOM) testing protocol.
Testing was carried out on three different species
(skeletonema costatum – a marine algae, acartia tonsa – a
crustacean, corophium volutator – a sediment reworker and
scophthalmus maximus juvenile – a fish) according to the
harmonized North Sea environmental testing requirements. In
addition to the toxicity testing, the biodegradability in
seawater (procedure OECD 306) and potential for
bioaccumulation (procedure OECD 117) were also tested for
each of the chemical components. Available heavy metals
were also analyzed by ICP-MS. These initial tests showed that
the products chosen were all of acceptably low toxicity,
showed no tendency to bioaccumulate and had very low
available heavy metals content.
One component of the accretion suppressant required a
chemical change to comply with specific chemical group
selection for the Norwegian environmental authorities, and the
product was reformulated to meet these requirements with
similar technical performance. The hydration suppressant
material showed lower than required biodegradation rates
SPE/IADC 103967
using the Seawater Test Method, and a chemical “tweak” was
made to this product composition to improve biodegradability
without sacrificing optimum performance. The net result of
these changes was to provide a North Sea optimized fluid
formulation that meets all the environmental demands of this
operating area. Similar requirements are set for operations in
East Coast Canada, Australia, New Zealand and Vietnam.
For land drilling applications, initial environmental
evaluation was carried out according to the Canadian
Microtox testing protocol, which evaluates the effect of the
system components on the growth of bacteria. All of the
system components were tested and deemed to be acceptable
for use and discharge to land at their normal operating
concentrations with the exception of the fluid-loss controller
and the accretion suppressant. Chemical redesign of the fluid
loss controller has resulted in a material which passes the
Microtox test. A reformulated accretion suppressant that meets
the Microtox test criteria is still under development.
Other test criteria taken into consideration foro use and
discharge on land are electrical conductivity and seed
germination studies. In the former case the ability to provide
an effective shale inhibitive fluid in a base of freshwater
(without requirement for use of highly conductive salts of
potassium, calcium or aluminum) and the utilization of
additives that have a low residual conductivity has allowed the
new HPWBM, and solids contaminated with this fluid, to meet
electrical conductivity requirements without resorting to
dilution or treatment of effluent/solids. Seed germination
studies (on bean sprouts) have been carried out comparing
germination rates in agricultural soil vs. germination rates in
the same soil contaminated with up to 20% of the new
HPWBM. These results show no reduction in either seed
germination quantity or in seedling elongation over a 72-hour
period by contamination of the soil with the new HPWBM. At
a 10% contamination level, the seed elongation test showed an
average improvement in the contaminated soil when compared
to the baseline.
When using the new HPWBM in the field, engineering
principles and procedures can be applied to the system to
ensure further protection to the environment over and above
those applied to more conventional inhibitive water-based
fluids. The chemical composition, high inhibitive performance
and tolerance to drill solids of the new HPWBM allow
engineering recyclability to be practiced.
Dewatering. Use of a custom developed deflocculation
chemistry package applied to a solids-laden HPWBM fluid,
allows the recycling of “base brine” that can be used as
dilution fluid for the existing circulating system, or can be
used as the base for building a new fluid system. Typically
carried out in land drilling operations, the dewatering process
recovers approximately 60 – 70% of the measured hydration
suppressant and 50 – 60% of the measured accretion
suppressant along with a solids-free base fluid. In low-density
fluids, this process can translate to a reduction in fluid and
chemical discharges of up to 50% as compared to more
conventional water-based fluids.
Storage and Reuse. By maintaining the new HPWBM
within programmed parameters (good solids control and
optimized dilution treatment) throughout a well, the new
HPWBM can be stored, reconditioned (if required) and reused
SPE 103967
on a subsequent well. This is possible because of the longterm stability of the system chemistry and the highly inhibitive
and solids-tolerant nature of the system. With effective
reconditioning and reuse principles applied, the new HPWBM
can allow a reduction in chemical discharges of up to 60% as
compared to more conventional water-based fluids.
Engineering Guidelines
Prior to the initial field trials of the new HPWBM, a series of
operational engineering guidelines, and some specific system
engineering tests, were developed to ensure the most optimum
control could be maintained over the drilling fluid at the
rigsite, and that optimized drilling performance could then be
obtained through use of the fluid. Over the course of the initial
field trials, and with usage of the system in a number of highly
complex drilling scenarios, these guidelines have been
modified to again allow for the best performance to be
achieved whilst utilizing this fluid system. These operational
guidelines can be summarized in the following points:
Rheology. Rheological parameters are controlled to meet
the requirements of a pre-determined hydraulics plan that is
designed to optimize hole cleaning and minimize ECD effects,
whilst maximizing pressure drop across the drill bit.
Hydraulics calculations are run throughout drilling of the well
and parameters adjusted accordingly to maintain optimization.
It is critical to adhere to optimized hole cleaning guidelines
(controlled rate of penetration, drill pipe rotation, circulation
time, tripping procedures) as the gauge hole and high cuttingsgeneration rate can rapidly lead to wellbore cleaning
problems.
MBT/Drill Solids. Although the new HPWBM will
tolerate high levels of drill solids contamination, in order to
maintain optimum drilling performance (hydraulics and
filtration) it is essential to maintain a good control over drill
solids content. This is achieved primarily by use of good
solids-control equipment (fine shale-shaker screens) coupled
with controlled dilution when necessary. The actual levels of
drill solids that are acceptable to maintain optimum properties
will be a function of the drilling fluid density. A chart
outlining these guidelines for solids contents and MBT is
shown as Figure 12.
Hydration Inhibitor Concentration. Typically the
volume of the hydration inhibitor is 3% and maintained
throughout drilling, with an expected 5-15% concentration
depletion possible depending on area, shale type, and drilling
parameters. The concentration of the hydration suppressant is
measured directly in the drilling fluid via a developed filtrate
titration test, allowing optimum control to be maintained.
Maintenance should be done via concentrated whole mud
premix when maintaining system volume during the drilling
process, however direct additions of the hydration suppressant
can be made without detrimental effect on system properties.
After gaining experience with the formations in an area, it may
be possible to maintain the concentration at a lower level (not
below 2% or a detrimental performance is observed) to
optimize economics. Observation of softer cuttings at the shale
shaker is an indicator of too low levels of hydration
suppressant.
Dispersion Suppressant Concentration. Typically 2
lbm/bbl of the dispersion suppressant is maintained throughout
5
drilling, with an expected 10-25% concentration depletion
being seen depending on area, shale type, and drilling
parameters. The concentration of the dispersion suppressant is
measured directly in the drilling fluid via a developed
hydrolysis/back titration test on whole fluid allowing optimum
control to be maintained. Maintenance should be done via
concentrated whole mud premix when maintaining system
volume during the drilling process, however direct additions
of the dispersion suppressant can be made without detrimental
effect on system properties. Observation of sticky, dull
cuttings at the shale shaker is an indicator of too low levels of
dispersion suppressant.
Accretion Suppressant Concentration. Typically 2%
by volume of the accretion suppressant is maintained
throughout drilling, with little depletion being seen. The
concentration of the accretion suppressant is measured directly
in the drilling fluid via a developed retort analysis test on
whole fluid allowing optimum control to be maintained.
Maintenance should be done via concentrated whole mud
premix when maintaining system volume during the drilling
process, however direct additions of the accretion suppressant
can be made without detrimental effect on system properties.
After gaining experience with the formations in an area, it may
be possible to maintain the concentration at a lower level (not
below 1% or a detrimental performance is observed) to
optimize economics Observation of whole cuttings that easily
adhere to each other at the shale shaker is an indicator of too
low levels of accretion suppressant. In certain areas, and at
higher fluid densities, concentrations of up to 3% by volume
may be required for optimum drilling performance.
Field Usage
The HPWBM described above was first operationally
introduced for field trials in late 2001, in the deepwater arena
of the Gulf of Mexico. Since these initial trials, the fluid has
been utilized on over four hundred wells on a global basis. In
over 50% of the applications, the HPWBM initial selection
has been on the basis of replacing either existing or planned
usage of invert emulsion fluids. A generalized breakdown of
the applications of the new HPWBM fluid by well type, and
by well geographic locations, is shown in Figures 13a and
13b.
The unique performance of the new HPWBM has led to
its consistent usage in a variety of difficult drilling situations.
Some of the highlights of its usage are:
• Deepwater record: 9,472 ft water depth, offshore
Brazil
• Maximum mud weight: 17.2 lbm/gal, Wyoming US
• Maximum angle built: >90o, United Arab Emirates;
Brazil
• Maximum number of intervals in one well: five (20,
17, 14.5, 12.25, 8.5-in.), Gulf of Mexico
• Longest interval: 9,384 ft, South China Onshore
• Longest directional interval: 8900 ft of 17½-in, 65°
angle, North Sea
Benchmarks against diesel, mineral oil and syntheticbased invert emulsion fluids as well as other water-based
fluids have been conduced, evaluating the drilling
performance, environmental performance and economic
6
performance of the new HPWBM in the field. In all of the
areas used, the new HPWBM has proven itself to far exceed
the performance of other inhibitive water-based fluids in terms
of improved wellbore stability, improved drilling performance
(ROP), ease of maintenance of fluid properties, lower dilution
rates and improved economics of the drilling operation. In
addition the new HPWBM has proven in many cases to show
equivalent drilling performance to invert emulsion fluids with
respect to wellbore stability and drilling rates. (Figure 14a-b).
The enhanced shale inhibition characteristics and low risk
of accretion seen from the new HPWBM has allowed the use
of high performance PDC drill bits to achieve optimal drilling
rates even through some extremely reactive shale formations,
while the gauge wellbore that characterized drilling with this
new HPWBM has ensured ease of directional control
maintenance. The use of the new HPWBM has been
characterized by large, well-defined, cuttings (Figure 15a-b)
readily removed by the primary solids-control equipment on
the first pass, ensuring that the fluid does not become rapidly
contaminated by drill solids, and that dilution rates to maintain
drilling fluid parameters is low. Also characteristic has been
clean bits and bottomhole assemblies (Figure 16a-b)
recovered from drilling with the new HPWBM in areas where
bit and BHA balling has been the norm with other inhibitive
water-based fluids.
Conclusions
The HPWBM developed and described in this paper is unique
in its design with a total-system approach. The fluid system
contains products specifically chosen to be synergistic and to
satisfy all of the requirements of a high-performance drilling
fluid. Unlike previously developed and used inhibitive waterbased fluids, the new HPWBM is extremely flexible in its
design and easy to engineer and control under various
conditions.
Laboratory tests indicated that the system could be
successfully formulated with a variety of base brines (from
freshwater to saturated salt) and at densities ranging from 8.6
to 16 lbm/gal. This has been borne out by field application
where fluids based on freshwater, seawater, NaCl and KCl
have been used, and fluid densities of up to 17.2 lbm/gal have
been utilized.
The environmental characteristics of the new HPWBM
have been designed to meet and exceed the environmental
requirements for use and discharge of such drilling fluids on a
global basis. This has been borne out by the acceptability of
the fluid to the regulators in each country where it has been
used. Significant additional environmental benefits from the
new HPWBM have been realized by applying recycling
techniques suited to the system design.
Development and application of field testing procedures
to measure actual product concentrations and implementation
of sound engineering guidelines have aided in ensuring that
the performance of the new HPWBM is maintained at an
optimal level.
The extensive field usage of the new HPWBM has
demonstrated that the fluid can be easily prepared, has good
screen-ability through fine shaker screens and has outstanding
drilling performance. The use of this fluid to drill numerous
highly reactive shale formations gas confirmed the laboratory
SPE/IADC 103967
predictions for cuttings integrity and wellbore stability.
Performance and flexibility are two attributes that bring this
drilling fluid closer to an invert emulsion based drilling fluid
than any other.
Acknowledgements
The authors wish to thank Mary Dimataris for her help
with the manuscript and M-I SWACO for permission to publish
this paper.
References
1. Downs, J.D., van Oort, E., Redman, D.I., Ripley, D. and
Rothmann, B.: “TAME: A New Concept in Water-Based
Drilling Fluids for Shales,” SPE 26699, Offshore Europe
Conference, Aberdeen, Sept 7-10, 1993.
2. Simpson, J.P., Walker, T.O., and Jiang, G.Z.: “Environmentally
Acceptable Water-Base Mud Can Prevent Shale Hydration and
Maintain Borehole Stability,” SPE 27496, SPE/IADE Drilling
Conference, Dallas, Feb 15-18, 1994.
3. Chenevert, M.E.: “Shale Alteration by Water Absorption,”
Journal of Petroleum Technology (Sept 1970) 1141.
4. Young, S. and Maas, T. “Novel Polymer Chemistry Increases
Shale Stability” AADE 01-NC-HO-41, AADE National Drilling
Conference, Houston, Mar 27-29, 2001.
5. Patel, A., Stamatakis, E., Friedheim, J.E. and Davis, E.:
“Highly Inhibitive Water-Based Fluid System Provides Superior
Chemical Stabilization of Reactive Shale Formations” AADE
01-NC-HO-55, AADE National Drilling Conference, Houston,
Mar 27-29, 2001.
6. Retz, J.R., Friedheim, J., Lee, L.J., and Welch, O.O.: “An
Environmentally Acceptable and Field-Practical Cationic
Polymer Mud System,” SPE 23064, Offshore Europe
Conference, Aberdeen, Sept 3-6, 1991.
7. Stamatakis, E., Thaemlitz, C.J., Coffin, G. and Reid, W.: “A
New Generation of Shale Inhibitors for Water-Based Muds,”
SPE 29406, SPE/IADC Drilling Conference, Amsterdam, Feb
28 – Mar 2, 1995.
8. Clark, R.K., Scheuerman, R.F., Rath, H. and Van Laar, H.G.:
“Polyacrylamide/Potassium Chloride Muds for Drilling WaterSensitive Shales,” Journal of Petroleum Technology (June
1976) 719.
9. Schlemmer, R., Patel, A., Friedheim, J., Young, S. and Bloys,
B.: ”Progression of Water-Based Fluids Based on Amine
Chemistry – Can the Road Lead to True Oil Mud
Replacements?” AADE-03-NTCE-36, AADE National Drilling
Technology Conference, Houston, April 1-3, 2003.
10. Young, S., Patel, A., Stamatakis, E., Cliffe, S.: Designing for the
Future – A Review of the Design, Development and Testing of a
Novel, Inhibitive Water-Based Drilling Fluid. AADE-02-60,
AADE National Drilling Technology Conference, Houston,
April 2-3, 2002.
SPE/IADC 103967
7
Table 3
Mysidopsis bahia Test Results
Test Substance/concentration
EC50, ppm SPP
Dispersion suppressant *(3% Vol)
>300,000
Hydration suppressant *(3 lbm/bbl)
>500,000
Accretion suppressant * (3% Vol)
248,000
Polymer viscosifier * (2 lbm/bbl)
>500,000
Fluid loss controller * (5 lbm/bbl)
>500,000
Seawater HPWBM
268,000
Seawater HPWBM (a)
>300,000
20% NaCl HPWBM
249,000
20% NaCl HPWBM (a)
>300,000
Field HPWBM (b)
219,000
Table 1a
Typical Composition of HPWBM (20% NaCl)
Seawater
(mL)
293.0
NaCl
(g)
80.4
Filtration controller
(g)
4.0
Polymer viscosifier
(g)
0.8
Dispersion suppressant (g)
2.0
Hydration suppressant (g)
10.5
Accretion suppressant
(g)
7.5
Table 1b
Typical Composition of Silicate Mud
Freshwater
(mL)
290.0
Sodium silicate
(mL)
42.0
Soda ash
(g)
0.5
KCl
(g)
30.0
Fluid loss agent
(g)
5.0
Polymer viscosifier
(g)
1.0
Acceptable internal limits are >100,000 ppm SPP.
* Tested in Generic mud #7.
# Each fluid contained 3% vol hydration suppressant, 2-lbm/bbl
cispersion suppressant, and 2% vol accretion suppressant. Weighed
to 12.0 lbm/gal with barite.
(a) Contained 30-lbm/bbl OCMA clay
(b) 20% NaCl-based Field mud after drilling Gulf of Mexico
deepwater well
Table 1c
Typical Composition of NaCl/Polymer Mud
Freshwater
(mL)
323.0
NaCl
(g)
73.2
NaOH
(g)
0.5
Bentonite
(g)
5.0
Fluid loss agent
(g)
3.0
PHPA
(g)
1.0
Polymer viscosifier
(g)
0.5
Table 1d
Typical Composition of Oil Based Mud
Mineral oil
(mL)
255.0
Primary emulsifier
(mL)
10.0
Secondary emulsifier (mL)
2.0
Lime
(g)
7.5
Polymer fluid loss agent (g)
2.0
Organoclay viscosifier (g)
6.0
25% CaCl2 Brine
(mL)
75.0
120
Cuttings Recovery (%)
100
80
60
40
20
Oxford
Foss Eikeland
0
0
Shale type
Arne
0.01
0.02
0.03
Material concentration
Fig. 1 – Inhibition performance of hydration suppressant by hotroll dispersion testing.
350
#1 - Gulf of Mexico deepwater well
#2 - South China Sea shelf well
#3 - Western USA land well
0
300
1%
2%
250
Torque (ftlbs)
Table 2
Typical Field Composition of HPWBM
Product / formulation #
#1
#2
#3
Freshwater
320
Seawater
(mL)
290
315
NaCl
80
KCl
(g)
20
Filtration controller
(g)
3
4
3
Polymer viscosifier
(g)
1.25
1
1.25
Dispersion suppressant (g)
2
2
2
Hydration suppressant (g)
10
8
10
Accretion suppressant (g)
8
6
3%
200
Shale
150
100
50
0
5
6
7
8
9
10
11
12
13
14
15
Num ber of turns
Fig. 2 – Inhibitive performance of hydration suppressant by bulk
hardness method (Oxford Clay).
8
SPE/IADC 103967
Raw Bentonite
120
120
100
Seaw ater
Percentage shale recovery
Linear expansion (%)
Oxford Clay
Foss Eikeland
100
80
3% Hydration
Suppressant
60
40
20
Arne Clay
80
60
40
20
0
12
0
11
0
90
Tim e (Minutes)
10
0
80
70
60
50
40
30
20
2
10
0
0
Fig. 3 – Inhibitive performance of hydration suppressant by linear
swelling test. (Nahr Umhr shale).
OBM
NaCl/Polym er
KCl/Silicate
HPWBM
Fig. 6 – Comparative shale inhibition by slake durability testing.
350
300
50
Torque (ftlbs)
Cuttings Recovery (%)
60
40
30
20
10
Oxford
250
200
OBM
150
NaCl/Polym er
100
KCl/Silicate
HPWBM
50
Shale
Foss Eikeland
0
0
1 lbm /bbl
Shale type
Arne
2 lbm /bbl
0
5
6
7
8
3 lbm /bbl
9
10
11
12
13
14
15
Number Of Turns
Material concentration
Fig. 4 – Inhibitive performance of dispersion suppressant by
slake durability testing
Fig. 7a – Comparative shale hardness testing (raw bentonite).
350
OBM
60
300
50
250
Torque (ftlbs)
% cuttings accreted
70
40
30
20
10
NaCl/Polym er
KCl/Silicate
HPWBM
Shale
200
150
100
Arne
Foss Eikeland
0
0
0.01
Oxford
0.02
Shale type
0.03
Material concentration
Fig. 5 – Performance of accretion suppressant by rolling bar test.
50
0
5
6
7
8
9
10
11
Num ber of Turns
12
13
14
15
Fig. 7b – Comparative shale hardness testing (Foss Eikeland
Clay).
SPE/IADC 103967
9
350
0.4
250 ftlbs
0.35
400 ftlbs
OBM
NaCl/Polym er
300
Torque (ftlbs)
250
Coefficient Of Friction
KCl/Silicate
HPWBM
Shale
200
150
100
0.3
0.25
0.2
0.15
0.1
0.05
50
0
0
OBM
5
6
7
8
9
10
11
Num ber of Turns
12
13
14
KCl/Silicate
HPWBM
Fig. 9 – Comparative lubricity 12.0-lbm/bbl fluids by Fann
metal/metal tester.
Fig. 7c – Comparative shale hardness testing (Oxford Clay).
100
350
OBM
NaCl/Polym er
300
KCl/Silicate
250
HPWBM
YP (lbs/100ft2)
Torque (ftlbs)
NaCl/Polym er
15
Shale
200
150
100
90
OBM
80
NaCl/Polym er
70
KCl/Silicate
60
HPWBM
50
40
30
20
50
10
0
0
5
6
7
8
9
10
11
Num ber of Turns
12
13
14
15
Fig. 7d – Comparative shale hardness testing (Arne Clay).
0
50
100
150
200
ppb OCMA clay added
250
300
Fig. 10 – Comparative solids tolerance by YP after aging at 200F,
16 hr.
Seawater
10% KCl
60
20% NaCl
100
Raw Bentonite
Percentage Shale accretion
Foss Eikeland
Arne Clay
40
30
20
Shale Recovery (%)
Oxford Clay
50
90
80
70
60
50
40
30
20
10
10
0
0
OBM
NaCl/Polym er
KCl/Silicate
HPWBM
Fig. 8 – Comparative shale accretion potential by rolling bar
testing.
Raw Bentonite
Oxford Clay
Foss Eikeland
Arne Clay
Fig. 11 – Shale inhibition of HPWBM formulated in differing base
brines.
10
SPE/IADC 103967
18
8
9
10
11
12
13
14
15
16
17
18
Mud Weight (lbm/gal)
SBM
SBM
2
SBM
0
SBM
4
1
0.5
SBM
6
SBM
8
2
1.5
SBM
10
3
2.5
SBM
12
HPWBM
14
3.5
HPWBM
MBT lbm/bbl
Drill Solids % vol
Days per 1,000ft BML
MBT (lbm/bbl), drill solids (%)
4
16
Fluid type used
Fig. 12 – HPWBM engineering guidelines - drill solids and MBT
content vs. mud weight.
Fig. 14a – Drilling performance comparison for offset wells in
deepwater Gulf of Mexico.
80
Max ROP
70
Min ROP
ROP (ft/hr)
60
50
40
30
20
Shelf wells
SBM
SBM
Deepwater Wells
NaCl/Polymer
Land Wells
SBM
0
HPWBM
10
Fluid system used
Fig. 13a – Usage of HPWBM by well type.
Fig. 14b – Drilling performance comparison for deepwater Gulf of
Mexico offset wells (16-in. hole section).
North America
South America
Europe/CIS
Africa
Middle East
Far East
Fig. 13b – Usage of HPWBM by geographic area.
Fig. 15a – PDC generated cuttings from drilling 12¼-in. hole
section in Vietnam with HPWBM.
SPE/IADC 103967
Fig. 15b – PDC generated cuttings from drilling 17½-in. hole
section in Gulf of Mexico with HPWBM.
Fig. 16a – Clean bottom hole assembly pulled after drilling
reactive clay secion in Gulf of Mexico with HPWBM.
11
Fig. 16b – Clean underreamer assembly pulled after drilling
reactive clay secion in Gulf of Mexico with HPWBM.