spe 77255

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 Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the International Association of Drilling Contractors or the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the IADC or SPE, their officers, or members. Papers presented at the IADC/SPE meetings are subject to publication review by Editorial Committees of the IADC and SPE. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

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

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.

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


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


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.


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.


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.


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


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


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.


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.


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


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


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.


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


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.


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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