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APPEA JOURNAL 2001—185
R.R. Hillis1, J.G.G. Morton2, D.S. Warner3 andR.K. Penney31NCPGG
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).
mailto:[email protected]:[email protected]:[email protected]:[email protected]
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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.
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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).
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R.R. Hillis, J.G.G. Morton, D.S. Warner and R.K. Penney
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).
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Deep basin gas: a new exploration paradigm in the Nappamerri
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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.
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R.R. Hillis, J.G.G. Morton, D.S. Warner and R.K. Penney
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.
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Deep basin gas: a new exploration paradigm in the Nappamerri
Trough, Cooper Basin, South Australia
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
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R.R. Hillis, J.G.G. Morton, D.S. Warner and R.K. Penney
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.
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Deep basin gas: a new exploration paradigm in the Nappamerri
Trough, Cooper Basin, South Australia
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).
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194—APPEA JOURNAL 2001
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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
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APPEA JOURNAL 2001—195
Deep basin gas: a new exploration paradigm in the Nappamerri
Trough, Cooper Basin, South Australia
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.
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196—APPEA JOURNAL 2001
R.R. Hillis, J.G.G. Morton, D.S. Warner and R.K. Penney
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).
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APPEA JOURNAL 2001—197
Deep basin gas: a new exploration paradigm in the Nappamerri
Trough, Cooper Basin, South Australia
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
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198—APPEA JOURNAL 2001
R.R. Hillis, J.G.G. Morton, D.S. Warner and R.K. Penney
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.
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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.