Toolachee Formation Research Articles

Performance evaluation of synthetic and natural polymers in nitrogen foam-based fracturing fluids in the Cooper Basin, South Australia

Hydraulic fracturing is a well-known stimulation technique for creating fractures in a subsurface formation to achieve profitable production rates in low-permeability reservoirs. Slickwater has been widely used as a traditional fracturing fluid. However, it has multiple disadvantages, such as high consumption of water, clay swelling and low flowback recovery. Foam, as an alternative fracturing fluid, consumes less liquid and provides additional energy. However, foam bubbles are typically unstable due to the degradation of surfactants, particularly in high temperature reservoirs, which reduces their capabilities of carrying and placing proppants into fractures. The purpose of this study is to provide general guidelines for an optimised application of polymers to improve the foam stability in high temperature reservoirs while increasing the proppant placement and water usage efficiencies. In this paper, the effects of natural hydroxypropyl guar (HPG) and synthetic polyacrylamide (PAM) polymers on the rheological properties of nitrogen foam-based fluids were examined by laboratory experiments conducted using temperatures up to 110°C. Then, a 3D hydraulic fracture propagation model was developed to study the fracturing performance of HPG-foamed and PAM-foamed fluids in the Toolachee Formation, Cooper Basin. It was found that synthetic PAM polymers were more effective than natural HPG polymers in stabilising foam viscosity under high temperature conditions. The simulation results indicate that foam-based fluids totally outperform slickwater in the field case application. This paper emphasises the significance of crosslinkers, foam quality and thermal stability on the performance of foams in high temperature environments.

Spatial mapping of seismic facies variations to mitigate reservoir risk in coal prone fluvial-deltaic settings

Seismic facies classification has been used to reduce risk in laterally heterogeneous reservoir prediction. Studies were focused on the Barrolka/Coolah/Durham Downs Trend in the south-west Queensland sector of the Cooper Basin. The primary reservoir targets are the fluvial channel sediments of the Toolachee Formation. Historically, well success rates across the area have been low, with highly variable reservoir development and connectivity identified as the limiting factors influencing well performance.Conventional seismic attribute analysis has typically yielded inconclusive results, often associated to the presence of thick coals that dominate the seismic response. However, recent drilling campaigns utilised seismic waveform classification mapping, which resulted in an increase in technical success rate of wells. This study aims to investigate the concepts behind the success of the waveform classification method and to determine alternate techniques to further delineate reservoir presence.Key outcomes f...

Simulation of hydraulic fracturing with propane-based fluid using a fracture propagation model coupled with multiphase flow simulation in the Cooper Basin, South Australia

In many unconventional reservoirs, gas wells do not perform to their potential when water-based fracturing fluids are used for treatments. The sub-optimal fracture productivity can be attributed to many factors such as effective fracture length loss, low load fluid recovery, flowback time, and water availability. The development of unconventional reservoirs has, therefore, prompted the industry to reconsider waterless fracturing treatments as viable alternatives to water-based fracturing fluids. In this paper, a simulation approach was used by coupling a fracture propagation model with a multiphase flow model. The Toolachee Formation is a tight sand in the Cooper Basin, around 7,200 ft in depth, and has been targeted for gas production. In this study, a 3D hydraulic fracture propagation model was first developed to provide fracture dimensions and conductivity. Then, from an offset well injection fall off test, the model was tuned by using different calibration parameters such as fracture gradient and closure pressure to validate the model. Finally, fracture propagation model outputs were used as the inputs for multiphase flow reservoir simulation. A large number of cases were simulated based on different fraccing fluids and the concept of permeability jail to represent several water-induced damage effects. It was found that LPG was a successful treatment, especially in a reservoir where the authors suspected the presence of permeability jails. The authors also observed that total flowback recovery approached 76% within 60 days in the case of using gelled LPG. Modelling predictions also support the need for high-quality foam, and LPG can be expected to bring long-term productivity gains in normal tight gas relative permeability behaviour.

Quantitative analysis of fluvial sandbodies of the Toolachee Formation, Cooper Basin, Australia

The Cooper Basin produces oil and gas from numerous fluvial channel sandstone bodies deposited within several formations such as the Late Permian Toolachee Formation; however, the geometry of these fluvial deposits are not well constrained. Five sandstone bodies (SS-1 to SS-5) have been identified within the Toolachee Formation. These sandstone bodies are characterized mainly by fining-upward packages, which have been interpreted to be deposited by high-sinuosity channels. This study aims to determine and interpret the size, geometry, and architecture of these fluvial sandstone bodies identified within the Toolachee Formation from well logs in the Meranji Field. The morphometric parameters examined in this study include channel width (w), channel depth (d), and meander-belt width (mbw). All of these parameters have been determined using empirical equations driven from modern rivers. The estimated maximum bankfull depth (d) ranges from 3.3 to 6 m, and the estimated channel width (w) ranges from 42 to 105 m, which indicates that these sandstone bodies were deposited by relatively small fluvial channels. The estimated meander-belt width (mbw) ranges from 800 to 2000 m, which indicates that some of these sandstone bodies (e.g., SS-1, SS-4, and SS-5) are connected and can be correlated between the adjacent wells within the Meranji Field. Furthermore, this indicates that these sandstone bodies are excellent reservoirs due to their good lateral extent. The empirical equations used in this study have improved the quantitative estimations of the channel dimensions and connectivity of the sandstone bodies. These equations can help to reduce the number of wells that are planned to be drilled in the Meranji Field.

Subsurface analysis of fluvial systems of Epsilon and Toolachee formations, Cooper Basin, Australia

Fluvial channel sandstones form major productive reservoirs in many basins around the world. In these basins, exploration and production activities are increasingly concerned with predicting the origin and distribution of fluvial sandstone bodies, which include a wide variety of stacking patterns, ranging from narrow and single-story sandstone bodies to wide and amalgamated multi-story bodies. Determining the geometry of sandstone bodies is critical to building and conditioning 3D reservoir models which help to determine the most efficient well spacing and thus improve reservoir management. The most critical dimension to be determined is the width of the sandstone bodies, which can be estimated from five methods: (1) well correlations, (2) outcrop analogues, (3) modern analogue, (4) empirical equations, and (5) 3D seismic geomorphology. This study was initiated to determine the geometry of subsurface fluvial sandstone bodies deposited within the Epsilon and Toolachee formations, two of the most productive formations within the Cooper Basin, South Australia. The intracratonic, Late Carboniferous–Middle Triassic Cooper Basin is characterized by three major elongate, synclinal depocenters which are separated by two anticlinal, intrabasin highs; these structures were active during deposition of the units studied here. On a regional scale, the Epsilon and Toolachee formations consist of fluvial, deltaic, and shoreface deposits. The fluvial sandstone reservoirs of interest within the study area of these formations were examined by using 3D seismic and well log data. This work indicates that most of the sandstone bodies within the Epsilon and Toolachee formations cannot be resolved on seismic data because the widths and thicknesses of these sandstone bodies are not great enough to be seismically visible, especially at deep burial depths. Two correlation panels were constructed using the widespread coal bed within the Toolachee formation as a datum to determine the width of the sandstone bodies. These correlation panels with the calculated sandstone portions suggested that sandstone bodies are amalgamated within the Toolachee formation and are isolated within the Epsilon formation; however, some of these sandstone bodies cannot be correlated between adjacent wells.

The Nappamerri Trough, Cooper Basin unconventional plays: proving a hypothesis

Beach Energy has started exploring unconventional gas in the Nappamerri Trough, the central trough within the Cooper Basin, where the Permian section has long been regarded as the primary source for most of the conventional hydrocarbons found within the basin. This extended abstract discusses the data used to identify the unconventional play and the exploration program carried out to date. Mud weights, drill stem test (DST) pressures and log data from early exploration wells identified the Permian formations as overpressured. This with geochemical and mineralogy analyses indicated that the Roseneath and Murteree Shales had potential similar to successful shale gas plays being developed in the USA. The quartz and siderite content within both shale sections indicated sufficient brittleness for successful fracture stimulation. In addition, the Nappamerri Trough Permian section showed low permeabilities, which, when combined with overpressure, suggested a basin-centred style play within the Epsilon and Patchawarra sandstones and possibly the Toolachee Formation sandstones. During 2010–11, Beach drilled two exploration wells sited outside structural closure to test both the shale gas and basin centred gas system. Both wells have now been fracture stimulated, with very encouraging gas flows from the Roseneath to Patchawarra section. The latest geological data confirms the pre-drill potential for both gas flow from the shales and the presence and production of gas from sandstones outside structural closure, resulting in a significant shale and tight gas resource booking. Ongoing exploration and development will target a potential 300 Tcf gas in place in PEL 218.

APPLICATIONS OF MODERN AND ANCIENT GEOLOGICAL ANALOGUES IN CHARACTERISATION OF FLUVIAL AND FLUVIAL-LACUSTRINE DELTAIC RESERVOIRS IN THE COOPER BASIN

Reservoir characterisation in fluvial and fluvial- lacustrine delta successions is enhanced by the use of appropriate modern and ancient analogues to understand subsurface reservoir architecture and to help build appropriately scaled reservoir models. Two case studies of reservoir characterisation in the Cooper Basin are used to illustrate the value of analogues. Firstly the Late Permian Toolachee Formation crevasse splay reservoirs of the Cooper Basin, southwest Queensland are outlined, and analogues from the Ob River in Western Siberia illustrate the relative scale of crevasse splay deposits within avulsion belts in a cool-temperate peat-forming environment. The South Blackwater coal mine in the Permian Bowen Basin is used as an analogue to quantify the 3D geometry and reservoir architecture of crevasse splays and to highlight subsurface reservoir heterogeneity.Secondly, the Early Permian Epsilon Formation shallow water lacustrine delta reservoirs are outlined, and analogues from the extant geometry of the distributary channels and relict mouth bar deposits from the fluvial dominated Neales Delta in Lake Eyre are used to interpret flow rate decline trends and probable reservoir architecture. The subsurface Tertiary lacustrine deltaic complex of the Sirikit Field from the Phitsanulok Basin, central Thailand, is selected as an ancient analogue for the multistorey reservoirs developed within amalgamated mouth bar complexes intersected in the lower Epsilon Formation.

NEW INSIGHTS INTO THE ACTIVE PETROLEUM SYSTEMS IN THE COOPER AND EROMANGA BASINS, AUSTRALIA

This paper presents geochemical data—gas chromatography, saturated and aromatic biomarkers, carbon isotopes of bulk fractions and individual n-alkanes—for oils and potential source rocks in the Cooper and Eromanga basins, which show clear evidence for different source-reservoir couplets. The main couplets involve Cooper Basin source and reservoir and Cooper Basin source and Eromanga Basin reservoir. A subordinate couplet involving Eromanga Basin source and Eromanga Basin reservoir is also identified, together with minor inputs from pre-Permian source rocks to reservoirs of the Cooper and Eromanga basins.The source–reservoir relationships are well expressed in the carbon isotopic composition of individual n-alkanes. These data reflect primary controls of source and maturity and are relatively insensitive to secondary alteration through migration fractionation and water washing, processes that have affected the molecular geochemistry of the majority of oils. Accordingly, the principal Gondwanan Petroleum Supersystem originating from a Permian source of the Cooper Basin has been further subdivided into two petroleum systems associated with Lower Permian Patchawarra Formation and Upper Permian Toolachee Formation sources respectively. Both sources are characterised by n-alkane isotope profiles that become progressively lighter with increasing carbon number—negative n-alkane isotope gradient. The Patchawarra source is isotopically lighter than the Toolachee source. Reservoir placement of oil in either the Toolachee or Patchawarra formations is, in general, a good guide to its source and perhaps an indirect measure of seal effectiveness. The subordinate Murta Petroleum Supersystem of the Eromanga Basin is subdivided into the Birkhead Petroleum System and Murta Petroleum System to reflect individual contributions from Birkhead Formation and Murta Formation sources respectively. Both systems are characterised by n-alkane carbon isotope profiles with low to no gradient. The minor Larapintine Petroleum Supersystem has been tentatively identified as involving pre-Permian source rocks in the far eastern YVarburton Basin and western margin of the Warrabin Trough in Queensland.Eromanga source inputs to oil accumulations in the Eromanga Basin can be readily recognised from saturated and aromatic biomarker assemblages. However, biomarkers appear to over-emphasise local Eromanga sources. Hence, we have preferred the semi-quantitative assessment of relative Cooper and Eromanga inputs that can be made using n-alkane isotope data and this appears to be robust provided that Eromanga source input is greater than 25% in oils of mixed origin. Enhanced contributions from Birkhead sources are concentrated in areas of thick and mature Birkhead source rocks in the northeastern Patchawarra Trough. Pre-Permian inputs are readily recognised by n-alkanes more depleted in I3C compared with late Palaeozoic and Mesozoic sources.Long range migration (>50 km) from Permian sources has been established for oil accumulations in the Eromanga Basin. This, together with contributions from local Eromanga sources, highlights petroleum pro- spectivity beyond the Permian edge of the Cooper Basin. Deeper, pre-Permian sources must also be considered in any petroleum system evaluation of the Cooper and Eromanga basins.

Depositlonai Architecture of Lacustrine-Delta and Fluvlal Systems of the Permian EpsiIon and Toolachee Formations at Duilingari Field, Southeastern Cooper Basin, South Australia: ABSTRACT

The Epsilon and Toolachee Formations record a transition from lacustrine deltas to fluvial depositional systems in the southeastern part of the Cooper Basin. Gas reservoirs in these formations occur mainly in narrow (typically less than 2 mi [3.2 km] wide) belts of distributary- and fluvial-channel sandstones in structurally high areas in Dullingari field and neighboring areas. In a study by the Bureau of Economic Geology and Santos to document distribution of Epsilon and Toolachee lithotacies, we mapped multiple depositional axes and projected them into undeveloped areas in the field. We performed a high-resolution sequence-stratigraphic study, defining four operational Epsilon subunits bounded by lacustrine mudstones recording periods of delta-platform abandonment and subsidence. In contrast, six genetic Toolachee subunits are bounded by regionally extensive coal seams recording pervasive sediment-supply shutoff and peat-swamp development over broad areas. Epsilon lacustrine deltas prograded northwestward over a muddy substrate on a broad, shallow basin floor. Distributary-channel axes, defined by narrow, northwest-trending belts of upward-fining sandstones less than 20 ft (6 m) thick, are projected across the field area. However, the younger Toolachee Formation contains northeast-trending sandstones in structural troughs, suggesting tectonic control on deposition. Detailed lithofacies maps of these formations provide a framework for assessing potentialmore » development targets at Dullingari field.« less

NEW GAS DISCOVERIES IN THE NORTHERN COOPER BASIN

Over the last two decades, minimal gas exploration was undertaken in the northeastern Cooper Basin. It was viewed the area held negligible gas potential due to the perceived absence of conventional anticlinal traps and the marginal reservoir quality of the Permian sandstones.With the award of permit ATP 549P to Mount Isa Mines Limited in mid-1993, available seismic and well data were reviewed to highlight potential fault-controlled traps in the region and to define areas likely to contain more favourable reservoir sandstones. A vibroseis seismic survey provided the initial prospects and leads inventory upon which the 1994 drilling program was based. Four prospects were tested resulting in three gas discoveries.Based on these encouraging results, an additional phase of seismic acquisition was completed to increase the prospect inventory. Thereafter, a five well program was undertaken. Whilst the two appraisal wells were successful, three wildcat wells failed due to ineffective trapping.A completion and testing program has been initiated to further evaluate the field discoveries.From an exploration viewpoint, the recognition of a consistently productive sandstone in the basal Toolachee Formation within a broad fairway across the eastern ATP 549P permit block was a significant result which has important implications for future activities. Within the fairway, gas flows varying from 0.4 MMcfd up to 6.0 MMcfd were measured on openhole tests. In addition, substantial gas volumes in low permeability sandstones within the Patchawarra Formation have been defined.These discoveries, coupled with the number of prospects and leads and the proposed gas pipeline to Mount Isa and to southeast Queensland markets, provide strong impetus to the continued evaluation of this northern extension of the Cooper Basin gas province.

Regional depth-conversion of mapped seismic two-way-times in the Cooper-Eromanga Basins

Mapped seismic two-way-times to the top of the Cadna-owie and Toolachee Formations in part of Petroleum Exploration Licences 5 and 6 of the Cooper-Eromanga Basins were depth-converted using the interval velocity and velocity anomaly methods. Two types of input velocity data were used for each depth-conversion method: (i) based on mapped seismic isochrons combined with thicknesses at well locations, and (ii) based on drift-corrected checkshot/sonic log data and thicknesses at well locations. The sequence was split into three layers for the depth-conversion: surface to top of the Mackunda Formation (layer 1), top of the Mackunda Formation to top of the Cadna-owie Formation (layer 2) and top of the Cadna-owie Formation to top of the Toolachee Formation (layer 3). The interval velocity method used constant layer interval velocities as predicted by interval velocity maps. In the velocity anomaly method, regional velocity/depth functions were fitted to the input layer velocities. Anomalies with respect to these regional functions were then mapped and used in conjunction with the regional functions in order to undertake the depth-conversion. The accuracy of the depth-conversions was assessed with reference to test wells not used in the determination of the input velocity models. The 95.5% confidence limits of the error in depth-conversion for the velocity anomaly method are 7?16% closer to zero than for the interval velocity method at the top of the Cadna-owie Formation, and 21?41% closer to zero at the top of the Toolachee Formation. Hence velocity anomaly can be more accurately mapped and predicted away from the input wells than 'raw' interval velocity. There is no significant difference between the errors in depth-conversion based on seismic isochron and checkshot/sonic log input velocities. Given that the former are more widely available, and more easily determined than the latter, their use is preferred.

THE INFLUENCE OF STRUCTURAL GROWTH AND OTHER FACTORS ON THE CONFIGURATION OF FLUVIATILE SANDSTONES, PERMIAN COOPER BASIN

The term structural growth is applied to subtle earth movements contemporaneous with sediment accumulation. To assess this factor, one must consider the roles of lateral sandstone accretion, river avulsion and sediment dispersal in the context of basin setting, climate and geological time.Interpretation of stratigraphic relationships and isopach and structural maps of areas comprising structural highs in the subsurface of the Permian Cooper Basin is based on the correlation of thin chronostratigraphic units in the Patchawarra Formation (Tirrawarra Field) and the Toolachee Formation (Big Lake-Moomba fields). Unit C of the Toolachee Formation in the Moomba area comprises several fining upwards sequences that appear cyclic and sheet-like. This facies relationship is similar to those in the immediate downflank areas of Big Lake. However, upflank in crestal areas, fluviatile sequences are more typical of multistorey sandstones. These crestal sandstones are the result of structural growth contemporaneous with deposition from a fluviatile meandering system during a significant interval of geological time. Meandering river systems are considered to have crossed the Big Lake-Moomba area locally from south-west to north-east. Isopach and percentage sandstone maps indicate that streams preferred an avenue of transport towards the Nappamerri Trough.Stratigraphic analysis of Patchawarra Formation Unit 2B in the Tirrawarra Field suggests a slightly greater rate of local subsidence there than in Big Lake and Moomba fields, resulting in a decreasing sand body interconnection. Although occasional fining upward sequences correlate across the field area, multistorey sandstone development occurs in an arcuate belt on its western side. This is the result of local structural growth and faulting contemporaneous with fluviatile deposition. Potential petroleum reservoirs of fluviatile origin occur in numerous basins worldwide. In basins exhibiting low rates of differential subsidence, potential reservoirs and seals occur as sheet-like bodies in structural traps near the margins of major depocentres. Knowledge of local and basinal differential subsidence and fluviatile architecture provides confidence for field exploitation and exploration for new plays.

SOUTH-WEST QUEENSLAND GAS — A RESOURCE FOR THE FUTURE

Natural gas has been discovered in 22 fields in the Central Eromanga and Cooper Basins of southwestern Queensland in the area comprised by ATP 259P. Proved, probable and possible reserves in excess of 36 × 109 m3 (1.27 TCF) are located in four discrete structural provinces. Fluvial sandstones of the Early Permian Patchawarra Formation and Late Permian Toolachee Formation contain the majority of the reserves. Minor amounts of gas are reservoired in the Early Permian Epsilon Formation, the Early-Middle Triassic Nappamerri Formation and the Early Jurassic Hutton Sandstone and Birkhead Formation. Considerable gas-liquids reserves are also found in these reservoirs.Existing reserves are located primarily in structural traps although lithofacies variations are widely recognised, particularly in the Patchawarra Formation, indicating both new play opportunities and difficulties in assessing the undiscovered gas potential of the permit. Additional gas potential is identified in flank areas of the more prominent structural axes such as the Jackson-Wackett-Innamincka Trend in fault-bounded, pinchout and sub-unconformity trapping configurations.More than 200 prospects and leads are identified with the potential to entrap approximately 51 × 109 m3 (1.80 TCF) of gas on an unrisked basis. When combined with reserves from established fields, the ultimate potential of the ATP is assessed as 87 × 109 m3 (8.10 TCF).Despite the very high success rate of previous exploration and appraisal programs, the ultimate gas potential of the Queensland portion of both the Cooper and Eromanga Basins has been only partially addressed. Exploration and appraisal programs providing future additions to proved and probable reserves are considered low risk and are dependent upon an agreement with the Queensland government that would enable the ATP holders to produce and sell gas interstate.

Point-Bar Deposits and Analysis of Subsurface Reservoir Dimensions, Toolachee Formation, Southern Cooper Basin, South Australia: ABSTRACT

Point-bar deposits occur ubiquitously within the lowest facies association of the Upper Permian Toolachee Formation (+500 ft thick). The association represents deposition in a moderate to high-sinuosity, mixed-load, fluvial channel system in which lateral bar deposits constitute major hydrocarbon sandstone reservoirs. Bars may be simple or punctuated in their upward-fining, vertical facies transitions, but heterolithic lateral accretion surfaces of upper point bars may occasionally be preserved in cores. Detailed facies studies of Association 1 in 17 cored wells reveal that pebbly thalweg lags locally include chaotic bank-collapse conglomerates. These basal point-bar deposits fine upward into cross-bedded sandstones. Ripple bedding is common in upper bar sequences. The bars are associated with a variety of abandonment fills, levees, and crevasse-splays, backswamp deposits, and autochthonous coals. Paleohydraulic studies of point bars in the Moomba field demonstrate an average bankfull depth of the Toolachee channels of 14 ft and bankfull width of 320 ft. Empirical relationships indicate a maximum meander loop diameter of 1,650 ft with meander belt width at 3,650 ft. These parameters allow an evaluation of reservoir geometry, storage potential, and permeability barriers. The latter, generated by clay-plug abandonment fills, can restrict fluid migration within the field and produce over-estimation of hydrocarbon reserves. Conversely, avulsive channel events may locally increase point-bar reservoir dimensions by partially, or totally, removing preexisting abandonment fills. End_of_Article - Last_Page 317------------

GEOLOGY OF THE DELLA FIELD, A PERSPECTIVE ON THE HISTORY OF THE COOPER BASIN

The Della Field produces dry gas from stacked fluvial sandstone reservoirs in the Early Permian Patchawarra Formation and Late Permian Toolachee Formation. Localised but severe fault activity and erosion in the late Early Permian have resulted in structural and stratigraphic complexities, particularly on the western flank of the field.A detailed study of lithofacies associations from cores has enabled constraints on the resolution of petrophysical logs to be appreciated. Within these constraints major facies associations are mappable across the field. Active channel migration in the Patchawarra Formation resulted in erosion and hence incomplete preservation of the fluvial sequence, which hinders mapping across the field. In contrast, the successive fluvial cycles of the Toolachee Formation are more completely preserved, enabling intrafield and some interfield correlation and mapping. The contrast is due to changing responses of the fluvial regime to prevailing tectonic conditions.A preliminary fluvial facies model, proposed after the first six Della wells, was upgraded during development drilling, with the result that productive reservoirs were successfully predicted. Integration of all available data provides one perspective on the evolution of the Cooper Basin in South Australia.

DIAGENESIS AND RESERVOIR QUALITY, TOOLACHEE FORMATION, COOPER BASIN

A preliminary petrological study of the Toolachee Formation in three Cooper Basin wells indicates that the intensity of diagenetic changes in the sandstones is the main factor influencing reservoir quality.Reduction of primary porosity occurs as a result of silica cementation as quartz overgrowths, dissolution of quartz grains forming microstylolitic grain contacts, authigenic clay mineral formation accompanying breakdown of chemically unstable grains, and cementation by siderite. Secondary porosity is erratically developed as a result of dissolution of some unstable grains particularly in rocks showing an advanced state of diagenetic alteration. High permeabilities are obtained only from those sandstones where significant primary porosity is still retained.Removal of chemically unstable grains during diagenesis has resulted in the formation of mineralogically mature sandstones, which consist almost entirely of quartz and clay minerals. The only other detrital components present are chemically resistant minerals such as muscovite or rock fragments composed of these resistant minerals.A relatively simple relationship of increasing intensity of diagenetic processes with increasing depth of burial may exist for the Toolachee Formation in the Cooper Basin.

REGIONAL LITHOFACIES AND PALAEOGEOGRAPHY OF THE GIDGEALPA GROUP

The Permian Gidgealpa Group contains major reserves of gas and minor amounts of oil in fluvial to marginal marine sandstone reservoirs within coal measures in the Southern Cooper Basin. Lithofacies analysis of a sequential set of palynologically defined time-rock units through the Gidgealpa Group has clarified depositional trends, identified regions of maximum channel development, located positions of shore-lines and shown directions of marine transgressions and regressions.Braided streams deposited the oldest unit, the Tirrawarra Sandstone, on a possibly glacially scoured land surface. As topographic gradients declined, rivers began to meander, and sandstone, shale and coal deposits of the Patchawarra Formation encroached over Tirrawarra Sandstone. Northwards flowing rivers gradually filled pre-Permian valleys with detrital sediments.During uppermost Patchawarra Formation deposition, the Cooper Basin was invaded from the east by a restricted sea, which then deposited the Murteree Shale. As this sea retreated, shoreline sediments of the Epsilon Formation prograded towards the east. A second transgression inundated the land, and the Roseneath Shale was deposited. Finally, delta deposits forming the Daralingie Beds prograded eastwards in the wake of the retreating sea.A period of erosion followed, during which time the present structural grain was imposed on the basin. Subsequently, eastward flowing meandering rivers deposited sandstone, shale and coal of the Toolachee Formation on an essentially flat topography, with only minor hills. The Toolachee Formation grades upwards into non -coal bearing beds, which perhaps register a climate change.

LITHOFACIES STUDY ON THE TOOLACHEE FORMATION, GIDGEALPA-MOOMBA-BIG LAKE AREA, COOPER BASIN, SOUTH AUSTRALIA

A lithofacies study on the Upper Permian Toolachee Formation has been conducted in the Gidgealpa-Moomba-Big Lake area to determine the suitability of the technique in the reconstruction of depositional environments and palaeogeographic trends throughout the Cooper Basin. The Toolachee Formation is one of the main gas producing intervals in the basin, especially in the area of study, which is approximately 2,000 square kilometres. Thirty-one wells drilled in this region indicate that the formation ranges in thickness from 35 metres to over 115 metres.The Toolachee Formation, taken as a whole, is too thick to show any significant features on a lithofacies map over the limited area of investigation. However, lithofacies maps of three approximately chronostratigraphic subdivisions of the same formation show both vertical and lateral trends. Vertically, the percentage of sandstone decreases from the lowermost subdivision to the uppermost subdivision; coal percentages show the opposite trend; and core material shows fining upwards sequences. Laterally, isopachous thin areas (depositional highs) in most cases correlated with an increase in shale or coal lithologies. Histograms of coal cycles show that the lower and middle parts have similar composite sequences of, from the base upwards, sandstone mixture of sandstone and shale-shalecoal.The depositional model proposed is an aggradational flood-plain which, prior to the commencement of deposition, had been eroded to a peneplain. Sediments were deposited from rivers of gradually declining flow gradient until marsh and lacustrine conditions prevailed for long periods of time. Deposition ceased at the sediplain stage.

THE DELIA FIELD, COOPER BASIN, SOUTH AUSTRALIA

The Della gas field of the Cooper Basin, South Australia, was discovered by Pursuit Oil No Liability and joint venture associates in July 1970. The field covers an area of approximately 17,000 acres in a discrete culmination on the Nappacoongee-Murteree anticlinal trend.Production is from several fluviatile sandstone units within the Toolachee Formation of the Upper Permian Gidgealpa Group. The trap is essentially structural with a maximum closure of some 450 ft on the top of the Toolachee Formation above a probable gas-water contact at 6,460 ft subsea.Five of the seven wells drilled to date in the field have been completed as potential gas producers. Production occurs between 6,270 and 6,670 ft and the average total depth is 7,180 ft. Net pay thicknesses vary from 37 to 98 ft and good reservoir characteristics are typical of the producing sands in the field. Twenty-two days are normally required to drill and complete a productive well.

THE GEOLOGY OF THE PALCHAWARRA AREA COOPER BASIN

This paper is another chapter in the long series of papers presented to APEA Conferences since 1964 on the geology of the Cooper Basin. The Patchawarra area became of interest after Bridge Oil on behalf of its partners discovered oil in the area while drilling Tirrawarra No. 1 as part of their obligations to earn a 50 percent interest in the area. This paper deals with the central part of the Patchawarra Gravity Low first described by the Author in 1966.The Tirrawarra Formation was deposited in the Patchawarra trough during early Permian. The Gidgealpa Innamincka trend constitutes the eastern boundary of this trough while the western boundary of the Patchawarra Gravity Low coincides with the western boundary of the Cooper Basin.Sedimentation during the Permian in the Cooper Basin is controlled regionally by the major structural trends such as, the Gidgealpa Innamincka Trend, but hiatii and minor local unconformities also developed around individual structrues.The major unconformity recognised in the Patchawarra Low occurs between the Upper Permian Toolachee Formation and the Lower Permian Moomba Formation.