Developing a High-Performance,
Oil-Base Fluid for Exploration Drilling
Conventional drilling fluids may interfere with formation evaluation. The base fluids,
emulsifiers and other additives infiltrate rock, cores and fluid samples, creating
inaccuracies in subsequent log and fluid analyses. A new drilling fluid system has
been developed to ensure the quality of information obtained from well logs and
formation sampling.
Irene M. Færgestad
M-I SWACO
Sandnes, Norway
Cameron R. Strachan
Statoil
Stavanger, Norway
Oilfield Review Spring 2014: 26, no. 1.
Copyright © 2014 Schlumberger.
For help in preparation of this article, thanks to Beathe
Pettersen and Russell Watson, Sandnes, Norway; and
Artur Stankiewicz, Clamart, France.
MDT is a mark of Schlumberger.
Fann is a registered trademark of Fann Instrument
Company.
Rock-Eval is a registered trademark of the Institut Français
du Pétrole.
Teflon is a registered trademark of E.I. du Pont de Nemours
and Company.
Viton is a registered trademark of DuPont Performance
Elastomers LLC.
26
Operators drill exploration wells primarily to
obtain information about the lithology, structure
and fluid content of the rocks that define a prospect. Often, the drilling process is driven by competing interests. Whereas the objective of the
drilling team is to drill the well safely and within
time and cost constraints, the focus of the petrophysicist, geologist and reservoir engineer is to
acquire accurate logging measurements and representative fluid and rock samples.
To achieve drilling objectives, operators
require a drilling fluid that meets both cost-efficient technical performance and environmental
standards. High-pressure, high-temperature (HPHT)
environments, which may significantly affect
drilling fluid performance, are especially challenging.1 From a driller’s perspective, oil-base
drilling fluids generally outperform water-base
fluids in HPHT conditions. Compared with most
water-base fluids, oil-base fluids exhibit better
viscosity stability, thermal tolerance and shale
inhibition properties, making them the preferred
solution for HPHT drilling.2
However, drilling fluids that satisfy the needs
of the drilling team may create problems for petrophysicists and engineers. For example, the
three primary technologies for characterizing reservoir pressure are well testing, wireline formation testing and formation pressure while drilling.
These methods rely on measurements at the wellbore wall and may therefore be influenced by the
drilling fluid. Filtrate from drilling fluids can
invade rock pores and mix with reservoir fluids; as
a result, formation and fluid evaluation may not
reflect actual reservoir conditions.3
Thick filtercakes and fluid invasion into the
reservoir rock can adversely impact fluid and rock
samples and disturb hydrocarbon shows, complicating phase behavior studies and some geochemical analyses and interpretations of reservoir
fluids.4 To make certain that fluid samples are
suited for geochemical analyses, engineers must
ensure that formation fluid samples and rock cuttings exhibit minimal presence of the drilling fluid.
For optimal laboratory analysis of reservoir rock
and fluid samples, the drilling fluid should have a
composition that is dissimilar to that of the
expected reservoir fluid. Infiltrated drilling fluid
can then be identified and its effects may be filtered out during data analysis. In particular, the
drilling fluid should have the following properties:
• No or low light hydrocarbon fractions (components C1 to nC10). Invasion of light hydrocarbon
fractions from the drilling fluid into the core
may cause problems when analysts attempt to
determine the original fluid saturations within
a reservoir rock. Most natural hydrocarbon
fluids contain 50% to 97% light hydrocarbons.
Therefore, light hydrocarbon originating from a
drilling fluid can mask light hydrocarbon occurring in the reservoir fluid. This may affect geochemical analyses of C7 components or saturate
and aromatic fractions of bulk petroleum in
such analyses as the SARA method.5
• No or low quantities of n-alkanes (nC15 to nC35).
The n-alkanes in drilling fluids may mask the
n-alkane fingerprints from in situ hydrocarbons, affecting interpretations of the whole-oil
gas chromatography (GC) and gas chromatography–mass spectrometry (GCMS) results.
Oilfield Review
• No or low concentration of biomarkers (terpanes and stearanes). Biomarkers are molecular remnants of biochemicals from organisms
and can be measured in both oil and source
rock. Biomarkers have unique fingerprints that
provide information about the age, lithology,
organic content, depositional environment and
thermal maturity of the source rock and degree
of oil degradation. Accurate biomarker analysis
can provide important information on microbial degradation and on maturity of rocks and
oil. A high biomarker concentration in the drilling fluid may negatively affect analysis of any
fluids—especially condensates, which traditionally have low biomarker concentrations—
by masking readings from the GCMS.
• No or low concentrations of aromatic hydrocarbons, which are commonly used for assessing
molecular maturity values. High concentrations
of aromatic hydrocarbon in the drilling fluid
can affect maturity assessments of the reservoir and strongly influence geochemical fingerprinting when taken using GC.6
To enable efficient and successful drilling,
most conventional drilling fluids are formulated
to have a stable viscosity, low fluid loss, low
equivalent circulating density (ECD) and minimal barite settling, or sag. Stable viscosity provides optimal cuttings transport and minimal
effects on pump pressure. Keeping fluid loss low
prevents formation damage and reduction in
wellbore productivity. Low ECD helps maintain
bottomhole pressures to avoid the fracturing or
collapse of wellbore walls. Barite, a common
drilling fluid weighting agent, may cause a phenomenon known as barite sag. Barite sag occurs
when the heavy barite particles settle to the
low side of the hole or the bottom of the well;
this phenomenon is most severe in high-angle
wells, especially those exceeding 45° deviation.
Barite sag may cause density variations in the
wellbore fluid column, potentially creating well
control issues.
This article describes the development of a
new drilling fluid designed to meet the require1. HPHT conditions defined by Norsk Sokkels
Konkurranseposisjon (NORSOK) standard D-010 are
wells with temperatures greater than 150°C [300°F] and
bottomhole pressures greater than 69 MPa [10,000 psi].
Other organizations may define HPHT differently.
2. In some cases, formate fluids, which are water based,
can perform as well as oil-base fluids.
3. Bennett B and Larter SR: “Polar Non-Hydrocarbon
Contaminants in Reservoir Core Extracts,” Geochemical
Transactions 1 (August 22, 2000), http://www.
geochemicaltransactions.com/content/1/1/34
(accessed April 23, 2014).
4. Filtercake, also known as mudcake, is the residue
deposited on a borehole wall at a permeable zone when
drilling fluid is forced against it under pressure. Filtrate is
Spring 2014
Fluid Specifications Set by Statoil
Property
Fann 35 dial reading at 600 rpm
Fann 35 dial reading at 100 rpm
Fann 35 dial reading at 3 rpm
HPHT fluid loss on 10-micron disk
Sag stability after 3 days
Sag stability after 5 days
Operator Specifications
for New HPHT Fluid
Average Values for
Previously Used Fluid
103 lbf/100 ft2
As low as possible
2
Less than 24 lbf/100 ft
2
33 lbf/100 ft2
12 lbf/100 ft2
5 to 10 lbf/ft
3
Less than 3 mL [0.2 in. ]
160 kg/m3 [1.3 lbm/galUS]
3
300 kg/m3 [2.5 lbm/galUS]
Less than 150 kg/m [1.2 lbm/galUS]
Less than 150 kg/m
10 to 12 mL [0.6 to 0.7 in.3]
3
> HPHT fluid specifications. The specifications for fluid properties set by Statoil were based on the
need for an improvement in performance compared with that of the drilling fluid previously in use in
similar fields offshore Norway. To conduct the HPHT test, engineers used a 10-micron disk, which best
represented the filtration capabilities of the formation rock to be drilled. To qualify for use, the new
HPHT fluid needed to meet all specifications. Dial readings from a Fann 35 viscometer were taken at a
fluid temperature of 50ºC [122ºF], and 30-minute HPHT fluid-loss tests were performed at a fluid
temperature of 150ºC [300°F].
ments for drilling, well logging and sampling.
Results from a field test offshore Norway demonstrate the minimal impact the new drilling fluid
has on formation rocks and fluid and, in turn, on
the majority of geochemical analyses.7
Development Criteria
In 2010, Statoil sought a new HPHT drilling fluid
that would not interfere with formation and fluid
evaluation and that would ensure good pressure
data for the Crux prospect, offshore Norway. Fluid
experts at Statoil had two objectives. The first was
to use an oil-base fluid that enables efficient and
safe drilling operations while causing minimal
impact on geochemical analyses of formation fluid
samples. The second was to qualify for use a more
reliable, low-ECD reservoir drill-in fluid (RDF)
with properties that would be stable in HPHT environments without additional cost.8 All qualification tests and analyses of drilling fluid properties,
formation damage and permeability were performed at the research laboratories of M-I SWACO,
a Schlumberger company, in Sandnes, Norway.
A set of first-use criteria was established by
Statoil in collaboration with M-I SWACO.9 Of
particular importance was the capacity to
5.
6.
7.
8.
the liquid that passes from the drilling fluid into the
formation, leaving the filtercake behind.
SARA stands for saturates, aromatics, resins and
asphaltenes and is a method that characterizes heavy
oils in the four solubility classes based on their molecular
weight species.
Bennett and Larter, reference 3.
Watson R, Johannesen J, Strachan C and Færgestad I:
“Development and Field Trial of a New Exploration HPHT
Reservoir Drill-In Fluid,” paper SPE 165099, presented at
the SPE European Formation Damage Conference and
Exhibition, Noordwijk, The Netherlands, June 5–7, 2013.
A reservoir drill-in fluid is designed exclusively for drilling
the reservoir section of a well. Qualification of fluids is a
Statoil internal procedure.
obtain high-purity formation fluid samples.
Additionally, the drilling fluid needed to be stable, have fluid properties that did not deviate
more than 10% from specifications and have the
lowest possible potential for analysis disturbance.10 No existing M-I SWACO drilling fluid
satisfied the strict Statoil requirements.
M-I SWACO research engineers began development of a high-performance HPHT exploration
drilling fluid by focusing on the specifications
provided by Statoil (above). Statoil drilling fluid
experts assessed the new fluid using a modified
qualification process that included laboratory
testing and optimizing to their specifications.
Measurements and Analyses
To measure critical characteristics, such as filtration volumes and permeability before and after
contact with the drilling fluid, M-I SWACO engineers performed return permeability tests on
core samples.11 Because of a limited availability
of representative reservoir core samples, initial
tests were performed on analogous outcrop core
material that was selected based on the type of
formation expected to be encountered in the exploration wells. Engineers used Berea sandstone
9. First-use criteria were set to evaluate the performance
of the new fluid.
10. Disturbance factors may be C15+ hydrocarbon fractions,
making data analysis more difficult by masking the
hydrocarbon content of formation fluid or rock samples.
11. Return permeability tests compare initial permeability to
that of the core sample after its exposure to drilling fluid
under simulated downhole conditions. Return
permeability is the ratio of a sample’s permeability after
exposure to drilling fluid to its initial permeability,
expressed as a percentage.
27
4.5 cm [1.77 in.]
3.84 cm
[1.5 in.]
> Filtrate invasion. After they finish a return permeability test on cores, engineers can often see filtrate
invasion if it has occurred. After 20 hours of an application of oil-base mud, this core exhibits filtrate
invasion to a shallow depth. Even though the filtrate invasion is fairly shallow (bottom, left of the yellow
dashed line), the 32% return permeability indicates that damage to the core is significant.
with permeabilities of 50 to 100 mD and Ohio sandstone with permeabilities of 1 to 10 mD (above).
Final tests were performed using reservoir core
material acquired from nearby production wells.12
Research engineers cleaned the sandstone
core plugs with solvent, trimmed and tested them
to determine base parameters such as grain density, porosity and permeability and then vacuum
> Mounted core holder. The core holder is typically mounted vertically in the
test equipment oven for return permeability measurements, with the formation
side of the core upward and wellbore side downward. Production simulations
are performed by flowing in the formation-to-wellbore direction (top to
bottom). Test fluids are applied to the wellbore end of the core plug.
28
saturated the cores with synthetic brine that was
formulated to match the fluid chemistry of the
Crux prospect. To obtain a consistent and representative saturation relatively quickly, engineers
used an ultracentrifuge to remove as much water
as possible, leaving the core plugs at irreducible
water saturation (next page, top right).13 The cores
were then mounted in a hydrostatic core holder.
To conduct the return permeability tests, engineers use a vertical core holder in which the core
is placed with the formation end of the core at the
top (next page, bottom right). A spacer ring at the
bottom, or wellbore end, of the core creates an
annulus with room for filtercake to build up during
the pressure overbalance, or drilling, period of the
test. Tubing carries fluid in and out of the annulus,
allowing flow of drilling fluid that might contain
small pieces of back-produced filtercake.14
Permeability is measured both with and without
the filtercake in place.
Engineers measure permeability at each
stage of the tests. After mounting the core holder
in the oven, they create conditions similar to the
downhole environment by applying confining
pressure and then increasing the temperature
(left). When the core reaches a stable pressure
and temperature, they measure permeability in
the core with mineral oil flowing from the top to
the bottom—from the formation into the wellbore. This permeability is designated ko1. Drilling
fluid is then pumped at overbalance pressure in
the opposite direction—wellbore to formation. A
high-precision fluid pump system applies constant pressure while engineers record the filtrate
loss into the core. After 20 hours, the overbalance
is reduced, and engineers begin simulated production in the core by allowing flow, or back production, from the formation end into the wellbore
end of the core.
At a stable back-production rate, the engineers measure the permeability in the production direction (ko2) at four low flow rates.15 These
four low flow rate measurements provide a statistically reliable permeability value. Engineers use
these permeability data to determine return permeability: the ratio of ko2 to ko1, expressed as a
percentage. High return permeability indicates
low impact of the drilling fluid on the formation.
After these permeability measurements are
completed, the core is cooled and depressurized.
Engineers remove the core from the core holder
and photograph and characterize it. They remove
any filtercake residues prior to remounting the
core into the holder. They then measure the permeability in the formation-to-wellbore direction
Oilfield Review
in the absence of filtercake to obtain ko3. Finally,
the core is prepared for post-test analysis to
determine the reason for any changes in permeability observed throughout the experiment.
Drilling fluid and its components, such as
emulsifiers, clays and fluid-loss agents, can
invade the rock, clog pores, mix with the native
reservoir fluids and compromise geochemical
analyses of cores and produced fluids.16 To map
the possible disrupting effects of the drilling fluids planned for use in a well, engineers perform
predrilling analyses:
• Total organic carbon (TOC) analysis and
Rock-Eval pyrolysis for characterization of sedimentary organic matter. TOC is a measure of
the organic richness of a rock, which gives a
semiquantitative measure of hydrocarbon
potential. TOC is reported as weight % organic
carbon. Rock-Eval pyrolysis assesses the quantity, quality, type and thermal maturity of whole
rock and kerogen samples.
• Deasphalting and group type separation. These
techniques are used to extract specific components such as asphaltenes and other compounds
from petroleum products; SARA analysis separates group types based on differences in solubility and polarity and is often performed as an
open column, low-pressure liquid chromatographic separation.
• Gas chromatography of whole oils. This method
fingerprints individual oil samples, thus enabling
scientists to determine essential oil composition. Whole-oil chromatograms display a collection of peaks of various size, all representing
components of crude oil that are affected by factors such as depositional environment and
lithology of the source rock, age of the oil and
processes within the reservoir. The components
making up the oil have differing size, chemical
composition and properties; hence, they will
12. The described test methodology is specific to this case.
13. Byrne MT, Spark ISC, Patey ITM and Twynam AJ: “A
Laboratory Drilling Mud Overbalance Formation Damage
Study Utilising Cryogenic SEM Techniques,” paper SPE
58738, presented at the SPE International Symposium on
Formation Damage Control, Lafayette, Louisiana, USA,
February 23–24, 2000.
14. The filtercake may break into pieces when drawdown
pressure is applied during back production. The tubes
need an inner diameter that is large enough to allow
these filtercake pieces to pass through along with the
drilling fluid.
15. A constant differential pressure is applied to the core,
and flow rate through the core is controlled by the
permeability of the core plug. As the core plug
permeability increases during drawdown, the flow rate
increases until it reaches a plateau. The permeability is
then measured.
16. Bennett and Larter, reference 3.
Spring 2014
> Core preparation. Engineers use a centrifuge to determine capillary
pressure curves and to prepare samples for return permeability tests.
A disassembled centrifuge core holder and a centrifuge rotor (right )
stand ready for the next test. This centrifuge can accommodate three
3.84-cm [1.51-in.] cores simultaneously.
Core holder cap,
formation end
Core holder
body
Formation end
Flow
direction
Core
Viton sleeve
Wellbore end
> Core holder setup. The core holder (right ) has
been disassembled to show its components. The
core is wrapped in Teflon coating (left, white),
and a Viton sleeve (black) is placed over the core
to protect the sides of the core from external
interference. The fluid flow is directed in and out
via the end faces of the core, from top to bottom;
thus, no fluid should enter or exit the core from
the core sides.
Spacer ring
Core holder cap,
wellbore end
29
Oseberg
East
Crimp field
Crux well
Brage
Oseberg
SWEDEN
Oseberg field
Tune
NORWAY
Bergen
Oslo
Stavanger
Oseberg South
DENMARK
> Fann 35 viscometer. The Fann Model 35 is a
direct indicating, coaxial cylinder rotational
viscometer. The outer cylinder rotates at known
velocities. The test fluid is held in the gap
between the cylinders. As the outer cylinder
rotates, the fluid viscosity creates torque on the
inner cylinder, known as the bob. The torque
registers as deflections of a precision spring.
Engineers read the spring deflections from the
display at the top of the viscometer; readings are
typically made at 600, 300, 100, 6 and 3 rpm.
exit the column with specific time differences,
creating peaks on the chromatogram. The height
of and areas under the peaks correlate with
concentration; therefore, their concentration
ratios can be used to describe unique characteristics—fingerprints—of reservoirs and fields. In
addition, the peaks allow analysts to identify
various compounds in the sample.
• GC with a flame ionization detector to determine the saturated hydrocarbon concentration
of extractable petroleum hydrocarbons. The
concentrations are determined by integrating
the area under the peaks on the chromatogram.
• GC with a mass spectrometer to identify biomarkers, diamondoids and aromatic hydrocarbons.17 Accurate biomarker analysis provides
important information on microbial degradation and maturity of rocks and oil. Diamondoids
in petroleum and sediment extracts have high
thermal stability and resist oil cracking.
Furthermore, diamondoids are generally more
stable than all other hydrocarbon classes in
geologic samples, which makes them more
resistant to alteration processes such as biodegradation and maturation. Because of these
30
>Crimp field. The Statoil Crux exploration well lies in the new Crimp play in the North Sea west of Bergen,
Norway. Crimp is an HPHT gas and condensate field that requires mud weights up to 1,900 kg/m3
[15.9 lbm/galUS] and has reservoir temperatures up to 155°C [311°F]. Development work has focused on
formulating an HPHT drilling fluid designed for reservoir temperatures of 150°C with a mud weight of
1,750 kg/m3 [14.6 lbm/galUS]. (Photograph by Harald Pettersen, copyright Statoil. Used with permission.)
properties, diamondoids have been used in
evaluating geochemistry of source rocks and
crude oils and in assessing biodegradation and
thermal maturity of high-maturity crude oil and
condensates. Aromatic hydrocarbons tend to
resist moderate to heavy biodegradation; therefore, they offer an excellent way of differentiating biodegraded and unbiodegraded oils.18
Special laboratory tests, such as rheology
measurements, HPHT fluid-loss tests and barite
settling tests, are designed to evaluate drilling
fluid viscosity, stability over time and filtration
properties, which are important factors in determining the overall performance of a drilling fluid
system. Using a Fann 35 viscometer, engineers
measured the rheological properties of the new
drilling fluid after mixing at 50°C [122°F], followed by hot rolling in an oven at 150°C
[300°F]—the expected bottomhole temperature—to create the effect of dynamic aging
(above left).19 After hot rolling, the engineers
remeasured the viscosity at 50°C and performed
HPHT filtration, also called fluid loss, of the hotrolled fluid. The HPHT filtration specifications
consisted of a test temperature of 150°C and collecting filtrate through a 10-micron ceramic disk
for 30 minutes.
The barite settling test, known as a sag test, is
performed by transferring 350 mL [21 in.3] of fluid
to a 400-mL [24-in.3] steel cell to static age samples at 150ºC for 16 hours, 3 days and 5 days.20 For
this test, technicians first separate the staticaged 350-mL drilling fluid sample in the aging
cell into six layers, making certain to not disturb
the fluid and to keep the cell vertical at all
times.21 They then transfer the six layers to individual containers. The first layer consists of any
separated, clear fluid on top of the drilling fluid;
layers two to six, all of the same volume, contain
drilling fluid of increasing mud weight. They
then record the volume of separated fluid and
weigh the other layers to find the mud weight. To
calculate the barite sag, or the change in mud
weight with depth in the cell, the initial mud
weight is subtracted from the mud weight of the
bottom layer.
Connecting the Dots
In addition to the qualification work done by
M-I SWACO staff, Statoil engineers performed
predrilling and company specific qualifying tests
and analyses at their laboratory in Sandnes.
Continual communication and results sharing
throughout the development of the new fluid system ensured that the testing progressed as
planned. The results showed that the final formulated drilling fluid passed all criteria set by
Statoil for a fluid for use in an exploration well at
the Crux prospect under the Oseberg field west of
Bergen, Norway (above right).
Results from the formation damage tests
yielded calculated return permeability varying
Oilfield Review
Return Permeability Values for Four Tests
Fluid Density,
kg/m3 [lbm/galUS]
Sandstone
Core Material
Test Temperature,
°C [°F]
Fluid Loss,
mL [in.3]
ko1,
mD
ko2,
mD
Calculated Return
Permeability, %
ko2/ko1 × 100
ko3,
mD
Calculated Return
Permeability, %
ko3/ko1 × 100
1,850 [15.4]
Berea
135 [275]
7.5 [0.46]
69.50
56.50
81
56.70
82
1,850 [15.4]
Crude oil–aged Berea
135 [275]
7.1 [0.43]
55.50
50.70
91
50.60
91
1,750 [14.6]
Ohio
150 [300]
6.9 [0.42]
1.55
1.21
78
1.21
78
2,020 [16.9]
Ohio
188 [370]
8.2 [0.50]
2.07
1.37
66
1.37
66
> Return permeability tests. Scientists performed two return permeability tests on high-permeability Berea sandstone cores and two on low-permeability
Ohio sandstone cores. Return permeability was measured both with and without the filtercake in place. The new HPHT drilling fluid (green) was tested on
an Ohio core at 150°C, yielding a return permeability of 78%, both with and without the filtercake. The initial permeability is designated ko1; permeabilities
after back production with intact filtercake and without filtercake are designated ko 2 and ko 3, respectively.
from 66% to 91% (above).22 The new drilling fluid
used in the exploration well gave results of 78%
return permeability, which Statoil considered a
good result.
Filtrate volumes recorded during the return
permeability testing were acceptable. Filtercakes
were thin in all experiments and did not stick to
the wellbore face of the core plugs when engineers
removed them from the core holder after tests
(below).23 Permeability measurements changed
little with or without filtercake, indicating that the
filtercake had undergone “lift off” or “pop off” during back production. These terms describe how
the filtercake separates from the formation surface at a given differential pressure; the pressure
causes the filtercake to burst or break and come
off in pieces or sheets. That the filtercake comes
off easily indicates good drilling fluid performance
and allows a logging tool rapid access to the pressurized formation fluids.24
Backscatter scanning electron microscopy of
the wellbore end of the Berea core plug showed
that directly behind the filtercake, pores of the
rock were open and no drilling fluid components
were present, demonstrating that the filtercake
served to protect the porous formation from the
drilling fluid (right).
0.5 cm
[0.2 in.]
3.2 cm [1.3 in.]
> Filtercake from a return permeability test. The
filtercake produced by the new HPHT drilling
fluid after the return permeability test is 0.5 cm
thick and has a 3.2-cm diameter. The surface
adjacent to the core plug is on the top, and the
filtercake is intact, confirming that no filtercake
has come off during simulated production.
Spring 2014
0 μm
100 μm
200 μm
300 μm
> Filtercake protection. A backscatter scanning electron micrograph of the wellbore end of an outcrop
core taken after return permeability testing with the new HPHT drilling fluid shows drilling fluid solids
(white) only on the wellbore face of the plug. The image shows no traces of deep fluid invasion into the
core. The dense drilling fluid filtercake remnants appear as the bright area at the top of the image.
17. The mass spectrometer is placed downstream from the
gas chromatograph. After molecules elute from the gas
chromatograph at specific retention times, the mass
spectrometer captures, ionizes, accelerates, deflects
and detects the ionized molecules one by one. The
molecules have been broken down into ionized
fragments, and the mass spectrometer detects these
fragments by identifying their mass-to-charge ratio.
The preparative and analytical methods used are based
on guidelines from the Norwegian Industry Guide to
Organic Geochemical Analysis. For more: NIGOGA
Edition 4.0 (May 30, 2000), http://www.npd.no/engelsk/
nigoga/default.htm (accessed February 14, 2014).
18. Wenger LM, Davis CL and Isaksen GH: “Multiple
Controls on Petroleum Biodegradation and Impact on Oil
Quality,” SPE Reservoir Evaluation & Engineering 5, no. 5
(October 2002): 375–383.
19. Hot rolling, also known as dynamic aging, is a procedure
in which the 350-mL [21-in.3] fluid sample is transferred
to a 400-mL [24-in.3] steel cell and put in an oven
equipped with rollers. The cells roll in the oven for a
specific amount of time at a specific temperature. Hot
rolling simulates the wear of the drilling fluid under
downhole conditions. Normal aging time is 16 hours.
20. Barite settling, or sag, testing is performed on static
aged samples. In static aging, the samples are arranged
vertically in an oven, where they are left standing for a
given period of time to simulate static conditions
in a well.
21. The static aged fluid will gel and exhibit a specific shear
strength. If the sample is stirred, the shear strength will
be dramatically reduced, the layers that are to be
measured will be mixed together, and the resulting barite
settling values will be incorrect. Therefore, for accurate
results, the cell must remain vertical at all times.
22. For more details on the test results: Viste P, Watson RB
and Nelson AC: “The Influence of Wettability on Return
Permeability,” paper SPE 165160, presented at the SPE
European Formation Damage Conference and Exhibition,
Noordwijk, The Netherlands, June 5–7, 2013.
23. Whether the volume of filtrate is acceptable depends on
client specifications. Normally, a filtrate volume of less
than 10 mL [0.6 in.3] is considered acceptable. Filtercakes
should have a thickness of less than 1 cm [0.4 in.].
24. Byrne M and Patey I: “Formation Damage Laboratory
Testing—A Discussion of Key Parameters, Pitfalls and
Potential,” paper SPE 82250, presented at the SPE
European Formation Damage Conference, The Hague,
The Netherlands, May 13–14, 2003.
31
Effect of Base Fluids and New HPHT Drilling Fluid on Geochemical Analyses
Sample
Pyrolysis and TOC
Extraction and
SARA
Whole Oil
Less Than C20
Saturates C10+
Biomarkers
Diamondoids
Aromatics
Base fluid 1
Severe
Severe
Low
Low
Not tested
Low
Low
Base fluid 2
Severe
Severe
Severe
Severe
Not tested
Severe
Low
Base fluid 3
Severe
Severe
Medium
Medium
Not tested
Low
Low
Base fluid 4
Severe
Severe
Medium
Medium
Not tested
Severe
Low
Base fluid 5
Severe
Severe
Medium
Medium
Not tested
Severe
Low
New HPHT system
Low
Low
Not tested
Low
Not tested
Low
Medium
HPHT system after use in well
Medium
Severe
Not tested
Medium
Medium
Not tested
Low
> Statoil fluid sensitivity evaluation. A predrilling analysis table, provided by Statoil engineers, shows the sensitivity of geochemical analyses to five base
fluids and the new HPHT drilling fluid, all of which are oil-base samples. The sample of fresh mixed, or new, HPHT drilling fluid has a low impact on four of
the seven analysis methods, while the sample of used HPHT drilling fluid shows more impact on most of the analyses than does the new fluid. The used
sample may have been contaminated by another fluid system used to drill a shallower section. However, both the fresh mixed and the used samples of the
HPHT drilling fluid have less effect on the geochemical analyses than do the other five tested oil-base samples.
The Statoil predrill analyses of six base oils
and fluid systems demonstrated that the impact
of the new drilling fluid is low and acceptable on
most geochemical analyses (above). Whole-oil GC
performed on the new fluid showed that the samples had a fairly limited hydrocarbon range from
C10 to C14, with low concentrations of both biomarkers and aromatic hydrocarbons. Emulsifiers,
fluid-loss chemicals and viscosifiers may have
hampered the geochemical analyses.
Statoil tested unused predrill fluid, used drilling fluid, drill cuttings and formation fluids.
Results showed that fresh, unused fluid had a low
impact on all analyses, though engineers speculated that traces of diamondoids and aromatic
biomarkers may have affected the samples and,
in turn, the interpretation of geochemical data.
Used fluid from the exploration well had a
higher concentration of saturates, biomarkers
and C15+ n-alkanes. However, these components,
which are known to interfere with geochemical
testing, are believed to have originated from a
different drilling fluid used in the shallower
171/2-in. section.25 The new drilling fluid did not
appear to impact the formation fluid, but it may
have slightly affected the drill cuttings in the
case of very weak petroleum shows. The fluid
may also have affected GC data interpretation of
the n-alkane fraction and biomarkers (terpanes
and stearanes) in the case of low biomarker
concentration.
The field test confirmed that there was good
communication between the reservoir and the
logging tools. Engineers ran an MDT modular formation dynamics tester to take fluid samples and
pressures in the 121/4-in. section. They were able
to reduce the tool’s pump pressure for the new
drilling fluid compared with the pressure
Simulations and ECD Calculation, Prewell Test
Parameters
New HPHT Drilling
Fluid, Field Sample
Conventional Drilling
Fluid, Field Sample
Surface density measured at 50°C, kg/m3
1,690
1,690
Pump rate, L/min
2,000
2,000
Rate of penetration, m/h
Drillstring rotations in revolutions per min
Downhole mud weight, ESD, kg/m3
15
15
160
160
1,681
1,682
Pump pressure, bar [MPa]
269 [26.9]
319 [31.9]
ECD at casing shoe, kg/m3
1,755
1,786
ECD at total depth, kg/m3
1,762
1,795
> Simulation input parameters (green) and calculated downhole results (tan) for the new HPHT drilling
fluid and for a conventional oil-base drilling fluid. Simulations were performed before the well was
drilled as part of the planning and qualification of the new HPHT drilling fluid system. Based on the
simulations, the HPHT drilling fluid yields both lower pump pressure and an overall lower ECD
contribution than does the conventional drilling fluid. The lower ECD contribution was confirmed by
ECD measurements taken during the drilling operation. The term ESD, equivalent static density,
represents the actual mud weight of the drilling fluid in use. It varies with the temperature profile of
the well, but is, for simplicity, assumed to be the lowest average mud weight in the well during any
operation. ECD represents the sum of the ESD and the friction losses in the annulus caused by drilling
fluid motion.
32
required for the previously used paraffin-base
drilling fluid. The new drilling fluid also had
lower ECD at total depth (below).
The new HPHT drilling fluid successfully
achieved all viscosity, HPHT fluid-loss control and
barite sag stability specifications (next page,
bottom). After one and five days, barite sag measurements were 10 kg/m3 [0.08 lbm/galUS] and
60 kg/m3 [0.5 lbm/galUS], respectively, well
within the specification of barite sag of less than
150 kg/m3 [1.2 lbm/galUS]. HPHT fluid loss was less
than 2 mL [0.1 in.3]. The measured viscosity
was relatively low—providing room for viscosity
adjustment based on sag and fluid-loss performance if necessary—and changed little over
time, proving the stable properties of the new
fluid. Statoil engineers reported that the fluid
performed well during prolonged static periods,
such as riser disconnect situations and wireline
logging, and that the fluid had a performance
comparable with that of other low-ECD HPHT
fluids for ECD contribution, hole cleaning and
log responses.
The fluid stability quantified by laboratory
measurements was confirmed in the field test
(next page, top). The new HPHT fluid was used to
drill the 1,320-m [4,330-ft] 121/4-in. section and
the 624-m [2,047-ft] 81/2-in. section of the Crux
well. Fluid rheology remained within specifications throughout the entire operation and did not
deviate more than 10% from the specifications.
Mud losses did occur during the drilling of the
well; however, drilling engineers attributed the
losses to the slight uncertainties in the fracture
and pore pressure values and not to the drilling
fluid itself.
25. Drilling fluids may take in fluids and solids from shallower
formations drilled with a different mud system, which
may then affect the properties of fluids used to drill
deeper sections.
Oilfield Review
Rheology Measured During Operation
Property
Specification,
lbf/100 ft2
Fann 35 dial reading at 600 rpm
As low as possible
Fann 35 dial reading at 100 rpm
Less than 24
Fann 35 dial reading at 3 rpm
5 to 10
Average Value,
12 1/4-in. Section, lbf/100 ft2
47 ± 4.1
Average Value,
8 1/2-in. Section, lbf/100 ft2
63 ± 3.7
19 ± 2.5
20 ± 1.7
8 ± 1.5
7 ± 1.1
> Specifications and measurements of drilling fluid
rheology for 121/4-in. and 81/2-in. well sections. The fluid
rheology was measured continuously offshore
throughout the drilling operation, and all Fann 35 dial
readings were well within specifications during the
entire operation. The wellsite engineers reported that
the drilling fluid performance was stable and easily
maintained. M-I SWACO technical service engineers
supported the operation offshore to ensure that the
fluid stayed within specifications at all times.
(Photograph by Ole Jørgen Bratland, copyright Statoil.
Used with permission.)
HPHT Drilling Fluid Formation and Averaged Properties
Material
Mass Concentration, kg/m3
Base oil
402
Emulsifier
23
Organophilic clay
12
Lime
23
Fluid-loss additives
25
Calcium chloride powder
26
Freshwater
137
Weighting material (barite)
1,102
Total
1,750
Property
Mud weight, kg/m3 [lbm/galUS]
Value
1,750 [14.6]
Fann 35 dial reading at 600 rpm, lbf/100 ft2
67
Fann 35 dial reading at 100 rpm, lbf/100 ft2
20
Fann 35 dial reading at 3 rpm, lbf/100 ft2
6
10-s gel strength, Pa
7
10-min gel strength, Pa
8
Plastic viscosity, mPa.s
27
Yield point, Pa
HPHT fluid loss, mL [in.3]
8
1.8 [0.11]
Sag stability after 16 hours
10
Sag stability after 3 days
60
Sag stability after 5 days
60
Fann 35 dial reading at 600 rpm after 3 and 5 days static aging, lbf/100 ft2
65 and 85
Fann 35 dial reading at 100 rpm after 3 and 5 days static aging, lbf/100 ft2
18 and 26
Fann 35 dial reading at 3 rpm after 3 and 5 days static aging, lbf/100 ft2
M-I SWACO technical service engineers supported the entire operation offshore, ensuring
optimal fluid quality at all times. The engineers
encountered no fluid-related problems during
the field test. Results of prolonged static sag tests
showed average barite sag of less than 30 kg/m3
[0.25 lbm/galUS] in both the 120°C [250°F]
121/4-in. section and the 150°C 81/2-in. section.
Results obtained with the new fluid in the Crux
well demonstrate that it met the Statoil specifications for drilling performance. In addition, formation and fluid evaluation as well as pressure
logging were not affected by the new drilling fluid.
The specially designed fluid, deployed for similar
operations in HPHT wells worldwide, meets operator specifications while ensuring the validity of
fluid and rock samples.
—IMF
6 and 9
> HPHT drilling fluid formulation and averaged properties. The HPHT fluid has a density of 1,750 kg/m3
and an 80/20 oil/water ratio. The fluid property parameters obtained in the laboratory were all within
Statoil specifications. These results formed the basis of the mud program specifications to be used
offshore. The presented results are averaged values. Sag stability measurements are presented as
delta mud weights; the measurements were made after 16 hours, 3 days and 5 days of static aging
at 150ºC.
Spring 2014
33