AADE-04-DF-HO-04

Case History: Hydraulics Modeling Software Helps Optimize Drilling

and ECD Control with High Degree of Accuracy on Deep, Hot Gulf of Mexico
Shelf Well
Steven L. Stegeman, Dominion E&P, Inc.; Brian Coles and Wayne Rogers, Baroid product service line, Halliburton

This paper was prepared for presentation at the AADE 2004 Drilling Fluids Conference, held at the Radisson Astrodome in Houston, Texas, April 6-7, 2004. This conference was sponsored by the
Houston Chapter of the American Association of Drilling Engineers. The information presented in this paper does not reflect any position, claim or endorsement made or implied by the American
Association of Drilling Engineers, their officers or members. Questions concerning the content of this paper should be directed to the individuals listed as author/s of this work.

Abstract
A number of hydraulics modeling programs have
been developed to help optimize drilling fluid
performance. The Gulf of Mexico (GOM) case history
presented in this paper reflects the high degree of
accuracy that can be achieved with proprietary software
designed specifically to produce verifiable predictive
models for all types of drilling fluids under well-specific
conditions, including compressibility, temperature
effects, and sweep impact. The ability to account for
temperature effects was critical because the anticipated
bottomhole temperature (BHT) was 350F at the
proposed total vertical depth (TVD) of 16,000 ft.
The program was used during the drill-well-on-paper
(DWOP) stage and while drilling to model equivalent
circulating densities (ECD), hole-cleaning efficiency, surge
and swab pressures, and pressure loss. Comparisons to
data from pressure-while-drilling (PWD) tools and
observed results at the wellsite indicate that the hydraulics
modeling software package provided consistently
accurate predictive modeling throughout well planning
and during well construction operations. For example,
correlations between actual PWD and predicted values
indicated that the average difference between measured
PWD and predicted ECD was 0.029 lb/gal.
The operator was able to drill three hole sections in
18 drilling days and 258 rotating hours. The actual total
mud cost was 17% below the planned cost.
As proven in field applications worldwide and
demonstrated in the case history, the modeling program
can produce an extremely reliable vision of drilling fluid
and wellbore behavior based on the conditions specified
by the user. The modeling software accounts for factors
that influence ECD, including the following factors:
Well geometry, tool joint effects, eccentricity
Rotary speed
Drilling fluid properties and downhole rheology
Bit nozzle selection
Pump output
Fluid compressibility and thermal expansion
Cuttings loading
Rotary drilling and sliding intervals

Cuttings size and slip velocity

Rate of penetration (ROP)sliding/rotating
Fluid properties of sweeps
Static and circulating wellbore temperature
profile

Introduction
A lower than desirable ROP and multiple hole
problems prompted the operator to change from a waterbased fluid (WBF) to a synthetic-based fluid (SBF) at the
5
13 /8-in. casing point on the OCS-G 22510 No. 2 well in
West Cameron Block 100. The No. 1 well had been
drilled entirely with WBF system because of the
operators previous experience with diesel-based mud
losses. However, drilling fluid charges on the No. 1 well
were more than twice the projected cost, and actual
days to reach total depth (TD) were significantly higher
than planned days.
The same issues were foreseen on the No. 2 well,
eliminating any cost benefits that might have accrued
from using the WBF system. The rig was not equipped
for the zero-discharge cuttings disposal process required
with diesel-based fluid. Drilled cuttings would be
discharged overboard as they had been with the WBF
system. The decision was made to drill the two final
intervals with an environmentally compliant, clay-free
SBF system.
The clay-free SBF system had been widely used in the
GOM and had an established track record for reducing
the whole mud losses typically associated with
conventional SBFs. However, at the time the No. 2 well
was drilled, the system had not been used to drill at the
density and temperature parameters expected. The mud
weight at TD could exceed 17.0 lb/gal, and the BHT could
reach 350F. Before this operation, the SBF system had
been run at 17.0 lb/gal in a 325F well and had been
successfully tested in the laboratory at 350F. The
proposed No. 2 well would provide a challenging field trial.
Drill Well on Paper (DWOP)
The operators decision to change out drilling fluid
systems took place approximately 30 days before the
spud date, accelerating the events that would normally

S.L. STEGEMAN, B. COLES, W. ROGERS

comprise well planning for a deviated, high-pressure,

high-temperature (HPHT) well. Using a highly accurate
hydraulics modeling software package, drilling fluids
personnel analyzed the well plan, potential density and
temperature effects, hole-cleaning efficiencies in the 39
angle wellbore, and numerous what-if cases to help
ensure the best outcomes could be achieved.
The New Orleans-based drilling fluids laboratory
performed extensive testing on the SBF system
prepared for the well. The SBF base fluids intended for
use on the No. 2 well were isolated at the shore-based
mud mixing plant in Cameron, Louisiana. Mud volumes
were mixed in 1.0-lb/gal increments based on the
densities expected while drilling. Each batch was tested

with the Fann 75 HPHT viscometer over a wide range

of temperatures.
Testing of invert emulsion fluids over the anticipated
temperature and density spectrum is of prime
importance. The expansion of the base fluid under
increased temperature leads to a decrease in volumetric
density not seen at the surface when the fluid is cooler.
The increased temperature also causes a decrease in
viscosity of the fluid. Conversely, increased pressure
causes a compression of the base fluid, which yields a
corresponding increase in volumetric density not seen
under surface conditions.
These changes in the fluid create a downhole
environment significantly different than surface
conditions. Testing with the Fann 75 viscometer allows
the modeling software to accurately predict rheology and
density under the actual drilling conditions; therefore,
changes in slip velocity, cuttings transport, and
circulating pressures can be accurately modeled.
The rheological properties obtained with the Fann 75
viscometer were used by technical support and field
personnel to model the hydraulics during the planning
phase of the No. 2 well. Based on the operators well
design, the rotation speed limit for each drilling
assembly, pump output, and the fluid properties at
various densities and temperatures, the modeling
software calculated hole-cleaning efficiency and ECD at
any point in the well. The parameters could be tested
with a range of ROPs to help ensure that the maximum
safe drilling rates could be sustained (Fig. 1). Modeling
results were validated by PWD data and shown to be
accurate within 0.03 lb/gal.
The program also accurately predicted surge
pressures while running casing, allowing the operator to
maintain an optimized balance between running speed
and loss prevention, a key factor in controlling drilling
fluid costs.
Of particular importance was the prevention of barite
sag at the proposed mud weights. The SBF system had
been used on more than 60 deepwater and shelf wells at
the time with zero incidences of sag, but the drilling
fluids specialists wanted to subject 17.0-lb/gal fluid
samples to long-term sag testing. If the fluid showed any

AADE-04-DF-HO-04

tendency to sag, the formulation could be adjusted

accordingly while the rheological properties necessary to
minimize downhole mud losses were preserved. No sag
occurred with the mud samples tested in the lab.
Drilling Challenges
The challenges that occurred over each interval are
discussed in the following sections.
The 12 -in. Interval
5
After setting 13 /8-in. casing at 11,444 ft measured
depth (MD), the operator drilled out with WBF and
obtained a 16.6-lb/gal equivalent mud weight (EMW) by
leakoff test, but only after a cement squeeze. The WBF
was displaced with a 14.7-lb/gal SBF system. The 17
angle was built to 39 at a rate of 2 per 100 ft.
To minimize seepage loss, the SBF was pretreated
with sized calcium carbonate. A known loss zone was
expected at 12,800 ft MD and was actually encountered
at 12,858 ft MD. The hole stayed full while static, but the
loss rate while circulating at 570 gal/min was
approximately 40 bbl/min. A 40-bbl pill formulated with a
mix of sized calcium carbonate, deformable carbonbased material, fibrous material, and walnut hulls was
spotted on bottom. The mud weight was reduced from
15.9 lb/gal to 15.7 lb/gal. Drilling resumed with no further
problems. The total loss during this incident was 266 bbl,
which was a relatively small volume compared to losses
that had occurred on offsets drilled with conventional
SBFs or diesel-based mud.
Hydraulics modeling was performed throughout the
interval to determine ECD and hole-cleaning efficiency
because of the sensitivity to lost returns of the drilling
fluid and the maintenance of wellbore stability. The
modeled ECD remained extremely consistent with PWD
values (Fig. 2). For example, the calculated ECD while
sliding at 12,236 ft MD was 15.763 lb/gal; the ECD
measured by PWD at the same depth was 15.65 lb/gal,
a scant 0.11-lb/gal difference. Temperature effects on
the EMW were also modeled with the hydraulics
software, as shown in the example results calculated at
13,100 ft TVD.
The interval was drilled to TD at 13,239 ft MD (12,858
ft TVD) with a final mud weight of 15.8 lb/gal. Hole
opener runs were made before logging and before
5
running 9 /8-in. casing. During each hole opener run,
minor losses were encountered in the same zone and
readily cured with the same lost-circulation treatment.
5

Zero Losses While Running and Cementing 9 /8-in.

Liner
To minimize losses while running and cementing the
5
9 /8-in. liner, both closed- and open-ended runs were
modeled. The software generated a set of profiles
showing the impact of different running speeds on ECD
5
(Figs. 3 and 4). The 9 /8-in. liner was run to the planned
depth of 13,239 ft MD at speeds up to 60 ft/min with zero

AADE-04-DF-HO-04

CASE HISTORY: HYDRAULICS MODELING SOFTWARE HELPS OPTIMIZE DRILLING AND ECD
CONTROL WITH HIGH DEGREE OF ACCURACY ON DEEP, HOT GULF OF MEXICO SHELF WELL

mud losses, despite the existence of the loss zone at

12,858 ft. The liner was circulated at 6.0 bbl/min and
cemented in place. Full returns were maintained
throughout the entire operation. A formation integrity test
(FIT) yielded an 18.0-lb/gal shoe test. No remediation
work was necessary for the primary cement job.
The well plan allowed eight drilling days for the 12 in. interval. The interval was actually drilled to TD in
seven days (96 rotating hours). No evidence of barite
sag was observed after trips or after logging. The actual
drilling fluids cost was 22% less than the planned cost
for the interval.
The 8 -in. Interval
5
With the 9 /8-in. liner set successfully at 13,430 ft
MD, drilling continued with an 8 -in. PDC bit and the
clay-free SBF system. The hole angle was dropped from
38 to 33 while drilling to TD at 15,747 ft MD (14,868 ft
TVD). The maximum mud weight was 16.8 lb/gal. The
ECDs were constantly modeled and correlated closely
with PWD values (Fig. 5). While drilling 50 ft/hr at 15,000
ft MD, for example, the calculated ECD was 16.874
lb/gal and the PWD measured density was 16.9 lb/gal.
The maximum BHT in this interval was 247F. The
temperature effect on EMW continued to be modeled for
this interval (Fig. 6).
Zero Barite Sag
At 16.9 lb/gal in the deviated well, the potential for
barite sag was very high. The mud weights in and out
were recorded every 15 minutes while circulating, with
close scrutiny applied after trips and other static
intervals. Variation in density occurred rarely, and the
maximum variation observed was 0.1 lb/gal or less.
Maximum and minimum mud weights recorded by the
PWD consistently confirmed the surface readings.
The rheological properties of the SBF system were
relatively low considering the demands created by high
density and high temperature. The funnel viscosity
remained 80 sec/qt or less except after several days of
logging, when the funnel viscosity was recorded at 90
2
sec/qt. The yield point was 10 to 13 lb/100 ft . Ten2
second/ten-minute gels averaged 12 to 25 lb/100 ft . The
HPHT fluid loss was controlled at 10 mL/30 min.
The ability of the unique SBF system to prevent
barite sag while also reducing whole mud losses that
typically occur with conventional SBFs has been
1
attributed in part to the character of the gel strengths.
The fluid forms robust gels quickly, allowing excellent
suspension. However, the gels are very fragile so that
relatively slight pressure is required to initiate circulation,
and surge pressures are minimized while tripping and
running pipe. The PWD logs from wells drilled with the
clay-free SBF in shelf and deepwater locations verify the
absence of the pressure spike commonly associated
with resuming circulation after a long static period.

Zero Losses While Running and Cementing 7 /8-in.

Liner
The hydraulics modeling software was used again to
calculate both closed- and open-ended casing runs
5
(Figs. 7 and 8). A 2,810-ft, 7 /8-in. liner was run to the
planned depth of 15,747 ft MD at speeds up to 50 ft/min
with zero mud losses during running, circulating, and
cementing operations. An FIT yielded an 18.5-lb/gal
shoe test. No remediation work was required.
The well plan allowed eight drilling days for the 8 -in.
interval. The interval was actually drilled to TD in seven
days (115 rotating hours). The actual drilling fluids cost
was 1% higher than the planned cost for the interval.
The 6 -in. Interval
The final interval registered a maximum static BHT of
335F. Flowline temperatures ranged from 130F to
170F. The well angle was dropped to 30 and drilling
continued to the planned depth of 17,015 ft MD.
No hole problems were noted while tripping before
the TD logging run. However, the wireline logging tools
would not go past 16,615 ft. A hole opener run was
made and a weighted sweep was circulated around
before pulling out of the hole to resume logging. After an
unsuccessful attempt at wireline logging, another hole
opener run was made. Pipe-conveyed logging tools were
run in the hole to bottom with no problem. The well was
5
eventually plugged back to 15,675 ft MD. A 7 /8-in.
tieback was run to surface and cemented.
The correlation between modeled ECD and PWD
data continued to be very accurate throughout the 6 in. interval (Fig. 9). Over the course of the entire well,
the average difference between calculated and
measured ECD was 0.029 lb/gal. No evidence of barite
sag was detected.
The well plan allowed nine drilling days for the 6 -in.
interval. The interval was actually drilled to TD in three
days (47 rotating hours). The actual drilling fluids cost
was 19% less than the planned cost for the interval.
Conclusions
The use of the highly accurate hydraulics modeling
software allowed the operator to predict the cuttings load
that would result from a given ROP at a given pump rate
and determine the impact of the cuttings load on ECD.
Accurate knowledge of the ECD and hole-cleaning
efficiency helped the operator maximize ROP while
minimizing the risk of lost circulation or hole packoff. On
the No. 2 well, the operator was able to achieve ROPs of
up to 130 ft/hr without negative consequences. The
12 -in., 8 -in., and 6 -in. hole sections were drilled
in 18 drilling days (258 rotating hours), seven days less
than planned, resulting in reduced rig costs of
approximately $100,000 per day saved.

S.L. STEGEMAN, B. COLES, W. ROGERS

The ability to model surge and swab pressures

before running each casing string allowed the operator
to select the optimal running speed and avoid costly
whole mud losses. This was especially notable in the
12 -in. interval, where a significant loss zone had been
encountered. No downhole mud losses occurred while
running and cementing each of the three liners. The total
mud cost for the three intervals was $676,276, which is
17% lower than the planned cost of $814,400.
Acknowledgments
The authors thank the management of Dominion
E&P, Inc. and Halliburton for their support and

AADE-04-DF-HO-04

permission to publish this paper. Additionally, the

authors acknowledge James Downs, Baroid Lab
Manager in New Orleans, for his contributions toward
the success of the No. 2 well.
References
1.

Burrows, K., Carbajal, D., Kirsner, J., and Owens, B.:

Benchmark Performance: Zero Barite Sag and
Significantly Reduced Downhole Losses with the
Industrys First Clay-Free Synthetic-Based Fluid, SPE
87138, IADC/SPE Drilling Conference, Dallas, Texas, Mar.
2-4, 2004.

Fig. 1Optimal ROPs based on ECD and cuttings loading are shown in drilling window at right

AADE-04-DF-HO-04

CASE HISTORY: HYDRAULICS MODELING SOFTWARE HELPS OPTIMIZE DRILLING AND ECD
CONTROL WITH HIGH DEGREE OF ACCURACY ON DEEP, HOT GULF OF MEXICO SHELF WELL

Fig. 2Comparison between modeled ECD and actual PWD data in 12 -in. interval

Fig. 3Closed-end surge and swab for 9 /8-in. liner run

S.L. STEGEMAN, B. COLES, W. ROGERS

Fig. 4Open-end surge and swab for 9 /8-in. liner run

Fig. 5Comparison between modeled ECD and actual PWD data in 8 -in. interval

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AADE-04-DF-HO-04

CASE HISTORY: HYDRAULICS MODELING SOFTWARE HELPS OPTIMIZE DRILLING AND ECD
CONTROL WITH HIGH DEGREE OF ACCURACY ON DEEP, HOT GULF OF MEXICO SHELF WELL

Fig. 6Modeled temperature effect on EMW vs. TVD in 8 -in. interval

S.L. STEGEMAN, B. COLES, W. ROGERS

Fig. 7Open-end surge and swab for 7 /8-in. liner run

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AADE-04-DF-HO-04

CASE HISTORY: HYDRAULICS MODELING SOFTWARE HELPS OPTIMIZE DRILLING AND ECD
CONTROL WITH HIGH DEGREE OF ACCURACY ON DEEP, HOT GULF OF MEXICO SHELF WELL

Fig. 8Closed-end surge and swab for 7 /8-in. liner run

Fig. 9Comparison between modeled ECD and actual PWD data in 6 -in. interval