DEEP BASIN GAS: A NEW EXPLORATION PARADIGM IN … · Elmworth and Hoadley in the Western Canadian...

APPEA JOURNAL 2001—185

R.R. Hillis1, J.G.G. Morton2, D.S. Warner3 andR.K. Penney3

1NCPGG and APCRCAdelaide University, Thebarton CampusAdelaide SA 50052Office of Minerals and Energy ResourcesPrimary Industries and Resources South AustraliaGPO Box 1671Adelaide SA 50013Santos Limited91 King William StreetAdelaide SA [email protected]@[email protected]@santos.com.au

ABSTRACT

Deep basin hydrocarbon accumulations have been widelyrecognised in North America and include the giant fields ofElmworth and Hoadley in the Western Canadian Basin.Deep basin accumulations are unconventional, being locateddowndip of water-saturated rocks, with no obviousimpermeable barrier separating them. Gas accumulationsin the Nappamerri Trough, Cooper Basin, exhibit severalcharacteristics consistent with North American deep basinaccumulations. Log evaluation suggests thick gas columnsand tests have recovered only gas and no water. Theresistivity of the entire rock section exceeds 20 Ωm overlarge intervals, and, as in known deep basin accumulations,the entire rock section may contain gas. Gas in theNappamerri Trough is located within overpressuredcompartments which witness the hydraulic isolationnecessary for gas saturation outside conventional closure.Furthermore, the Nappamerri Trough, like known deepbasin accumulations, has extensive, coal-rich source rockscapable of generating enormous hydrocarbon volumes. Theabove evidence for a deep basin-type gas accumulation inthe Nappamerri Trough is necessarily circumstantial, andthe existence of a deep gas accumulation can only be provenunequivocally by drilling wells outside conventional closure.

Exploration for deep basin-type accumulations shouldfocus on depositional-structural-diagenetic sweet spots(DSDS), irrespective of conventional closure. This is ofparticular significance for a potential Nappamerri Troughdeep basin accumulation because depositional modelssuggest that the best net/gross may be in structural lows,inherited from syndepositional lows, that host stackedchannel sands within channel belt systems. Limitingexploration to conventionally-trapped gas may precludeintersection with such sweet spots.

KEYWORDS

Deep basin gas, Nappamerri Trough, log evaluation,overpressure, source rocks, depositional-structural-di-agenetic sweet spots (DSDS), conventional closure, newexploration paradigm.

INTRODUCTION

Deep basin hydrocarbon accumulations, also knownas basin-centre or continuous accumulations, have beenrecognised in the Rocky Mountain Laramide Basins ofthe central-western United States and in the WesternCanadian Basin. The Western Canadian deep basin gasresource is estimated to be 1,750 tcf. Original reserveestimates for the Elmworth Field were 17 tcf and 6–7 tcffor the Hoadley Field (Masters, 1984; 1992; Chiang,1984). Deep basin accumulations are unconventional inthat they lie downdip of water-saturated rocks with noobvious impermeable barrier separating them, and be-cause the porosity in such deep basin accumulations isalmost entirely hydrocarbon-saturated (Fig. 1).

There have been relatively few published descrip-tions of deep basin gas accumulations outside of NorthAmerica. However, it seems unlikely that the phenom-

DEEP BASIN GAS: A NEW EXPLORATION PARADIGM IN THENAPPAMERRI TROUGH, COOPER BASIN, SOUTH AUSTRALIA

Figure 1. Schematic illustration contrasting the nature of deepbasin hydrocarbon accumulations and conventional accumulations.Conventional accumulations are isolated pools that are structur-ally- and/or stratigraphically-trapped and display distinct hydrocar-bon-water contacts. Deep basin accumulations are in hydraulicisolation and abnormally pressured, with all porosity hydrocarbon-filled. The key to commercial production of deep basin accumula-tions lies in locating sweetspots of enhanced reservoir potential.From Spencer (1989) and Surdam (1997).

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186—APPEA JOURNAL 2001

R.R. Hillis, J.G.G. Morton, D.S. Warner and R.K. Penney

enon is restricted to North America. Indeed, Urien andGarvey (1997) described possible deep basin gas in theNeuquen Basin of Argentina. This paper investigateswhether the thick, low permeability gas columns in theNappamerri Trough of the Cooper Basin, South Austra-lia, may constitute a deep basin hydrocarbon accumula-tion and the implications of such for exploration strategyin the area.

QUO VADIS EXPLORATION IN THECOOPER BASIN: A NEW PARADIGM?

The Cooper Basin is a relatively mature explorationprovince in the Australian context, and at the end of1997, 121 gas fields had been discovered from 298 newfield wildcats in the South Australian sector of the basin,with total recoverable raw gas reserves of around 8 tcf(Morton, 1998). Estimates of the undiscovered potentialof the basin vary greatly according to the estimationtechniques used (Morton, 1998). The first 30 fields dis-covered in the Cooper Basin constituted approximately80% of the cumulative gas reserves base, with the re-maining 91 contributing only the remaining 20%. It istypical that early field discoveries in a basin are thebiggest and later ones smaller. If new Cooper Basin gasfields of significant size are to be discovered, it is likelythat new plays will need to be targeted. One such pos-sible new play is deep basin gas.

NORTH AMERICAN DEEP BASINGAS EXPERIENCE

Masters’ (1979) paper on the gas trapped in the Creta-ceous of the deepest part of the Western Canadian Basinfirst alerted the wider exploration community to theoccurrence of deep basin hydrocarbon accumulations.Many of the following points regarding deep basin gasaccumulations in North America are based on Masters’(1979) original and subsequent papers (Masters, 1984;1992). Much additional relevant information is includedin AAPG Memoirs 38, 61 and 67.

In reference to the Western Canadian Basin, Masters(1979) stated:

‘With very limited exceptions, the entire Mesozoicrock section in the Deep Basin is saturated with gasbelow a depth of about 3,500ft (1,065 m). Within thisarea it is not possible to drill a dry hole; non-commer-cial wells, yes, but no completely dry holes. Everystringer of porosity holds gas.’.Wireline log data provided the key evidence used to

infer the presence of deep basin gas in the WesternCanadian Basin. Rapidly increasing resistivities are ob-served throughout the entire Cretaceous section as thedeeper part of the Western Canadian Basin is reached. Inthis area of increased resistivities, formation tests re-cover only gas. There is no free water beneath the gas.The increased resistivities cannot be explained by de-creasing water salinity, cement or mineralogical content,or any other rock characteristic (Masters, 1979). The

Figure 2. Location of the Nappamerri Trough and wells referredto in the text.


Deep basin gas: a new exploration paradigm in the Nappamerri Trough, Cooper Basin, South Australia

excess resistivity is caused by gas. In hindsight, it seemsremarkable that the deep basin gas accumulation wasnot recognised sooner, but the many wells from whichwireline log and formation test data were compiled wereoriginally drilled targeting deeper oil plays, and, further-more, water was known to saturate the Cretaceous unitsupdip (Fig. 3). The occurrence of gas accumulations withwater updip, and no obvious impermeable barrierbetween them, was unrecognised at the time. That thistype of hydrocarbon accumulation was previouslyunrecognised undoubtedly retarded the discovery ofdeep basin accumulations.

Now numerous deep basin hydrocarbon accumula-tions, including some of the largest gas fields in NorthAmerica, are recognised, such as Elmworth, Hoadley andMilk River in the Western Canadian Basin, the Blancogas field in the San Juan Basin (New Mexico/Colorado),the Wattenburg gas field in the Denver Basin, the EchoSprings and Wamsutter gas fields in the Washakie Basin(Greater Green River Basin, Wyoming) and the Altamont-Bluebell oil field of the Uinta Basin (Utah).

One of the key aspects of deep basin accumulations isthat they are invariably abnormally pressured (Davis,1984; Surdam et al, 1997). The Western Canadian DeepBasin accumulations are underpressured (Fig. 3), as arethose of the San Juan Basin. Accumulations in the GreenRiver Basin are variously underpressured or overpres-sured (Fig. 4). Abnormal pressures witness hydraulicisolation between the deep basin accumulations andoverlying, normally pressured water-bearing strata. Dueto their hydraulically isolated nature, such pressurecompartments are associated with fields that are notconstrained by conventional structural closure or strati-graphic pinch-out (Al-Shaieb et al, 1994a; Surdam, 1997).

Deep basin hydrocarbon accumulations appear to beassociated with extensive, coal-rich source rocks capableof producing enormous volumes of hydrocarbons. Con-sidering the generative potential of coals and shales,Masters (1984) estimated that the Mesozoic section inwestern Alberta has a total generative potential in therange of 10,000 trillion cubic feet (tcf) of gas and 7,500billion barrels of oil. These source rocks have supplied(at least in part) the vast Athabascan tar deposits, thedeep basin gas and the (volumetrically relatively insig-nificant) thousands of conventional stratigraphic poolson the eastern flanks of the basin.

In deep basin accumulations, all the rock exhibits highresistivity. In the case of the San Juan deep basin accu-mulation, all rock exhibits resistivities of in excess of 20Ωm. The entire section is gas-saturated, not only the mainpay sands, but every silt zone and every streak of sand inthe entire section is gas charged. Even the tightest shaleswhen examined right off the shaker bleed gas under themicroscope. It is suggested that this reflects theinterbedded nature of the coal and shale source rocksand the reservoir sands. The authors suggest that not allthe gas has undergone primary migration from thesesource rocks into the interbedded sands; hence they aregas charged and exhibit high resistivities.

Figure 3. Summary of fluid types and pressures in the CadotteFormation, Elmworth area, Western Canadian Basin. (a) Fluid typesand pressure data points, structure contours are to top of CadotteFormation; (b) Pressure-depth plot; (c) Generalised fluid cross-section. From Davis (1984).



Since the entire section is gas-saturated, the key tocommercial exploitation of deep basin accumulationslies not in intersecting gas, but rather in intersectingzones of enhanced porosity and permeability in thegenerally tight sandstones of the deep basin settings.With respect to the Western Canadian Deep Basin, Mas-ters (1984) noted that:

‘It needs to be stated clearly again that the DeepBasin accumulation is not all in tight sands. Within thetight sand accumulation, downdip from the bottleneck,there are belts of conventional porosity-permeabilityrocks. The Falher conglomerate beaches providesuperb reservoirs up to 10-mi wide and 30-mi long (16by 48 km), with permeabilities up to darcys and welltests reaching 40,000 mcf/d at 1,200 psi flowingpressure. Other porous beach reservoirs occur in theCadotte, Notikewin, and Bluesky sections. These sweetspots are analogous to the fracture trends in the SanJuan Basin tight sands which provide high welldeliverabilities and large total recoveries.’.Commercial accumulations in the Western Canadian

Deep Basin are present where coarse-grained marineshoreline (beach barrier) sands occur. Early Cretaceousshorelines in the Western Canadian Basin were dominantlynortheast-trending, with six main trends developed as thesea generally regressed from south to north. The mostnortherly, and youngest reservoir sequence at Elmworth isalso the most extensive because it was an area of shorelinestillstand where multiple beaches are stacked vertically.Initial attempts to follow reservoir sand trends in theWestern Canadian Deep Basin were unsuccessful becausethey assumed that they followed the subsequently developednorthwest-trending structural grain of the basin. Hence, itis critical, in the exploration for commercial deep basinhydrocarbons, to have an appropriate depositional model.

Natural fracturing of otherwise tight rocks can alsohelp develop reservoir quality in the deep basin sands.This occurs both in the San Juan Basin as described byMasters (1984) above, and in the Washakie Basin (Surdam,1997). The advent of deviated drilling has led to theincreased exploitation of naturally fractured sweet spotsin deep basin accumulations (Spencer, 1989).

The diagenetic history of the sandstones is also criticalto the preservation of reservoir quality in sandstones indeep basin settings. Indeed, the extension of the Albertadeep basin gas play into British Colombia was predicatedon the continuation of the Falher Sandstone beach bar-rier sequences from Alberta into British Colombia. How-ever, these were generally tightly cemented on the Brit-ish Colombia side of the border, and the overlying CadotteFormation beach conglomerates provide reservoir qual-ity (Masters, 1992). In the Washakie Basin, grain-rim-ming clays inhibit quartz cementation and serve to pre-serve reservoir quality in the deep basin (Surdam, 1997).In ideal circumstances depositional, structural and di-agenetic processes mutually reinforce one another toprovide reservoir quality in the deep basin sands. Theauthors term such as depositional-structural-diageneticsweet spots (DSDS).

Figure 4. Summary of fluid types and pressures in the Tertiary andUpper Cretaceous, Green River Basin, Wyoming. (a) Fluid typesand pressure data points, structure contours are to top of FortUnion Formation; (b) Pressure-depth plot; (c) Generalised fluidcross-section. From Davis (1984).



Thin permeable zones in deep basin accumulationscan produce gas volumes in excess of that containedwithin the sweet spot itself. For example, in the AlmondFormation at Standard Draw (Washakie Basin), gas pro-duction can only be accounted for by the draining ofadjacent tight sands via the sweet spot (Iverson andSurdam, 1995). Production from thin permeable zonesmay draw down their pressure, creating a pressure dif-ferential between the sweet spot and the adjacent tightsand. Such a pressure differential may exceed the rela-tively high displacement pressure of the adjacent tightsands, leading to the draining of gas from the tight sandsinto the adjacent sweet spot. Masters (1984) describedsuch thin permeable zones as behaving like horizontalfractures.

In summary, the deep basin gas play, with total gassaturation downdip of water saturation, has been provenin North America and includes several giant fields. Deepbasin accumulations are always abnormally pressured,and the hydraulic isolation of abnormally pressuredcompartments results in fields that do not require con-ventional structural or stratigraphic closure. Deep basinaccumulations are generally associated with source rockswith very great generative potential. The key to theircommercial exploitation lies in finding depositional, struc-tural and/or diagenetic sweet spots within the otherwisetight sands of deep basin settings. Deep basin hydrocar-bon accumulations represent a vast reserve, only a smallproportion of which is currently commercially extract-able in sweet spots.

SEALING MECHANISMS

Production from deep basin gas fields downdip ofwater with no obvious impermeable barrier between, hasirrefutably proven the existence of this type of previ-ously unrecognised hydrocarbon accumulation. However,the nature of the seal to these accumulations remainsunclear. The Western Canadian and San Juan deep basingas accumulations are underpressured and associatedwith potentiometric lows. Hence, water flow in thesesystems is downdip and against the gas accumulation,and the accumulations may be, at least partially, hydro-dynamically trapped (Masters, 1979; Bachu, 1995; Bachuand Underschultz, 1995).

Hydrodynamic trapping cannot account for the seal-ing of overpressured deep basin gas accumulations likethose of the Greater Green River Basin which are associ-ated with potentiometric highs (Surdam et al, 1997) .Two-phase flow effects in hydrocarbon-water systemsmay be critical to the trapping of hydrocarbons in theseoverpressured systems (Fig. 5; Surdam et al, 1997). Thepermeability of a rock to single phase flow for a givensaturating fluid, e.g. water, is its absolute permeability.However, in two-phase flow, the two immiscible fluidsinterfere with each other and the effective permeabilityto the flow of either phase (e.g. gas and water) is reducedfrom its absolute permeability. The summation of effec-tive permeabilities is always less than 100% (Fig. 5). In a

gas-water system, with water wet rocks, as the gas satu-ration increases and water saturation decreases, therelative permeability to gas increases and the relativepermeability to water decreases. In the example shownin Figure 5, at approximately 75% water saturation, therelative permeability to both water and gas is only 10%of the absolute permeability to water. Hence, relativepermeability effects may serve to help seal deep basinaccumulations, the sealing properties being triggered bythe generation of hydrocarbons. Indeed, it is interestingto speculate whether the commonly observed coinci-dence of top overpressure and hydrocarbon generation isrelated to relative permeability effects in seals, ratherthan, as more commonly assumed, to increased porepressures associated with kerogen cracking to gas.

Diagenetic banding commonly occurs in associationwith anomalously pressured compartments (Al-Shaiebet al, 1994b; Shepherd et al, 1994). Banding resultsfrom diagenetic processes such as pressure solutionand, for example, in the Anadarko Basin, is expressedby silica- and carbonate-cemented layers that areseparated by clay-coated porous layers in sandstones(Al-Shaieb et al, 1994b). Although diageneticallybanded intervals comprise layers of moderately highporosity, the bands act collectively as low permeabilityseals for pressure compartments (Shepherd et al, 1994),and may potentially contribute to the sealing of deepbasin gas accumulations.

Figure 5. Relative permeability curves for a Travis Peak Formationtight gas sand. Depth 8 270 ft (2521 m), permeability at netoverburden pressure 0.028 mD. Redrawn from Johnson et al.(2000). krgas: relative permeability to gas, krwater: relative permeabil-ity to water.



It is likely that deep basin gas accumulations are notperfectly sealed and that leakage is continuously occur-ring from the anomalously pressured compartments.However, leak rates are sufficiently slow that, perhapscombined with ongoing hydrocarbon generation, anoma-lous pressures and gas saturation are maintained withina dynamic process. Hydrodynamic flow, relative perme-ability effects and diagenetic banding may all contributeto the sealing process to different degrees in differentbasins.

NEW EXPLORATION PARADIGM

Deep basin accumulations require a different explora-tion methodology to that applied in the search for con-ventional, structurally- and stratigraphically-trappedhydrocarbons (Fig. 6). The focus of exploration needs tobe the search for porosity-permeability sweet spots inthe otherwise tight sands of the deep basin (Fig. 1).Conventional traps are not required. However, giventhat deep basin accumulations are hydraulically isolatedand abnormally pressured, defining the geometry ofabnormally pressured compartments should also be afocus of exploration (Surdam, 1997). If deep basin gas isbelieved to exist from log data, well tests, and otherfactors such as those discussed herein, the regional pres-sure system should be mapped (Fig. 6). Sonic log data

from abnormally pressured wells can be used to investi-gate the velocity response to abnormal pressure and,under optimal conditions, the extent of overpressuremay then be mapped using seismic processing velocities.Once the geometry of abnormally pressured, gas-satu-rated compartments is known, the key to obtaining com-mercial production lies in the location of sweet spots(Fig. 6). The search for deep basin sweet spots shouldcover the entire anomalously pressured, gas-saturatedcompartment(s) and should not be restricted to areas ofclosure. Finally, drilling and completions must be opti-mal for, and specific to the sweet spot to be exploited(e.g. deviated drilling for naturally fractured sweet spots).

Good engineering practice is critical to the successfulexploitation of deep basin reservoirs. Fracture stimula-tion is commonly undertaken in the relatively tight, deepbasin accumulations (Stayura, 1984; Spencer, 1989). Tightreservoirs are particularly prone to formation damage(Spencer, 1989), and oil-based muds (Myers, 1984) andunderbalanced drilling present potential strategies tominimise such. It is beyond the scope of this paper toaddress the optimum drilling and completion practicesfor deep basin accumulations.

EVIDENCE FOR DEEP BASIN GASIN THE NAPPAMERRI TROUGH

There is no unequivocal evidence that the NappamerriTrough hosts a deep basin gas accumulation. No wellshave been drilled outside of structural closure in thetrough, and only with the drilling of such can the deepbasin gas hypothesis be fully tested. However, there issignificant circumstantial evidence that a deep basinaccumulation exists in the Nappamerri Trough.

Tests from the deep part of the trough have recoveredonly gas. However, in many tests, permeabilities havebeen such that the gas flow was at a rate too small tomeasure. At such low permeabilities, gas may preferen-tially flow due to relative permeability effects, and/orgas, naturally dissolved in water zones, may exsolve dueto pressure reduction during the testing process. Testsmay not always be definitive indicators of gas-saturatedzones in low permeability reservoirs and wireline logdata may be more reliable.

Correlation of resistivity log data through the troughshows large intervals where the entire rock columnexceeds 20 Ωm resistivity (Figs 7 and 8). It is difficult tointerpret this data in any other way other than that thesection contains very little water and that the porosity ishydrocarbon filled. Quantitative log analysis based onwater resistivities known from other parts of the basinsuggests that the reservoirs in these zones are at close toirreducible water saturation, which if located in a con-ventional structural closure would require huge gas col-umns to be present due to the low permeability. As in thedeep basin gas accumulations of North America, it ap-pears that the entire rock section may contain gas. Everysand, silt and shale exhibits high resistivity throughmuch of the section. It is suggested that this reflects the

Figure 6. Flowchart illustrating exploration methodology for deepbasin hydrocarbon accumulations.



interbedded nature of the coal and shale source rocksand the reservoir sands, and that not all the gas hasundergone primary migration from these source rocksinto the interbedded sands, hence they are gas chargedand exhibit high resistivities.

Neutron-density log crossovers can be unreliable indi-cators of gas in the Nappamerri Trough because sand-stones exhibit extensive breakout and the density logoften reads anomalously low due to hole rugosity. Inmore recent wells, dual-axis density tools have been runin which the pad containing the source and detectors isforced into the short axis of the hole, yielding morereliable density measurements. The same type of toolwas likewise used to help overcome breakout-relateddegradation of density log quality in the Western Cana-dian Basin (Sneider et al, 1984). Sands in the postulatedNappamerri Trough deep basin accumulation are gener-

ally associated with neutron-density crossover. How-ever, these cross-overs cannot be confidently ascribed tothe presence of gas and neutron-density-based interpre-tation of gas is equivocal.

Although the entire postulated deep basin gas sectionshows high resistivity, there is a significant drop inresistivity in the lower Patchawarra Formation,Tirrawarra Sandstone and Merrimelia Formation.Resistivities typically drop from in excess of 100 Ωm inthe overlying units to below 100 Ωm in these lower units.The origin of this reduction in resistivity is unclear. Insome areas it is related to an increase in clay content ofthe sands as witnessed by the gamma ray log. However,shale interbeds also show a similar decrease in resistiv-ity. It may be related to a reduction in gas saturation, butsimilar lower resistivity units produce gas on the flanksof the Nappamerri Trough, for example, in the Big Lake

Figure 7. Regional log correlation through the Nappamerri Trough. Resistivity logs are illustrated with shading to a 20 Ωm cut-off on thelaterolog deep or equivalent (red >20 Ωm; blue <20 Ωm). Note thick sections with high resistivities that appear to be entirely gas-saturated.Left track shows gamma ray and sonic logs, gamma ray shaded yellow <80 API (sands) and sonic shaded black >90 ms/ft (coals). Verticalscale exaggerated relative to horizontal scale.



Field. Furthermore, the total gas count in Bulyeroo–1 isat least as high, if not higher through the low resistivityzone than through the overlying high resistivity zone(Fig. 8). The reduction in resistivity may reflect a changein clay mineralogy (e.g. diagenesis from kaolin tosecondary illite, which has a higher cation exchangecapacity and hence lower resistivity), increase in second-ary porosity and/or more saline formation water resistiv-ity in the deep basin. The increased illitisation withdepth in the basin (Schulz-Rojahn and Phillips, 1989)may itself reduce resistivity, and also reduce permeabil-ity such that cations produced by ongoing fluid-rockinteraction cannot be flushed from the system, therebyresulting in further decreased resistivity (N. Lemon,NCPGG, pers. comm., November 2000).

The deep Nappamerri Trough is anomalously pres-sured. Overpressures are witnessed by drill stem testpressures, mud weights and undercompaction of soniclog velocities (van Ruth and Hillis, 2000; Fig. 9). Thehighest pore pressure observed in wells to-date in theNappamerri Trough is ~17 MPa/km (0.75 psi/ft). The over-pressures cannot be due to thick gas columns alone,because this would require free water levels within thebasement to the trough. Overpressure-induced under-compaction is witnessed by reversals in the normallyincreasing trend of sonic velocity with depth from~5,000 ms-1 to ~4,500 ms-1 (van Ruth and Hillis, 2000).Given the low well density in the Nappamerri Trough,there is a strong imperative to map the top of the over-pressure using seismic data. It is not yet clear whetherthe velocity reversal associated with overpressure in theNappamerri Trough can be resolved using seismic pro-cessing velocities, but such will be a focus of investiga-tion using both old and future seismic data.

Gas column pressures vary in different parts of theTrough (Fig. 10). Hence, overpressures in the NappamerriTrough do not form a single overpressured compartment,but rather there are nested pressure compartments withinthe overall overpressured system. In the Anadarko Basinof Oklahoma, the overpressured system (so-calledmegacompartment complex) can be subdivided into twosmaller-scale levels of compartmentalisation (Al-Shaiebet al, 1994c). Level 2 compartments in the AnadarkoBasin are within a particular stratigraphic interval and32–49 km long by 19–32 km wide by 122–183 m thick,with reserve estimates reaching in excess of 2 tcf. Level3 compartments in the Anadarko Basin consist of a singlesmall field or a particular reservoir that is nested withina Level 2 compartment. There is not sufficient data toresolve Level 3 compartments in the Nappamerri Trough,if indeed they do exist.

Anomalous pressures do not, of course, per se demon-strate the existence of a deep basin gas accumulation.Conventionally-trapped accumulations with recognisablehydrocarbon-water contacts may be overpressured. How-ever, abnormal pressure is one of the key aspects of deepbasin gas accumulations, and the occurrence of overpres-sures demonstrates the existence of hydraulically iso-lated compartments within the Nappamerri Trough. If

Figure 8. Log composite plot for Permian section of Bulyeroo–1,Nappamerri Trough. Note: gamma ray, sonic and laterolog deepshading are as in Figure 9 and neutron/density crossover shadedorange.



Figure 9. Pore pressure profiles in wells in and around the Nappamerri Trough (a) Kirby–1 (b) McLeod–1 (c) Darmody–1 and (d) ThreeQueens–1. The hydrostat, mud weight and sonic-based Eaton pressure prediction are all shown. In Kirby–1 and McLeod–1 in the NappamerriTrough, mud weights and Eaton prediction are consistent with drill stem test data, all indicating overpressure. Normal pressure is observedin wells on the flanks of the trough (Darmody–1 and Three Queens–1). From van Ruth and Hillis (2000).



such compartments are entirely gas-saturated, then con-ventional traps are not required and exploration shouldfocus on the search for sweet spots within these overpres-sured compartments.

Like the deep basin gas accumulations of NorthAmerica, the Nappamerri Trough has extensive, coal-rich source rocks capable of generating enormous vol-umes of hydrocarbons. The authors consider this likely tobe a factor in the complete gas saturation of deep basinaccumulations. Morton (1998) estimated the total gasgenerative potential of the source rocks of the CooperBasin to be 4,027 (minimum estimate) - 8,055 (maximumestimate) tcf. Masters (1984) estimated that the Meso-zoic section in western Alberta has a total generativecapability in the range of 10,000 tcf of gas. Source rockvolumes are much smaller in the Cooper Basin (5,300km3) than in the Alberta Basin (90,000 km3; Morton, 1998;Masters, 1984). However, the average total organic car-bon content (combining shales and coals) is 11% in theCooper Basin, and 1.5-2.5% in the Alberta Basin. Fur-thermore, Cooper Basin coals may have a higher hydro-gen index and higher maturity (maximum vitrinite re-flectance of 8) than those in the Alberta Basin. Thesmaller source rock volume of the Cooper Basin is coun-teracted by its considerably richer nature and results in

Figure 10. Pressure plot for gas columns in the NappamerriTrough. Plots are anchored on one reliable drillstem test-derivedpressure (squares) with an assumed gas gradient extrapolated forthe thickness of the unit in which the test was undertaken. The gascolumns exist in separate, overpressured cells within an overalloverpressured system. A normally pressured free water level forthese columns would be located in the basement to the NappamerriTrough.

total gas generative capacities of the same order as thatin the Alberta Basin. If high generative potential ofsource rocks is critical to the occurrence of deep basingas accumulations, the Cooper Basin, and particularly itsmain depocentre, the Nappamerri Trough, is certainlysuitably endowed with such source rock potential. Un-less the Cooper Basin has a particularly low rate ofretention of hydrocarbons in reservoirs, significant re-serves may exist in poorly explored plays such as thedeep basin gas play (or indeed basement reservoirs, orcoal bed methane).

No wells have been drilled outside structural closurein the Nappamerri Trough, hence it is not possible toassess the key determinant of a deep basin accumulation,ie. gas saturation outside conventional closure. How-ever, recent drilling at Moomba North is consistentlyencountering gas at structurally deeper locations on theflanks of trough, and Moomba–6 has produced a signifi-cant amount of gas from a thin stratigraphic reservoir inthe Patchawarra Formation that is probably mostly lo-cated outside structural closure. However, there arealways uncertainties in the precise extent of structuraland especially stratigraphic closure. Indeed, even if gasis found outside probable structural closure in theNappamerri Trough, it may never be convincingly dem-onstrated to be outside possible stratigraphic closure.

In summary, there is no unequivocal evidence that theNappamerri Trough hosts a deep basin gas accumulation.No wells have been drilled outside structural closure inthe trough, and only with the drilling of such can the deepbasin gas hypothesis be fully tested. However, the follow-ing are consistent with gas in the deep NappamerriTrough constituting a deep basin-style accumulation:• thick gas columns with high resistivities in the sands,

silts and shales;• anomalously pressured compartments from which tests

recover only gas and no water, and;• coal-rich source rocks capable of generating enor-

mous volumes of hydrocarbons.

SIGNIFICANCE OF THE DEEP BASIN GASMODEL TO EXPLORATION METHODOLOGY

IN THE NAPPAMERRI TROUGH

A significant change to conventional exploration meth-odology is required if targetting a deep basin gas accu-mulation. The general approach to exploration for deepbasin accumulations was outlined above (Fig. 6). Thissection addresses consequences for exploration specificto the Nappamerri Trough if it hosts a deep basin typeaccumulation.

As with other deep basin gas accumulations (andinherent in the nature of the play), reservoir permeabil-ity is the key risk factor. Hence, as in North America, ifthere is a deep basin accumulation in the NappamerriTrough, the key to its commercial exploitation may lie infinding sweet spots of porosity and permeability withinthe basin centre. The best reservoir quality is likely to be



found where all DSDS (depositional, structural and di-agenetic sweet spot) elements are mutually re-inforcing.It is beyond the scope of this paper to review all therelevant depositional, structural and diagenetic factorsaffecting reservoir quality in the Nappamerri Troughwhich lead to a myriad of sub play types. However, somekey issues with relevance to the postulated NappamerriTrough deep basin gas play are discussed.

Acceptance or otherwise of the deep basin model hasparticular significance in the Nappamerri Trough. Syn-depositional topographic lows, many of which are pre-served as present-day structural lows, are likely to havehosted the depositional environments associated with themost significant reservoirs. Drilling conventional structuralhighs may preclude intersecting the thickest reservoirs inthe trough. Sequence stratigraphic studies in intracratonicbasins have shown that the best net/gross can be encounteredin fluvial channel systems and associated crevasse splays(Lang et al, 2000). Preliminary seismic sequencestratigraphic interpretation has postulated that channel

belt systems can be recognised on 2D seismic profiles fromwithin the Nappamerri Trough (Fig. 11). From availableopen file wells in the Nappamerri Trough, it is clear thatwhere genetic intervals containing channel belt systemsthicken, there is a tendency to have higher net/gross thanwhere these intervals are thinner over syndepositionalhighs. Similar features have been noted in the EromangaBasin (Allen et al, 1996; Musakti, 1997). Many of the syn-depositional lows in the Nappamerri Trough were controlledby deep basin structure, and remain as structural lows.Hence, many of the sand-rich channel belt systems arelocated in structurally low positions. The search fordepositional sweet spots must be undertaken within theframework of an overall sequence stratigraphic andpalaeogeographic model because not all syndepositionallows are sand-prone. Sand-prone axial channel beltsterminate into lakes or broad floodouts where there isdecreasing net/gross (Lang et al, 2000). Furthermore, somechannel belts may have only received fine-grained sediment,and therein reservoir quality may be limited.

Figure 11. 2D seismic profile through an interpreted channel belt system in Nappamerri Trough.



Whilst a preliminary seismic sequence stratigraphicanalysis has indicated the presence of likely sand fair-ways, it is not possible to undertake the detailed se-quence stratigraphic and palaeogeographic analysis re-quired to map the channel/crevasse splay systems usingthe existing 2D seismic data for the Nappamerri Trough.Dating of the relevant sequence boundaries by sporecolouration is also impossible due to the very high tem-peratures in the trough. However, by way of comparison,Nakanishi and Lang (2001) present several exampleswhere sequence stratigraphic analysis of 3D seismic data(from the Moorari Field area of the adjacent PatchawarraTrough) predicts reservoir quality developed off-struc-ture in channel systems in the Patchawarra, Epsilon,Toolachee and Poolowanna Formations (Fig. 12).

Experience in extending the Alberta deep basin playinto British Colombia witnesses the signficance of incor-porating a diagenetic component into sweet spot predic-tion (the Falher Sandstone beach barrier sequencescontinue from Alberta into British Colombia, but they

are generally tightly cemented on the British Colombiaside of the border, and the overlying Cadotte Formationbeach conglomerates provide reservoir quality). Thediagenetic history of the Cooper Basin has been de-scribed by Schulz-Rojahn and Phillips (1989), Rezaeeand Lemon (1996) and Rezaee et al (1997). The cleanestand the coarsest sands in the Cooper Basin make the bestreservoirs. Coarse sediments have relatively large porespaces that require much cement to fill, and clean sandsare low in the rock fragments and feldspar that alter toproduce reservoir-damaging kaolin and illite (N. Lemon,NCPGG, pers. comm., September 2000). Coarse sands inthe Cooper Basin sequence are associated with the mainfluvial channels (as described above) and clean sandswith lacustrine shorelines. Thus reservoir diagenesis isultimately controlled by depositional environment(Rezaee and Lemon, 1996), and the search for both thedepositional and diagenetic components of an optimumDSDS can be undertaken within a sequence stratigraphicand palaeogeographic framework.

Figure 12. Channel system observed on 3D seismic data from horizon slice within the Poolowanna Formation (Jurassic) in the MoorariField area, Patchawarra Trough, Cooper Basin. Note much of the channel/crevasse splay system is off-structure. From Nakanishi and Lang(2001).



Structural sweet spots, i.e. zones of enhanced naturalfracturing, have significant potential within theNappamerri Trough. Many cores from vertical or nearvertical wells in the Cooper Basin intersect natural frac-tures that are predominantly steeply-dipping, which sug-gests that deviated drilling has significant potential tointersect zones of permeability greatly enhanced bynatural fracturing. Considerable work has been under-taken on locating structural sweet spots within theNappamerri Trough. This has involved re-interpretationof the structural evolution of the Cooper Basin inte-grated with core- and image-log based analysis of naturalfractures in order to develop a model for the origin ofnatural fractures that can be used predictively. Theprediction of structural sweet spots has also utilisednumerical modelling in order to predict high strain zonesprone to natural fracturing and the associated fracturestyle. Finally, determination of the in-situ stress field ofthe trough is critical to the exploitation of the deep basingas resource, because the impact of the in-situ stress fieldon the hydraulic conductivity of pre-existing naturalfractures must be factored into the prediction of struc-tural sweet spots.

In summary, the nature of the gas accumulation has acritical impact on the appropriate exploration methodol-ogy. If the Nappamerri Trough accumulation is a deep basintype, the best DSDSs should be located, with the search notlimited to conventional traps. If the gas in the NappamerriTrough is a conventional accumulation, then the search forDSDSs must be trap-limited, and may be precluded fromintersecting the best reservoir quality.

THE CHALLENGE FOR DEEP BASINGAS EXPLORATION IN THE

NAPPAMERRI TROUGH

Deep basin accumulations were only recognised in theWestern Canadian Basin after having been by-passed inthe search for deeper oil plays. Eighty-five wells weredrilled through the Elmworth Field prior to its recognitionby Canadian Hunter (Masters, 1992). Similarly, theHoadley Glauconitic sand bar was penetrated by hundredsof wells prior to the recognition of 6–7 tcf gas reserves(Chiang, 1984). In hindsight it seems remarkable that theElmworth deep basin gas accumulation was not recognisedsooner, but water was known to saturate the reservoirunits updip, and the occurrence of gas accumulationswith water updip, and no obvious impermeable barrierbetween was unrecognised at the time.

Undoubtedly the fact that deep basin accumulationswere previously unrecognised retarded the discovery ofthese fields. However, once the accumulations wereproven to exist, there was a very significant database,especially of wireline log data, from wells that had by-passed the field upon which to base further exploration.No such extensive database exists in the NappamerriTrough, with only eight wells intersecting the postulateddeep basin gas accumulation, and none of those wellsoutside structural closure. The challenge for exploration

in a sparsely drilled area such as the Nappamerri Troughis to confirm the existence of a deep basin accumulation,and, if this does exist, to define and exploit the resourcewith vastly fewer wells than in North America. The keyto successfully meeting this challenge lies in:• learning from the North American deep basin gas

experience;• applying modern exploration technologies such as

sequence stratigraphic analysis of 3D seismic data todefine depositional and diagenetic sweet spots andAVAZ (amplitude variation with offset and azimuth)to determine natural fracture strike and density andthus define structural sweet spots;

• applying state-of-the-art knowledge and modelling ofdepositional, structural and diagenetic processes tolocate DSDSs, and;

• applying modern drilling and completion techniquessuch as deviated drilling.The potential size of a deep basin gas resource in the

Nappamerri Trough and the existing infrastructure inthe Cooper Basin are two key drivers for making thenecessary investment in improved technologies, andimproved understanding of the geological processes con-trolling sweet spot formation, to exploit the potentialdeep basin gas resource of the Nappamerri Trough.

CONCLUSIONS

A new play type must be developed for significant newgas reserves to be located in the Cooper Basin. The vastamount of gas generated within the Cooper Basin sug-gests that significant gas reserves may be located in newplays, unless the Cooper Basin is, on the global scale, aparticularly leaky system in which only a very smallpercentage of the gas generated is trapped in reservoirs.

One such new play concept is that of deep basin gas,with total gas saturation downdip of water saturation,which has been widely recognised in North America.There is significant circumstantial evidence that a deepbasin accumulation may exist in the Nappamerri Trough,i.e. thick gas columns interpreted from logs and testing,anomalous pressures and rich source rocks (Figs 7-10).There is, however, no unequivocal evidence that theNappamerri Trough hosts a deep basin gas accumula-tion. No wells have been drilled outside of structuralclosure in the trough, and only with the drilling of thesecan the deep basin gas hypothesis be fully tested.

The exploration methodology for deep basin gas isconsiderably different than that for conventional hydrocar-bons (Figs 1 and 6). The search for commercial deep basingas should focus on locating depositional-structural-diagenetic sweet spots (DSDS) within anomalously pressuredgas-saturated compartments, irrespective of conventionalstructural or stratigraphic closure. Indeed, depositionalmodels for the Nappamerri Trough suggest that the bestnet/gross may be in structural lows inherited fromsyndepositional lows, where stacked channel sands arelocated within channel belt systems. Limiting explorationto conventionally-trapped gas may preclude intersection



with such sweet spots, and indeed, it is likely that theNappamerri Trough hosting a deep basin type accumulationprovides the best chance for commercial production to beestablished within the foreseeable future.

ACKNOWLEDGEMENTS

The concept that the Nappamerri Trough hosts a deepbasin gas accumulation has been long in development,and remains in gestation. Over that period many people,at NCPGG, at PIRSA and at Santos, have contributed toour ideas on the concept. They may not necessarily agreewith all the ideas presented herein, but we thank themall for their input, especially John Kaldi, Simon Lang,Nick Lemon, Scott Mildren and Peter van Ruth at NCPGG,Alan Sansome and Tony Hill at PIRSA, Ashok Khurana,Carl Greenstreet, Sharon Tiainen, Rhodri Johns andThomas Flottmann at Santos and also David Campagnaof ARI. David Moreton and an anonymous reviewer arethanked for their constructive comments on the manu-script.

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Authors’ biographies over page.


THE AUTHORS

Richard Hillis holds the Stateof South Australia Chair in Pe-troleum Reservoir Properties/Petrophysics at the National Cen-tre for Petroleum Geology andGeophysics (NCPGG), Univer-sity of Adelaide. He graduatedBSc (Hons) from Imperial Col-lege (London, 1985), and PhDfrom the University of Edinburgh(1989). After seven years at the

Adelaide University’s Department of Geology and Geophysics,Richard joined the NCPGG in 1999. His main research inter-ests are in petroleum geomechanics and sedimentary basintectonics. He has approximately 50 published papers and hasconsulted to many Australian and international oil companies.He is SA Branch president of the ASEG. Member: AAPG, AGU,ASEG, EAGE, GSA, GSL, PESA and SEG.

John Morton is currently Prin-cipal Petroleum Geologist withthe Petroleum Group of the Of-fice of Mineral and Energy Re-sources, PIRSA. He graduatedwith a BSc (Hons) from the Uni-versity of Otago (Dunedin, NewZealand) in 1980, and this wasfollowed by a MSc in AppliedGeology from the University ofNew South Wales in 1982. He

joined the SA Department of Mines and Energy in 1982 as adevelopment geologist estimating gas reserves of the Cooperand Otway Basins for government gas contract advice, and haspublished more than 35 papers and reports. More recently,John has worked mainly on regulatory, legislative and policyissues, but retains an interest in reserve estimation, develop-ment geology, petrophysics and quantitative undiscoveredresource evaluation of petroleum plays. Member: PESA andSPE.

David Warner is a senior staffgeoscientist with the SantosGroup. He is currently involvedwith the Low Deliverability GasTask Force within Santos whichis dealing with developing inno-vative exploration and comple-tion methodologies to apply tothe tight gas provinces of theCooper Basin in Australia. Hegraduated with a BSc (Hons) from

The University of New England in 1971 and an MSc fromImperial College, London in 1979. David has extensive experi-ence in both exploration and development within the majoronshore basins of Australia. His initial job in the oil and gasindustry included a two-year secondment to Amoco Researchwhere he was involved in overpressure detection and evalua-tion and drilling optimisation techniques. This lead to a clearunderstanding of the potential for formation damage in tight gasprovinces and the need for application of non-conventionalexploration and completion techniques to unlock potential inthese areas. Member: SPE and AAPG.

Richard K. Penney has beenManager of Santos’ Low Del-iverability Gas Task Force since1996. He joined Santos in 1994 asChief Petrophysicist with respon-sibility for evaluations in Santosoperations in Australasia, SE Asia,Europe and USA. Richard previ-ously spent 12 years with ShellInternational, working for Op-erators in the North Sea, North-

ern Europe and the Middle East, holding various PetroleumEngineering positions plus roles in planning, economics andbusiness analysis. Richard has published papers in the areas offormation evaluation, business process modelling and assetmanagement. Richard graduated first in his class and with BEng(First Class Honours) in Engineering Science and completed aPost-Graduate Research Fellowship in Harbour Simulation,both at the University of Auckland, New Zealand. He is amember of the advisory committees of the NCPGG andGeophysics (University of Adelaide) and the School of Petro-leum Engineering at the University of New South Wales. He isthe 2000 Treasurer of the SPE South Australian Section andserves on the Editorial Committee of SPE’s Journal of Petro-leum Technology. Member: SPE and SPWLA.

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