Patchawarra Formation Research Articles

Molecular hydrogen from organic sources in geological systems

We have recently shown that molecular hydrogen generation from organic matter occurs at high maturity levels (vitrinite reflectance 3–5%) in Lower Cretaceous shales of the Songliao Basin. To evaluate and extend these implications to a wider range of source rock types and organofacies, we report on two Paleozoic maturity suites from Australia, namely the Permian Patchawarra Formation (fluviodeltaic; Type-III; Cooper Basin) and the middle Cambrian Arthur Creek Formation (marine; Type-II; Georgina Basin), and additional mature marine source rocks from Europe and the USA.It can be inferred from high resolution mass spectrometry that rapid growth of aromatic ring systems is the major pathway for the formation of thermogenic molecular hydrogen from all organic matter types. Extensive open system pyrolysis experiments indicate that the main generation pulse occurs in the vitrinite reflectance range 3.5–5.0%. Kinetic parameters were constructed by subtracting the hydrogen associated with hydrocarbon formation from total hydrogen in the open-system experiments via adjustment factors defined by the relative yields of CH4 and H2. A cumulative H2 potential of 20 mg/g TOC is found with maximum rates of generation that are sufficient for feeding the deep biosphere. Back of the envelope calculations indicate ∼3.5E+10 tonnes of in-place accessible H2 globally, which is an order of magnitude lower than in-place shale gas resource estimates. Regionally, inferred here for the Patchawarra Formation in the Nappamerri Trough (Cooper Basin), yields per unit rock volume resemble those of economic shale gas in the Barnett Shale, Fort Worth Basin, USA.Organic particles are, at the SEM-scale (>30 nm), barren of secondary porosity in the case of terrigenous samples at all maturity stages, but show sponge-like porosity in the investigated marine source rocks exhibiting vitrinite reflectance >∼2.0%. Presence of such meso- and macropores is crucial for H2 storage in marine shales, as microporosity (<2 nm) yielding sorptive storage space for H2, is usually much higher in mature terrigenous kerogens.

New insights on the age and stratigraphy of the Cisuralian succession in the Cooper Basin, Australia, based on U–Pb CA-TIMS dating of volcanic air-fall tuffs

Absolute age constraints for Cisuralian units in the Cooper Basin have been hampered by poorly calibrated palynostratigraphic schemes, with implications for pan-Australian and global correlations. New U–Pb CA-TIMS (uranium–lead chemical abrasion-thermal ionisation mass spectrometry) dates acquired from volcanic air-fall tuff beds from the Patchawarra Formation combined with legacy palynological data offer new insights on the age, stratigraphy and tectonic history of the basin. Six tuffs from different regions of the Cooper Basin give dates from 284.87 to 277.36 Ma, which suggest that the Patchawarra Formation was deposited between the Artinskian and Kungurian rather than from the Sakmarian to Kungurian, as previously thought. The new dates indicate a possible unconformity at the base of the Patchawarra Formation and the underlying Tirrawarra Sandstone. They also suggest that the overlying REM succession (Roseneath Shale, Epsilon Formation and Murteree Shale) is entirely Guadalupian age rather than ranging from the Cisuralian to the Guadalupian. Consequently, existing Cisuralian and Guadalupian high-resolution spore-pollen zonations should be used with care when applied in conjunction with U–Pb CA-TIMS dates. The tuff dates in the thin Patchawarra Formation over the prominent Gidgealpa–Merrimelia–Innamincka Ridge within the Cooper Basin support the interpretation that the ridge was an area of relatively slow subsidence rather than being a positive feature during deposition. Compacted sediment accumulation rates of between 25 and ∼40 m/My for this unit are faster than for most cratonic basins, which raise questions on the tectonic setting of the Cooper Basin. The use and further acquisition of tuff dates will enhance correlations and facilitate improved paleogeographic reconstructions and our understanding of the late Paleozoic ice age. KEY POINTS Six volcanic air-fall tuff beds dated from the Cisuralian Patchawarra Formation, Cooper Basin. U–Pb CA-TIMS dates range from 284.87 to 277.36 Ma. Dates suggest deposition occurred between the Artinskian and Kungurian. New insights on basin tectonics, sedimentation rates and basin stratigraphy.

Generating pseudo-capillary pressure curves from nuclear magnetic resonance (NMR) data: a case study from the Cooper Basin, Australia

This study evaluates the accuracy of generating pseudo-capillary pressure curves from laboratory nuclear magnetic resonance (NMR) analysis and NMR wireline log data by comparing threshold pressures and curve characteristics to rock-derived mercury injection capillary pressure (MICP) analysis. Accurate production of pseudo-capillary pressure curves from NMR data could negate or reduce the need for expensive and rig-time-consuming core acquisition and subsequent MICP analysis. Successful application of this technique will allow production of pseudo-capillary pressure curves for large stratigraphic intervals at a significantly reduced cost and help to better constrain petroleum reserves and improve near field exploration prediction outcomes. The Tindilpie-11 well in the Cooper Basin, Australia, was used as a case study because of extensive existing conventional ore analysis and presence of an NMR wireline log covering the sampled intervals in the Permian-aged Patchawarra Formation. Six core samples underwent MICP and laboratory NMR analyses, with capillary pressure curves generated for each method. Six pseudo-capillary pressure curves were also generated from the NMR wireline log data at the coincident sample depths. The pseudo-capillary pressure curves generated from laboratory NMR data closely resemble the MICP results (mean threshold pressure error of 0.63 MPa absolute [91.4 psi]) and proved the applicability of this approach. The NMR wireline log data used is an average over a ∼1.6 m interval, which has likely led to discrepancies when compared with laboratory NMR pseudo-capillary pressure curves and MICP curves. Nonetheless, this study confirms the applicability of using laboratory NMR data to generate pseudo-capillary pressure curves that resemble MICP results. Continued development of NMR log technology and reduced logging speeds will improve the data resolution and ultimately provide high density NMR data that can be used to create pseudo-capillary pressure curves for large stratigraphic intervals at a significantly reduced cost. KEY POINTS Pseudo-capillary pressure curves derived from NMR data. Reservoir characterisation requiring minimal rock acquisition for ground truthing. Case study on the Patchawarra Formation (Cooper Basin, Australia) using SCAL data.

Re-evaluation of depositional models for the lower Permian Patchawarra Formation, Cooper Basin, South Australia: implications for petroleum exploration

The Late Carboniferous–Triassic Cooper Basin is Australia’s most prolific onshore petroleum province. The lower Permian Patchawarra Formation, which is up to 680 m thick and consists of up to 10% coal, is a major exploration target in the basin. Eighteen cores through the formation have been logged to re-evaluate the existing fluviolacustrine depositional model. The siliciclastics form fining- and coarsening-upward sequences that are 1–10 m thick. They are predominately fine-grained with abundant lenticular bedding, wavy bedding and thinly interlaminated siltstones and clays resembling varves. Granules and pebbles, interpreted as dropstones, are present throughout the formation. Coal beds are up to 60 m thick and rich in inertinite. Other than the coal beds, there is little evidence of the establishment of terrestrial conditions: roots are rare and there are no siliciclastic palaeosols. The siliciclastics are interpreted as the deposits of a large glaciolacustrine system, with the fining-upward successions deposited in subaqueous channels cut by hyperpycnal flows and the coarsening-upward successions deposited as overbank splays between those channels. Hyperpycnal flows may have resulted from sediment-laden cold water emanating from glacially-fed rivers, similar to those seen in many large glacial lakes in high latitudes and altitudes today. Much of the coal is interpreted as the accumulation of peats from floating mires that covered large parts of the glaciolacustrine system at certain time intervals. The high inertinite content of many coals is interpreted as the decay of organic matter within the floating mire. These new interpretations have the potential to enhance reservoir characterisation within the basin.

Investigation of increasing hydraulic fracture conductivity within producing ultra-deep coal seams using time-lapse rate transient analysis: A long-term pilot experiment in the Cooper Basin, Australia

Ultra-low permeability, inertinite-rich, poorly cleated, dehydrated, overpressured coal seams deeper than 9000 ft (2740 m) in the Cooper Basin of central Australia represent a fundamentally different play type to shallow and “deep” coal seam gas reservoirs. Proof-of-concept gas flow was achieved in 2007. Four Patchawarra Formation coal seams were subjected to low-proppant concentration slick-water hydraulic fracture stimulation within a dedicated vertical wellbore at a depth of 9500 ft (2900 m). Gas was produced for 81/2 years at a slowly increasing base flow rate, averaging 0.1 MMscfd (2.8 Mscmd). Experimental data were gathered for characterising dynamic reservoir behaviour. This included multiple extended pressure build-up tests. The authors have previously investigated the three largest of these using time-lapse pressure transient analysis. The published results reveal a dominant bilinear flow regime, associated with an isolated domain of increasing coal fabric permeability surrounding the hydraulic fracture.This paper builds upon the time-lapse pressure transient analysis study by specifically investigating conductivity of the hydraulic fracture, which the authors postulate to have also increased. The hypothesis is tested by applying time-lapse rate transient analysis to the two specially designed pressure drawdown tests to atmospheric pressure that immediately follow the first two pressure build-up tests of the time-lapse pressure transient analysis. Between the two pressure drawdown tests, spaced 586 days apart, the wellbore flowed gas continuously for 327 days, at an average flowing bottom-hole pressure of 580 psig (4.0 MPag). Hence, there was ample opportunity for hydraulic fracture conductivity to change between the tests.Both pressure drawdown tests were monitored for 24 h using high-resolution surface pressure gauges. Each was initiated from the same surface shut-in pressure of 2500 psig (17.2 MPag). The flow pressure data are initially used to construct “diagnostic plots” that clearly identify the hydraulic fracture linear flow regime, early in each test, immediately after the dissipation of wellbore storage. Hydraulic fracture properties are then extracted using “specialty plots” that display rate-normalised pseudo-pressure difference versus linear superposition time.Comparing the slopes of the two speciality plot trends indicates that the hydraulic fracture flow property bfkf∅f increased during the 327-day gas flow period by a factor of 4. This is supported by a 60% increase in the initial gas flow rate from “hydraulic fracture storage”, from 7.5 to 12.0 MMscfd (212.4 to 340.0 Mscmd). Additionally, despite a significantly larger volume of “hydraulic fracture storage” gas being produced to surface during the second test, the duration of the hydraulic fracture linear flow regime is less than for the first. These observations are consistent with an increasingly more conductive hydraulic fracture over flowback time that allows compressed gas within it to discharge more rapidly.

Using mud gas components to quantify hydrocarbon liquid yields for gas zones in the Patchawarra Formation of the Western Flank, Cooper Basin

The Patchawarra Formation is a Permian age fluvial sand and coal measure system deposited in the Cooper Basin of Central Australia. Fluvial sand channels up to 20 m thick form conventional gas rese...

Hydrocarbon prospectivity of the Cooper Basin, Australia

The Pennsylvanian-Middle Triassic Cooper Basin is Australia's premier conventional onshore hydrocarbon-producing province. The basin also hosts a range of unconventional gas play types, including basin-centered gas and tight gas accumulations, deep dry coal gas associated with the Patchawarra and Toolachee Formations, and the Murteree and Roseneath shale gas plays. This study used petroleum systems analysis to investigate the maturity and generation potential of 10 Permian source rocks in the Cooper Basin. A deterministic petroleum systems model was used to quantify the volume of expelled and retained hydrocarbons, estimated at 1272 billion BOE (512 billion bbl and 760 billion BOE) and 977 billion BOE (362 billion bbl and 615 billion BOE), respectively. Monte Carlo simulations were used to quantify the uncertainty in volumes generated and to demonstrate the sensitivity of these results to variations in source-rock characteristics. The large total generation potential of the Cooper Basin and the broad distribution of the Permian source kitchen highlight the basin's significance as a world-class hydrocarbon province. The large disparity between the calculated volume of hydrocarbons generated and the volume so far found in reservoirs indicates the potential for large volumes to remain within the basin, despite significant losses from leakage and water washing. The hydrocarbons expelled have provided abundant charge to both conventional accumulations and to the tight and basin-centered gas plays, and the broad spatial distribution of hydrocarbons remaining within the source rocks, especially those within the Toolachee and Patchawarra Formations, suggests the potential for widespread shale and deep dry coal plays.

Evolving Exploration Methods in the Hydrocarbon Play Within the Patchawarra Formation on the Western Flank, Cooper Basin

The hydrocarbon play in the Patchawarra Formation lies within a Permian age, high latitude, fluvial sand and coal measure system that is up to 300m thick in the Cooper Basin of Central Australia. Fluvial channel belt sands, ranging from 1 to 20m thick, form a conventional reservoir. Seal and source play components are in the inter-bedded overbank, silts, clays and coal seams. The low seismic reflectivity sands combined with the numerous, high seismic reflectivity coals makes standard seismic interpretation difficult. These factors combined with the thin, irregular geometry of the reservoir, make exploring for hydrocarbon traps challenging. The largest fields in the Western Flank, discovered to date, are considered to have a stratigraphic trap component that is combined with a structural influence. Each field has a single main pay zone located in a different clastic package compared to the other fields in the play. An evolving exploration method is reviewed that uses the coals as local timelines with trap limits defined using structural and stratigraphic indications from the seismic. This method combined with ideas of source and trap has recently proved successful in extending the play. Examples of some of the hydrocarbon traps and concepts are shown that may help with evolving ideas and future exploration methods in this basin and other basins with similar fluvial plays.

Mapping permeable subsurface fracture networks: A case study on the Cooper Basin, Australia

The spatial distribution of permeable fracture networks is constrained in the subsurface Cooper Basin (Australia) through the integration of most positive curvature (K+) analysis of five three dimensional (3D) seismic surveys, wellbore fracture data, and geomechanical modelling. The K+ provides the likely distribution of subsurface extensional fractures based on the stress redistribution along the outer arc of an anticline. These results are reprocessed into the semblance (similarity) attribute to improve the signal-noise ratio prior to being extracted along the gas-rich and low permeability Patchawarra Formation. The subsurface fracture distribution maps show the geometry and density of extensional fractures that have been shown to facilitate fluid migration in this province, particularly those striking SE-NW and E-W, as these are properly oriented to undergo tensile reactivation. The density of these permeable SE-NW and E-W striking fracture sets is predicted to significantly increase along E-W elongate anticlines and may contribute to improved hydrocarbon recovery in this low permeability stratigraphic interval. We show that wellbore fracture data (n = 917) in the Patchawarra Formation presents a close relationship to K+ results and can be used to generate high density structural data in this basin, with the methodology applicable to other subsurface and offshore provinces.

Play-based exploration in the southern Cooper Basin: a systematic approach to exploration in a mature basin

Exploration within a mature basin poses many challenges, not least how to best utilise resources and time to maximise success and reduce cost. Play-based exploration (PBE) provides a team-based approach to combine key aspects of the petroleum system into an integrated and wholistic view of basin prospectivity. While the PBE methodology is well established, it is not often applied to its full extent on a basin scale. After a period of declining exploration success in parts of the South Australia Cooper-Eromanga Basin, this study was undertaken by a dedicated regional geoscience team with the aim of rebuilding an understanding of the basin, based on first principles and stripping away exploration paradigms. The study area comprises an acreage position in the South Australian and Queensland Cooper-Eromanga Basins covering 70 000 km2 in which Senex Energy has 14 oil fields, has drilled more than 80 exploration wells and has acquired 2D and 3D seismic material. A plethora of proven and emerging plays exist within the acreage ranging from high productivity light sweet oil (Birkhead and Namur Reservoirs) to tight oil (Murta Formation), conventional gas (Toolachee/Epsilon and Patchawarra Formation), tight gas (Patchawarra Formation) and the emerging deep coal play (Toolachee and Patchawarra Coals). Play-based exploration methodologies incorporating the integration of seismic data, log and palynological data, structural analysis, geochemistry, 3D basin modelling, consistent well failure analysis and gross depositional environment maps have allowed the systematic creation of common risk segment maps at all play levels. This information is now actively utilised for permit management, business development, work program creation and portfolio management. This paper will present an example of the work focussing on the southern section of the South Australian Cooper-Eromanga Basin.

Exploring for stratigraphic traps in the Patchawarra Formation, Cooper Basin: an integrated seismic methodology

The Patchawarra Formation is characterised by Permian aged fluvial sediments. The conventional hydrocarbon play lies within fluvial sandstones, attributed to point bar deposits and splays, that are typically overlain by floodbank deposits of shales, mudstones and coals. The nature of the deposition of these sands has resulted in the discovery of stratigraphic traps across the Western Flank of the Cooper Basin, South Australia. Various seismic techniques are being used to search for and identify these traps. High seismic reflectivity of the coals with the low reflectivity of the relatively thin sands, often below seismic resolution, masks a reservoir response. These factors, combined with complex geometry of these reservoirs, prove a difficult play to image and interpret. Standard seismic interpretation has proven challenging when attempting to map fluvial sands. Active project examples within a 196 km2 3D seismic survey detail an evolving seismic interpretation methodology, which is being used to improve the delineation of potential stratigraphic traps. This involves an integration of seismic processing, package mapping, seismic attributes and imaging techniques. The integrated seismic interpretation methodology has proven to be a successful approach in the discovery of stratigraphic and structural-stratigraphic combination traps in parts of the Cooper Basin and is being used to extend the play northwards into the 3D seismic area discussed.

Composition changes of hydrocarbons during secondary petroleum migration

We investigate secondary migration of hydrocarbons with significant composition difference between the source and oil pools in the Cooper-Eromanga Basin, Australia. The secondary migration period is significantly shorter than the time of the hydrocarbon pulse generation, so neither adsorption nor dispersion of components can explain the concentration difference. The filtration coefficients, obtained from oil compositions in source rock (Patchawarra Formation) and in the reservoir (Poolowanna Formation and Hutton Sandstone), monotonically increase as carbon number increases. The monotonicity takes place for heavy hydrocarbons (n &gt; 10). Loss of monotonicity for light and intermediate hydrocarbons can be explained by their evaporation into the gas phase. The evaporation of light and intermediate hydrocarbons into the gas phase is supported by their concentrations in oil, which are higher in source rock than in trapped reservoir oil. The paper proposes deep bed filtration of hydrocarbons with component kinetic retention by the rock. Introduction of the component capture rate into the mass balance transport equation allows matching the concentration difference, and the tuned filtration coefficients are in the common range. The results suggest that deep bed filtration controls the final reservoir oil composition during secondary migration in the Cooper-Eromanga Basin petroleum system, which was not previously considered.

HyLogging unconventional petroleum core from the Cooper Basin, South Australia

ABSTRACTThe Cooper Basin is currently Australia's premier onshore hydrocarbon-producing province and hosts a range of unconventional gas play types, including the very extensive basin-centred and tight gas accumulations in the Gidgealpa Group, both shallow and deep dry coal seam gas associated with the Patchawarra and Toolachee formations, as well as the shale gas plays in the Murteree and Roseneath shales. Characterisation of mineralogical properties of shales is critical to hydraulic fracture design and development of unconventional hydrocarbon resources. Properties are sensitive to variations in mineralogy, especially clays, and historically, acquisition of a suite of rock mechanics analyses has been on a point-source basis rather than on a continuous sampling approach, which is uncommon. In this paper, a near-continuous 382 m cored section, comprising the lower Permian Daralingie Formation, Roseneath and Murteree shales, the Epsilon Formation and the top portion of the Patchawarra Formation from Holdfast-1 well (DH261958) in the southern Cooper Basin, was measured using robotic core scanning spectroscopy with automated mineral identification. HyLogger 3 incorporates visible, near infrared, shortwave infrared and thermal infrared hyperspectral measurements recorded every 0.8 cm along the core at the rate of approximately 1 m per minute. These data are co-registered with a high-resolution image and a laser profile of the core. X-ray diffraction and thin-section petrology from the Holdfast-1 well-completion report (Beach Energy, 2011) provided relative proportions of minerals including quartz, kaolinite, dickite, muscovite, illite, chlorite and siderite that enabled the modelled vs actual mineralogies to be constrained in the thermal infrared with a correlation coefficient of 0.85 for quartz, 0.79 for muscovite and 0.68 for kaolin; illite and siderite were more poorly correlated. HyLogger logging, when integrated with other petrophysical and analytical core data, provides a useful tool to better understand unconventional reservoirs and may assist in identification of zones that are conducive to fracture stimulation.

A Cooper Basin simulation study of flow-back after hydraulic fracturing in tight gas wells

After fluid injection (slickwater) during hydraulic fracturing, the flow-back of fracture fluid is necessary before gas production starts. A review of fracture treatments indicates that the incomplete return of treating fluids is a reason for the failure of hydraulic fracturing and is associated with poor gas production. The aim of this study is to investigate the parameters that limit flow-back in low permeability gas wells in the Cooper Basin. The authors used numerical simulation to find the critical controlling parameters to introduce the best practice for maximising the flow-back in the Cooper Basin. Several 3D and multiphase flow simulation models were constructed for three wells in the Patchawarra Formation during fracture fluid injection, soaking time and during flow-back. All models were validated using history matching with the production data. The results show that the drainage pattern is distinctly different in the following directions: vertically upward, vertically downward, and horizontal along the fracture half-length and along the matrix. The lowest recovery is observed during the upward vertical displacements due to poor sweep efficiency. Furthermore, it is observed that drawdown does not influence the recovery significantly for upward displacements. Surface tension reduction, however, can improve sweep efficiency and improve recovery considerably. Also, the wettability of the rocks has a significant impact on ultimate recovery when the effect of gravity is dominant. The authors conclude that a significant amount of injected fluid is trapped in the formation because of poor sweep efficiency and formation of gas fingers, which results from low mobility ratio and gravity segregation.

Next steps to crack the code on tight Permian Toolachee and Patchawarra sandstones of the Cooper Basin, southwest Queensland

Historic wells drilled by Real Energy Corporation Limited (Real Energy) in the Windorah Trough (Cooper Basin, southwest Queensland) characterised the Toolachee and Patchawarra formations as being gas-charged, tight-gas, sandstone/lacustrine shale sequences having layers of coaly source rock with high total organic content and moderate hydrocarbon indices. Consistent with being tight-gas reservoirs, drill stem tests have mostly either failed to produce gas or resulted in non-commercial flow rates. To date, North American methodologies for tight and shale gas extraction have not been consistently successful when applied in non-normal stress regimes outside of North America (i.e. Cooper Basin, China, Poland, Middle East, etc). Real Energy anticipated that North American technologies and practices were not likely to be directly applicable, as noted by published case studies for Australian shale gas wells (Johnson and Greenstreet, 2003; Pitkin et al, 2012; Scott et al, 2013; Johnson et al, 2015). Thus, it became an imperative to evaluate any methodologies or technologies more applicable for the Australian strike-slip to transpressional stress regimes to prevent fracture misalignment or disorientation, effects that result in ineffective fracture stimulation. Overall, a more scientific approach must be applied to developing and understanding the most efficient reservoir stimulation processes (e.g. drilling techniques, rock mechanical properties determination, well azimuth, perforating schema, and well interval selection) to optimise the stimulated reservoir volume (SRV). In this extended abstract the authors take the first steps at defining the stimulation strategies required for these tight sandstones using data and results from two case study wells. The authors outline the well observations and report key lessons in a cooperative spirit to solicit industry feedback and further technologies that can aid development of fit-for-purpose technologies to facilitate extraction of these largely untapped resources across the undeveloped troughs and flanks of the Cooper Basin.

Cooper Basin source rock atlas

The Australian Petroleum Source Rocks Mapping project is a new study to improve understanding of the petroleum resource potential of Australia’s sedimentary basins. The Permian source rocks of the Cooper Basin, Australia’s premier onshore hydrocarbon-producing province, are the first to be assessed for this project. Quantifying the spatial distribution and petroleum generation potential of these source rocks is critical for understanding both the conventional and unconventional hydrocarbon prospectivity of the basin. Source rock occurrence, thickness, quality and maturity are mapped across the basin, and original source quality maps prior to the onset of generation are calculated. Source rock property mapping results and basin-specific kinetics are integrated with 1D thermal history models and a 3D basin model to create a regional multi-1D petroleum systems model for the basin. The modelling outputs quantify both the spatial distribution and total maximum hydrocarbon yield for 10 source rocks in the basin. Monte Carlo simulations are used to quantify the uncertainty associated with hydrocarbon yield and to highlight the sensitivity of results to each input parameter. The principal source rocks are the Permian coals and carbonaceous shales of the Gidgealpa Group, with highest potential yields from the Patchawarra Formation coals. The total generation potential of the Permian section highlights the significance of the basin as a world-class hydrocarbon province. The systematic workflow applied here demonstrates the importance of integrated geochemical and petroleum systems modelling studies as a predictive tool for understanding the petroleum resource potential of Australia’s sedimentary basins.

Prediction of mobile water in a tight gas sandstone reservoir using NMR and fractional flow model

One of the objectives of petrophysical interpretation is the estimation of the respective volumes of formation fluids. With traditional interpretation using conventional openhole logs it is only possible to determine the total amount of water. The challenge is to determine the volumes of bound water (clay-bound and capillary-bound) and free water. At the moment, NMR is the only measurement that can help distinguish the volumes of each water component (clay-bound, capillary-bound and mobile), using cut-offs on T2 (transverse relaxation time). However NMR interpretation also requires information on reservoir properties. Alternatively, steady-state relative permeability and fractional flow of water can be used to determine the potential of mobile water. The study area, located in the Cooper Basin, South Australia, is the target of a planned gas development project in the Patchawarra formation. It comprises multiple stacked fluvial sands which are heterogeneous, tight and of low deliverability. The sands are completed with multi-stage pin-point fracturing as a key enabling technology for the area. A comprehensive set of data, including conventional logs, cores and NMR logs, were acquired. Routine and special core analysis were performed, including NMR, electrical properties, centrifuge capillary pressure, high-pressure mercury injection, and full curve steady state relative permeability. A fractional flow model was built based on core and NMR data to determine potential mobile water and the results compared with production logs. This paper (SPE 165766) was prepared for presentation at the SPE Asia Pacific Oil &amp; Gas Conference and Exhibition, held in Jakarta, Indonesia, from 22–24 October 2013.

Reservoir characterisation of the Patchawarra Formation within a deep, basin-margin gas accumulation

An exploration program to assess the basin-centred gas (BCG) and stratigraphic trap potential of the Mettika Embayment in the southern Cooper Basin resulted in the discovery of gas at Hornet–1 and Kingston Rule–1. The embayment is a confined fluvial sedimentary depocentre surrounded by prolific gas fields producing from structurally closed anticlines. Gas pay was identified and both wells produced sustained gas flows to surface of between 1.2 and 2.2 MMscf/d after fracture stimulation. Core collected from the Patchawarra Formation sandstone reservoir was analysed to constrain the depositional environment and establish petrophysical properties by routine and special core analysis. An integrated reservoir study was undertaken to understand depositional setting, reservoir architecture, trapping mechanisms, permeability, and saturation controls on productivity. Gas identified in the embayment appears to have accumulated in subtle stratigraphic and combination structural traps against the flanks of existing fields and does not display the geological and physical characteristics of a BCG play. The impact and analysis of hydrocarbon migration and reservoir trapping influences in this basin-margin gas accumulation may be applicable to other under-explored flank and trough plays of the Cooper Basin.

Proven and possible petroleum plays of the northern Cooper and Eromanga basins, South Australia

SummaryPIRSA recently released vacant acreage in the northern Cooper and Eromanga basins, South Australia. The release has focused attention on the proven and untested petroleum plays of this area.This paper summarises the current knowledge of source rocks, hydrocarbon generation, migration and traps. The importance of the Patchawarra Formation in the Cooper Basin and the Birkhead Formation in the Eromanga Basin are emphasised. A variety of oil and gas plays are discussed.

Proven and possible petroleum plays of the northern Cooper and Eromanga basins, South Australia

PIRSA recently released vacant acreage in the northern Cooper and Eromanga basins, South Australia. The release has focused attention on the proven and untested petroleum plays of this area. This paper summarises the current knowledge of source rocks, hydrocarbon generation, migration and traps. The importance of the Patchawarra Formation in the Cooper Basin and the Birkhead Formation in the Eromanga Basin are emphasised. A variety of oil and gas plays are discussed.