Have we Deciphered the Canning? Discovery of the Ungani Oil Field.

Peter Edwards & Eric Streitberg

Buru Energy, Perth, Australia

Email: peteredwards@buruenergy.com; EricStreitberg@buruenergy.com

The 2011 discovery of the Ungani oil field by Buru Energy has driven a far-reaching change in

perceptions of the prospectivity of the Canning Basin of Western Australia. Previously the basin

had been portrayed as ‘difficult’, with a number of potential and even promising petroleum systems

that had not lived up to expectations.

Ungani 1 was intended as a follow-up to the 1967 Yulleroo gas discovery, 30 km to the west, which

tested gas from the Lowermost Carboniferous Laurel Formation. That discovery was ignored at the

time, in part because there was no market for gas in Western Australia. Although located within the

same fault terrace on the southern margin of the Fitzroy Trough, the targeted tight sands of the

Laurel Formation were absent at Ungani 1. Instead, the well intersected a Lower Carboniferous or

latest Devonian pervasively dolomitised limestone over 140 m thick, of which the upper 57 m is oil

bearing. The oil has an API gravity of approximately 37°API, with DST tests yielding up to 1,647

bpd on a 12.7 mm (32/64 inch) choke with a flowing well head pressure of 124 kPa (18 psi).

Quantifying the extent and production parameters of the reservoir and even understanding its

geologic setting remain problematic with the current dataset, thereby placing large uncertainties on

estimations of recoverable oil reserves. Consequently it is unclear what the long term implications

of Ungani might be for the basin. Nevertheless the discovery seems likely to revitalise exploration

in the basin, and in particular the search for the next field on the trend.

KEYWORDS: Ungani oil field; Canning Basin; dolomitisation; Western Australia hydrocarbons

Abstract Submission 86

Reference Number 179

1. INTRODUCTION

In late 2011 Buru Energy and its partner Mitsubishi Corporation announced an oil flow from the

Ungani 1 well. This signified the first potentially commercial hydrocarbon discovery in the

Canning Basin since 1990, and the first significant onshore discovery in Western Australia for 10

years. Coming after decades of largely unsuccessful exploration by numerous operators, ranging

from poorly funded entrepreneurs to major corporations, the find has stimulated a resurgence of

interest in the region.

The Ungani crude is of premium quality, with recoverable reserves estimated at between 0.5 and 20

million barrels. This wide range is due to the unusual nature (for Australia) of the reservoir section

and to ambiguities in structural configuration. Uncertainties in reservoir character were addressed

with an extended production test, and trap geometry will be clarified by future acquisition of a 3D

seismic dataset. Significant challenges have been encountered in planning a full scale development

of the field including the crude export system and land access. Nevertheless, Ungani undoubtedly

represents an important economic resource for the region and possibly for the State as a whole.

Coming relatively late in the exploration record, the Ungani discovery challenges accepted oil-patch

wisdom that larger fields in a basin tend to be discovered early. There have been some 250

exploratory wells, over one hundred and fifty thousand line kilometres of seismic acquisition and

generations of technical analysis which, until Ungani, identified just a handful of small oilfields in

the Canning Basin with total production of less than three million barrels.

An explanation may lie in the relatively unsophisticated technology used in the early stages of

exploration within the basin, coupled with overly ambitious expectations which virtually guaranteed

a cycle of disappointment, discouragement and diminished activity. Notwithstanding a prolonged

exploration history, the sheer size and complexity of the basin remain daunting despite recognition

that all the factors necessary for one or more productive hydrocarbon systems are present (Goldstein

1989; Cadman et al. 1993). Even within the last decade, Carlsen and Ghori (2005) could maintain

that “The Canning Basin may be the least explored of Palaeozoic basins of the world with proven

petroleum systems. Lack of information continues to contribute to the perception of low

prospectivity…”

The strategy of Buru (and its predecessor, ARC Energy) has been one of progressive focus,

narrowing from a fresh basin-wide analysis to definition of high-potential play concepts and

acreage fairways, and appraisal of specific prospects. In this process, the company has had a

number of advantages over its earlier counterparts:

• Access to a plentiful archive of prior exploration data, in part inherited from successive

operators in the basin but greatly infilled and expanded by government agencies. Within

this material is a concise record of what did not work, as well as what almost (or indeed in

some cases should have) pointed the way to a successful outcome.

• An industry climate of disinterest, allowing substantial acreage acquisition in the basin at

relatively low entry and commitment investment levels.

• Changing economic conditions which ensured that (1) relatively small oil discoveries could

be economically developed, and (2) gas discoveries could, under the right circumstances, be

commercially viable in their own right.

• A belated recognition of the so-called unconventional potential of a number of specific

geologic formations in the basin. This new exploration environment gave different

emphasis to the exploration agenda, offering directions and opportunities that were not

available in the past.

Further success in the Ungani trend will depend on a thorough understanding of the field’s geologic

setting, and the interaction of hydrocarbon system dynamics with local structural, stratigraphic and

diagenetic factors. At this point it is unclear what the long term implications of Ungani might be in

relation to the additional potential in the basin, however the discovery has undoubtedly advanced

the industry’s long term mission to ‘decipher the Canning’.

Figure 1. Tectonic elements of the Fitzroy Trough, Canning Basin, overlain on surface topography. Small oil fields on the northern flank of the Trough, discovered during the 1980s, are currently shut in after decades of production.

2. GEOLOGIC SETTING

The Canning Basin, covering over 430,000 square kilometres in the north of Western Australia, is

one of Australia’s largest onshore sedimentary basins. It was initiated in the early Paleozoic as a

broad epicratonic sag, now divided into two major northwest-southeast trending units: the

connected system of Fitzroy Trough and Gregory Sub-basin, and the Kidson Sub-basin (Hocking et

al 2008). These older basins are for the most part concealed beneath widespread Permian and

Mesozoic strata.

The Fitzroy-Gregory structural system is estimated to contain up to 16 km of predominantly

Ordovician, Devonian and Permo-Carboniferous sedimentary rocks, and is divided by the Jones

Arch into the Fitzroy Trough in the northwest and Gregory Sub-Basin in the southeast. The overall

trend is the product of a major cycle of thermal uplift and instability followed by rift subsidence

during a period of regional Upper Devonian extensional tectonism. This episode left the Kidson

Sub-basin more or less undisturbed.

The southern Fitzroy Trough margin (the SFTM) comprises a series of downward-stepping terraces,

separating the Broome Platform from the main depocentre. The Ungani structure lies within the

most basinward of these platform margin terranes - a complex zone generally referred to as the

Jurgurra Terrace (Figure 1).

The oldest sedimentary deposits recorded in the basin are Ordovician to Silurian clastic and

carbonate facies, representing early Palaeozoic sag-basin fill (Figure 2). A significant thickness of

salt overlies these units in the Kidson Sub-basin to the south, but is absent through dissolution and

withdrawal on the platform areas between the Kidson and Fitzroy Trough depocentres. Although

some halokinetic structures are known from the SFTM, the extent of salt originally present in the

Fitzroy Trough and immediately adjacent areas is obscure due to the multiphase structural

deformation of a substantial thickness of younger deposits.

The margins of the Fitzroy-Gregory structural system incorporate a number of discrete depocentres

of mid to late Devonian age. Local age gaps and disconformities in this stratigraphic section

indicate a period of crustal instability, however during the latest Devonian the generally tensional

tectonic regime evolved into a recognisable NW-SE rift system. During this phase the Fitzroy

Trough developed as a deep marine embayment rimmed by carbonate-dominated shallow marine

shelves along the Jurgurra and Dampier Terraces, and around the Lennard Shelf on the northern

side of the trough. Deep water marine shales of the earlier Givetian to Frasnian Gogo Formation

and equivalents, deposited in local areas of subsidence, were overlain by widespread sub-littoral to

mid-ramp marine deltaic units of the Clanmeyer-Luluigui association representing rapid

accumulation of siliciclastic material in a more open marine environment.

Pull-apart of the SFTM terrace-graben system continued into the Early Carboniferous, with episodic

growth along the bounding fault and hinge lines throughout the Tournaisian and Visean evidenced

by substantial thickness and facies variation in the both the Laurel Formation (here taken to include

all the members of the Fairfield Group, and to be essentially equivalent to that unit) and the

following Anderson Formation, respectively.

In this environment the maximum flooding events of the lower Tournaisian resulted in deposition of

thick anoxic argillaceous sediments of the Lower Clastics member of the Laurel Formation.

Although there is abundant organic material in this member, dilution due to high sedimentation

rates has generally limited the total organic carbon (TOC) content to between 0.5% and 1.5%.

Nevertheless, the regional potential for better source rocks within the Laurel Formation remains

uncertain, with TOC levels likely underestimated due to sampling bias. In this unit rich organic

fractions often occur as finely laminated argillaceous elements distributed through the section.

Furthermore a more optimistic view of the oil and gas generation potential of the Laurel Formation

seems justified by the presence of small oil fields on the Lennard Shelf, along the northern margin

of the Trough (Crostella 1998; Jonasson 2001) and by the ubiquitous appearance of gas in wells

which penetrate the system.

The Fitzroy Trough had essentially failed as an extensional rift system by the mid Carboniferous.

Subsequent crustal weakness enabled sag accommodation of Upper Carboniferous fluvial to

marginal marine units (Reeves Formation) followed by regional glaciation in the early Permian with

basinwide glacigene lacustrine to estuarine-lagoonal sedimentation of the Grant Group.

Deposition of the overlying Poole Formation began with a marine transgression that inundated most

of the Canning Basin. The maximum extent of this Early Permian marine transgression is

represented by the Noonkanbah Formation, consisting of massive, shallow to moderately deep open

marine mudstones and siltstones which transgressed across the earlier terraces.

Deposition of these early Permian sediments was influenced by episodic tectonics including local

uplift, erosion and associated fault inversion. The SFTM was subsequently subjected to prolonged

non-deposition and/or exposure during the Middle Permian to Middle Triassic periods. The final

major tectonic episode to affect the area was the Triassic Fitzroy Transpressive Event, which again

inverted some of the older tensional faults and locally created substantial wrench uplifts centred on

the axial zones of the trough, with local removal of thousands of metres of the sedimentary strata.

Figure 2. Tectono-stratigraphic chart of the Canning Basin, showing elements of three known hydrocarbon systems. The Ungani discovery, in the Laurel Formation, relates to the youngest, Permo-Carboniferous system. Modified from Jonasson (2001), the section is highly schematic but can be pictured as running from south (left side) to north across the basin.

3. DISCOVERY WELL

Coordinated geological studies of the Canning Basin began in 1941, when government agencies

began systematic mapping and integration of data collected by small oil companies which had been

active since the 1920s. In spite of several phases of intense activity in succeeding decades, the area

of the Jurgurra and northern Dampier Terraces, covering over 5000 sq km, had until recently only

six well tests which were mostly drilled for stratigraphic information (Table 1).

WELL YEAR OPERATOR OBJECTIVE

Barlee 1 1956 WAPET Stratigraphic

Yulleroo 1 1967 Gewerksshaft Elwerath Stratigraphic

Logue 1 1972 WAPET Devonian carbonates

Cow Bore 1 1983 Gulf Devonian carbonates

East Crab Creek 1 1984 Gulf Devonian carbonates

Mahe 1 1997 Sterling Permian clastics (Grant Fm)

Table 1: Pre-2008 Exploratory Wells on the Jurgurra and northern Dampier Terraces

In 2008 ARC Energy drilled Yulleroo 2 to appraise wet gas flows and favourable geochemical

results from the Laurel Formation in Yulleroo 1. As in Yulleroo 1, Yulleroo 2 encountered a thick

gas-charged sandy and silty argillaceous section in the Lower Clastic member of the Laurel

Formation, however full evaluation of the section was curtailed at a total depth of 3740 m by

mechanical and other operational problems. In late 2010, Buru Energy re-entered Yulleroo 2 to

conduct a reservoir stimulation of the Laurel Formation tight gas section. Despite equipment

limitations which imposed a sub-optimal stimulation design, the operation was successful in that it

produced strong, if unstabilised, flows of gas and condensate.

Ungani 1 was drilled by Buru in late 2011 in Exploration Permit EP391 some 30 km ESE of the

Yulleroo structure. The well was located on a large four-way dip closed anticline on the Jurgurra

Terrace, with the primary objective being a siliciclastic section within the Tournaisian Laurel

Formation as encountered in the Yulleroo field. It was anticipated that reservoir parameters would

be somewhat better than seen at Yulleroo owing to the shallower depth to the target, coupled with

modest uplift (and corresponding limits to maximum burial depth) during the period of the Fitzroy

Transpression (Figure 2).

In the event, the target Laurel Formation was encountered approximately 45 m deep to prediction,

and the entire Laurel Formation was substantially condensed relative to the equivalent section in the

Yulleroo wells. Oil shows and associated elevated mud gas readings were observed in the

overlying Grant and Anderson Formations from approximately 950 m Measured Depth (MD), and

into the top of the Laurel Formation at 1869 mMD. At 2156 mMD, the well encountered a massive

dolomite unit with strong oil shows. After drilling 142 m of dolomite, the well penetrated a 105 m

thick argillaceous section, followed by a limestone-dominated section to 3524 mMD, at which point

a red-brown siliciclastic section was encountered (Figure 3) before reaching a total depth of 3593

mMD.

Figure 3. Generalised stratigraphy of Ungani 2, with detail of the ‘Ungani Dolomite’, 2227-2457 mMD (Measured Depth). The reservoir section was intersected some 450 m NNE of the discovery well, Ungani 1, which had a less complete log suite but penetrated deeper in the section as indicated by the inset at the bottom of the stratigraphic column.

During subsequent conditioning of the hole to facilitate logging, the drill string became stuck and

consequently parted, with the top of the fish at 2216 mMD. Ensuing attempts to obtain wireline

logs, particularly over the interval of hydrocarbon shows in the dolomites of the (presumed) Laurel

Formation, were unsuccessful. The well was then sidetracked below a casing shoe at 1993 mMD,

to a depth of 2324 mMD.

Substantial fluid losses into the dolomite formation which had occurred in the original well bore

were ameliorated to some degree by careful control of drilling mud properties in the sidetrack. At

the same time, equally good hydrocarbon indications were recorded. However wireline logs over

this section again could not be obtained due to shale washouts and severe ledge effects at the top of

the dolomite. Logs were eventually obtained by running LWD tools on drill pipe. Substantial

invasion of the reservoir by drilling fluid during these protracted operations has been a major

problem for ongoing petrophysical analysis.

Despite these problems a potential oil column was indicated in the dolomite section, which in the

absence of a definitive age dating has been informally named the ‘Ungani Dolomite’. Initially it

was inferred that the entire dolomite could be oil-bearing, but further analysis suggests an effective

free water level at around 2214 mMD separating an upper, potentially oil productive zone of

approximately 57 m gross thickness from a lower zone with only residual hydrocarbon saturation.

In light of deteriorating hole conditions, the well was completed with a slotted liner over the

interpreted reservoir section in order to conduct an immediate cased hole test of the flow potential

of the reservoir and to determine the composition of the reservoir fluids. After initial swabbing,

natural flow of light oil (API gravity ~37 degrees) with no significant gas was quickly established.

With the oil were varying but minor amounts of completion fluid, filtrate and lost circulation

material (LCM) from the approximately 3000 barrels of drilling mud and LCM lost to the formation

during drilling operations. The well was flowed for a total of 8 hours at varying choke sizes with a

peak rate of 1,647 bpd on a 12.7 mm (32/64 inch) choke with a flowing well head pressure of 124

kPa (18 psi). The well was then shut-in with the well head pressure stable at 2965 kPa (430 psi).

Ungani 1 was suspended and an appraisal well, Ungani 2, was drilled from the same well pad.

Ungani 2 was deviated to the NNE along the key seismic line control to test the oil-bearing zone

near the free water level projected onto the mapped structural closure. At some 450m lateral

distance from Ungani 1 the well intersected the top of the Ungani Dolomite high to prediction,

within a few metres of the Ungani 1 depth. In addition, the Ungani Dolomite in Ungani 2 is thicker

than expected at 220 m. Otherwise, general lithology and hydrocarbon shows are similar to Ungani

1. Two conventional cores of 63 m and 27 m were attempted but in each case recovery was less

than 10%. In total 7.4 m of core was acquired, and this was supplemented by 19 mechanical

sidewall cores recovered from 41 attempted in the dolomite zone. The low recovery rate raises

questions as to whether samples are representative of the unit as a whole as presumably the more

cohesive parts, with potentially poorer reservoir characteristics, are over-represented in the

recovered material.

4. DEVONIAN CARBONATES OF THE CANNING BASIN

Despite predictions of a Yulleroo-like clastic-dominated Laurel Formation section, the presence of

massive carbonates in Ungani 1 was not wholly unexpected. Carbonates of this general age are

well known from outcrop in the Lennard Shelf, immediately north of the Fitzroy Trough, as well as

from prior well intersections along the SFTM – albeit in structural settings which are on, or closer

to, platform areas than Ungani. Furthermore seismic correlations on which the prediction was

based, particularly from the Yulleroo wells, are tenuous at best below the Permian section.

In a dynamic structural environment at the edge of a developing rift, stratigraphic facies are likely

to be highly dependent on local variations in water depth, sediment influx and accommodation

space, as well as on the productivity of existing carbonate-producing biota under contemporaneous

climatic conditions.

Upper Devonian carbonate outcrops of the northern Canning Basin are widely regarded as an

exemplary record of the evolving marine ecology of the period (Southgate et al, 1993; Playford et

al. 2009; Copp 2000). While finer details of the stratigraphic inter-relationships remain ambiguous,

these authors define two second-order carbonate-dominated sequences from the Middle to Upper

Devonian – a Givetian to Frasnian sequence (the Pillara cycle), overlain by a Famennian sequence

(the Nullara cycle). These are in turn overlain by a latest Famennian to Tournaisian mixed

siliciclastic and carbonate ramp complex (the Laurel Formation, here taken as synonymous with the

‘Fairfield Group’), representing the last in a basic three-fold chronostratigraphic division of the

marine succession during the main phase of rifting of the Fitzroy Trough.

The Late Devonian, as a period of successive global extinction events, has been the subject of

intense worldwide scrutiny. Two of the most widely recognised events are potentially associated

with the transitions between the Canning Basin depositional units noted above: the

‘Frasnian/Famennian Mass Extinction’ (F/F event) and the ‘Devonian/Carboniferous Mass

Extinction’ (D/C event) – also termed the ‘Hangenberg Event’ (McGee 1996; Sandberg et al. 2002).

Discussion on causes has focused on orbitally forced climatic changes (House 2002) or, for the F/F

event, a possible cometary impact cluster (McGee 1996). The D/C event, in particular, appears to

have triggered an abrupt eustatic sea level fall followed by a more protracted and multifaceted

glacial episode.

If these correlations are valid, the consequences of two global events for Canning Basin carbonate

systems were profound. In both cases frame- and reef-building organisms were effectively removed

from the geologic record in this basin. During the Pillara-Nullara (F/F) transition the hiatus was

relatively short and the reef complexes were renewed, though with different reef builders. In turn

the Nullara microbial reef-building community suffered an even more severe ecologic breakdown,

being supplanted by a cool-water tolerant bryozoan, crinoidal and microbialite assemblage with

distinctly different growth habits (Wood 2004; Playford et al. 2009).

Away from condensed platform areas the Devonian/Carboniferous boundary was a time of

extremely rapid sedimentation across the Fitzroy Trough. In this part of the succession

biostratigraphic resolution is largely dependent on palynology as age-diagnostic conodont and

ammonoid fossils are rare (Jones & Young 1993; Playford et al 2009). The distinctive miospore

Retispora lepidophyta is used as an indicator of the latest Famennian, which includes the so-called

D/C event arguably as a definitive separator between the Nullara and Laurel/Fairfield depositional

cycles. The appearance of the Grandispora spiculifera assemblage marks the accepted Devonian-

Carboniferous boundary, some 2‒4 MY after the extinction event itself. The biozonation and

chronology of the Devonian-Carboniferous transition are summarised by Copp (2011) and

Seyedmehdi (2011).

5. THE UNGANI DOLOMITE

The Ungani Dolomite is provisionally dated as latest Famennian based on R. lepidophyta, although

there remains some possibility of a slightly younger, earliest Tournaisian (G. spiculifera) age. This

places the unit ambiguously at the top of the Nullara cycle or in the lower Laurel Formation (Figure

4), a distinction which may have significant ramifications for exploration strategy in the basin.

Figure 4. Chronostratigraphic setting of the ‘Ungani Dolomite’. The relationship between the “D/C mass extinction” and the Hangenberg event, and their correspondence to the end of the Nullara reef cycle in the Canning Basin are speculative, as discussed in the text. Uncertainty in the affiliation of the ‘Ungani Dolomite’ is reflected in the gap in the stratigraphic column in the latest Devonian. Ages as summarised by Seyedmehdi (2011). Eustatic curve from Schutter and Laurie (1998). Depositional facies and formation nomenclature adapted from Playford et al (2009) and others.

Physical description of the Ungani reservoir relies primarily on conventional and rotary sidewall

cores from Ungani 2, supplemented by an assortment of electric log data from both Ungani 1 and 2.

Recovered conventional Cores 1 and 2 represent only a small fraction (approximately 10%) of the

attempted core interval, but nevertheless provide valuable reference points for interpretation of

resistivity image logs and other indirect data.

In gross terms the reservoir unit is a more or less homogeneous, pervasively dolomitised lithologic

package with extensive vuggy porosity. Resistivity imaging (such as the excerpt shown in Figure 5)

presents a more partitioned aspect, with intervals of chaotic appearance and sharp, high angled

texture interspersed with more regularly bedded shallow-dipping zones. The chaotic zones show

evidence of irregular vuggy porosity at a range of scales from large, almost cave-like voids down to

the resolution limit of the imaging tools. Fractures can be identified in places but are not consistent

features.

The core pieces, presumably from the more competent parts of the cored intervals, include clast-

and matrix-supported breccias comprising crinoidal rudstone and microbial boundstone fragments

in a matrix of crinoidal floatstone-rudstone. Ungani 2, Core 2 (2327.8 ‒ 2354.8mMD, recovery

9.7%) is interpreted as a lower energy deposit, possibly the background sedimentation to episodic

debris flows identified in Core 1 (2241.3 ‒ 2305.7mMD, recovery 8.15%). The reservoir unit was

likely deposited in a mid- to outer ramp environment with an overall waning in energy levels,

culminating in low-energy suspension deposits represented by the overlying sealing shale.

All conventional and sidewall cores from Ungani 2 over the interval 2228 m to 2355 mMD are

completely dolomitised. The dolomite is coarsely crystalline and is similar to the extensive Upper

Devonian dolomite of the Barbwire Terrace (Wallace, 1990). Visible porosity within the samples is

largely mouldic (after bioclasts) or fracture-related porosity, but some primary porosity is also

present. The mouldic porosity was almost certainly produced during the later stages of a major

dolomitisation event, as a consequence of the volume reduction that occurs during the conversion of

limestone to dolomite.

The diagenesis can be divided into two distinct phases: (1) An early phase dominated by replacive

dolomitisation and planar dolomite cement and, (2) A later phase characterized by quartz, kaolinite

and saddle dolomite cements. Saddle dolomite is only present in the deepest samples (Core 2,

below 2328 m). There is weak evidence that stylolitization began before dolomitisation

commenced, suggesting some early phase dolomitisation during burial.

In addition to porosity production during the later stages of replacement dolomitisation, there was a

significant porosity-producing event during the later stages of planar dolomite precipitation. The

porosity event is marked by dolomite dissolution, brecciation and fracturing, and was immediately

followed by precipitation of bright luminescent planar dolomite. Iron sulphide precipitation appears

to be approximately contemporaneous with this porosity producing event, indicating that H2S may

have been responsible for dolomite dissolution.

The ‘Ungani Dolomite’ is bounded top and bottom by relatively thin claystone units, and upper and

lower adjoining limestone beds which show no obvious dolomitisation effects. Such inconsistent

appearance of dolomite in the Upper Devonian to lowermost Carboniferous section is characteristic

of the Canning Basin. Devonian carbonates in SFTM wells such as Crab Creek 1, East Crab Creek

1 and Cow Bore 1 are partly dolomitised, whereas the overlying Tournaisian interbedded dolomite-

limestone-siliciclastic facies are only lightly affected. This suggests that either there were partial

lithofacies barriers to later dolomitising fluids or that different dolomitising processes were active.

Seyedmehdi (2011) interpreted the equivalent dolomitised interval on the Lennard Shelf as having

been formed by reflux dolomitisation, which similarly did not affect the entire carbonate

succession.

Figure 5. Detail of XRMI and GVR electric log images from the reservoir section of Ungani 2. Depth interval indicated in Figure 3 XRMI panels display higher resolution but are segmented due to sensor pad separation. Calculated stratigraphic dips are 10 ‒ 20 degrees, west to northwest.

At Ungani the stratigraphic isolation of the dolomitised interval indicates that the containing shales

may have acted as a diagenetic trap, directing magnesium-rich fluids into the bedded limestone.

Such a mechanism is documented in the Lennard Shelf Mississippi Valley Type mineral belt, where

robust boundaries between argillaceous clastic and carbonate lithologies have constrained

hydrothermal fluids migrating through aquifers and permeable fault systems (Dorling et al., 1998).

Ultra-violet microscopy reveals no visible fluorescent hydrocarbon inclusions within the any of the

porosity occlusions (planar dolomite, saddle dolomite, quartz cements), thereby indicating that

hydrocarbon influx was a relatively late diagenetic event. Two distinctly different types of

hydrocarbons are present in the pore space; non-fluorescent opaque bitumen and fluorescent non-

opaque fluid hydrocarbons.

6. THE UNGANI OIL

The Ungani oil is a 37 degree API gravity paraffinic crude with a pour point of 12 degrees C, with a

Gas-Oil Ratio (GOR) of less than 10 ft3/bbl. The gas chromatogram of the whole oil is

characterised by a unimodal n-alkane distribution with a maximum at C15. The oil has high wax

content with the n-alkanes extending out to C34. There is a slight odd-carbon number preference in

the C15 to C19 n-alkanes. A depletion in the low-molecular-weight hydrocarbons (<C12) is evidence

for minor water washing, although there appears to be no significant alteration by processes such as

bio-degradation, in-field mixing or contamination with other hydrocarbon sources during migration.

A relatively low pristane-phytane ratio (1.45) is indicative of a source rock deposited in somewhat

oxic conditions. Biomarker distributions indicate derivation from primarily marine algal material

with some contribution from terrigenous sources. These factors are consistent with a marine

depositional environment, most likely proximal to an estuary or bay setting. Aromatic maturity

parameters indicate hydrocarbon generation in the early to peak oil window.

The n-alkane distribution and biomarker signature of the Ungani oil is similar to those of the

Sundown and Meda crude oils, which are inferred to have been sourced from the Laurel Formation

(Home Energy 1985; Kennard et al. 1994; Edwards & Zumberge 2005).

7. VOLUMETRIC ASSESSMENT

The Ungani prospect was mapped on the basis of regular but loosely spaced seismic lines with a

grid density of about 2x4 km (Figure 6). The lines are of vintages ranging from 1973 to 2010, and

although the combined data set is of fair to good quality overall, the two or three lines that cross the

Ungani structure are inconsistent in frequency and phase content. Consequently there is

considerable uncertainty as to the form and internal geometry of the oil accumulation.

In general terms the structure is an east ‒ west trending anticline with four-way dip at the reservoir

level. The southern margin is truncated by a compound east-west fault system, with smaller faults

having an interpreted NNW – ESE orientation cutting across the central part of the anticline (Figure

7). The underlying tectonic style of the structure is difficult to determine due to the lack of seismic

control, although closure appears to have been established during transpressive stresses of the

Lower Triassic Fitzroy event.

Figure 6. Depth structure map, Ungani oil field and surrounds. Top of ‘Ungani Dolomite’ unit.

Figure 7. Seismic line BYS10-21, PSDM processing, with the positions of Ungani 1 and Ungani 2 marked. Line location shown on Figure 6.

In the absence of adequate structural control, a key indicator of both reservoir parameters and

accessible hydrocarbon volumes has been production performance under a test program involving

both Ungani 1 and 2 wells. Both wells have been compromised to some extent by having been

completed for production prior to the recognition of the nature of the reservoir, and consequently

not being set up to optimise long term production rates. The oil-bearing interval in Ungani 1 has no

effective isolation from the underlying water zone, and the base of the Ungani 2 completion is close

to the oil/water contact. Consequently the wells were expected to produce water relatively early on

in their productive life, and planning was initiated to ensure future production well design

maximises oil production and defers water production for as long as possible.

Production testing during 2012 yielded a total of 76,609 bbl of oil from the two wells. Limited

storage and trucking facilities restricted normal daily production to less than 1000 bbl although rates

in excess of 1500 BPD were achieved on test.

Analysis of the test results leads to a number of favourable conclusions. Pressures recorded during

drawdown, build-up and interference tests indicate excellent horizontal permeability between the

wells. Calculations of ‘observed oil’, representing only that which is directly accessible by the

wells under test, suggest an in-place volume of around 20MMbbl. Clearly this is only an order of

magnitude estimate, subject to change when more is known about the trap geometry, internal

configuration and productive capacity of the reservoir. Of particular significance in the latter

category is the potential for additions from primary porosity – not included in the present

calculations due to the relative brevity of the test program.

Results also suggest that, in common with other fields with high quality reservoirs, horizontal

production wells drilled along the top of the reservoir for up to 2000 metres will be capable of high

oil production rates at low water cuts for extended periods. It is therefore expected that the Ungani

oil field will be able to be developed with two to four horizontal wells.

8. IMPLICATIONS FOR BASIN PROSPECTIVITY

The discovery of the Ungani oil field has unquestionably raised the profile of the Canning Basin as

having the potential to add substantial hydrocarbon resources on a national, if not global scale.

Preliminary evaluation of the find raises the prospect that Buru has uncovered a new and possibly

extensive oil system on the terraced southern margin of the Fitzroy Trough. Significant factors for

consideration in future exploration of this system are:

• The reservoir is a massive carbonate of Late Devonian to earliest Carboniferous age. While

precise stratigraphic correlation is unclear at this point due to limited palynologic resolution,

it is believed that the carbonate package dates from the latest Devonian, postdating a

worldwide extinction event which ended a phase of reef aggradation by frame-building

organisms. Climatic cooling associated with the event ensured that when carbonate

deposition was re-established it followed a distinctive crinoidal and microbial-dominated

ramp and mound pattern, potentially identifiable on seismic data and in physical samples.

• At Ungani the reservoir unit is pervasively dolomitised, with vuggy to cavernous porosity

providing excellent horizontal permeability. A range of dolomitisation processes has been

identified in core samples, of which burial diagenesis appears to have been the most

significant for creation of present day porosity. Other Canning Basin carbonates of similar

age have exhibited different types of dolomitisation, with varying degrees of replacement

and consequent effects on reservoir parameters through porosity enhancement and/or

occlusion. Understanding the controls on the progression of dolomitisation in different

geologic settings will be key to identifying and prioritising targets for future exploration in

the basin.

• Analysis of the Ungani oil indicates close ties with crude from Sundown and other fields on

the Lennard Shelf which are considered to be sourced from within the Laurel Formation.

On the basis of rather extensive if patchy geochemical analyses, this unit has historically

been classified as a fair source at best, with a tendency towards gas rather then liquids

generation. The presence of a substantial volume of low GOR crude at Ungani

demonstrates that a richer Laurel Formation source, near optimal thermal maturity for oil, is

present within the migration catchment of the structure. The implication that oil currently in

the reservoir may represent only a fraction of a larger field, greatly reduced in recent times

by leakage and/or partial flushing, can only reinforce such a conclusion. Establishing the

present areal and depth distribution of this inferred oil source is another key objective to

facilitate effective follow-up of the discovery.

• The Ungani oil field presents an opportunity to utilise innovative production technologies to

minimise the effective footprint of operational activities. These would be based particularly

around horizontal completion practices from central pads, which appear ideally suited for

optimal development of the Ungani reservoir.

Initial conclusions such as these will need thorough review as more information becomes available.

At this stage the fields’ overall contribution to ultimate production from the Canning, and hence its

implication for future prospectivity of the basin, is uncertain due to inadequate data on size and

production characteristics. Consequently improving the understanding of field parameters,

especially through imaging by modern 3D seismic techniques, is recognised as a priority for Buru.

This in turn will require careful planning and consultation to achieve consensus with Traditional

Owner groups and other stakeholders to ensure that the heritage and environmental values of the

region are preserved.

For the present, though, the most far reaching contribution of the Ungani discovery may be its

compelling validation that the Canning Basin is under-explored, imperfectly understood, and

seriously under-estimated as a major hydrocarbon resource.

9. REFERENCES

CADMAN, S. J., PAIN, L., VUCKOVIC, V. & POIDEVIN, S. R., 1993. Canning Basin, W.A. Bureau of Resource Sciences, Australian Petroleum Accumulations Report 9.

CARLSEN, G. M. & GHORI, K. A. R,. 2005. Canning Basin and global Palaeozoic petroleum systems – a review. The APPEA Journal 45, 359-364.

COPP, I. A., 2000. Subsurface facies analysis of Devonian Reef complexes Lennard Shelf, Canning Basin Western Australia. Geological Survey of Western Australia Report 58.

COPP, I. A., 2011. Late Devonian (Famennian) facies of the outer Lennard Shelf, Canning Basin, Western Australia – a preliminary study. Geological Survey of Western Australia Record 2011/5.

CROSTELLA, A., 1998. A review of oil occurrences within the Lennard Shelf, Canning Basin, Western Australia. Geological Survey of Western Australia Report 56.

DÖRLING, S. L., GROVES, D. I. & MUHLING, P., 1998. Lennard Shelf Mississippi Valley-type (MVT) Pb-Zn deposits, Western Australia. AGSO Journal of Australian Geology & Geophysics 17, 115-120.

EDWARDS, D. S. & ZUMBERGE, J. E., 2005. Oils of Western Australia II, regional petroleum geochemistry and correlation of crude oils and condensates from Western Australia and Papua New Guinea. Geoscience Australia Report, cat. 37512.

GOLDSTEIN, B. J., 1989. Waxings and wanings in stratigraphy, play concepts and prospectivity in the Canning Basin. The APEA Journal 29, 466-508.

HOCKING, R. M., PLAYFORD, P.E., HAINES, P. W. & MORY, A. J., 2008. Paleozoic Geology of the Canning Basin – a field guide. Geological Survey of Western Australia Record 2008/18.

HOME ENERGY, 1985. EP 129R1 Geochemistry study. Geological Survey of Western Australia, statutory petroleum exploration report R1 A20 (unpublished).

HOUSE, M. R., 2002. Strength, timing, setting and cause of mid-Paleozoic extinctions. Palaeogeography, Palaeoclimatology, Palaeoecology 181, 5-25.

JONASSON, K. E., 2001. Western Australia atlas of petroleum fields, onshore Canning Basin. Petroleum Division, Department of Mineral and Petroleum Resources. Volume 2, Part 1.

JONES, P. J., & YOUNG, G. C., 1993. Summary of Phanerozoic biostratigraphy and paleontology of the Canning Basin (Lennard Shelf), Canning Basin Project, Stage 1, Lennard Shelf. Australian Geological Survey Organisation Record 1993/4.

KENNARD, J. M., JACKSON, M. J., ROMINE, K. K., SHAW, R. D. & SOUTHGATE, P. N., 1994. Depositional sequences and associated petroleum systems of the Canning Basin, WA. In: Purcell, P. G. & Purcell, R. R. (eds), The sedimentary basins of Western Australia. Proceedings of West Australian Basins Symposium, Petroleum Exploration Society of Australia, Perth, 657-676.

MCGHEE, G. R., 1996. The Late Devonian mass extinction: The Frasnian/Famennian crisis. New York, Columbia University Press.

PLAYFORD, P. E., HOCKING, R. M. & COCKBAIN, A. E., 2009. Devonian reef complexes of the Canning Basin. Geological Survey of Western Australia Bulletin 145.

SANDBERG, C. A., MORROW, J. R. & ZIEGLER, W., 2002. Late Devonian sea-level changes, catastrophic events, and mass extinctions. Geological Society of America Special Paper 356.

SCHUTTER, S. R., & LAURIE, J. R., 1998. In SRK Consulting: Canning Basin Project, 1998, Enclosure 3. Geological Survey of Western Australia, statutory petroleum exploration report S6353 R1 A5 (unpublished).

SEYEDMEHDI, Z., 2011. Depositional history and reservoir characterisation of the latest Devonian-Early Carboniferous Fairfield Group, northwestern Lennard Shelf, Canning Basin, Western Australia. PhD Thesis, School of Earth and Environment, University of Western Australia.

SOUTHGATE, P. N., KENNARD, J. M., JACKSON, M. J., O’BRIEN, P. E. & SEXTON, M. J., 1993. Reciprocal lowstand clastic and highstand carbonate sedimentation, subsurface Devonian reef complex, Canning Basin, Western Australia. In: Loucks, R. G., & Sarg, J. F. eds. Carbonate sequence stratigraphy: recent developments and applications, AAPG Memoir 57, 157-179.

WALLACE, G. E., 1990. Origin of dolomitization on the Barbwire Terrace, Canning Basin, Western Australia. Sedimentology 37, 105-122.

WOOD, R., 2004. Paleoecology of a post-extinction reef: Famennian (Late Devonian) of the Canning Basin, north-western Australia. Paleontology, 47, part 2. 415-445.