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Copyright 2002, IADC/SPE Asia Pacific Drilling Technology This
paper was prepared for presentation at the IADC/SPE Asia Pacific
Drilling Technology held in Jakarta, Indonesia, 911 September 2002.
This paper was selected for presentation by an IADC/SPE Program
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have not been reviewed by the International Association of Drilling
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Abstract Designing a development drilling program for the
Legendre Field required a systematic approach that incorporated the
lessons learned during the exploration and appraisal drilling
phase. A significant part of the planning endeavor focused on
arriving at a geomechanical solution that would prevent many of the
instabilities and lost circulation events from being repeated.
Detailed image analysis for wellbore failure, and a systematic
stress and rock strength analysis was performed to identify the
optimal well trajectories and mud weights to successfully drill and
complete the production wells. The results of this geomechanical
analysis indicated that the stress state in the Legendre Field area
is associated with a strike-slip stress regime. Horizontal wells
drilled sub-parallel to the maximum principal stress are optimally
oriented to ensure wellbore stability in the overburden, while
using a lower mud weight within the reservoir reduces the risk of
massive lost circulation. Introduction Developing a production
program for any hydrocarbon field is a complicated process. In many
cases, the most successful execution of a development plan involves
an integrated approach between geologists, geophysicists, reservoir
engineers and drilling/completion engineers, with each discipline
contributing information that hopefully generates an accurate
description of the reservoir to design a sound development program.
There will always be risks; however, by integrating information
from a multi-disciplinary team it is
possible to assess these risks and build into the development
program a mechanism for managing these risks.
An important component of this multi-disciplinary approach to
field development design involves constructing a geomechanical
model for the asset. In the case of the Legendre Field, a
geomechanical model was constructed to provide valuable information
for identifying appropriate wellbore trajectories and to design an
optimal mud program in order to reach the reservoir target and
minimize drilling problems. The anticipated risks associated with
drilling these development wells are wellbore stability and lost
circulation through natural fractures and possibly faults.
Quantifying the mechanical behavior of the natural fractures seen
in the wells can be accomplished using the same geomechanical
model. The objective of this paper is to illustrate how the
analysis of geologic and engineering information from the
exploration and appraisal wells in the Legendre field was used to
build a geomechanical model, which was then used to design four
development wells and one injection well. Geologic Setting and
Structural Framework The Legendre Field is compartmentalized into
the Legendre North and Legendre South Fields which are situated in
the southeastern part of the Dampier Sub-basin of the offshore
Carnarvon Basin of Western Australia, about 100 km north of Dampier
(Fig. 1). Located on the continental shelf in water depths of 50 to
60 metres, the Legendre Field represents the most significant
hydrocarbon accumulation along the Legendre Trend adjacent to the
Rosemary Fault System. The Rosemary Fault System is one member of
many NE-SW trending fault systems, presumed active up until the
Early Cretaceous, which are predominately responsible for the
hydrocarbon-bearing basins in the area. A more detailed description
of the depositional and structural framework, depositional setting,
and hydrocarbon generation of the Dampier Sub-basin can be found in
Refs. 1-3.
The Legendre reservoir rocks (B. reticulatum) are Berriasian to
Barremian aged sandstones that were deposited during the Early
Cretaceous and are oil-sourced from the underlying Tithonian to
Oxfordian claystones (Late Jurassic) and gas-sourced from the
underlying Bajocian (Middle Jurassic). Detailed 3D seismic mapping,
seismic migration,
IADC/SPE 77255
The Legendre Field Development and Geomechanical Program: From
Exploration to Drilling to Production David Castillo, SPE,
GeoMechanics International, Inc., and Phil Ryles, and Kirsty John,
Woodside Energy Limited
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2 D.A. CASTILLO, P. RYLES, K. JOHN IADC/SPE 77255
semblance analysis, and well results were used to characterize
the structure and fault architecture for the Legendre area.
Underlying the Legendre area is a Triassic to Jurassic north-south
trending fault system providing compartmentalization of depocentres
along the northeast-southwest trending Rosemary Fault System for
the Oxfordian to Tithonian reservoirs. This variation in regional
fault system trends has had an impact on the deposition and
distribution of the Berriasian reservoir. The Mio-Pliocene
transgressive phase in the Dampier Sub-basin lead to widespread
strike-slip tectonics resulting in associated folding, fault
generation and fault reactivation along the Rosemary Fault System,
which is responsible for the majority of faults seen within the
Legendre North and Legendre South Fields. The dominant fault
patterns within the Legendre area are the northeast-southwest fault
fabric in Legendre North, and the east-west to east northeast-west
southwest fault pattern in Legendre South.
Variations in the Oil-Water-Contact (OWC) and residual columns
between the Legendre North and South compartments imply that these
reservoirs have been breached. The higher OWC in the Legendre South
Field may have resulted from preferential leakage along a series of
reactivated faults, which appear to be more pervasive than in the
Legendre North area.
Exploration and Appraisal Drilling Experiences Between 1968 and
1998, there were six exploration and appraisal wells drilled within
or in the vicinity of the Legendre structure. Three of these wells
(Legendre-1, Jaubert-1 and Legendre South-1) encountered oil column
heights ranging from 13 to 37 meters. In particular, Legendre-1
represented the first offshore oil discovery in Western Australia.
Although the other three wells (Legendre-2, Titan-1 and Samson-1)
did not encounter oil-bearing reservoirs, the information acquired
in these wells contributed to a greater understanding of the
lateral extent of the reservoir. The drilling of the Legendre-1,
Jaubert-1/ST1, Titan-1 and Legendre-2 wells clearly defined the
Legendre North compartment while only the Legendre South-1 well was
used in the discovery of the Legendre South compartment.
With the exception of the Legendre-2 well, all the wells drilled
along the Legendre structure encountered drilling and HSE (Health,
Safety and Environmental) hazards which included gas kicks,
excessive cuttings, borehole instabilities (such as bridging, tight
hole and stuck bottom-hole-assembly, which later required a
side-track), and partial to total losses of circulating fluids. A
detailed description of the drilling hazards encountered in these
wells is outlined in Table 1.
Determining the appropriate mud weight for ensuring well control
in intervals suspected of being over-pressured for future
development wells proved to be problematic. Data from Legendre-1,
Legendre South-1, Titan-1 and Jaubert-1 wells was used to calibrate
a Woodside in-house (DISCO) pore pressure prediction profile for
the Legendre Field within the Early Cretaceous to Early Tertiary
claystones. It was determined that future development wells could
encounter a
maximum predicted pore pressure between 1.19 and 1.20 SG over
the interval 1100-1450 mTVDss. However, there were anomalous
experiences such as the 20% gas kick in Legendre South-1 at about
1,580 m (Muderong Shale), that required a mud weight between 1.25
and 1.30 SG, implying a formation pore pressure between 1.25 and
1.30 SG to regain pore pressure balance (Table 1). Jaubert-1 also
encountered a high gas reading in Muderong Shale with a mud weight
of only 1.15 SG. Interestingly, Titan-1 did not encounter any
significant gas despite a Dxc analysis indicating a pore pressure
increase to about 1.20 SG within the Muderong Shale. Direct pore
pressure measurements within the B. Reticulatum reservoir sandstone
and the Angel Formation indicated a normally pressured
reservoir.
A preliminary Woodside analysis of the drilling experiences from
Jaubert-1/ST1, Titan-1 and Legendre South-1 indicated that
insufficient mud weight and prolonged exposure to the Early
Tertiary to Early Cretaceous claystone in the overburden intervals
contributed to the wellbore instabilities encountered in these
wells. Although future drilling through the overburden section
using a mud weight of at least 1.30 SG could prevent some wellbore
failure in the planned development wells, there was concern that
these high mud weights would enhance the likelihood of lost
circulation.
Circulation losses were a serious problem in the Legendre
exploration and appraisal wells (Table 1). The pervasively
fractured and faulted nature of the Legendre Field (Fig. 1) was
believed to be responsible for these circulation losses. Also, the
unexpected gas kicks indicating differences in pore pressure in
some of the wells suggested that some faults are sealing while
others are not. A preliminary assessment of this pore pressure
variability within the field suggested that the non-sealing faults
may be critically-stressed with respect to the present-day stress
state, and therefore prone to fault slip which could lead to seal
failure and circulation losses. In addition to well control issues,
the mechanical instability of some of these faults and natural
fractures in the hydrocarbon reservoir pools in the Legendre South
and Legendre North compartments may explain the presence of gas in
the overburden above present day oil accumulations (Jaubert-1 and
Legendre South-1), the residual oil columns observed in Jaubert-1
and Titan-1, and the difference in observed oil water contacts for
the two compartments (Legendre North, 1,900 mSS; Legendre South,
1896 mSS).
To better assess the risks associated with the well development
designs for the Legendre Fields, particularly with respect to
wellbore stability, directional drilling and well control, a
geomechanical study was performed using data collected in the
exploration and appraisal wells. Before using this geomechanical
model to predict wellbore stability during the drilling of the
planned development wells, it was imperative that the geomechanical
model specific to the Legendre field first explains the drilling
experiences from the existing wells. An additional intent of this
study was to quantify the mechanical behavior of the natural
fractures and faults.
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IADC/SPE 77255 THE LEGENDRE FIELD DEVELOPMENT AND GEOMECHANICAL
PROGRAM 3
Geomechanical Approach Constraining the geomechanical model for
any particular asset provides valuable information for better
characterizing the reservoir and formulating a development plan
that optimizes drilling and production operations. These benefits
include predicting wellbore stability in deviated and
extended-reach boreholes, minimizing the use of excessive mud
weights for preventing formation damage and circulation losses, and
understanding the role of natural fractures.
To accomplish the study goals, a broad suite of geologic,
geophysical and engineering data was analyzed to map in detail the
magnitudes and orientations of the in situ stress across the field.
The methodology requires characterization of drilling-induced
wellbore failures through analysis and interpretation of available
wellbore image data. Least principal stress values (S3) inferred
from available leak-off tests, the vertical stress (Sv) from
density logs, and pore pressure (Pp) data from direct measurement
or inferred from drilling data, are used along with the observed
wellbore failures to constrain the full stress tensor in the
reservoir, including the magnitude and orientation of the maximum
horizontal stress (SHmax).
Observations of wellbore failure within any well provides an
important diagnostic tool for constraining the in situ state of
stress because they reflect the interplay between the stress
concentration around the wellbore (due to the stress state and
borehole trajectory) and rock strength. For instance,
stress-induced wellbore breakouts reflect compressional wellbore
failure along the borehole wall where the maximum stress
concentration around the wellbore exceeds the compressive strength
of the rock. In vertical wells, such as those in the Legendre Field
(Fig. 2), borehole breakouts form at the azimuth of the minimum
compressive horizontal stress (Shmin). Hence, breakouts are direct
indicators of stress orientation. In contrast, tensile wall
fractures form where the stress concentration around the wellbore
is minimal and exceeds the tensile strength (T0) of the rock. While
these drilling-induced fractures only occur in the skin of the
wellbore wall and do not present a risk for drilling, they are
diagnostic of both stress orientation and magnitude. In vertical
wells, they form 90 degrees from breakouts at the azimuth of SHmax.
For a more detailed description of the stress analysis methodology
used in this study, the reader is referred to several theoretical
and case study examples (Refs. 4-13). Geomechanical Modeling In
order to construct a well-constrained geomechanical model for the
Legendre Field a wide suite of geologic, geophysical and
engineering information was analyzed. Drilling-induced tensile wall
fractures (fine-scale vertical fractures on opposite pads of FMI
data) and wellbore breakouts (poor resistivity resolution on
opposite pads of FMI data) were pervasive in the Titan-1 well.
Similar wellbore failure was also seen in Jaubert-1 and Legendre
South-1 wells. Observations of wellbore failure (breakouts and
tensile wall fractures) in the Jaubert-1, Legendre South-1 and
Titan-1 wells (Figs. 3 and 4)
indicate a dominant SHmax stress direction of about N72E (Figs 2
and 4). Although the SHmax stress direction of ~N50E is inferred
from limited failure in the Jaubert-1 well, this may represent a
local variation due to faulting in the region. Considering the more
pervasively failed sections of Legendre South-1 and Titan-1 (Fig.
4), we would infer that the N72E is the dominant SHmax
direction.
Figure 5 is a stress and pore pressure profile of the Legendre
Field. The vertical stress (SV) was constrained using wireline
density data, while the least principal stress (S3) was constrained
from leak-off and extended leak-off tests. Because S3 is less than
SV, S3 must be the minimum horizontal stress (Shmin). Direct pore
pressure measurements in the reservoir indicated near-hydrostatic
pressure conditions, while pore pressure modeling using Woodsides
DISCO pore pressure program indicated a slight pore pressure
increase in the overburden.
Figure 6 shows how the magnitude of SHmax was constrained at a
depth of about 1700 meters in the Jaubert-1 well. The stress
polygon illustrated corresponds to the full range of permissible
Shmin and SHmax stress magnitudes at a specific depth for the given
borehole conditions, where the vertical stress and pore pressure is
known. In this case SV is about 34.4 MPa and pore pressure is near
hydrostatic. Superimposed on the stress polygon are the Shmin and
SHmax combinations required to induce tensile wall fractures
(inclined blue contours for various tensile rock strength situated
along the left side of the polygon) and wellbore breakouts
(near-horizontal red contours for various uniaxial compressive rock
strength within the interior of the polygon). The boundary of the
stress polygon describes the frictional limit that stress
accumulation can achieve before slip along optimally oriented
faults occur, assuming a coefficient of sliding friction of 0.75
(Ref. 14). Leak-off tests indicate that Shmin at this depth is
about 31 MPa; and because tensile wall fractures and wellbore
breakouts were seen at this depth, the SHmax required to develop
this style of failure must be in the 54-59 MPa range. Had SHmax
magnitudes been less than 54 MPa there would not have been
sufficient stress concentration at the borehole wall to form
tensile wall fractures. In order to be consistent with observations
wellbore breakouts at this depth, the uniaxial compressive strength
of the rock should be in the 73-89 MPa range. Figure 5 shows the
results of this stress analysis for the Juabert-1 and Legendre
South-1 wells, which indicates that the Legendre Field is
associated with a strike-slip stress regime (Shmin
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4 D.A. CASTILLO, P. RYLES, K. JOHN IADC/SPE 77255
was drilled west of the Legendre Field into a sand unit, which
is situated down-dip of the producing wells.
The geomechanical model described above was used to help design
a mud program for each of the five wells in order to maximize
wellbore stability in the reservoir and in the overburden. Figure 7
illustrates the mud weight needed to restrict the development of
wellbore breakouts along the entire Legendre South-2H trajectory (2
plots at left in Fig. 7a) and as a function of measured depth
(center plot in Fig. 7a). It was important to determine the optimal
mud program because the trajectory was designed to avoid a fault in
order to reduce the risk of lost circulation, as was encountered in
the previous Legendre South-1 appraisal well drilled in the area.
The center plot in Figure 7 shows the mud window (bright green
rectangle on the right) versus depth for the Legendre South-2H
well. The lower bound of the mud window is defined by the borehole
collapse pressure the minimum mud weight needed to prevent
excessive compressive failure of the wellbore wall (red line). The
upper bound of the mud window is defined by the minimum principal
horizontal stress (brown line). The Pp (blue line) and the vertical
stress (black line) are shown. The predicted mud weight for
maintaining wellbore stability along any arbitrary borehole
trajectory is shown on a lower hemisphere stereographic projection
corresponding to a depth of about 1640 mTVD (Fig. 7b) and at about
1920 mTVD (Fig. 7c) in Legendre South-2H. The results shown in Fig.
7 indicate that a 1.3 SG mud density is required to maintain
stability along the inclined portion of the trajectory deviated to
the southeast. As the trajectory direction changes to realign with
the Legendre South compartment, the final hole deviation and hole
direction is optimally oriented allowing for a lower mud weight in
the reservoir section. The far right side of Fig. 7a illustrates
the relatively small amount of wellbore failure (indicated by the
red region) that likely occurred while drilling the Legendre
South-2H well using a 1.3 SG mud density. The relatively minor
amount of wellbore failure is consistent with the reported good
hole conditions encountered during the drilling of this well.
The Legendre-1H, -2H and -3H wells, generally drilled in the
northeast direction into the Legendre North compartment, could
similarly be drilled with a lower mud weight along the horizontal
portion of the well. Figure 8 shows the predicted mud weight, mud
window and actual casing selection points for the Legendre-3H well,
which was drilled the farthest into the northeast sector of the
field. As in the case of the Legendre South-2H well, it was
possible to use a reduced mud weight (~1.1 SG) in the reservoir
section to maintain wellbore stability.
Using a low mud weight near and within the reservoir section was
particularly important due to the risk of experiencing lost
circulation events when the wellbore intersected permeable
fractures. The same geomechanical model for the Legendre Field
could be used to assess which fracture orientations are optimally
oriented for shear failure and therefore prone to permeability
enhancement. Figure 9 is an example which shows the fracture
population in the
Legendre South-1 well most likely to be critically-stressed with
respect to the present day stress state. Plotted in the
lower-hemisphere projection is the critical fluid pressure (pore
pressure or mud weight) required to induce shear failure along any
arbitrary fracture plane in the near-wellbore region.
Critically-stressed fractures are red dots on the center tadpole
plot based on the stress state shown in the far-left plot. These
same critically-stressed fractures are located along or above the
failure line in the Mohr diagram and are shown as white dots on the
stereographic projection. Using a lower mud weight in the
development wells drilled in the ENE-WSW direction minimized the
risk associated with inducing near-borehole fracture slip on
fractures dipping 30-60 to the northeast.
There were some mud losses encountered while drilling the
horizontal development wells for the Legendre Field, but the losses
were markedly less using a 1.1 SG mud density as compared to the
serious losses encountered in the Legendre South-1 well which used
up to a 1.35 SG mud density. It was possible to reduce the risk of
shear failure occurring along fractures that were at the threshold
of fault slip by avoiding the use of elevated mud densities.
Production During the final commissioning of the facility in the
4th quarter of 2001 oil production averaged 33,400bbl/d. The
project was completed ahead of the original schedule and within the
approved budget. At the beginning of 2002, after overcoming initial
difficulties with its gas re-injection compressor, production was
steady at 42,000bbl/d. The field life is estimated to be between 3
and 8 years.
Conclusion A detailed geomechanical model for the field was used
to design future well plans to avoid, in part, a repeat of the
excessive wellbore instabilities and lost circulation events
encountered in the Legendre Field exploration and appraisal. It is
absolutely essential that a geomechanical model first explain the
drilling experiences in the previous wells before it is used to
predict drilling performances in future well plans. A geomechanical
model is built through the examination of geologic, geophysical and
engineering information analyzed in an integrated approach to
constrain the three principal stresses, stress directions, pore
pressure and rock strength.
Our results indicate that the Legendre Field is associated with
a strike-slip stress regime (Shmin
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IADC/SPE 77255 THE LEGENDRE FIELD DEVELOPMENT AND GEOMECHANICAL
PROGRAM 5
References 1. Veevers, J.J., Powell, C.M.C.A., and Roots, S.R.:
Review
of Sea Floor Spreading Around Australia. I. Synthesis of the
patterns of spreading, Australian Journal of Earth Sciences (1991)
38, 373.
2. Barber, P.: Late Jurassic-Early Cretaceous Systems of the
Dampier Sub-basin- Quo Vardis?, The Appea Journal (1994) 34 No. 1,
566.
3. Willetts, J.M., Mason, D.J., Guerrera, L. and Ryles P.:
Legendre: Maturation of a Marginal Offshore Oil Discovery to
Dvelopment Project, The Appea Journal (1999) 39, Part 1, 504.
4. Bell, J.S., and Gough, D.I.: Northeast-southwest compressive
stress in Alberta: Evidence from oil wells, Earth and Planetary
Science Letters (1979) 45, 475.
5. Moos, D., and Zoback, M.D.: Utilization of Observations of
Well Bore Failure to Constrain the Orientation and Magnitude of
Crustal Stresses: Application to Continental Deep Sea Drilling
Project, and Ocean Drilling Program Boreholes, Journal of
Geophysical Research(1990) 95, 9305.
6. Zoback, M.D and Healy, J..H.: Introduction to Special Section
on the Cajon Pass Scientific Drilling Project, Journal of
Geophysical Research (1992) 97, No. B4.
7. Castillo, D.A., and Zoback, M.D.: Systematic Variations in
Stress State in the Southern San Joaquin Valley: Inferences Based
on Wellbore Data and Contemporary Seismicity, American Association
of Petroleum Geologists Bulletin (1994) 78, No. 8 1257.
8. Peska, P. and Zoback, M.D.: Compressive and Tensile Failure
of Inclined Wellbores and Determination of in situ stress and rock
strength, Journal of Geophysical Research (1995) 100 (7), 12,
791.
9. Barton, C.A., Zoback, M.D., and Moos, D.: Fluid Flow Along
Potentially Active Faults in Crystalline Rock, Geology (1995) 23
(8), 683.
10. Brudy, M., and Zoback, M.D.: Compressive and Tensile Failure
of Boreholes Arbitrarily-inclined to Principal Stress Axes:
Application to the KTB Boreholes, Germany, Int. J. Rock Mech. Min.
Sci. & Geomech. Abstr. (1997) 30, No. 7, 1035.
11. Castillo, D.A., Barton, C.A., Moos, D., Peska, P., and
Zoback, M.D.: Characterising The Full Stress Tensor Based on
Observations of Drillinginduced Wellbore Failures in Vertical and
Inclined Boreholes Leading to Improved Wellbore Stability and
Permeability Prediction, The Appeal Journal, (1998) 38 Part 1,
466.
12. Wiprut, D., and Zoback, M.D.: Fault Reactivation and Fluid
Flow Along a Previously Dormant Normal Fault in the Northern North
Sea, Geology (1998) 28, No. 7, 595.
13. Castillo D.A., Bishop, D.J., Donaldson, I., Kuek, D., de
Ruig, M., Trupp, M, and Shuster, M.W.: Trap Integrity in the
Laminaria High-Nancar Trough Region, Timor Sea: Prediction of Fault
Seal Failure Using Well-constrained Stress Tensors and Fault
Surfaces Interpreted From 3D Seismic, Appea Journal (2000) 151.
14. (Byerlee, J.: Friction of Rocks, Pure and Applied Geophysics
(1978) 116, 615.
15. Zoback, M.D., and Healy, J.H.: In-situ Stress Measurements
to 3.5km depth in the Cajon Pass Scientific Research Borehole:
Implications For the Mechanics of Crustal Faulting, Journal of
Geophysical Research (1992) 97, 5039.
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6 D.A. CASTILLO, P. RYLES, K. JOHN IADC/SPE 77255
TABLE 1
Well Depth (m KB/RT)
Hazard Description
Legendre-1 To 1,034 m Lost circulation
Severe losses requiring seven cement plugs to overcome. Total of
8,000 bbls of mud were lost.
Legendre-1 1,034- 1,893 m
Tight hole Major cavings
Tight hole conditions and major cavings were encountered between
1,034 m KB to 1,893 m KB.
Titan-1 1,983 m Borehole instability/ Cavings
Large volume of cavings following a 50 bbl pill to assist in
hole cleaning. A wiper trip performed after the first logging run
could not penetrate past 1,952 mRT. A 1.30 SG MW was necessary to
be deepened to 1,990 mRT
Jaubert-1 1,143 m
1,831 m
1,891 m
Borehole instability/ Cavings
Mud weight increased to 1.24 SG after encountering tight hole
and excessive cavings prior to wireline logging. Bridges prevented
placing the 95/8 casing past 1,798 mRT. 1,800 mRT. The bottom hole
assembly became stuck at 1,311 mRT during clean up trip requiring
the string to be backed off at 1,213 mRT and a cement plug. A
sidetrack kick-off at 1,133 mRT using a mud weight of 1.30 SG made
drilling to a TD of 2,015 mRT possible. The trip out was clean and
the 95/8 casing was run to 2,005 mRT, with one bridge encountered
at 1,987 mRT. Higher mud weight in Jaubert-1ST background gas,
total gas was reduced and the borehole condition significantly
improved.
Legendre South-1
1,583 m
1,660 m
1,946 m
Gas Kick
Lost
Circulation
Total Losses
At 1,583 mRT while drilling with a 1.25 SG KCl/PHPA mud system
20% gas was recorded at the shakers and a flow check showed that
the well was flowing. An increase in mud weight to 1.35 SG at 1,583
mRT killed the gas flow.
Drilling with a 1.35 SG MW between 1,583 and 1,660 mRT
experienced about 14 m3 of mud losses, reduced only after lowering
the pump rate.
During coring total losses occurred at 1,946 mRT due to
intersecting a fault or fracture network. Pumping numerous LCM
pills, decreasing mud weight to 1.27 SG, and setting a cement plug
between 1,862-1,900 mRT cured the problem.
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IADC/SPE 77255 THE LEGENDRE FIELD DEVELOPMENT AND GEOMECHANICAL
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Figure 1. Regional structure map of the North West Shelf area of
Australia. The Legendre North and South Fields are located on the
downthrown side of the Rosemary Fault System that separates the
Lewis Trough to the northwest from the Enderby Trend to the
southeast.
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8 D.A. CASTILLO, P. RYLES, K. JOHN IADC/SPE 77255
Figure 2. Field development map showing the location of the
vertical appraisal wells (Jaubert-1, Titan-1 and Legendre South-1)
and the horizontal development wells (Legendre North-1, -2 and 3,
Legendre South 2, and Legendre West-1) drilled from the same
platform. The orientation of SHmax is indicated by the
inward-facing arrows. The base map is the top reservoir structure
map
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IADC/SPE 77255 THE LEGENDRE FIELD DEVELOPMENT AND GEOMECHANICAL
PROGRAM 9
Figure 3. Example of the FMS image data collected in the Titan-1
well. Observations of drilling-induced wellbore breakouts and
tensile wall fractures were also pervasive in the Jaubert-1 and
Legendre South-1 wells.
Tensile Wall Fractures
Pad Standoff likely due to wellbore breakouts
Titan-1
Electrical Conductivity
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10 D.A. CASTILLO, P. RYLES, K. JOHN IADC/SPE 77255
0 30 60 90 120 150 180
1200
1300
1400
1500
1600
1700
1800
1900
2000
Titan-1
Tensile Wall FracturesWellbore Breakouts
Compressive and Tensile Failure Orientation (degN)
Haycock Marl
Muderong Shale
Forestier ClaystoneBerriasian SS.
a)
b)
Figure 4. Analysis results of mapping compressive and tensile
wellbore failure in (a) the Titan-1 well. (b) An overview of the
SHmax stress directions inferred from failure seen in the
Jaubert-1, Titan-1 and South Legendre-1 wells. The SHmax stress
directions inferred from failure seen in the Titan-1 and South
Legendre-1 wells appears to be more representative of the regional
stress, although local faulting may be influencing the SHmax stress
direction in the Jaubert-1 well.
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IADC/SPE 77255 THE LEGENDRE FIELD DEVELOPMENT AND GEOMECHANICAL
PROGRAM 11
0 10 20 30 40 50 60 70 80
0
500
1000
1500
2000
2500
Stress Profile of the Legendre
SvPp (Disco)Pp (Jaubert-1; DST)Extended LOT (J-1, LS-1)Shmin
(J-1, LS-1)SHmax (Jaubert-1)SHmax (Legendre South-1)
Stress and Pressure (MPa)
SHmax
SvShminPp
LS-1
T-1
J-1
XLOT
B. Reticulatum Ss.
Muderong Sh.
Haycock Marl &Windalia Radiolite
Toolonga Calcilutite
FMI/FMSImage Data
Lambert-Miria-Withnell Sh.
Figure 5. Stress and pore pressure profile of the Legendre
Field. The vertical stress (Sv) is constrained using density data.
Leak-off data indicates that the minimum horizontal stress (Shmin)
is less than the Sv, while wellbore failure analysis indicates that
the maximum horizontal stress (SHmax) is greater than Sv.
-
12 D.A. CASTILLO, P. RYLES, K. JOHN IADC/SPE 77255
Jaubert-1Depth 1700 mTVD
Shmin ~ 31.0 MPa
SHmax ~ 54- 59 MPa
Sv ~ 34.4 MPaPp ~ 18.7 MPa
Rock Strength~73 _89 MPa
Figure 6. Stress polygon showing a range of permissible Shmin
and SHmax stress magnitudes at a depth of about 1700 meters in the
Jaubert-1 well. Results indicate a strike-slip stress regime
(Shmin
-
IADC/SPE 77255 THE LEGENDRE FIELD DEVELOPMENT AND GEOMECHANICAL
PROGRAM 13
9 5/
8 c
asin
g7
line
rMudWindow
Map View
Cross-Section
1992 MD1642 mTVD
3500 MD1922 mTVD
1992 MD1642 mTVD
3500 MD1922 mTVD
Mud Weight for Stability
a)
LeastPrincipal
Stress
MinimumMud Wt.
for Stability
VerticalStress
PorePressure
SHmax
N
S
EW
Shmin
Sv
Mud WeightFor Stability,
SG
Legendre South-2Hat 1642 mTVD
SHmax
N
S
EW
Shmin
Sv
Legendre South-2Hat 1922 mTVD
Mud WeightFor Stability,
SG
b) c)
Figure 7. Predicted mud weight program for the Legendre South-2H
well. The required mud weight needed to maintain wellbore stability
is shown in a) as a function of location along the wellbore
trajectory and measured depth. The far right side of a) illustrates
the expected degree of failure based on the actual mud density used
to drill the well. Shown on a lower hemisphere stereographic
projection is the predicted mud weight for any arbitrary borehole
trajectory corresponding to a depth of b) ~1640 mTVD and c) ~1920
mTVD in the Legendre South-2H well. For comparison the actual
Legendre South-2H trajectory at the corresponding depth is also
shown.
-
14 D.A. CASTILLO, P. RYLES, K. JOHN IADC/SPE 77255
9 5/
8 c
asin
g
MudWindow
Map View
Cross-Section
Mud Weight for Stability
a)
LeastPrincipal
Stress
MinimumMud Wt.
for StabilityVerticalStress
PorePressure
5075 MD1918 mTVD
5075 MD1918 mTVD
b)
SHmax
N
S
EW
Shmin
Sv
Mud WeightFor Stability,
SG
Legendre North-3Hat 1918 mTVD
Figure 8. Predicted mud weight and mud window for the Legendre
North-3H well. A mud weight of 1.1 SG was used in the Legendre
North-3 well where very little wellbore failure or difficulties due
to wellbore instabilities were encountered in the well.
-
IADC/SPE 77255 THE LEGENDRE FIELD DEVELOPMENT AND GEOMECHANICAL
PROGRAM 15
Pp
SHmax
Shmin
Sv
Figure 9. Stress analysis of the natural fractures seen in the
Legendre South-1 well quantifying the state of stress resolved
along the fractures mapped from image data. Results were used to
determine the critical borehole fluid pressure (mud weight) needed
to induce shear failure along the natural fractures.
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