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APPEA Journal 2015—1FINAL PROOF—HOSKIN 06 FEBRUARY 2015

E. Hoskin1, S. O’Connor1, S. Robertson2, J. Streit3, C. Ward1, J. Lee1 and D. Flett4

1Ikon GeopressureThe Rivergreen Centre, Aykley HeadsDurham, United Kingdom, DH1 5TS2Santos LtdLevel 22, 32 Turbot StreetBrisbane, Queensland 40003Woodside Energy Ltd240 St Georges TerracePerth, WA 60004Ikon Science Asia Pacific45 Ventnor AvenueWest Perth, WA [email protected]

ABSTRACT

The Northern Carnarvon Basin has a complicated geological history, with numerous sub-basins containing varying formation thicknesses, lithology types, and structural histories. These set-tings make pre-drill pore pressure prediction problematic; the high number of kicks taken in wells shows this.

Kicks suggest unexpected pore pressure was encountered and mudweights used were below formation pressure. The horst block penetrated by the Parker–1 well is focused on in this peer-reviewed paper. This horst is one of many lying along Rankin Trend’s strike. In this well, kicks up to 17.2 ppg (pounds per gallon) were taken in the Mungaroo reservoir. The authors investigate whether the kicks represent shale pressure—or rather, represent pressure transferred into foot-wall sandstones—by using well data from Forrest 1/1A/1AST1 and Withnell–1, and wells located in the Dampier Sub-basin and the hanging-wall to the horst. This anomalous pressure could result from either cross-fault flow from juxtaposed overpressured Dingo Claystone or transfer up faults from a deeper source.

Using a well data derived Vp versus VES trend, the authors establish that the kicks taken in Parker–1 are more likely to result from pressure transfer using faults as conduits. These data lie off a loading trend and appear unloaded but likely represent elevated sand pressures and not in situ shale pressure. Pressure charging up faults in the Northern Carnarvon Basin has been recognised in Venture 1/1ST1, however, this paper presents a focused case study.

Pressure transfer is noted in other basins, notably Brunei. From unpublished data, the authors believe that buried horst blocks, up-fault charging and adjacent overpressured shale may explain high reservoir pressures in other basins, including Nam Con Son in Vietnam.

KEYWORDS

North West Shelf, Carnarvon Basin, Dampier, Barrow, Rankin Trend, fault, pressure, transfer, lateral, overpressure mechanisms, reservoir, Bowers, loading, unloading, vertical effective stress (VES), velocity, Dingo, Mungaroo, kicks, horst, graben, Parker–1, Withnell–1, Venture–1.

Influence of faulting on reservoir overpressure distribution in the Northern Carnarvon Basin

Lead author EdHoskin

INTRODUCTION

The Northern Carnarvon Basin is part of the Australian North West Shelf and is bordered to the north by the Roebuck and off-shore Canning basins and by the Southern and Perth basins to the south (Fig. 1). The seawater depth of the basin ranges from less than 10 m in near-coastal waters to up to 2,000 m in the outer shelf, while Barrow Island, in the southeast, is above sea level. It is a highly petroliferous basin, with close to 1,000 exploration and appraisal wells drilled to date. Many of these wells have encountered problems associated with unexpected pore pres-sure while drilling (Tingate et al, 2001). Wells identified as highly pressured in the Northern Carnarvon Basin include Parker–1, Dixon–1, Forrest 1/1A/1ST1, Venture 1/1ST1 and 2ST1, and Bar-row L35J and F24J (Dodds et al, 2001).

There has been a lot of focus on the overpressure genera-tion mechanisms in the Carnarvon Basin. Some of these stud-ies examined very small areas, while others were more regional. Some studies include detailed petrophysical, geochemical or geophysical analysis into the origins of overpressure. Dodds et al (2001) provided a useful summary of which mechanisms were considered important, divided by sub-basin. For instance, dis-equilibrium compaction or ineffective dewatering (Swarbrick et al, 2002) was recognised as a major generator of overpressure by Nyein et al (1977), Vear (1998), Russell (1998), Swarbrick and Hillis (1999) and Tingate et al (2001). These authors also recog-nised hydrocarbon generation as a source, although only Russell (1998) recognised it as a major contributor. Earlier studies such as Horstmann (1988), Zaunbrecher (1994) and Yassir and Bell (1996) considered that hydrocarbon generation was the domi-nant process. Studies such as Swarbrick and Hillis (1999) and Dodds et al (2001) identified gas—as opposed to oil generation, in particular—as the key process.

Later studies have been less specific in identifying secondary processes that contribute to overall overpressure in the basin, referring to those processes collectively as fluid expansion. For example, the actual fluid expansion mechanism could not be determined from porosity verses vertical effective stress (VES) in van Ruth et al (2004). The authors do, however, speculate that there are several possible fluid expansion mechanisms; for ex-ample, oil cracking to gas, thermal pressuring or lateral transfer of pressure.

Previous studies relied predominantly on conventional data such as drill stem tests (DSTs), wireline formation tests (WFTs), and mudweight data (e.g. Horstman, 1988; van Ruth et al, 2000; Tingate et al, 2001; van Ruth et al, 2004). More recently, Sagala and Tingay (2012) have used drilling data such as connection gases and kicks to conclude that fluid expansion is the operative mecha-nism for the highly overpressured wells around the Alpha Arch and Bambra area. The data chosen for their study were selected because they allowed them to focus on understanding purely shale pressure processes. The relative contribution of disequilibrium compaction and other processes are quantified in studies such as Swarbrick and Hillis (1999). Bekele et al (2001) specifically states that organic maturation contributes approximately 15% to the maximum pressure anomaly within the Barrow Sub-basin.

2—APPEA Journal 2015 FINAL PROOF—HOSKIN 06 FEBRUARY 2015

E. Hoskin, S. O’Connor, S. Robertson, J. Streit, C. Ward, J. Lee and D. Flett

Finally, lateral stress increase through compressional tectonics has been proposed as a cause of additional overpressure. North-northeast trending anticlines of the Carnarvon Basin have seen Neogene-to-Recent growth, including the Barrow Island oilfield located in the Barrow Island inverted anticline. This is the result of Neogene-to-Recent intraplate deformation in the Australian continent (Hillis et al, 2008). Swarbrick and Hillis (1999), how-ever, state that although there have been indications of compres-sional structures, especially in the Neogene of the North West Shelf; these are localised and it is not thought to contribute to overpressure as significantly as vertical stress increase.

Analysing the re-distribution of overpressure around a basin is as equally important as understanding its mechanism of genera-tion. This re-distribution occurs in permeable aquifers. Otto et al (2001) and others have discussed that aquifers can be regional in nature, and divided the stratigraphic column based on hydro-stratigraphy (i.e. a series of regionally connecting sandstones such as Mungaroo and equivalent, Angel and equivalent, and Barrow Group sandstones and equivalent). These are separated by aquitards such as the Muderong Shale and Dingo Claystone. The implication of this is that any pressure generated in the shales by the processes described above can be communicated and dis-sipated across large distances. Both Vear (1998) and Otto et al (2001) imply that these aquifers are hydrodynamic in nature.

Extensive aquifers are one method for pressure transfer in a basin; these aquifers tend to drain pressure from the surround-ing shales and thus have less overpressure than the fine-grained lithologies surrounding them. Juxtaposition across faults and up-faults provides alternative methods for pressure re-distribution. Examples are reported from this basin; for example, Tingate et al (2001) propose that overpressure in the Muderong Shale in the Venture 1/1ST1 well is fault-related. Van Ruth et al (2004) identi-fied fluid expansion as a potential mechanism of overpressure generation in their analysis of overpressures in Carnarvon, specu-lating that this anomalous overpressure was as a result of pressure transfer. Although not stated specifically, up-fault communication would be a logical deduction from this statement. In contrast to the regional aquifers, the overpressure in these up-fault-charged reservoirs would be higher than the surrounding shales.

In this peer-reviewed paper, a horst block penetrated by the Parker–1 well, drilled in 1979, is focused on. This block lies on the edge between the Rankin Trend and the Dampier Sub-basin (Fig. 2). The authors establish that kicks encountered in the Mungaroo reservoir lay substantially off a loading curve; that is, a Vp (from sonic converted to compressional velocity in m/s) versus VES trend, suggesting fluid expansion, in line with pre-vious analyses. In this study, however, the authors specifically identify the fluid expansion mechanism as pressure transfer up the associated fault. This is shown by the hanging wall shale overpressures (penetrated by Withnell–1) being insufficient at the depth of the Parker–1 kicks to be the cause of overpressure in the Mungaroo by cross-fault flow. Without first calculating the background shale pressures, an assessment of the kicks in terms of whether they are similar to/exceed/are less than shale pressures cannot be ascertained.

Pressure transfer is not a new observation globally, as various studies such as Offshore Brunei (Grauls and Baleix, 1994), Eugene Island 330 Field, Gulf of Mexico (Finkbeiner et al, 2001) and Brunei (Tingay et al, 2007; 2009) highlight this process as an important mechanism for generating overpressure in reservoirs. Vertical transfer has similarly been identified in the Malay Basin by Ma-don (2007) and in the northern Malay Basin (Tingay et al, 2013).

Pressure transfer has been mentioned in the Carnarvon by Tingate et al (2001) and van Ruth et al (2004). The authors of this paper believe this study is the first attempt to focus on a particular horst block. The authors determine in situ shale pres-sure using a Vp versus VES trend to explain whether the reservoir pressures in the footwall are appropriate for their depth of burial or are anomalous. The conclusion is that pressure transfer up fault explains their magnitude. This workflow can be used to aid future well planning in similar structural settings in Carnarvon and in other global basins, by way of calculating the maximum possible reservoir pressures in prospects, assuming complete up-dip transfer from fault sole depths. An application of this workflow in Nam Con Son in Vietnam, for instance, may help to de-risk the horst block plays; where, from the authors’ expe-rience (unpublished), pressure transfer seems evident in res-ervoirs, and these unexpected pressures are a drilling hazard.

Figure 1. Map of the Northern Carnarvon Basin showing sub-basins and wells used in the analysis. Line of section is shown in red (Fig. 3).



GEOLOGICAL BACKGROUND

The geological history of the Northern Carnarvon Basin is vital to further understand why pressure distribution and gen-eration are problematic. It is subdivided into seven main sub-basins (Fig. 1), but can also be described as consisting of three main zones of geological similarity: 1. in-board structural high areas of the Peedamullah and

Lambert shelves; 2. the intermediate zone, consisting of the large depocentres

of the Beagle, Dampier, Exmouth and Barrow sub-basins; and,

3. the extensive marginal Exmouth Plateau, and the Rankin Trend, an uplifted outboard margin (He and Middleton, 2002; Geoscience Australia, 2013).

Each of these three provinces has its own unique character-istics that have influenced stratigraphy, structure, depositional history, and resulting overpressure generation and distribution. The basins that will be the focus of this paper are in zones 2 and 3, and Figure 1 shows the location of the wells that feature in this paper.

The evolution of basin stratigraphy in the Northern Carnar-von Basin can be separated into three phases:1. Late Paleozoic (Silurian) to Late Triassic extensional pre-

rift phase, creating significant accommodation space. This was filled with a thick Triassic fluvio-deltaic section containing both major gas prone source rocks and key sandstone reservoir targets.

2 Early Jurassic to Early Cretaceous (Valanginian) syn-rift phase, resulting in well-defined northeast–southwest trending rift depocentres. Rapid deposition in these de-pocentres has resulted in the formation and preservation of good-quality oil and gas source rocks—for example, Dingo Claystone—as well as zones of overpressure that are investigated in this study. The Dingo Claystone gradu-

ally filled the depocentres of the Barrow, Dampier and Exmouth sub-basins, and overlapped the flanks of the high fault blocks (Tindale et al, 1998). The majority of kicks in Upper Jurassic sequences have been observed in parts of the basin where the Dingo Claystone exists. Hinterland uplift provided a variety of sediment sources/provinces, producing the stratigraphic complexity seen in the sub-basins. Major hydrocarbon reservoirs (namely Angel, Dupuy, Biggada, and Eliassen) were deposited during this phase in primarily shallow marine to deepwater environ-ments (Jenkins et al, 2003; Moss et al, 2003). Many of these sandstone units were regionally extensive—for example, the Angel Formation—and pressures are, on the whole, at or near hydrostatic pressure conditions and lower than the surrounding shale overpressure (Vear, 1998; Otto et al, 2001). Dodds et al (2001) state that pressure is being dis-sipated and dispersed by these large aquifer systems. Not all of the sandstones are regionally extensive. The Biggada sandstone may form isolated turbidity channels perhaps on the flanks of the main channels (Jenkins et al, 2003; Moss et al, 2003). These more restricted sand intervals are more likely to have similar pressures to the surrounding shales.

3. Early Cretaceous (Valaginian) to Recent passive margin conditions, (punctuated by a period of Miocene compres-sion) with marine sag phase shales overlain by prograding Mid Cretaceous (e.g. Muderong shales) to Recent carbon-ate shelf deposits (He and Middleton, 2002). This age was punctuated by a period of Miocene compression that resulted in up to approximately 900 m of uplift (Densley et al, 2000). This uplift was most significant in areas such as the Legendre Trend and the Alpha Arch. In reviews of over-pressure mechanisms by van Ruth et al (2004) and Sagala and Tingay (2012), many of the wells associated with fluid expansion are in these uplifted areas.

Figure 2. Schematic based on the original seismic line showing structural features of the basin trending northwest–southeast. Wells are shown in relative, rather than actual, locations on the line (image adapted from Geoscience Australia, 2012). Parker–1 is located on a horst; Withnell–1 and Forrest 1/1A/AST1 are located in the hanging wall. Webley–1A is drilled into the horst overburden.



METHODS AND DATABASE

The focus of this paper is primarily the Parker–1 horst block. Mungaroo at this location has several large kicks associated with the reservoir. These kicks (and other relevant geological information) are displayed in pounds per gallon (ppg) in Figure 3. Shale pressure can be estimated using various data types. Sagala and Tingay (2012) successfully used drilling data such as kicks and connection gases to determine pressure. Other approaches involve using seismic velocity data or wireline log data and a choice of algorithms, based on the overpressure generating mechanisms present. For a general review of these approaches Mouchet and Mitchell (1989) is suggested.

The authors of this paper sourced data for the study from multiple sources. These data primarily consisted of well comple-tion reports (WCRs) from which information such as kick data, temperature and drilling data (gas, D-exponent), age markers, lithology from composite logs, and lost circulation data could be extracted. Digital wireline logs were also used, mainly: GR (gamma ray), Vp, resistivity, Rho (density), and neutron.

Seismic data such as amplitudes for visualisation and veloc-ity for pressure prediction were not available, except for those images available in the public domain and/or in WCRs. Tem-perature data, either DST or wireline-derived, were corrected for time since circulation.

The following steps were undertaken to establish shale pressure in the Dingo Claystone. This formation is juxtaposed against the Mungaroo in Parker–1. To select the correct algo-rithm to use for shale pressure prediction, the mechanism of overpressure generation also had to be determined.1. A common (normal) or hydrostatic pressure gradient of

a well was defined from the reservoir pressure measure-ments; that is, WFTs. No wells featured in this paper had WFT data. Other wells studied (but not published in this paper) suggest a concentration in values between 0.432 psi/ft and 0.434 psi/ft. There was no identifiable systematic variation of gradient between the wells anal-ysed, and the lack of salts and anhydrites gave confidence to use a relatively freshwater hydrostatic gradient in the shale pressure calculation. Published hydrostatic gradients

Figure 3. Well correlation panel through the main wells described in this paper, showing GR, lithology and overpressure values (ppg). Line of section is shown in Figure 1. The kick data in Parker–1 is up to 1 ppg higher than in the neighboring shales at the same depth. This is suggestive of pressure transfer up-fault. Background shale pressure is 16 ppg.



are rare; more commonly, these gradients are shown on pressure-depth plots but no specific gradients are provided (e.g. Otto et al [2001]).

2. Density data (Rho) were used to either build or blind test the overburden model. Prior to using the logs, they were quality controlled, and spurious non-geological data were edited. The edits were made with reference to the Rho correction log (DRHO) as well as cross-plots of Vp versus Rho. Where DRHO logs were not available, caliper-based out of gauge zones were identified by subtracting the caliper from the bit size. A two-layer overburden pressure model was produced (derived from density trends), and could be applied wherever the two following stratigraphic layers were identifiable: seabed to Top Windalia Radiola-rite or equivalent; and, Top Windalia Radiolarite to well total depth (TD). These overburden models, when tested, agreed within 1.6% of an overburden generated directly from Rho data. The results are comparable to the King et al (2010) paper where overburden pressure gradients spanned between 0.89 psi/ft and 1.05 psi/ft. No attempt was made to compare the model to the overburden algo-rithms in van Ruth et al (2004) or Sagala and Tingay (2012).

3. Kick data were available for this study. Where possible, shut-in drilling pipe pressures (SIDPP) were used for the non-swab kicks; for the swab kicks, kick pressure should be just lower or equal to the initial mudweight. The kick data correlated—once units were converted—with those values is published in Sagala and Tingay (2012). Some examples of the key kicks include:a) Forrest 1/1A/1AST1 had a gas kick at 3,809 m (MD

[measured depth]), which required the mudweight to be weighted to 14.5 ppg. A swab kick, in which 12 bar-rels was gained after a 10-stand wiper trip, occurred at 4,036 m (MD) and mudweight was increased to 16.0 ppg. In addition, another swab kick of 0.5 barrels was seen on a trip out at TD. The kicks at 3,809 m and 4,036 m (MD) were in Dupuy, and the swab kick at TD was taken when the bit was in the Dingo Claystone.

b) Parker–1 had a saltwater kick at 4,559 m (MD), which required an increase of mudweight to 16.2 ppg, and then drilling continued to 4,627 m (MD) where a second salt-water kick occurred, which had to be killed with a mud-weight of 17.2 ppg. These kicks occurred in Mungaroo.

4. The authors investigated overpressure generation mecha-nisms using Vp versus Rho and vertical effective stress (VES) versus Vp cross-plots, where VES is calculated from overburden minus pore pressure. The cross-plots were used to help distinguish between overpressures generated by low-temperature processes like disequilibrium compaction and overpressure generated by fluid expansion. A review of this process is contained in Swarbrick (2012). Only shale data is used in this analysis; volume shale (Vsh) cut-off at 0.6 has been applied to highlight only shale data. A limitation of this approach is that deep Rho data is noticeably absent in many wells in the Northern Carnarvon Basin, from the authors’ experience; an example of this is Forrest 1/1A/1AST1. Where Rho data is available, however, the mechanisms of overpres-sure generation have been assessed. Since the three main wells in this paper have minimal shallow Rho data, the au-thors also included data from the Withnell Formation from Webley–1A. The well did not reach its Triassic objective in 1998, leaving the horst structure untested. It was abandoned due to operational difficulties related to an overpressured Windalia Radiolaria, where several kicks were taken. The Withnell Formation, regionally, is shale and marl, however, in Webley–1A there are some non-calcareous strata in the in-terval above 2,685 m (MD) stated in comments in the WCR.

Also, the Late Cretaceous Withnell Formation is indicated as shale rather than carbonate in the Dampier Sub-basin (Gradstein et al, 2004).

5. A Vp versus VES plot, similar to that described in Bowers (1995), has also been plotted. Any data that lies off this trend are said to be unloaded. Some VES values added to the plot are calculated from mudweight values. Mudweight should always be treated cautiously, as a direct indicator of pore pressure magnitude; indeed, Vear (1998) states that the Muderong has often been drilled under-balanced (i.e. the Muderong Shales have been drilled with a mudweight lower than the actual formation pressure). Where mudweight has been used as a pressure proxy in this paper, however, drilling data such as connection gases were consulted to ensure it was likely at a similar level compared to the pore pressure of the well. Similar data types were used successfully in the Sagala and Tingay (2012) paper.

RESULTS

Mentioned in the methods and database section, one of the methods available to identify overpressure generating mecha-nisms is to plot shale Vp versus Rho. The trends commonly identified are described in Swarbrick (2012); however, to sum-marise, the Rho log is invariant where fluid expansion is pres-ent. Thus, a sharp drop in Vp for minimal Rho change, except for that due from elastic rebound (approximately 1%), suggests gas generation is active in the shales. If density increases, then this implies either changes in rock compressibility (a process termed load transfer/framework weakening by Osborne and Swarbrick [1997]) or cementation occurs. These processes all have implications for pore pressure, to differing degrees. A re-view of these processes and their implications is included in Swarbrick et al (2002). Ineffective dewatering or disequilibrium compaction shows a trend where both Vp and Rho increase or decrease, depending on porosity preservation in relation to effective stress.

Figures 4 to 9 show the results of Vp versus Rho cross-plotting from the wells featured in this study. A 75 m Gauss-ian smoothing filter was applied to the Vp and Rho data and a 0.6 Vsh cut-off applied. These figures are coloured by well, for-mation, depth (TVDbml [total vertical depth below mudline]), temperature, VES and pore pressure gradient (psi/ft).

Figure 4. Well data plot by velocity and density. Data coloured by well). The majority of the data define a trend sub-parallel to the Gardner Shale. The Withnell Formation shales in Webley–1A plot in a similar position to the Dingo Claystone shales in Withnell–1.



The data in Figure 9 is coloured by pore pressure gradient. The colour-coding enables the path taken by the data to be tracked.

In Figures 4 and 5 the data are shown by well and by general formation. Figure 6 shows the same data by depth below the seabed and the same data are shown by temperature (Fig. 7), referenced to the same datum. In all cases, a trend line (red dotted line) is sub-parallel to Gardner shale (green line). Figure 8 shows that the VES decreases along this trend with stratigraphic age. This is most clear in Forrest 1/1A/1AST1, which has the longest combined Vp and Rho log run. Finally, Figure 9 shows an increase in pore pressure as expressed in pressure gradient. This plot shows an increase in pore pressure gradient and reversals in Vp and Rho. Ideally, these reversals would have been observed in a single well, but few wells have continuous sections of Rho logged through thick sections of Muderong Shale and Dingo Claystone. Figures 4 to 9, however, show that these reversals and increase in pore pressure gradi-ent are consistent with increasing depth and stratigraphic age; that is, the data can be treated as a whole. The observed rever-sal in Rho is larger than could be attributed to purely elastic rebound, which suggests that disequilibrium compaction is

Figure 7. Data coloured by temperature (°C). As the temperatures increases in the Barrow Group and Dingo Claystone, the velocity continues to decrease. The red data close to the Gardner Shale trend is normally pressured and corresponds to the high net/gross Dingo Claystone section in Parker–1.

Figure 8. Data coloured by VES. As the temperature increases in the Barrow Group and Dingo Claystone sediments, the effective stress reduces; that is, the pore pres-sure and overpressure increase.

Figure 9. Data coloured by pressure gradient (psi/ft). Increases in the pressure gradient in Barrow Group and Dingo Claystone intervals accompanies a reversal in velocity and density. If gas generation is solely responsible for an increase in the pressure gradient, then density would be invariant.

Figure 5. Data coloured by formation. There is a noted velocity/density reversal as the stratigraphy gets older.

Figure 6. Data coloured by depth (TVDbml). A red dotted trend line, which is sub-parallel to the Gardner Shale line, has been added. This suggests disequilibrium compaction is the main mechanism, agreeing with previous studies. The Withnell Formation shales in Webley–1A plot in a similar position to the Dingo Claystone shales in Withnell–1.



the dominant mechanism operating in these shales. This in-terpretation is consistent with previous studies in this area by Tingate et al (2001), van Ruth et al (2004) and Sagala and Tingay (2012). There are few shallow normally pressured shale data in Northern Carnarvon due to the dominance of the Haycock Marl, Mandu and Trealla limestones. The lack of shallow shale means that defining a loading curve with normally pressured data is problematic. To this end, data from the Webley–1A well was used. The Withnell Formation shales in Webley–1A share similar Vp and Rho values to the Dingo Claystone shales in Withnell–1. Assuming the Withnell Formation shales are non-calcareous, this suggests that the Dingo Claystone data lie on a loading curve. Indeed, supportive evidence for these being true shales comes from Gradstein et al (2004) who noted that the Pa-laeocene Wilcox Formation and the Late Cretaceous Withnell Formation are shale rather than carbonate in the Dampier Sub-basin. The Dingo Claystone, however, does have a density of 2.55 g/cc indicating low-porosity, which is not as often consis-tent with an interpretation of disequilibrium compaction. With the limited data here the authors have no way to determine if gas generation makes a small contribution to the overpressure level. Withnell–1 does lie on the boundary between those ar-eas affected by fluid expansion and by disequilibrium compac-tion described by Sagala and Tingay (2012), so these secondary mechanisms cannot be ruled out.

Disequilibrium compaction as the dominant mechanism is supported by the data in Figure 10 where VES data from the above wells are plotted by Vp. The VES is calculated using kick data for pore pressure and mudweights, where connection gas evidence is present. These data proved useful as they aid definition of a load-ing curve. The data define a simple power law relationship. The formula for this trend line is Equation 1.

Vp = (14.7 × VES0.6) + 1,500 (1)

In Equation 1, compressional velocity is in m/s and VES is in psi.

This relationship has been used to generate shale pres-sure for wells Withnell–1, Forrest 1/1A/1AST1 and Parker–1 (Figs 11–13) in this paper. Noticeably, saltwater kick data from Parker–1 lie significantly off this trend.

DISCUSSION

The evidence presented in the results section suggests that the mechanism of pressure generation is disequilibrium com-paction in the shales. This is consistent with the interpretation in Tingate et al (2001) and Sagala and Tingay (2012) for the same wells, and also consistent with the trend in Figure 10. The resulting shale pressures in Withnell–1 in Figure 11 are 1,000 psi (1 ppg) lower, at approximately the same depth as the kicks in Parker–1 (Fig. 13). It should be noted that the Vp data in Parker–1 ends approximately 50 m above the reser-voir. These observations lead to a conclusion that the Munga-roo reservoir pressures have been much inflated in Parker–1 relative to the immediately surrounding shales. Figure 14 shows the Vp data for Withnell–1 and Parker–1. Top Dingo Claystone is marked in both wells as a horizontal line; the depth of this marker is 500 m deeper in Parker–1. This figure implies that, in Parker–1, Mungaroo reservoirs are juxtaposed against the larger Vp regression seen in the Dingo Claystone in Withnell–1. This indicates that:1. the hanging-wall shales (Withnell–1) are highly overpres-

sured (large velocity regressions); and, 2. the shales in Parker–1 are not as overpressured.

Figure 10. Vp versus VES plot. The data is consistent with the interpretation of disequilibrium compaction. Data from Webley–1A defines the loading trend.

Continued next page.



Figure 12. Single well plot (ppg) of Forrest 1/1A/1AST1 showing the shale pressure estimate derived from the Vp versus VES trend shown in Figure 10.

Figure 11. Single well plot (ppg) of Withnell–1 showing the shale pressure estimate derived from the Vp versus VES trend shown in Figure 10.

Continued from previous page.



Figure 13. Single well plot (ppg) of Parker–1 showing the shale pressure estimate derived from the Vp versus VES trend shown in Figure 10. In Parker–1, the shale inter-pretation for pressure does not match the kick, although the very final section of velocity log is missing (approximately 50 m).

Figure 14. Velocity versus depth (TVDbml) plot of Vp data from the Withnell–1 and Parker–1 wells. The top Dingo Claystone is marked in both wells, Parker–1’s marker is 500 m deeper. Non-shale data is shown in grey. There is a large regression in velocity in the hanging-wall well data. This suggests overpressures that could have leaked cross-fault into the Parker–1 reservoir; however, the shale interpretation in Figures 3 and 11 suggest this is insufficient to explain the kick magnitudes seen in Figure 13.



There are two options to explain the anomalously high pres-sures in the Mungaroo reservoir in Parker–1: cross-fault flow, or flow up faults. It would appear that Dingo Claystone juxtaposition against Mungaroo alone is not sufficient to transfer the pressures represented by the kicks in Parker–1; that is, a further 1,000 psi or 1 ppg of pressure is required (Fig. 3). This excess pressure is, therefore, likely to have been communicated or transferred up-wards from depth, likely along faults. Tingate et al (2001) report a fault-related overpressure occurrence in the Muderong Shale in Venture 1/1ST1, a well in a similar structural position to Parker–1. The kicks were shallower than Mungaroo, suggesting up fault movement rather than simply cross-fault. In this well, oil in the Muderong associated sandstones was noted as not associated with the Muderong but must have come from at least 1,500 m deeper.

Fault rock permeability is likely to be the control in allowing vertical transfer of pressures (and fluids). Fault inversion causes re-activation of faults. Sibson (1995) suggested that re-activation is due to:• preferential reactivation of shallowest-dipping normal faults

in a region that previously underwent the greatest extensional dominoing of fault blocks;

• the presence of anomalously low friction material along par-ticular faults; and,

• a heterogeneous distribution of fluid overpressures with preferential reactivation occurring in the area of most intense overpressuring.Thus, inversion may frequently be highly selective, with only

some of an existing normal fault-set being reactivated. There was no access to seismic data in this study so any comment on fault plane geometry is problematic. Given a seismic volume, however, it may be possible to determine elevated risk for certain fault-sets, depending on their orientation in the prevalent stress field.

The timing of this re-activation is likely Miocene to Recent, where periods of compressional/transpressional events oc-curred. This event caused tilting, inversion and renewed fault movement in the Northern Carnarvon Basin (Malcolm et al, 1991; Cathro and Karner, 2006). The latter authors map out the orientation of maximum horizontal stress (S

Hmax) from the Cre-

taceous to Recent; this stress increased markedly in the Early-Middle Miocene. The orientation of the stress was perpendicular to many of the faults along the Rankin Platform and Dampier Sub-basin, increasing the risk of re-activation. Any faults oblique to this stress may have been preferentially shadowed from any effects of inversion. These structures may, therefore, not be af-fected by pressure transfer.

Additionally, many of the wells that took kicks (e.g. Parker–1, Venture–1, etc.) are located near zones of fault intersection (i.e. where two faults intersect). A recent major study in the Barents Sea by Hermanrud et al (2014) reported that all dry structures have fault intersections at the top reservoir level up-dip of the well position. Escape of hydrocarbons would be consistent with high fault permeability, also facilitating pressure dissipation to shallower horizons.

Another method that could facilitate pressure transfer, par-ticularly from the deep lithologies, is that turbidite sands such as Biggada and Dupuy are acting as carrier beds, channelling high overpressures from the depocentre into the horst blocks. These sandstones are Late Jurassic in age and interleaved with the Din-go Claystone (Jenkins et al, 2003; Moss et al, 2003). The authors of this paper do not have any sandstone distribution maps available for this study, however, by their very nature they are likely to be of only limited areal extent, and are discussed in the literature (e.g. Tingate et al [2001] and others), as mainly being a feature of the Barrow Sub-basin. It may be possible, however, to map these sand units, and where they are juxtaposed against horst faults, enhanced risk of pressure transfer could be present and factored into the planning of wells.

CONCLUSIONS

This study has shown that background shale pressure or cross-fault flow is unlikely to be sufficient to generate the mag-nitudes of overpressure to explain the kicks taken in the Munga-roo reservoir in Parker–1, drilled in 1979. A more logical conclu-sion is that pressure transfer has occurred up the fault, or faults, communicating with deeper levels. This supports examples previously documented in the Carnarvon Basin; for example, Venture 1/1ST1. Parker–1 sits in a similar structural position along the margin of the Rankin Trend. Pressure transfer, there-fore, can be considered an exploration and drilling hazard in future campaigns targeting these horst structures.

The significance of the observations in this paper are:1. If seismic amplitude data can reveal fault sole, then a maxi-

mum possible effect of pressure transfer could be calculated that would provide a high case for well planning for reservoir pressure, assuming complete communication up the fault length with depth.

2. Geomechanical assessment including stress orientation and definition of mechanical stratigraphy would be an important step to ascertain risk of fault permeability and inversion.

3. Facies interpretations and mapping of Biggada and Dupuy sands, if seismically resolvable, could rule out the chance of enhanced charging through carrier beds.

ACKNOWLEDGMENTS

The authors would like to thank the companies that sponsored the non-proprietary Australian North West Shelf Pressure Study: Carnarvon Basin for permission to publish some of the results. The authors would also like to thank the two referees whose constructive comments have greatly improved the quality of this manuscript.

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Ed Hoskin is a Team Leader and se-nior geologist at Ikon Geopressure, and has worked at the company since 2008. He previously held roles in other companies as a junior engi-neering geologist and as a support geoscientist. Ed graduated from the University of Southampton in 2003 with a MGeol (Master of Geology).

Member: European Association of Geoscientists and Engineers (EAGE) and Petroleum Exploration Society of Great Britain (PESGB).

[email protected]

THE AUTHORS

Stephen O’Connor is responsible for all technical aspects of Ikon Geo-Pressure globally. He oversees the entire lifecycle of pressure predic-tion projects and regional pressure studies from concept to completion. Technically, he leads and mentors the GeoPressure team.

Stephen has more than 20 years of experience, and his background as a petroleum geolo-gist has lead him to work with many types of oilfield data, particularly in the areas of reservoir quality, structural ge-ology—with particular reference to geomechanics—fault seal and pore pressure.

After graduating from Leeds University with a BSc in geological sciences he started his career working on ex-ploration assignments for Unocal and BP/Amoco before returning to university to undertake a MSc in sedimentol-ogy at Reading University. Following this Stephen worked for service companies on sedimentology/diagenesis in ar-eas such as the United Kingdom Continental Shelf (UKCS) including the Atlantic Margin, and the Middle East before specialising in areas such as pore pressure and fault seal.

[email protected]

Stephen Robertson graduated from the Queensland University of Technol-ogy (QUT) after completing a Bachelor of Applied Science (Geology) in 1996. The following year he completed a Bachelor of Applied Science (Honours) degree in Petroleum Geology and Geophysics at the National Centre for Petroleum Geology and Geophysics

(NCPGG) through the University of Adelaide. Joining Santos in 1998 Stephen has since worked a number of basins both onshore and offshore Australia, and internationally, for the company in primarily exploration geologist roles. Stephen now works as a geologist in the Santos Geomechanics team after switching roles from Northern Carnarvon Basin explora-tion to subsurface services in early 2014. Member: Petroleum Exploration Society of Australia (PESA) and the American Association of Petroleum Geologists (AAPG).

[email protected]

Jurgen Streit is a Geohazards Man-ger at Woodside Energy Ltd where he leads a team working on shallow hazards, pore pressure, borehole stability and reservoir geomechan-ics. He has previously held geome-chanics positions with Geomechan-ics International (GMI; 2004–07) and the Australian CO2CRC (2000–04).

During his academic career as a lecturer and researcher in geomechanics (1994–2004), Jurgen established a pub-lication record on earthquake and fault mechanics, fluid-rock interaction and CO2 storage. Jurgen holds a PhD in Earth sciences (1994, Australian National University, Canberra). Member: American Geophysical Union (AGU) and the Society of Petroleum Engineers (SPE).

Authors' biographies continued next page.



THE AUTHORS

Chris Ward is a graduate geologist who has been working for Ikon Geo-Pressure since 2012. He has worked on a variety of studies, from small scale to regional-scale Roknowledge studies (which are regional-scale pressure studies involving many hundreds of wells, of which the Australian North West Shelf Pressure

Study: Carnarvon Basin is one). Chris graduated from the University of Durham with a BSc (Hons) in geology. This degree included specialisms in petroleum geosciences and structural geology, as well as large amounts of field-work and mapping across Europe. Chris is a Fellow of the Geological Society. Member: PESGB.

[email protected]

Jack Lee is a graduate geologist who has been working for Ikon Geo-Pressure since 2012. He has worked on a variety of studies, from small scale to regional-scale Roknowl-edge studies. Jack studied at the University of Durham reading a BSc in geology. His dissertation involved the geological and structural map-

ping of the Lizard Peninsula, Cornwall; an area of highly variable polyphase deformation and serpentinisation of an ophiolitic sequence.

[email protected]

David Flett commenced his geological career with honours at Leicester University and subsequently Shef-field University in the UK. He moved to the Far East in 1985 and became the regional Asia Pacific Managing Director of Roberston Research based in Jakarta, Indonesia, in 1988. In 1992, a move to Mincom—Australia’s largest software developer—saw David head-up the Petroleum Technology Division, initially in Asia and subsequently in the Europe, Africa and Middle East (EAME) region from 1992–99, developing a business around the company’s flagship petrophysical product, GEOLOG. Following the acquisition of GEOLOG by Paradigm, David became Regional Vice President of the Asia Pacific Region for Paradigm before moving into the muticlient seismic business as the global head of sales for Searcher Seismic in Perth in 2008. David joined Ikon in the Kuala Lumpur regional headquarters as Asia Pacific President in October 2011.

[email protected]

Authors' biographies continued from previous page.



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