In situ stresses of the West Tuna area, Gippsland Basin

Transcription

1 Australian Journal of Earth Sciences (2005) 52, ( ) In situ stresses of the West Tuna area, Gippsland Basin E. J. NELSON* AND R. R. HILLIS Australian School of Petroleum, University of Adelaide, SA 5005, Australia. The in situ stress tensor has been evaluated in the West Tuna area of the Gippsland Basin based on petroleum well data. Borehole breakouts and drilling-induced tensile fractures interpreted on image logs from six wells constrain the maximum horizontal stress orientation to *1388N. Four leak-off pressures and one closure pressure suggest the upper bound to the minimum horizontal stress in the West Tuna area is *20 MPa/km. The vertical stress was derived from checkshot velocity, density and sonic log data and the average value from sea-level is 20 MPa/km to 1km and 22 MPa/km to 3km depth. Formation test pressures indicate that pore pressure in the West Tuna area is hydrostatic above 2800 m. The maximum horizontal stress magnitude was constrained to MPa/km based on the occurrence of drilling-induced tensile fractures on the West Tuna image logs. The in situ stress regime in the West Tuna area is therefore interpreted to lie on the boundary of strike-slip and reverse faulting (S Hmax 4 S v & S hmin ). The maximum horizontal stress orientation determined herein is broadly consistent with previous orientations derived from 4-arm caliper logs from nine other fields across the Gippsland Basin. The consistent northeast southwest orientation suggests that large-scale tectonic forces are the primary control on the in situ stress tensor in the Gippsland Basin and indeed elsewhere in southeastern Australia. The horizontal stress magnitude in the Gippsland Basin with the minimum horizontal stress approximately equal to the vertical stress, are significantly higher than in other Australian basins including the Otway Basin. The (oblique compressional) plate boundary at New Zealand may be primarily responsible for the horizontal stress orientation and high horizontal stress magnitude in the Gippsland Basin and is discussed herein. KEY WORDS: in situ stress, Gippsland Basin, West Tuna area. INTRODUCTION Knowledge of the in situ (present-day) stress is critical to understanding continental-scale tectonic issues such as the driving forces of plate movements (Zoback 1992; Coblentz et al. 1995), and smaller scale engineering issues such as the stability of petroleum wells or underground excavations (Hillis & Williams 1993; Fairhurst 2003; Martin et al. 2003). In sedimentary basins, the stress tensor can be reduced to five components (Bell 1996): (i) the vertical stress (S v ) magnitude; (ii) the orientation of the maximum horizontal (S Hmax ) stress; (iii) the minimum horizontal stress (S hmin ) magnitude; (iv) the maximum horizontal stress magnitude; and (v) pore pressure. Much of the data required to determine the in situ stress tensor are acquired during drilling and subsequent logging of oil and gas wells (Bell 1990, 1996; Hillis et al. 1995). There were few data quantitatively describing the in situ stress field of the Gippsland Basin prior to this study. The orientation of the maximum horizontal stress had been described as north-northwest southsoutheast from observations of movement of rock walls during opencut mining of the Morwell coal mine in the Latrobe Valley (Barton 1980). Seven measured maximum horizontal stress orientations were previously available for the Gippsland Basin based on borehole breakout. These breakout orientations were interpreted from 4-arm dipmeter logs available in the Australian Stress Map (Hillis & Reynolds 2000). Breakout interpretation from 4-arm dipmeter logs is much less reliable than the image log interpretation used herein (Brudy & Kjorholt 2001). Furthermore the early data were inherited when the Australian Stress Map took over the World Stress Map for the region, and the origin is unknown (i.e. author/source of these interpretations). Quantitative stress-magnitude data were also previously unavailable, although previous analysis of focal mechanisms from shallow seismic events had suggested compressive north-northwest south-southeast stress in southeast Australia (Barton 1980; Denham 1980). Interpretation of inversion structures and fault reactivation on seismic sections has also led interpreters to suggest that compressional stresses have existed in the Gippsland Basin from the Eocene onwards (Johnstone et al. 2001; Power et al. 2003). The main aim of this study was to constrain quantitatively the magnitude and orientation of the in situ stress tensor in the Gippsland Basin. The West Tuna area of the Gippsland Basin provides a dense dataset of well information for in situ stress determination. For the purposes of this study the West Tuna area refers to an area encompassing the West Tuna and Tuna Fields and the area around the East *Corresponding author: enelson@asp.adelaide.edu.au ISSN print/issn online ª Geological Society of Australia DOI: /

2 300 E. J. Nelson and R. R. Hillis Pilchard 1 exploration well which is situated 15 km to the east of the Tuna/West Tuna platforms and is adjacent to the Kipper Field (Figure 1). The West Tuna platform was constructed in late 1996 and hosts over 40 development wells. The platform produces from both the shallow, conventional top Latrobe Group reservoirs, and also from sands of the deep intra-latrobe Group and Golden Beach Subgroup (Figure 2). Image logs, wireline log data and pressure data were available from the Tuna 4 exploration well, five development wells drilled from the West Tuna platform (West Tuna 8, 32, 37, 39, 44) and the East Pilchard 1 exploration well. This paper focuses on determining each component of the in situ stress tensor in the West Tuna region, and discusses some of the tectonic implications for the Gippsland Basin. TECTONIC HISTORY OF THE GIPPSLAND BASIN The east west-trending Gippsland Basin initially formed in response to rifting along the southern margin of Australia (north of Tasmania) in the Late Jurassic (Willcox et al. 1992). The early rift stage saw the deposition of the fluvial and lacustrine sediments of the Strzelecki Group which is considered economic basement in the Gippsland Basin. In the Cenomanian the rift locus shifted to the south of Tasmania and seafloor spreading started there in the Campanian (Veevers 1991; Hill et al. 1995). Rift-related subsidence continued in the Gippsland Basin despite the shift in rift locus and provided accommodation space for the largely nonmarine sediments of the Golden Beach Subgroup (Bernecker & Partridge 2001; Norvick & Smith 2001). Eastern margin rifting separated Australia from New Zealand and the Lord Howe Rise in the Late Cretaceous and allowed incursion of the Tasman Sea at the eastern end of the Gippsland Basin (Hill et al. 1995; Norvick & Smith 2001; Power et al. 2003). Continued fault-controlled subsidence provided accommodation space for deposition of shallow-marine Latrobe Group sediments, and the Oligocene to Holocene carbonates of the Seaspray Group, respectively (Johnstone et al. 2001; Power et al. 2001). The tectonic history of the Gippsland Basin changed from one of extension to one of intermittent inversion, variable uplift and channel incision during the Eocene (Johnstone et al. 2001). The tectonic events driving the intermittent inversion and uplift are difficult to constrain. Postulated tectonic drivers include: (i) strike-slip transpressional tectonics due to plate boundary interactions (Duff et al. 1991; Willcox et al. 1992); (ii) Figure 1 Location map of the Gippsland Basin. The West Tuna area includes the Tuna, West Tuna and East Pilchard localities.

3 In situ stress West Tuna, Gippsland Basin 301 Analysis of the in situ stress field undertaken in this study indicates that the present-day stress is also one of very high horizontal stresses. However it seems unlikely that the tectonic drivers for high horizontal stresses in the Eocene are the same as those which control the contemporary stresses. VERTICAL STRESS The magnitude of the vertical stress is the pressure exerted by the weight of overlying rocks at a given depth. It is calculated by integrating sedimentary rock densities from the surface to the depth of interest (Engelder 1993): s v ¼ Z 0 rðzþg dz ðequation 1Þ z where r(z) is the density of the overlying rocks at depth z and g is acceleration due to gravity. Vertical stress profiles were determined using data from the Tuna 4 exploration well and the West Tuna 39 development well. Three issues must be addressed before density log data can be integrated to obtain vertical stress magnitudes: (i) logging depths need to be converted to true vertical depths sub sea; (ii) the density log must be quality controlled to edit out poor quality data; and (iii) the average density from the surface to the top of the density log must be estimated. The following section outlines the workflow used to calculate the vertical stress profiles in the West Tuna 39 and Tuna 4 wells. Removal of poor quality data Figure 2 Stratigraphic column (modified from Johnstone et al. 2001) collision of the Indo-Australian plate with southeast Asia (Gilbert & Hill 1994; Power et al. 2001); and (iii) ridge push from increased rate of sea-floor spreading in the Southern ocean at the Pacific Australia plate boundary south of Australia and New Zealand (Sutherland et al. 2001). Density logging tools are sensitive to bad hole conditions and read spuriously low when the borehole is enlarged (Rider 2000). Spurious data can usually be removed from density logs by means of a DRHO (bulk density correction) filter. The DRHO value is derived from the difference between long- and short-spaced density measurements and is calculated automatically during logging (Asquith & Gibson 1982). Assuming laterally consistent lithology and good borehole conditions, the long- and short-spaced density measurements should be equal. Asquith and Gibson (1982) suggested that density data are generally inaccurate where the absolute value of DRHO is g/cm 3. However, the tighter criterion DRHO was deemed appropriate for the West Tuna dataset after comparing DRHO, density and caliper logs. The data points that remain after filtering are represented by pink squares in Figure 3. Some very low-density data points remained in the West Tuna data after applying the DRHO filter. Densities 5 2 g/cm 3 are considered unreliable in some studies (Tingay et al. 2002), although coals in the Gippsland Basin are often associated with such low values. Crossplotting density and sonic from the West Tuna wells revealed two clusters of real data points interpreted as clastics and coals (Figure 4). A group of low-density,

4 302 E. J. Nelson and R. R. Hillis Figure 3 Density vs depth plot for Tuna 4. RHOB is the original bulk density log. The plot shows the points that remained after each filtering step. The blue diamonds represent the original resampled data. The pink squares represent the points removed following DRHO (bulk density correction) filtering. The orange data points are those remaining after the borehole condition correction. The light blue data points are those remaining after despiking. The final data points used in the vertical stress calculation are represented by purple stars. high-velocity points considered to be spurious given the absence of evaporites in the region was also revealed. Where data points had a density g/cm 3 and sonic velocity of ms, they were removed from the dataset (Figure 4). The remaining data points are represented by orange squares in Figure 3. Finally, a running median despiking filter and a running average filter were applied to smooth the remaining data. The final, corrected density data used in the vertical stress calculation are coloured purple in Figure 3. Average density from the seabed to the top of the density log Vertical stress calculations require density data from sea-level. The average density from sea-level to the top of the density log run can be estimated by converting checkshot velocity survey data to average density using the Nafe Drake velocity/density transform (Ludwig et al. 1970). Checkshot survey data from the Tuna 4 well were used to obtain an average velocity to the top of the density logs. The Nafe Drake velocity/density transform was calibrated to the Tuna 4 and West Tuna 39 data by cross-plotting density and sonic velocity for each of the wells, and laterally shifting the Nafe Drake transform in order that it passed through the average velocity/density value for the West Tuna area. The recalibrated Nafe Drake transform was then used to obtain an average density to the top of the density log, based on the average velocity to the top of the density log from checkshot data (Table 1). The average velocity to the top of the density log and the calculated average density to the top of the density log are listed in Table 1.

5 In situ stress West Tuna, Gippsland Basin 303 Figure 4 Density vs sonic plot for Tuna 4. RHOB is the original bulk density curve, DT is the sonic slowness (delta time). The cross-plot allows the log data to be quality controlled by distinguishing real (true) data points from spurious data points (see text). Table 1 Average velocity and density to the seabed calculated using a Nafe Drake transform calibrated to the West Tuna area. Well Depth to top of the r log (TVDSS m) Average velocity to top of density log (km/s) Average velocity to top of density log from recalibrated Nafe Drake (g/cm 3 ) Source of checkshot data Tuna Tuna 4 West Tuna Tuna 4 Calculating the vertical stress profile The vertical stress profile from the sea-level was calculated for the Tuna 4 and West Tuna 39 wells (Figure 5). As is commonly seen in other basins (Hillis et al. 1998), the average vertical stress gradient from sea-level to the depth of interest is not constant in the West Tuna area and is approximately 20 MPa/km to 1000 m and 22 MPa/km to 3000 m (TVDSS: true vertical depth sub-sea). This non-linearity can be probably attributed to increasing sediment density with depth (compaction). The vertical stress profile in West Tuna is consistent with the average value of 1psi/ft or 22.6 MPa/km often assumed for vertical stress in the petroleum industry. HORIZONTAL STRESS ORIENTATION Breakouts and drilling-induced tensile fractures form as a consequence of the stress concentration about the wellbore generated during drilling (Aadnoy 1990; Aadnoy & Bell 1998). As the well is drilled, the wellbore wall must support stresses previously carried by the removed rock. This causes stress concentration about the borehole that depends on the orientations of the wellbore and of the far-field in situ stress (Jaeger & Cook 1979; Moos & Zoback 1990; Amadei & Stephansson 1997). The perturbed stress which acts tangential to the wellbore wall is known as the circumferential stress. Borehole breakout is compressive failure that occurs when the maximum circumferential stress exceeds the compressive strength of the rock (Figures 6, 7). Drillinginduced tensile fractures are tensile fractures that form where the minimum circumferential stress is less than the tensile strength of the rock (Figures 6, 7). The orientation of borehole breakouts and drilling-induced tensile fractures in vertical wells has been demonstrated to indicate the orientation of the in situ horizontal stress field (Bell & Gough 1979; Brudy & Zoback 1999). Breakouts and drilling-induced tensile fractures in the West Tuna area were interpreted using resistivity image logs, specifically from the Formation Micro- Imaging (FMI) tool (Ekstrom et al. 1987). Breakout and drilling-induced tensile fracture orientation depends on well deviation and the far-field in situ stress magnitudes (Mastin 1988; Peska & Zoback 1995; Barton et al. 1998). The azimuth of breakout and drillinginduced tensile fractures may not directly reflect the orientation of the horizontal stresses in highly deviated wells (Mastin 1988; Peska & Zoback 1995). Therefore, only breakouts and drilling-induced tensile fractures observed in image logs from vertical to nearvertical parts of the wellbore are considered here (Table 2). Breakouts were observed in vertical sections of the East Pilchard 1 well, and the West Tuna 8, 32, 37, 39 and 44 wells. Drilling-induced tensile fractures were observed in vertical sections of the West Tuna 8 and East Pilchard 1 wells.

6 304 E. J. Nelson and R. R. Hillis Figure 5 Vertical stress profile in the West Tuna area calculated using density data. Black line, West Tuna 39; grey line, Tuna 4. Figure 6 Wellbore stresses diagram illustrating circumferential stress at the wellbore wall. Breakouts occur when the circumferential stress exceeds the compressive rock strength. Axial drilling-induced tensile fractures (DITFs) occur when the minimum circumferential stress is less than the tensile strength of the rock.

7 In situ stress West Tuna, Gippsland Basin 305 Figure 7 Left: a borehole breakout observed in West Tuna-39 (left). The breakout appears electrically conductive (dark) because compressive failure has resulted in parts of the wellbore wall spalling inward which have been replaced by conductive drilling fluid. Depth is in metres. Right: schematic cross-section through a wellbore showing the orientation of breakout formation (in the direction of S hmin ). Table 2 Image logs run in near-vertical sections of the West Tuna wells. Well name Log type Run TVDSS top (m) TVDSS Bottom (m) Average well inclination (8) East Pilchard 1 FMI *0 West Tuna 08 FMI *5 West Tuna 32 FMI *5 West Tuna 37 FMI *15 West Tuna 39 FMI *7 West Tuna 39 FMI *5 Borehole breakout Ninety-one intervals of borehole breakout were interpreted from the six image logs available in the West Tuna area. The average S Hmax orientation derived from the interpreted breakouts is 1388N (Figure 8). The standard deviation of breakout orientation in the six wells is Drilling-induced tensile fractures Five zones of axial drilling-induced tensile fractures were observed in image logs from the West Tuna area; two in the West Tuna 8 development well and two in the East Pilchard 1 exploration well (Table 3). The four sections of drilling-induced tensile fractures interpreted in the West Tuna area indicate a maximum horizontal stress orientation of 1398 N (Figure 8), with a standard deviation of The horizontal stress orientation determined from drilling-induced tensile fractures in the region is highly consistent with the S Hmax azimuth deduced from borehole breakouts. The average S Hmax inferred from breakouts (1388N) is here used to characterise the S Hmax azimuth in the West Tuna area. Comparison of the S Hmax orientation with previous data Previous determinations of maximum horizontal stress were based on logs from 4-arm dipmeter tools at 10 locations across the Gippsland Basin ( ; Hillis & Reynolds 1998). The average maximum horizontal stress orientation based on previous data is 1258N (Figure 9; Table 4). These breakout orientations were interpreted from 4-arm dipmeter logs, which are much less reliable than image log interpretation as evidenced in the scatter of orientations listed in Table 4. The data was inherited when the Australian Stress Map took over the World Stress Map for the region and the origin is unknown. The dipmeter logs were not available for this study and as such the quality of the interpretation could not be assessed. The orientation of S Hmax determined in the West Tuna area herein is consistent within the wells studied and is considered more reliable than the existing data. The S Hmax orientation of 1388N determined herein is still broadly consistent with the orientation calculated previously and confirms a northeast southwest maximum horizontal stress orientation in the Gippsland Basin. MINIMUM HORIZONTAL STRESS MAGNITUDE The most reliable determination of the minimum horizontal stress (S hmin ) magnitude is yielded by hydraulic fracture tests (Enever et al. 1998; Gjønnes et al. 1998). In such tests a tensile fracture is opened in a vertical well by increasing the fluid pressure in an isolated section of the wellbore. The fluid pressure at

8 306 E. J. Nelson and R. R. Hillis Figure 8 Rose diagrams of S Hmax orientation from breakouts and drilling-induced tensile fractures (DITFs). Table 3 Location and orientation of axial drilling-induced tensile fractures in the West Tuna area. Well TVDSS (m) Hole azimuth (8) Hole deviation (8) Pore pressure (MPa/km) Mud weight (MPa/km) East Pilchard West Tuna West Tuna West Tuna East Pilchard which the hydraulic fracture closes provides a direct estimate of S hmin (Bell 1996; Desroches & Woods 1998). Unfortunately, no hydraulic fracture tests have been conducted in the West Tuna area. Leak-off tests are tests run in the wellbore to measure the pressure at which a fracture opens at the wellbore wall and hence the safe operating mud-weight window. These tests are routinely run in the Gippsland Basin. Leak-off test data are not as reliable as fracture closure pressures for the determination of S hmin. This is largely because the leak-off pressure (or fracture-opening pressure) is strongly influenced by the disturbed stress field at the wellbore wall. The leak-off pressure must also overcome the tensile strength of the formation which is often unknown. Despite this, it is widely accepted that the lower bound to leak-off pressures in vertical wells gives a reasonable estimate of the magnitude of S hmin (Haimson & Fairhurst 1967; Kunze & Steiger 1992). Leak-off tests in the Gippsland Basin are conducted to ensure that the formation will withstand the maximum expected mud weight required to drill the next section of hole. For this reason many leak-off tests are stopped at a pre-determined pressure that does not fracture the formation. Leak-off tests which do not fracture the formation are referred to as formation integrity tests. In a leak-off test, the pressure in the wellbore increases linearly with volume of drilling mud pumped until a fracture forms at the wellbore wall. After fracturing, the wellbore pressure increases less rapidly with mud volume pumped, resulting in an inflection point on the pressure vs volume-pumped plot (Figure 10). The point of inflection is known as the leak-off pressure. Pumping is stopped after the leak-off point and the pressure then declines rapidly until a second inflection point known as the fracture-closure pressure is reached (Figure 10). The closure pressure is presumed to be equivalent to the magnitude of S hmin because at this point the fluid pressure in the fracture equals the S hmin acting to close the fracture (Haimson & Fairhurst 1967). The leak-off pressure is often slightly higher than the closure pressure (Figure 10). Historically, the pressure decline is not monitored in the Gippsland Basin, only one test from the West Tuna 39 well provides a closure pressure (Figure 10). Minimum horizontal stress from leak-off tests Formation integrity tests are often, incorrectly, recorded as leak-off tests. Hence pressure (or volume pumped) vs time records should be checked to verify leak-off test pressure values recorded in daily drilling or well-completion reports. Unfortunately only one pressure vs volume-pumped plot was available for this study. Most leak-off pressures were only recorded as equivalent mud weights in daily drilling reports. While leak-off pressures in vertical wells reflect the horizontal stresses, the same pressure tests from deviated wells are a function of the vertical and horizontal stresses and wellbore trajectory with respect to those stresses (Aadnoy 1990; Brudy & Zoback 1993). In this study, only leak-off pressures from vertical wells were used to constrain S hmin in the West Tuna area. One leak-off test and one closure pressure were available

9 In situ stress West Tuna, Gippsland Basin 307 Figure 9 (a) S Hmax orientation from the Australian Stress Map (Hillis & Reynolds 2000). (b) S Hmax orientation determined from the interpretation of breakouts on FMI (Formation Micro Imager) images in the West Tuna area. Table 4 Previously calculated S Hmax orientations in the Gippsland Basin. Locality S Hmax Azimuth (8N) Flounders 122 Hapuku Fortescue 1 80 Whiting Selene Omeo Hermes Helios Wirrah Wirrah Source: 5 Australian Stress Map 4 Figure 10 Pressure vs volume-pumped record for a leak-off test undertaken in the West Tuna 39 development well.

10 308 E. J. Nelson and R. R. Hillis form a pressure vs time plot for West Tuna 39. Three reported leak-off pressures were available from the Tuna 4 exploration well-completion report (Table 5; Figure 11). The five data points are consistent and indicate S hmin *20 MPa/km (Figure 11). A minimum horizontal stress gradient of *20 MPa/km is high compared with those reported in other Australian basins (Hillis et al. 1998). For example leak-off pressures from the neighbouring Otway Basin suggest the minimum horizontal stress in the Otway Basin is *16 MPa/ km (Hillis et al. 1995). A leak-off test conducted in the Kipper 1 well (Gippsland Basin) also indicates a S hmin gradient of *20 MPa/km in the Kipper Field. This suggests that the minimum horizontal stress in the Gippsland Basin is consistently high. Table 5 Leak-off test data from the West Tuna area of the Gippsland Basin. Well name Depth (TVDSS) Type Pressure (MPa) Tuna REP_LOT 16.7 Tuna REP_LOT 47.6 Tuna REP_LOT 62.7 West Tuna LOT 43.3 West Tuna CLOSURE 41.6 PORE PRESSURE Pore pressure data can be obtained from formation tests using wireline tools (e.g. repeat formation tests and modular dynamics tests) and from drill stem tests. In repeat formation tests and modular dynamics tests a probe is placed against the wellbore wall and isolated with a packer. Pressure is then reduced in the test chamber drawing fluid into the probe. The rate at which the pressure stabilises in the test chamber gives a measure of permeability, and the equilibrium pressure provides the pore fluid pressure (Zimmerman et al. 1990; Goode et al. 1991). Pore pressures were determined from modular dynamics tests in five of the West Tuna development wells (West Tuna 8, 31, 32, 39, 44) and the Tuna 4 and East Pilchard 1 exploration wells. The pore pressure gradient in the West Tuna area is generally hydrostatic, with no evidence of overpressuring above 2800 m TVDSS (Figure 12). This depth coincides with the depth of the volcanics that mark the boundary between deep intra-latrobe Group and Golden Beach Subgroup reservoirs. The pore pressure in sandstones below the volcanics are 6 MPa overpressured at 3000 m TVDSS in West Tuna 39 (Figure 12). The East Pilchard 1 well is slightly (0.5 MPa/km) overpressured from *2600 m (Figure 12). None of the leakoff test pressures were from overpressured intervals. MAXIMUM HORIZONTAL STRESS MAGNITUDE The S Hmax magnitude can be determined where breakouts or drilling-induced tensile fractures are observed on image logs and where the compressive rock strength or tensile rock strength respectively is known (Bell & Gough 1979; Brudy & Zoback 1999). Unfortunately no rock-strength data are publicly available for the Gippsland Basin. The tensile strength of general, reservoirtype rocks is often assumed to be negligible (Wiprut et al. 1997; Barton et al. 1998; Brudy & Kjorholt 2001). If the tensile strength of the reservoir rocks in the West Tuna area is considered to be zero then axial drilling-induced tensile fractures observed on image logs may be used to constrain the S Hmax magnitude. Tensile failure occurs when the minimum circumferential stress (stress tangential to the wellbore) is less than the tensile strength of the rock (Figure 6). The criterion for formation of axial drilling-induced tensile fractures in elastic, impermeable rocks in vertical wellbores can be represented by the equation: s yy min ¼ 3S hmin S Hmax DP T; ðequation 2Þ where s yymin is the minimum circumferential stress, DP is the difference between the mud weight and pore pressure and T is the tensile rock strength (Hubbert & Willis 1957; Peska & Zoback 1995). Assuming T = 0 then Equation 2 becomes: Figure 11 West Tuna leak-off test (LOT) data. The black line represents the average S hmin gradient and is equal to 20 MPa/km. s yy min ¼ 3S hmin S Hmax P w P p 0 : ðequation 3Þ Five sections of drilling-induced tensile fractures were observed in the study area (Table 3). The pore pressure

11 In situ stress West Tuna, Gippsland Basin 309 Figure 12 Pore pressure in the West Tuna area determined using modular dynamics test data. The pressure gradient is normal above 2800 m except in the East Pilchard 1 well which is slightly overpressured below 2600 m. and mud weight at the depth of drilling-induced tensile fractures occurrence are recorded in Table 3. Substitution of the in situ stress tensor determined herein (S hmin, P p and P w ), into Equation 3, indicates that the magnitude of S Hmax in the West Tuna area is *39 MPa/km. The S Hmax magnitude calculated using Equation 3 in the West Tuna area is likely to be a lower bound to S Hmax, since the drilling-induced tensile fractures in West Tuna 39 and East Pilchard 1 are well developed and it is likely that the tensile strength of the West Tuna rocks (which are consolidated and cemented) is greater than zero. Allowable region diagram The range of possible relative principal stress magnitudes for normal, strike-slip and reverse faulting environments can be visualised on an allowable region diagram (Moos & Zoback 1990). The allowable stress conditions for a particular geographic region can be assumed to lie within an area defined by frictional limits (Figure 13). Frictional limits theory states that the ratio of the maximum to minimum effective stress cannot exceed the magnitude required to cause faulting on an optimally oriented, pre-existing, cohesionless fault plane (Sibson 1974). The frictional limit to stress is given by: S 1 P p S 3 P p qffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi 2 ðm 2 þ 1Þþm ðequation 4Þ where m is the coefficient of friction on an optimally oriented pre-existing fault, S 1 is the maximum principal stress and S 3 is the minimum principal stress (Jaeger & Cook 1979). In a reverse stress regime (S Hmax 4 S h- min 4 S v ) or strike-slip stress regime (S Hmax 4 S v 4 S hmin ) where S Hmax is S 1 (and S hmin or S v are S 3 and known), then frictional limits provide an upper bound to S Hmax. A m of 0.6 is normally considered an average value for reservoir rocks (Handin 1969; Byerlee 1978). The frictional limits equation (Equation 4) constrains the allowable values of S Hmax in the West Tuna area to within the black outline in Figure 13 (assuming P p = 9.8 MPa/km and m = 0.6). The criterion S Hmax 5 S hmin further constrains the possible stress states to the upper left of the pink line, and hence to the frictional limits polygon in Figure 13. The green lines representing

12 310 E. J. Nelson and R. R. Hillis Figure 13 Allowable region diagram for the West Tuna area of the Gippsland Basin. The cross represents the in situ stress tensor of the West Tuna area determined herein. NF, normal fault regime; SS, strike-slip fault regime; RF, reverse fault regime. See text for discussion. S Hmax =S v and S hmin =S v separate the normal, strike-slip and reverse fault regimes (Figure 13). Observation of drilling-induced tensile fractures also help constrain the allowable stress space, and hence the magnitude of S Hmax. The circumferential stress is plotted as a blue line in Figure 13. The maximum horizontal stress magnitude must lie in the region to the left of the blue line in order for drilling-induced tensile fractures to form. Therefore the S Hmax magnitude can be constrained to less than the frictional limit value and greater than the drilling-induced tensile fractures value (the yellow area in Figure 13). The magnitude of S hmin / S v has been plotted as a dashed red line in Figure 13. If the West Tuna stress tensor (S hmin *20 MPa/km, S v *21 MPa/km, P p *9.8 MPa/km, P w *11.2 MPa/km) is considered (where m = 0.6) and substituted into Equation 4, then the S Hmax magnitude can be constrained to MPa/km. The observation of drilling-induced tensile fractures on image logs combined with knowledge of S hmin,p p and P w can therefore constrain the stress field in the West Tuna area to one on the border of strike-slip and reverse faulting (S Hmax 44S hmin * S v ). IMPLICATIONS FOR THE ORIGIN OF REGIONAL STRESSES IN THE GIPPSLAND BASIN Regionally uniform horizontal tectonic stress orientations are observed over wide intraplate areas within the crust (Richardson et al. 1979; Richardson 1992; Zoback 1992). In most plates the maximum horizontal stress orientation parallels the direction of absolute plate motion (Zoback 1992). The orientation of S Hmax in the Indo-Australian Plate, and in Australia in particular, is more complex than in many of the other plates/continents (Coblentz et al. 1995). Regional S Hmax orientation in Australia does not simply parallel the absolute plate motion. However modelling of the Indo- Australian stress field has shown that regional stress rotations in Australia can be accounted for in terms of plate-boundary forces once allowance is made for the complex plate-boundary configuration of the Indo- Australian Plate (Richardson et al. 1979; Reynolds et al. 2003). A S Hmax orientation of 1388N has been determined herein for the West Tuna area of the Gippsland Basin. As mentioned previously, this orientation is consistent with that previously determined for the Gippsland Basin and reported in the Australian Stress Map (Hillis & Reynolds 2000). The S Hmax orientation in the Gippsland Basin is also consistent with the S Hmax orientation of *1318N previously determined in the Otway Basin (Hillis & Reynolds 2000). The consistent (northeast southwest) nature of the maximum horizontal stress direction in the Gippsland Basin, and indeed southeast Australia, suggests the primary control on the in situ stress field is largely tectonic. Two models for explaining the controlling factors for the orientation of the stress field in southeast Australia have been proposed in the literature. These are: (i) the Pacific Australian plate boundary and generation of Alps in New Zealand (Coblentz et al. 1995, 1998; Sandiford 2003); and (ii) density structure associated with the development of the eastern Australian margin (Zhang et al. 1998). The latter point is considered more likely to influence the local stress regime and not the tectonic stress in the

13 In situ stress West Tuna, Gippsland Basin 311 southern (Gippsland, Bass, Otway Basins) margin where there is no prominent coastal escarpment (Sandiford et al. 2004). Compressional structures and inversion in the Gippsland Basin date back to the Eocene (Johnstone et al. 2001; Power et al. 2003). The tectonic influence on the compressional force has been postulated to be ridge push from the onset of fast sea-floor spreading in the Southern Ocean (at the Pacific Australia plate boundary south of Australia and New Zealand) and the effects of collision of the northern Australian Plate with southeast Asia (Norvick & Smith 2001; Power et al. 2001; Sutherland et al. 2001). Finite-element modelling has shown that the northwest southeast maximum horizontal stress orientation in southeast Australia and the Gippsland Basin cannot be explained by considering only the plate-boundary forces and collisional zones along the northern plate boundary which resist plate motion (Reynolds et al. 2003; Sandiford et al. 2004). Rather, stress focusing at collisional boundaries also has to be considered (Coblentz et al. 1995; Coblentz et al. 1998; Reynolds et al. 2003). The modelling of Coblentz et al. (1998) and Reynolds et al. (2003) has shown that compressional forces along the New Zealand and south of New Zealand plate-boundary segments can account for a northwest southeast maximum horizontal stress direction in the Gippsland Basin (Reynolds et al. 2003). Oblique compression has occurred at the Australian Pacific plate boundary since 6.4 Ma (Walcott 1998). Transpression is documented to have resulted in 90 km of shortening since 6.4 Ma along the central Alpine Fault (Walcott 1998). As oblique compression at the Alpine Fault is young it cannot account for the high horizontal stress magnitude and horizontal stress orientation that resulted in the Eocene to Miocene inversion structures. Although the orientation of the stress tensor responsible for the Eocene to Miocene inversion and the contemporary stress are consistent they have resulted from different tectonic drivers. The horizontal in situ stress magnitude is much higher in the Gippsland Basin than in the Otway Basin. The Otway Basin is considered to be in a strike-slip stress state with relative magnitudes of S v *21.7 MPa/ km, S hmin *15 MPa/km and S Hmax *24 26 MPa/km (Meyer 2002). This difference in horizontal stress magnitude suggests that the influence of the compressional boundary in New Zealand on in situ stress is dependent on proximity to the plate boundary. It is therefore proposed that the in situ stress tensor in the Gippsland Basin is due largely to its proximity to the compressional boundary at New Zealand. SUMMARY An S Hmax orientation of *1388N has been determined from 91 breakouts and five intervals of axial drillinginduced tensile fractures in the West Tuna area, Gippsland Basin. Vertical stress magnitudes range from 20 MPa/km at 1000 m to 22 MPa/km at 3000 m TVD. Four leak-off tests indicate that the magnitude of S hmin is approximately 20 MPa/km. Occurrence of drillinginduced tensile fractures and the frictional limits equation constrained the magnitude of S Hmax to between *39 and *42 MPa/km, given the known magnitudes of P p and S hmin. The in situ stress tensor determined herein suggests the contemporary stress regime in the West Tuna area is on the border between strike-slip and reverse faulting. 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