The Latrobe Formation in the Gippsland Basin \(SE Australia\) As a Potential Reservoir for Underground CO2 –Storage- a Lite
33.5324.00/05/03 Confidential REPORT
The Latrobe Formation in the Gippsland Basin (SE Australia) as a potential reservoir for underground CO2 –storage - A literature-based evaluation drawing on experience from the North Sea Sleipner case
Peter Zweigel & Erik Lindeberg
SINTEF Petroleum Research August 2003
REPORT TITLE The Latrobe Formation in the Gippsland Basin (SE Australia) as
SINTEF Petroleumsforskning AS a potential reservoir for underground CO2 –storage SINTEF Petroleum Research - A literature-based evaluation drawing on experience from the North Sea Sleipner case
N-7465 Trondheim, Norway
Telephone: +47 73 59 11 00 AUTHOR(S) Fax: +47 73 59 11 02 (aut.) Peter Zweigel & Erik Lindeberg Enterprise no.: NO 936 882 331 MVA
CLASSIFICATION CLIENT(S) Confidential Statoil, SACS consortium, NFR-KLIMATEK REPORT NO. 33.5324.00/05/03
REG. NO. DATE PROJECT MANAGER SIGN. 2003.034 4 August 2003 Peter Zweigel Peter Zweigel
NO. OF PAGES NO. OF APPENDICES LINE MANAGER SIGN. 45 2 Torleif Holt Torleif Holt SUMMARY The Gippsland basin offshore southeast Australia is a large petroleum province close to major onshore CO2 point sources. Based on publicly available literature, this study investigates the technical suitability for storage of anthropogenic CO2 underground in the Gippsland basin as a potential means to reduce CO2 emission to the atmosphere. The evaluation is based on experiences from the underground storage project at the Sleipner field (North Sea).
The main reservoir system in the Gippsland basin consists of siliciclastic rocks of the upper Latrobe Group as the reservoir and the carbonaceous deposits of the Seaspray Group as the seal. Efficacy of this system is proven by the existence of large hydrocarbon accumulations. Reservoir parameters indicate that the system is likely to be suitable for underground CO2 storage. For a pilot phase, storage in strongly or partly depleted oil fields is suggested. Already produced oil corresponds to an available pore 6 space for storage of approximately 250·10 tons CO2, which is around five times the annual CO2 emissions from use of coal for electricity and heat production in the adjacent state of Victoria. Underground CO2 storage in the Gippsland basin is therefore rated as a major option to reduce emissions considerably.
Prior to start of injection of CO2 into the Latrobe Group, technical investigations will be necessary. These need especially address the effect of CO2-brine mixtures on the reservoir and seal rocks, and potential adverse consequences for site stability and long-term seal efficacy.
KEYWORDS ENGLISH KEYWORDS NORWEGIAN
Gippsland basin Gippslandbassenget Australia Australia
Underground CO2 storage Underjordisk karbondioksidlagring Literature study Litteraturstudie
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Table of Contents
1. Executive summary...... 3 2. Background and purpose of the study ...... 4 3. Requirements for underground CO2 storage sites...... 7 4. The Latrobe Group/Gippsland basin reservoir system...... 9 4.1 Geological overview...... 9 4.2 Geological reservoir properties of the Latrobe Group...... 13 4.3 Temperature and pressure at storage site level...... 15 4.4 Seal properties ...... 18 4.5 Traps ...... 21 4.6 CO2 properties at reservoir conditions...... 23 5. Discussion...... 28 5.1 Reservoir formation suitability...... 28 5.2 Seal efficacy ...... 28 5.3 Storage capacity...... 29 5.4 Monitoring...... 31 5.5 Additional precautions...... 35 5.6 Use of CO2 for enhanced oil recovery (EOR) ...... 35 6. Conclusions and recommendations ...... 37 7. References...... 39
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1. Executive summary
Power production based on local coal deposits in Victoria (SE Australia) generates large amounts of CO2 which are emitted to the air. The neighbouring, offshore Gippsland basin is a mature hydrocarbon province in which the existence of large hydrocarbon fields proves efficacy of the reservoir-seal system. This literature-based study investigates the technical suitability for storage of anthropogenic CO2 underground in the Gippsland basin as a potential means to reduce CO2 emission to the atmosphere.
Major technical conditions for feasibility of underground CO2 storage are the availability of sufficiently large storage volumes, high density of CO2 at reservoir conditions, high permeability of the reservoir formation, and the absence of negative effects due to reactions of the CO2-water brine with the host and seal rock. Further, seal efficacy must be ascertained prior to injection, and it may be desirable to be able to monitor the distribution of CO2 in the underground.
In the Gippsland Basin, the reservoir system consists of the Cretaceous to Oligocene, siliciclastic Latrobe Group as the reservoir and the Oligocene to recent, carbonaceous Seaspray Group as the seal. Especially the top parts of the Latrobe Group exhibit very good reservoir properties and host large hydrocarbon accumulations. These accumulations document excellent seal efficacy.
The seal rock is carbonaceous and the reservoir rocks contain locally significant amounts of carbonate minerals. Potential reactions of CO2-containing brine with these rocks may have adverse effects on storage site safety and must be addressed adequately prior to start of any potential CO2 injection.
Hydrocarbon fields in their final stages of production are suggested here as the prime targets for pilot underground CO2 storage projects in this basin. This is because these sites have demonstrated seal efficacy and because relevant on-site infrastructure exists. Furthermore, injected CO2 may help to enhance oil recovery from these fields, therefore generating an economic value for the CO2.
Typical net storage volumes per trap have been estimated here to be in the order of 0.1 9 3 – 0.5·10 m for the larger traps. CO2 density at reservoir conditions is expected to vary as a function of geothermal gradient from approx. 350 kg/m3 in the western, proximal fields to approx. 600 kg/m3 in the eastern, distal fields. The typical storage capacity in the large traps is thus estimated to be approx. 100·106 tons per trap, which is 5 times the quantity planned to become injected in the Sleipner case.
Production of hydrocarbons from the Gippsland basin until now provides pore space for 6 approximately 250·10 tons CO2. This corresponds to 5 times the annual CO2 emissions from use of coal for electricity and heat production in Victoria. Underground CO2 storage in the Gippsland basin could thus contribute significantly to reduce annual emission rates over a period of a few 10s of years. Economics have not been considered quantitatively here, but we note that costs for pipelines may provide a hurdle for the economic feasibility of underground CO2 storage in the Gippsland basin.
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2. Background and purpose of the study
Australia contributes approximately 1.5% of global total anthropogenic greenhouse gases, its per capita emission of 33.3 tons/year (1990 data) being the highest of all OECD countries (Durie 1998 after Samarin 1999). Stationary electricity and heat 6 production accounts for 171·10 tons CO2 emissions per year (1999 data), which is approximately 55 % of all CO2 emitted annually in Australia (AGO 2001). Increased energy demand in this sector caused a rise of greenhouse gas emissions by 1.9% from 1998 to 1999 in spite of declining average emission intensity. Approximately 93% of the CO2 emitted from the stationary energy production sector come from firing of brown and black coal (AGO 2001).
Victoria, as the Australian state onshore of the Gippsland basin (Figure 2.1), has extensive coal production. Much of this coal production is located directly onshore of the Gippsland basin, because the Latrobe Group, which is the main source rock for Gippsland basin hydrocarbon accumulations (e.g. Rahmanian 1990), contains abundant coals that are exploited onshore. Several power plants, predominantly utilising locally mined brown coal, are situated in southeastern Victoria (Figure 2.2a) and additional such plants are planned (Figure 2.2b) to meet increasing energy demands. In 1995, CO2 emissions from use of coal for electricity and heat production in Victoria amounted to 45·106 tons (AGO 1998).
AUSTRALIA
Victoria Gippsland Basin
Figure 2.1 Location of Victoria and the Gippsland basin.
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(a)
(b)
Figure 2.2 Existing (a) and planned (b) power plants close to the Gippsland basin. Maps from the Fossil Fuel Power Station database of the Australian Greenhouse Office (http://www.agso.gov.au/fossil_fuel/).
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Large point sources, where vast amounts of CO2 are emitted from a few outlets, are primary targets for efficient use of technologies to separate and capture CO2 from flue gases. The location of several such large point sources close to an underground reservoir may provide a setting for short, i.e. low-cost, transport of CO2 to potential underground deposition sites (e.g. Holloway 1996) at which CO2 could remain separated from the atmosphere for thousands of years or more. Since the Gippsland basin contains reservoir rocks and traps that proved to be tight over Millions of years to retain upward migrating hydrocarbons in economic quantities (e.g. Rahmanian 1990), it may potentially provide space for underground CO2 storage, too.
The purpose of this report is to document results of a literature-based evaluation of the potential suitability of the main Gippsland basin reservoir formation, the Latrobe Group, for long-term underground CO2 storage. The evaluation summarises major characteristics of the reservoir formation and of its seal and evaluates them in comparison with experiences from the first industrial underground CO2 storage site at the Sleipner field in the North Sea.
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3. Requirements for underground CO2 storage sites
Underground CO2 storage facilities will have to satisfy technical criteria that especially define safety requirements and performance. Since large-scale underground CO2 storage is a new technique which so far was only implemented in one single case (the Sleipner field; Baklid et al. 1996), there do not yet exist generally accepted standards or formal regulations that explicitly define applicable technical criteria. There may, however, be national or international regulations or agreements that bear upon underground CO2 storage, e.g. conventions about storage/deposition of substances offshore or regulations for underground storage of gas or waste. The existence and potential applicability of such formal requirements was not investigated here.
Results of a general feasibility study on underground CO2 storage (Holloway 1996) and experiences from the ongoing Sleipner project allow to define a preliminary list of technical requirements that a potential underground CO2 storage site most likely will have to fulfil. The most important of these requirements are listed below.
Technical and economic feasibility
Storage sites must have a sufficiently large storage volume to keep costs for transport and storage installations per stored unit of CO2 reasonably low. The volume is defined by the accessible pore space in places from which CO2 escape into the atmosphere or to other undesired destinations (e.g. ground water reservoirs) is below a critical quantity within a defined time span. Such places can be either geological traps or laterally open reservoir units in cases where migration of free CO2 to escape locations is strongly limited. Traps can be proven ones (e.g. depleted former hydrocarbon fields) or unproven ones (trap geometries in water filled aquifers). Open reservoirs with a sufficient retention capacity can be constituted by cases where migration velocity along the reservoir is in the long-term outpaced by the rate of dissolution of CO2 into formation water, such that potential leakage sites in some distance of the injection location cannot be reached by free CO2 (Lindeberg 1997).
The pressure and temperature of the reservoir will influence the density of CO2. In general, temperatures low enough and pressures high enough to get CO2 into supercritical (dense) or liquid state are desirable because then the storable quantity will increase considerably as compared to the gaseous state.
Temperature, pressure, and injection gas and formation water chemistry must be such to exclude formation of CO2-hydrates which would clog the migration pathway from the injection locality (well) to the storage site.
Similarly, potential reaction of CO2 (especially when dissolved in brine) with the reservoir rock should not result in major reductions of porosity and/or permeability or mechanical destabilisation of the storage site.
Permeability must be large enough to allow injection at high rates.
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Safety of the storage site
Tightness of the storage site, i.e. reservoir seal efficacy to prevent migration of CO2 into the atmosphere or to locations where it could cause danger for humans, installations, or the environment, is the primary safety concern when selecting storage sites.
Sufficient seal efficacy is often indicated in storage locations where CO2 shall be injected into traps that contain depleted hydrocarbon accumulations. CO2 might, however, react chemically with the seal formation and thereby reduce its retention capability. Dissolution of reservoir rock components may cause pronounced compaction and subsequent subsidence of the overburden, which may include deformation (fracturing) of the seal.
Further, increased pressure due to injection of CO2 may cause hydraulic fracturing of the seal, generating upward migration pathways. Increased pore pressure may in addition facilitate seismic activity with potential detrimental effects on the seal and/or on any underground and surface facilities in the area. A major problem related to seal efficacy is that it cannot be proven, and often not tested, (at least not for the whole area of interest) prior to injection of much (or all) of the CO2 to be stored. The evaluation of reservoir tightness and safety will have to rely on predictions and simulations.
Control of reservoir behaviour during and after injection may be mandatory, requiring monitoring of the underground distribution of CO2. This may enable to detect previously unidentified migration pathways and then to implement measures that counteract escape to unwanted areas. Monitoring may further be a requirement to get credit for the storage under greenhouse gas emission reduction schemes. At present, only seismic time-lapse methods have been proven to be suitable to monitor the spatial distribution of CO2 underground (Eiken et al. 2000). The ability to detect desirable small quantities of CO2 by seismic monitoring depends strongly on rock physical parameters of the reservoir and the overburden.
Effects on other activities in the area
An artificial CO2 accumulation may affect the possibilities to use the storage site area for other purposes. Migration of CO2 into reservoir zones with freshwater may cause contamination of potential drinking water. The presence of CO2 in the reservoir may imply a reduction of the ability to explore for resources (e.g. hydrocarbons) underneath, for example because the carbon dioxide may unfavourably influence the seismic properties of the rocks (e.g. cause strong energy scattering). There might be an increased risk for drilling problems when drilling through underground CO2 accumulations, especially in cases of elevated reservoir pressure. Surface subsidence due to CO2-induced reservoir compaction may preclude the storage site area from use for any surface installations.
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4. The Latrobe Group/Gippsland basin reservoir system
4.1 Geological overview
The Gippsland basin is a sedimentary basin offshore Victoria, southeast Australia (Figure 4.1). It is approximately 100 km wide in North-South and 100 to 150 km in East-West direction. The basin contains abundant hydrocarbons. Approximately 15 % of nearly 650 million scm oil reserves and more than half of approx. 270 billion scm gas reserves remained to be produced in 1998 (Bishop 2000).
(a)
(b)
Figure 4.1 (a) The Gippsland basin, anticline trends and major faults; from Abele et al. (1988). (b) Hydrocarbon fields in the Gippsland basin; from Smith (1988).
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The Gippsland basin had an essentially 2-phase, non-coaxial rifting evolution in the Cretaceous followed by a thermal sag stage in the Early Tertiary. This was overprinted by a contractional phase from the latest Eocene to Middle Miocene and some contractional reactivation in the Pleistocene to recent (Rahmanian et al. 1990; Douglas & Ferguson 1988 and Bishop 2000 provide recent summaries of published work).
Structurally, the basin consists mainly of an East-West striking ‘Central Depression’, flanked in the North and South by terraces that lead to high platforms. The transitions from the platforms to the terraces and from the terraces to the Central Depression are accommodated by major, roughly East-West striking, normal fault zones. The Central Depression contains abundant normal faults which strike predominantly Northwest to Southeast (Rahmanian et al. 1990). The basin has a general dip from west to east (Bishop 2000). In the west, landward equivalents of many of the basin sediments crop out onshore (Douglas & Ferguson 1988). In the East, processes forming the recent Bass Canyon have eroded the upper parts of the basin infill (DISR 2000).
Stratigraphy
The basin infill can be divided into three major sedimentary groups (Figure 4.2). The Lower Cretaceous Strzelecki Group consists of clastic sediments, coals, and volcanoclastics, which were interpreted to have been deposited in a fluviatile environment (Rahmanian et al. 2000) or in lakes, swamps, and floodplains (Bishop 2000). They range in thickness from a few hundreds to more than 2600 m (Bishop 2000, Smith 1988). The Strzelecki Group has not yet been proven to contain sediments with porosities suitable to constitute a reservoir (Bishop 2000).
Separated by an erosional unconformity of latest early Cretaceous and Cenomanian age, the Strzelecki Group is overlain by the Latrobe Group. Sediments of this group reach thicknesses of up to more than 4500 m in the Central Depression (Hocking 1988). Nomenclature for (the lower part of) the Latrobe Group is not uniform. Some authors separate latest Cenomanian to middle Campanian sedimentary rocks into a separate Golden Beach Group that is further divided into subgroups (Bishop 2000; who states similarly to Kanen 1993 that this is the name used since 1990). Classically, this lower interval was treated as a part of the Latrobe Group. Kanen 1993 terms it ‘Lower Latrobe’, whereas it appears in official documents DISR (2000) as a lower Emperor Subgroup and an upper Golden Beach Subgroup. We will here follow this latter, governmental nomenclature.
The Emperor Subgroup (or Kipper shale, Bishop 2000) was mainly deposited in a large, deep lake (Partridge 1996 quoted by Bishop 2000) and marginal alluvial fans and braided rivers (DISR 2000). An unconformity separates it from coastal plain and marine deposits of the Golden Beach Subgroup, which in turn is overlain unconformably by Campanian volcanics.
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G r o STRATIGRAPHY Discovery AGE Ma u p Levels s ONSHORE OFFSHORE Pleistocene 1.3 Pliocene T 5.3 S e Gippsland a Limestone E Miocene s Mid Miocene p Channels r R Lakes Entrance 23.8 a Formation y T Oligocene 33.7
I Barracouta Latr Gurnard Fm. Eocene obe Snapper A Tuna Tuna/Flounder Marlin Coar Channel Marlin se Silicic Channel Bream 54.8 Kingfish R L lastics Latrobe Coarse Fortescue a Siliciclastics Paleocene t Flounder Y r Latrobe 65 Siliciclastics o Turrum Maastrichtian b e C 73 West Tuna Campanian R West Tuna E 83 Golden Beach Kipper Santonian 87 Subgroup Archer T Coniacian 89 Anemone Turonian A 91 Cenomanian Emperor Subgroup C 97.5 S E t Albian r
O z .) U 108 e Aptian l S e (undiff 115 c Barremian k i Figure 4.2 Stratigraphy of the Gippsland basin (after DISR 2000).
The middle and upper parts of the Latrobe Group have been divided (DISR 2000) into the ‘Latrobe siliciclastics’, the ‘Latrobe coarse siliciclastics’ and the ‘Gurnard Formation’ (Figure 4.2). The Latrobe siliciclastics represent alluvial plain to marginal marine deposits in several transgressive-regressive cycles. Rahmanian et al. (1990) mention also lower shoreface to deep marine facies. This sequence contains abundant coals and coaly shales which are the primary source rocks for hydrocarbons in the basin (Moore et al. 1992 quoted by Bishop 2000) and which are mined for in the onshore extension of the basin.
The ‘coarse siliciclastics’ are a package of stacked coastal to nearshore barriers (DISR 2000) or of fluvial and estuarine deposits (Glenton 1991). They constitute the predominant reservoir for hydrocarbon accumulations in the basin. Especially in the eastern part of the basin, submarine channels were cut into the Latrobe Group during the Eocene and filled shortly after. The Gurnard Formation in the uppermost part of the Latrobe Group consists of marine glauconitic sandstones and mudstones that represent a condensed interval (DISR 2000). Kanen (1993) states an erosion phase prior to deposition of the Gurnard Formation, which is in contrast to other authors (e.g. Rahmanian et al. 1990, Bishop 2000, DISR 2000).
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The upper parts of the Latrobe Group have been eroded in the East during an uplift stage in the late Eocene and Oligocene (Rahmanian et al. 1990). This uplift stage was associated with reverse reactivation of previous normal faults and with folding, generating anticlines with Northeast-trending fold axes that constitute the major traps.
From the Oligocene to recent times, the Seaspray Group has been deposited in facies ranging from shelf over slope to deep marine (Holdgate et al. 2000). The lithology of the Seaspray Group shows a general trend starting with marly shale deposits at the base and exhibiting an increasing carbonate content upward. The subdivision of the group (Figure 4.3) has classically been according to lithology into the lower, shaly (distal) Lakes Entrance Formation and the upper, carbonaceous (proximal) Gippsland Limestone (e.g. Rahmanian et al. 1990). Recently, Holdgate et al. (2000) and Gallagher et al. (2001) used a different, seismic-stratigraphic/biostratigraphic terminology. Their Angler Subgroup would in the central part of the basin correspond to the Lakes Entrance Formation and their Albacore and Hapuku Subgroups would there correspond to the Gippsland Limestone (Figure 4.3). Angler Subgroup deposits show onlap on the erosional top Latrobe unconformity and a predominantly parallel internal seismic pattern (Gallagher et al. 2001). The Albacore and Hapuku Subgroups contain large channel cut-and-fill structures (Holdgate et al. 2000). Note that Holdgate et al. (2000) and Gallagher et al. (2001) differ considerably in their interpretation of the depth (and two-way time) position of the Albacore/Hapuku boundary.
Proximal Distal (NW) (SE) roup Hapuku Subg Gippsland Limestone roup Time Albacore Subg
Lake Entrance Formation roup Angler Subg
Figure 4.3 Seaspray Group stratigraphy, illustrating the relationship between the traditional lithostratigraphic division (as, e.g. in Douglas & Ferguson 1998) and the biostratigraphic/seismostratigraphic division of Holdgate et al. (2000) and Gallagher et al. (2001).
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Deformation
As mentioned above, the Gippsland basin underwent a polyphase deformation history, including two non-coaxial phases of extension and at least one subsequent contractional deformation stage (e.g. Douglas & Ferguson 1988). Normal faults at the basin margin strike predominantly East-West, whereas those in the basin centre have mainly a Northwest-Southeast strike (Figure 4.1a).
Active, rift-related normal faulting ended by and large in the earliest Eocene (Smith 1988). Some further activity of the normal faults during the post-rift period occurred, when the faults served to accommodate differential subsidence. Most post-early Eocene normal faults are restricted to the northern and western part of the basin.
Latest Eocene to Miocene contraction created large folds and inversely reactivated some of the pre-existing faults. Anticlinal and domal structures resulting from this contraction constitute now the main traps in the Gippsland basin.
As a consequence of the fault-age distribution, traps in rocks older than early to middle Eocene strata are broken into many, fault-separated compartments, whereas accumulations at the top of the Latrobe Formation constitute huge, rather uniform traps (Smith, 1988). This is illustrated by, e.g., the Snapper Field, where an increase of faulting intensity with depth was observed (Glenton 1991).
4.2 Geological reservoir properties of the Latrobe Group
The Latrobe Group has a complex internal architecture, due to stacking of numerous transgressive and regressive cycles. However, it contains a large fraction of porous sandstones that constitute potential reservoirs. The reservoirs are usually grouped into two categories: Top Latrobe reservoirs directly beneath the Top Latrobe unconformity or beneath the Gurnard Formation, and intra Latrobe reservoirs which are in stratigraphically deeper positions. The Top Latrobe reservoirs are in the ‘coarse siliciclastics’ litho-stratigraphical group.
Porosity in reservoirs of both categories is very good, with an average of more than 20% (Table 1). Likewise, permeability is very good with values predominantly above 1 Darcy (Table 1). Diagenesis in the Top Latrobe reservoirs is often immature (Kanen 1993), but some parts contain extensive dolomite cement which reduces permeability considerably (Bodard et al 1984 after Bishop 2000). Glenton (1991), e.g., reports much reduced productivity in dolomitised intervals. However, dissolution of dolomite cement possibly associated with hydrocarbon emplacement, generated secondary porosity (Bodard et al 1984 after Bishop 2000). As a general trend, porosity decreases with burial depth, and Bishop (2000) states that porosity is low below 4 km depth.
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Table 1 Reservoir properties for lithological and or stratigraphic units or for individual fields in the Latrobe Group.
Field/Unit Porosity Perm. Others Source Latrobe 25% (1800 m) Kanen 1993 12 % (3000m) Top Latrobe Sandstones 22-30 % Kanen 1993 Fortescue Field (fore- avg. 20% 5000 mD Rahmanian et shore & shoreface sst) al. 1990 Fortescue Field 15-25% 50 – 10000 Hendrich et mD al. 1992 East Kingfish Field 21% 5000 mD Rahmanian et (HST) al. 1990 Flounder Field (intra 20% 1200 mD Rahmanian et Latrobe, lowstand al. 1990 wedge sst) Snapper Field, Top 24% approx. Glenton 1991 Latrobe reservoir 2000 mD middle Latrobe Group 18-27% > 1000 mD Net/Gross Smith 1988 (Kingfish, Halibut, mainly Mackerel, Cobia, >85% Fortescue, Tuna, Flounder Fields) upper Latrobe Group 20-30% > 1000 mD Net/Gross Smith 1988 (Barracouta but also avg. 80% Marlin, Snapper, Tuna, Bream Fields)
The complex sedimentary architecture of the Latrobe Group implies that the reservoir sequence contains numerous finer grained intervals that act as baffles and barriers to fluid flow. Rahmanian et al. (1990) show considerable lateral and vertical lithological heterogeneity in the East Kingfish Field (their Fig. 21) but in the Fortescue, Cobia and Halibut Fields, sand layers are stacked into amalgamated sand bodies of up to more than 50 m thickness each (their Fig. 18).
The sand-dominated deposits at the top Latrobe level are in distal positions replaced by shales (e.g. in the eastern part of the Kingfish Field; Rahmanian et al. 1990). These may provide additional seal for deeper traps in the easternmost part of the basin.
Glenton (1991) interprets uniform reaction of the field to production-induced pressure reduction in the thick gas cap of the Snapper Field as indicating good connectivity in the top Latrobe reservoir. On the other hand do differing levels of the oil-water contact
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and observations during production of the only few m thick oil leg in that field show that horizontal connectivity is not always given in the field. The increasing abundance of normal faults with depth in the Latrobe Group (Smith 1988) may be the cause for some depth-dependent changes in connectivity. Possibly, connectivity is better in the shallower, less faulted intervals than in the deeper, stronger faulted, and often thinner bedded intervals.
Kanen (1993) reports that intra-Latrobe (but also in top Latrobe position) siltstones and mudstones are often very carbonaceous. Reaction with sour brines may therefore be possible.
4.3 Temperature and pressure at storage site level
Direct public domain data on present-day reservoir temperature in the Gippsland basin fields have only been found for the Snapper field (Glenton 1991). He reports a reservoir temperature of 73ºC at a depth of 1326 m, and a geothermal gradient of 55ºC/km. Since data on geothermal gradient, depth to the 100ºC isotherm, and vitrinite reflectance data for large parts of the basin were publicly accessible, reservoir temperatures have been calculated based on these data.
A published temperature gradient map (Smith 1988; Figure 4.4) shows as a general regional tendency a decrease of the geothermal gradient towards the east and towards the basin centre. Almost all major hydrocarbon fields of the Gippsland basin are in the area between 30 and 40 ºC/km geothermal gradient on this map (Table 2).
Figure 4.4 Isolines of the geothermal gradient in the Gippsland basin (Smith 1988). For location of hydrocarbon fields, refer to Figure 4.1.
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Table 2 Input data and results for calculation of reservoir temperature based on geothermal gradients in Smith (1988). In all cases, a sea floor temperature of 10ºC has been assumed. Water depth and reservoir depth according to Rahmanian et al. (1990); for Snapper according to Glenton (1991).
Field Water depth Reservoir depth T gradient Reserv. temp [m] [ m bsf] [ºC/km] [ºC] Barracouta 40 1100 32 44 Snapper 55 1300 35 54 Bream 100 1850 35 71 Kingfish 170 2250 30 72 Fortescue/Cobia/Halibut 170 2350 30 75 Flounder 190 2500 35 91
Rahmanian et al. (1990) presents a map showing depths to the 100ºC isotherm (Figure 4.5). Most Gippsland basin fields fall in the range of 1750 m to 2600 m depth to the 100ºC isotherm, which corresponds to geothermal gradients between 37 and 52 ºC/km (Table 3).
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Figure 4.5 Depth to the 100ºC isotherm in the Gippsland basin, map from Rahmanian et al. (1990). For location of hydrocarbon fields, refer to Figure 4.1
Table 3 Input data and results for calculation of reservoir temperature based on depths to 100ºC isotherm in Rahmanian et al. (1990). In all cases, a sea floor temperature of 10ºC has been assumed. Water depth and reservoir depth according to Rahmanian et al. (1990); for Snapper according to Glenton (1991).
Field Water depth Reservoir depth Depth to 100ºC Gradient Temp [m] [m bsf] [m] [ºC/km] [ºC] Barracouta 40 1100 1750 52 65 Snapper 55 1300 2100 44 65 Bream 100 1850 2250 41 82 Kingfish 170 2250 2250 43 99 Fortescue/Cobia/Halibut 170 2350 2500 38 93 Flounder 190 2500 2600 37 95
Additionally, the temperature in some of the potential storage sites can be estimated based on published vitrinite reflectance (R0) data. Rahmanian et al. (1990) show cross sections and burial diagrams containing the depth to 0.7% vitrinite reflectance. Assuming a correspondence of 0.7% R0 to a temperature of approx. 135ºC (based on modelled R0 at heating rates of 2.5ºC/Myr and slightly faster; U. Ritter, pers. comm., 2001), we calculated geothermal gradients and temperatures at top Latrobe reservoir level which are in the range of 35 to 45 ºC/km (Table 4).
Table 4 Input and results for calculation of reservoir temperatures from vitrinite reflectance data, assuming R0=0.7% to represent 135ºC, and a water temperature of 10ºC. Data from Rahmanian et al. (1990).
Field Water depth Reservoir depth Depth to Gradient Temperature
R0=0.7% [m] [m bsf] [m] [ºC/km] [ºC] Barracouta 40 1100 2800 45 58 Bream 100 1850 3000 43 85 Kingfish 170 2250 3700 35 83
The reported and calculated reservoir temperatures are summarised in Table 5. A considerable spread of values derived by the different methods is evident, with maximum differences between extreme cases for the same field in the order of 20ºC. The temperatures based on Smith (1988) are generally much lower than those calculated by the other methods. The other three methods yield much more similar results and they are preferred due to this mutual consistency. Note, however, that the
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base data for the 100ºC isotherm and for the vitrinite reflectance methods are from the same publication. The general tendency is an increase in reservoir temperature towards sites in more distal positions, in which the reservoir is at larger depth (Table 5). In contrast, the geothermal gradient decreases towards distal sites (Table 3; note that shallower reservoirs are in more proximal position).
Table 5 Temperatures at reservoir level for selected Gippsland basin hydrocarbon fields, calculated based on different data sources. See Table 2 to Table 4 for details.
Data source Smith (1988) Rahmanian Vitrinite Glenton et al. 1990 reflectance (1991) Field Reservoir Depth Temperature Temperature Temperature Temperature [m bsf] [ºC] [ºC] [ºC] [ºC] Barracouta 1100 44 65 58 Snapper 1300 54 65 73 Bream 1850 71 82 85 Kingfish 2250 72 99 83 Fortescue etc 2350 75 93 Flounder 2500 91 95
Reservoir pressure
There has not been found much data on present date pressure in the public domain. In the Snapper Field, an initial pressure of 13.87 MPa at a depth of 1326 m and a pressure gradient of 0.01048 MPa/m have been measured (Glenton 1991). This corresponds approximately to hydrostatic conditions, and no major overpressure can therefore be inferred.
4.4 Seal properties
The seal of the best reservoir rocks (‘coarse siliciclastics’) at the top of the Latrobe Group is mainly formed by fine-grained Seaspray Group sedimentary rocks (Figure 4.2). In proximal (western) areas, the condensed, often fine-grained Gurnard Formation of the uppermost Latrobe group may act as a seal to the underlying sandstones. This unit has, however, been eroded in distal areas. In the most distal (eastern) areas, sandstones of the upper Latrobe Group interfinger with, and are stratigraphically overlain by, marine mudstones that provide seals (West Kingfish Field; Rahmanian et al. 1990).
There was no public data on seal relevant properties of the Gurnard Formation and of the marine mudstones of the distal Latrobe Group available. Since most of the area covered by these potential seal formations is also covered by the major regional seal, the Seaspray Group, the study concentrated on the latter.
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Published seismic sections of the Seaspray Group show parallelism of reflectors in the lower part, i.e. the Angler Subgroup (Holdgate et al. 2000, Gallagher et al. 2001). This may indicate lateral continuity of rock properties. The Angler Subgroup comprises carbonaceous mudstones, marlstones and wackestones with typical carbonate contents below 50%, decreasing systematically downward, reaching <20% towards the contact to the Latrobe Group (Holdgate et al. 2000).
The Angler Subgroup was in the central Gippsland basin area, where most hydrocarbon fields are located, deposited in slope facies. It shows a landward change through outer shelf/upper slope facies to shelf facies (Gallagher et al. 2001) which is accompanied by an increasing carbonate content (Holdgate et al. 2000). In the East, the sediments of the Angler Subgroup have been thinned by erosion, as evident from publicly accessible seismic lines (DISR 2000). The thickness of the unit varies between approximately 400 m and more than 1500 m (estimated from seismic two-way-time and sonic velocity data in Holdgate et al. 2000). Note, however, that it contains in its thickest, landward parts carbonates and marls (Fig. 3 of Holdgate et al. 2000).
The Albacore and Hapuku Subgroups have higher carbonate contents than the Angler Subgroup (Holdgate et al. 2000). In the central Gippsland basin area, they were deposited in upper slope to shelf facies (Gallagher et al. 2001). Their combined thickness varies from approximately 300 m at the coast to more than 3000 m at the shelf break (based on two-way travel times and velocity-depth trends in Holdgate et al. 2000). In the central Gippsland basin areas, their thickness ranges mainly from 1000 m to 2000 m. They have been strongly thinned and partly totally eroded in the East (according to seismic data in DISR 2000).
Thin section analyses of Holdgate et al. (2000) show a reduction of intraparticle porosity from 20 to 50 % at sea bed to zero below approximately 800 m depth, indicating strong diagenesis of Albacore and Hapuku Subgroup sediments during initial burial. Neither rock porosity nor permeability data for the Seaspray Group have been found. However, the lithologies of all parts of the Seaspray Group are typical for seals: carbonaceous mudstones of the Angler Subgroup and marlstones and limestones of the Albacore and Hapuku Subgroup. Reported strong diagenesis of these carbonaceous lithologies is expected to have reduced rock porosity strongly, and rock (matrix) permeability can be expected to be very low.
Deformation during deposition of the Angler Group (until Middle Miocene) has been reported by, e.g., Rahmanian et al. (1990). Publicly available seismic data (Holdgate et al. 2000, DISR 2000) show the presence of normal faults within the Angler Subgroup, some of which extend downward into the Latrobe Group. None of these faults reaches into the Albacore Group. The upward limitation of the faults indicates that their activity ended in Middle Miocene times. Subsequent intensive diagenesis of the carbonate- containing host rocks during burial can be expected to have provided much dissolved carbonate into the faults, causing their healing.
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Late Eocene to Miocene faulting has probably affected the Gurnard Formation and the distal, shaly upper parts of the Latrobe Group. Their lithology may not be favourable for fast healing of faults, and their seal efficacy may accordingly be reduced.
Rahmanian et al. (1990) report some compressional deformation from Pleistocene to recent. Such deformation could potentially have caused fracturing of the well-cemented seal rocks of the Seaspray Group and reduced their seal efficacy.
The abundance of trapped hydrocarbons at the top of the Latrobe Group in the central parts of the Gippsland basin suggests that the Seaspray Group has very good seal properties. Some leakage may however take place, if the accumulations are dynamic systems in which the quantity of hydrocarbons entering the trap per time interval is at least as large as the quantity leaving it within the same interval, e.g. through the seal. Rahmanian et al. (1990) show that source rocks of the Latrobe Formation almost everywhere in the basin are at present in the oil window. Bishop (2000) states that oil and gas generation from the lower (Golden Beach) and middle parts of the Latrobe Group in the central eastern portion of the basin took already place prior to Late Eocene to Miocene trap formation. However, she accounts accumulation of hydrocarbons in existing fields to younger oil generation from younger Latrobe source rocks. A dynamic fill-and-leak situation can therefore not be excluded.
Possible leakage from the Kingfish field into the overburden has been interpreted by Cowley & O’Brien (2000). They present seismic data that illustrate a vertical chimney structure and an amplitude anomaly above the Kingfish field. The postulated gas chimney can only be traced downward to approx. 1200 ms two-way travel time, i.e. not until the reservoir top, and its origin due to generation of biogenic gas cannot be excluded. Cowley & O’Brien (2000) argue, however, that this chimney should be related to thermogenic gas migration. They point to the reported abundance of thermogenic gas seeps detected in the basin (quoting Heggie et al. 1991, reference see in Cowley & O’Brien 2000) and the lack of biogenic seeps. Further, they interpret the lack of a gas cap and gas-undersaturated oil in the Kingfish field as additional evidence for leakage.
Seismic sections (DISR 2000) show that the present basin topography mimics in some areas the rift basin, i.e. former heights are below present heights and former depressions are at positions of present depressions. This may indicate effects of differential subsidence, e.g. due to stronger compaction of thicker sediment packages in the basin than on the shoulders. These lateral variations in subsidence may cause deformation in post-rift sediments, with an expected concentration of potential normal faults roughly above the former basin margin faults. Further, the basin margins may have acted as weakness zones during reported young contractional deformation, causing concentration of faulting and fracturing at those locations. Seal efficacy at the basin margins may therefore be strongly reduced.
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4.5 Traps
Most, and the largest, hydrocarbon accumulations in the Gippsland basin are at the top of the Latrobe Group (Table 6); some smaller accumulations are deeper in the Latrobe Group (‘intra Latrobe’), and only a few have been identified so far in units below the Latrobe Group (Bishop 2000).
Most identified traps in the Gippsland basin are structural traps (e.g. Rahmanian et al. 1990). The larger accumulations are predominantly in large domal or anticlinal structures, some minor accumulations are fault-bounded. Stratigraphic trapping is a component for some of the smaller traps (see, e.g., Glenton 1991), and Rahmanian et al. (1990) report facies changes as an important mechanism for the West Kingfish field. Erosion into the upper, often coarse grained parts of the Latrobe Group and subsequent filling of the channel structures with finer grained material is another stratigraphical contribution to the trapping mechanisms of some of the traps.
The large traps at the top of the Latrobe Group are often relatively simply structured, mainly because they are in rocks which were deposited after the main normal-faulting events (Smith 1988). The intra Latrobe traps, however, show considerable compartmentalisation due to the presence of post-depositional normal faulting. Erosion into the upper, often coarse-grained parts of the Latrobe Group and subsequent filling of the channel structures with finer grained material contributed to
Smith (1988) states that intra-reservoir faults do probably not constitute good seals over long time because there exist large high API gravity accumulations at the top of the reservoir sequence.
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Table 6 Stratigraphic position and content of major hydrocarbon accumulations in the Gippsland basin. Major sources: Rahmanian et al. (1990), Glenton (1991), Hendrichs et al. (1992).
Field Reservoir level Oil or gas in main reservoir Barracouta Top Latrobe gas (oil in intra-Latrobe) (& intra Latrobe) Bream Top Latrobe gas & oil Cobia Top Latrobe mainly oil Dolphin Top Latrobe mainly oil Flounder intra Latrobe oil & gas Fortescue Top Latrobe mainly oil Halibut Top Latrobe mainly oil Kingfish Top Latrobe mainly oil Kipper intra Latrobe gas (&oil) Mackerel Top Latrobe mainly oil Marlin Top Latrobe mainly gas Perch Top Latrobe mainly oil Seahorse intra Latrobe (& top oil & gas Latrobe ???) Snapper Top Latrobe gas & some oil (mainly oil in (& intra Latrobe) intra Latrobe) Sunfish ?? mainly oil Tarwhine Top Latrobe oil & gas Tuna Top Latrobe oil & some gas in intra & intra Latrobe Latrobe
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Trap volumes
No direct data about trap volumes were accessible. Scarce data about reserve quantities (e.g. for the Snapper Field in Glenton 1991) are not easily transferable into trap volumes due to the different pressure and temperature conditions at standard conditions and in the reservoir, respectively.
Maps of reservoir top with the oil-water contact indicated were available for the Snapper Field (Glenton 1991) and for the Kingfish Field (Rahmanian et al. 1990). Based on these, the gross trap volume for these two fields was estimated (Table 7).
Table 7 Calculation of gross trap volumes for the Snapper and Kingfish fields based on published reservoir top maps. The volume of depth slices was estimated assuming an elliptical conical slice geometry.
Snapper Kingfish Depth slice Volume Depth slice Volume base top (gross) base top (gross) [m bsl] [m bsl] [109 m3] [m bsl] [m bsl] [109 m3] 1390 1340 2.43 2300 2280 1.05 1340 1300 1.26 2280 2260 0.61 1300 1260 0.78 2260 2240 0.25 1260 1220 0.35 2240 2230 0.02 1220 1200 0.03 Sum 1.93 Sum 4.85
4.6 CO2 properties at reservoir conditions
Density
The density of CO2 in potential traps will mainly depend on the temperature and the pressure prevailing in these traps. Temperatures for selected potential storage sites (hydrocarbon fields) which cover the range of conditions for the top Latrobe ‘storage play’ have been calculated based on several methods (Table 5). Reservoir pressures are assumed to be hydrostatic, because no other indications have been found in the literature. Consequently, reservoir pressures in our calculations depend only on water depth and on the depth of the reservoir below sea floor (input data are given in Table 2).
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The density of CO2 for six selected sites has been calculated according to the procedure outlined in Appendix A. The results show a wide spectrum of calculated densities for individual sites (Figure 4.6), reflecting the temperature uncertainty for each of the sites. However, as discussed in Chapter 4.3, the temperatures based on the geothermal gradient data of Smith (1988) are rated here as less convincing.
The general tendency is thus that at top Latrobe sites (Barracouta to Fortescue-Coiba- Halibut in Figure 4.6) CO2 would have an increasing density with increasing distance of the site from land, and correspondingly with increasing depth of the site. Sites close to the coast would consequently have lower storage efficiency per reservoir volume unit than sites further offshore. At the Flounder field, as an example for an intra-Latrobe site, CO2 would have a high density. This is due to the distal position of this site. At distal sites, CO2 would have a density comparable to that in the Sleipner case (approx. 700 kg/m3).
At low geothermal gradients (below approx. 33ºC/km), the pressure-temperature path from the reservoir to the surface will intersect the gas-liquid phase boundary of CO2 (see Figure 4.7a for the case of a 30ºC/km gradient). This implies that any CO2 which would cross this boundary, would undergo a sudden density change. At higher geothermal gradients, the transition between high and low density phases is more gradual (Figure 4.7b).
800 CO2 density at reservoir depth ]
3 700 m g/ k
[ 600 y t i
ns 500 Gradients - Smith 1988
de Rahmanian et al. 1990 2
O From depth to R0 = 0.7
C 400 Glenton 1991
300 Barracouta Snapper Bream Kingfish Fortescue Flounder etc
Figure 4.6 CO2 density at reservoir conditions for six selected hydrocarbon fields in the Gippsland basin, calculated by a range of different methods (see text and tables in Chapter 4.3). The fields are grouped according to reservoir depth (left: shallow, right: deep). Hydrostatic conditions are assumed. Overpressure would cause higher densities. The values based on Smith (1988) are regarded as less trustworthy since they do not conform to the values derived by the other three methods.
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(a) 800 400
700 350 C ° e,
600 300 r u t
Density of pure CO2 a r e 3 500 CO2 with 2.5% CH4 250 p m / g
Pre ssure tem k d ,
y 400 200 an it
Temperature s r n a e b D 300 150 , e r
200 100 essu r P 100 50
0 0 0 500 1000 1500 2000 2500 3000
Depth below sea level, meter (b) 800 Density of pure CO2 400 CO2 with 2.5% CH4 700 350 Pre ssure C ° e, 600 Temperature 300 r atu er 3 500 250 p /m g tem
k , 400 200 d y n it a s r n a
e 300 150 b D , e r 200 100 essu r 100 50 P
0 0 0 500 1000 1500 2000 2500 3000
Depth below sea level, meter
Figure 4.7 Density versus depth for geothermal gradients of (a) 30ºC/km and (b) 40ºC/km. In case (a), the gas-liquid phase boundary of CO2 becomes intersected, corresponding to a sudden density change. In contrast, in case (b) the transition from a low density to a high density state is gradual.
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Bulk modulus
Presence of CO2 in the pores of the reservoir rock will change the seismic behaviour of the rock as compared to the situation where pores are filled with formation water or hydrocarbons. The two pressure and temperature dependent parameters of CO2 that influence acoustic velocity, are density (see above) and bulk modulus. We calculated the bulk modulus at reservoir conditions (see Appendix A for calculation principles) for three cases, one for the Sleipner case conditions, and two with alternative pressure- temperature setups for the Kingfish field, one of them where the geothermal gradient intersects the liquid-gas phase boundary, and one where it does not (Figure 4.8). Figure 4.8 shows that the bulk modulus of CO2 at Kingfish field reservoir conditions is probably between 0.064 GPa (at a reservoir temperature of 99º C) and 0.089 GPa (at a reservoir temperature of 83º C), which differs strongly from the bulk modulus of water (approx. 2.42), that is the other main pore fluid (in the oil depleted case). In the Sleipner case, the calculated bulk modulus of CO2 is 0.075 GPa at reservoir conditions, that is within the range of the values calculated for the Kingfish case.
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(a) 800 0.16 700 0.14 600 0.12 ] 3 s m lu / 500 0.10 u g d k o [
y 400 0.08 t m i s lk n
300 0.06 u B De 200 Density of CO2 0.04 100 Bulk modulus 0.02 0 0.00 0 1000 2000 3000 Depth (m)
(b) 800 0.16 700 Reservoir depth 0.14 600 0.12 ] 3 s u m 500 0.10 l u g/ d k o [
y 400 0.08 t m i lk ns
300 0.06 u e B D 200 Density of CO2 0.04 100 Bulk modulus 0.02 0 0.00 0 1000 2000 3000 Depth (m)
(c) 800 0.16 700 0.14
] 600 0.12 3 s u m l
500 0.10 u g/ d k o [
y 400 0.08 t m i lk
ns 300 0.06 u e B D 200 Reservoir depth 0.04 Density of CO2 100 0.02 Bulk modulus 0 0.00 0 1000 2000 3000 Depth (m)
3 Figure 4.8 Calculated CO2 density (kg/m ) and CO2 bulk modulus (GPa) for pressure and temperature conditions as estimated for (a) the Sleipner case (reservoir at approx. 800 to 1000 m bsf), (b) the Kingfish field with a reservoir temperature of 99º C, and (c) the Kingfish field with a reservoir temperature of 83º C. Calculations are based on thermo- dynamic data and the equation of state as outlined in Appendix A.
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5. Discussion
5.1 Reservoir formation suitability
The main characteristics for a reservoir formation to make it suitable for underground CO2 storage, are high porosity and high permeability. Large parts of the Latrobe Group, and especially its uppermost parts (the ‘coarse siliciclastics’) fulfil these conditions. Porosity there is around 20 % (Rahmanian et al. 1990), which is less than in the Sleipner case (Zweigel et al. 2000) but still high. Permeability is in the order of 103 mD, reaching values up to 5000 mD in several fields (Rahmanian et al. 1990). It is thus similar to permeability determined for the Utsira Sand in the Sleipner case (Zweigel et al. 2001) which proved to be very good for injection at a rate of approximately 3000 metric tons per day.
Dolomite cementation in Latrobe Group sediments (Bodard et al. 1984, quoted by Bishop 2000) causes reduced porosity and permeability, as shown, e.g. by severely reduced productivity of wells perforated in dolomitised zones (Glenton 1991). CO2 injection well paths and perforation intervals should be chosen such that injection rates are not much negatively affected by the presence of dolomitised zones.
On the other hand, dolomite, other carbonate cement and carbonate rock constituents may become dissolved by acid CO2-brine. This could increase porosity and permeability, but may also reduce reservoir stability, as could the dissolution of feldspars and clays. The effect of CO2-brine on reservoir rocks should therefore be studied in geochemical experiments prior to injection.
5.2 Seal efficacy
The most favourable parts of the potential CO2-reservoir, the coarse siliciclastics of the uppermost Latrobe Group, have evidently an effective seal as being proven by the existence of numerous hydrocarbon accumulations. Published data on facies, lithology and rock properties of the overlying Seaspray Group are in accordance with the inferred favourable seal qualities for this unit. The unit has a large thickness (more than thousand meters in the central parts of the Gippsland basin) and good sealing properties exist probably throughout most of the vertical succession. In the central areas of the Gippsland basin, the seal is therefore expected to be of good quality.
Potentially active dynamic fill-and-leak processes involved in generation and maintenance of existing hydrocarbon accumulations may suggest better seal properties than they in effect are. The presence of seeps of thermogenic gas in the basin (Heggie et al. 1991 quoted by Cowley & O’Brien 2000) indicates the possibility for migration through the seal sequence. Potential leakage-related structures above the Kingfish field may further imply that hydrocarbon fields are not tight on a geological time scale. For underground CO2-storage, the required residence time may be much shorter than necessary for generation of a hydrocarbon accumulation. Typical desired residence times may be a few 1000 years, and it is well possible that leakage rates are so small that the seal can be considered effectively tight over such an interval.
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An assessment of the effect of slow leakage on CO2 storage suitability requires an evaluation of present hydrocarbon leakage rates (especially of the low-density, gaseous components) through the seal. Quantitative analysis of hydrocarbon indicators in the overburden (e.g. from seismic and/or well data), at the sea floor (e.g. seeps and pock marks) and at the water surface would be part of such an evaluation. Further, modelling of previous and present hydrocarbon generation and migration, and comparison of model results with observed hydrocarbon accumulations may indicate ongoing leakage (when predicted generation is considerably larger than accumulations) and help to constrain leakage rates.
In areas above or close to major underlying faults, differential subsidence and/or reactivation of the faults may have created fractures and faults that may be open at the present day and that can provide migration pathways to the sea floor. Facies changes towards the basin margin (Gallagher et al. 2001) may imply reduced seal quality there. The effect of this reduction may be enhanced by the lower thickness of the Seaspray Group towards the land.
CO2 will become progressively dissolved in the formation water, which will probably increase pH. Acid formation water may cause reaction with, and dissolution of, carbonate minerals in the seal formation, which may reduce seal quality. An assessment of this risk based on experiments with seal formation samples should be carried out prior to injection start.
Especially in near-shore traps in the Gippsland basin, CO2 will have a relatively low density (Figure 4.6) causing a large density contrast to water. Large CO2 columns may therefore induce considerable overpressure which may constitute a risk for hydraulic fracturing. This must be evaluated for each potential storage site individually.
If CO2 should leak from sites with a low geothermal gradient into regions much shallower than 1 km bsl, it will cross the liquid-gas phase boundary during its rise. The strong density decrease – and consequently volume increase – when crossing the phase boundary may cause formation damage and may facilitate further upward rise. This risk has to be addressed prior to injection start.
5.3 Storage capacity
The total storage volume of the Gippsland basin is difficult to estimate, based on the scarce data that are publicly available.
One approach to estimate the storage capacity, is to take the volume of produced hydrocarbons as an approximation. For simplicity we will restrict us to the produced oil volumes because it is difficult to estimate gas volumes at reservoir conditions from given gas volumes at standard conditions when reservoir temperature, pressure, and gas composition are not given. Bishop (2000) reports that approx. 550 Mill scm oil have been produced (apparently until 1998) from the basin. This may be taken to almost directly reflect the available pore space in partly depleted traps. Production of he remaining oil reserves in the near future will increase this volume by approx. 15 %.
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Until now, production concentrated on oil-dominated reservoirs. Production of the gas reserves will create additional available pore space in the future. Enhanced oil recovery may increase the amount of oil to be produced and may therefore further add available pore space. Enhanced oil recovery may be achieved using CO2, combining storage and oil production with positive effects on storage costs (see Chapter 5.6).
The pore space available for CO2 storage in traps is defined by four main parameters: gross trap volume, porosity, net/gross ratio, and storage efficiency.
Gross trap volumes for two selected fields have been calculated here (Table 7).
Data on (average) porosity are listed in Table 1 as are scarce available data on the net/gross ratio.
Storage efficiency is a factor that expresses how much of the available pore space in the (net) reservoir rock in the trap will become filled with CO2 as a separate phase. Several processes may cause considerable deviation from the ideal case of full saturation: (a) residual saturation of pore space by other fluids (oil, water); (b) separation of reservoir zones due to the presence of low permeability barriers; (c) focussing of CO2 flow in high permeability zones leaving zones of lower permeability unsaturated. CO2 may however not only fill the formation as a separate phase, but can also dissolve in oil or water phase. This process is partly controlled by molecular diffusion and partly on induced convectional mixing in the liquid phases.
Storage efficiency cannot necessarily simply be estimated from depletion efficiency. This is because the filling process is not a direct inversion of depletion. The traps will still contain remnants of gas and oil, which will partly be displaced, but parts of them will permanently occupy some fraction of the pore space. CO2 constitutes an additional phase in the system, and e.g. capillary properties may strongly deviate from that of methane. Injected CO2 will preferably migrate along the reservoir top (as known for injected gas from gas storage sites) and it will therefore spill before the trap is full.
In our calculations, we used an estimate of the storage efficiency factor of 0.5.
Using available data for the Snapper and Kingfish fields (Glenton 1991 and Rahmanian et al. 1990), the available storage volume for these sites can be estimated. Given the density estimates for these sites (Figure 4.6), also the storage capacity in metric tons of CO2 can be estimated (Table 8).
The calculations show that these two sites have estimated storage capacities that could hold approximately twice (Kingfish) or four times (Snapper) the annual CO2 emissions from use of coal for electricity and heat production in Victoria (see Chapter 2), and could therefore contribute to a significant reduction of CO2 emissions.
The already emptied space in oil fields in the Gippsland basin would – assuming an 3 average CO2 density of 0.5 tons /m - provide space for approximately 250 Mtons CO2.
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Table 8 Input parameters and calculated storage volume and storage capacity (in metric tons) for the Snapper and Kingfish fields. For input data, see Table 1, Table 7, and Figure 4.6.
Field Trap volume Porosity Net/gross Storage Storage Density Capacity ratio efficiency volume [109 m3] [109 m3] [ton/m3] [106 ton]
Snapper 4.85 0.24 0.8 0.5 0.466 0.4 186.4
Kingfish 1.93 0.2 0.8 0.5 0.154 0.6 92.4
Trap structures that did not contain hydrocarbons, may constitute additional potential CO2 storage sites if leakage can be excluded as the reason for the non-presence of hydrocarbons. This may be validated by, e.g., hydrocarbon generation and migration simulations.
Intra-Latrobe traps may be more difficult for use as CO2 storage sites than top Latrobe traps. This is because the latter are seismically not well resolved due to much seismic energy becoming absorbed by coals in the upper part of the Latrobe Group. Poorer seismic resolution implies less detail in reservoir characterisation prior to injection and less accuracy during seismic monitoring.
5.4 Monitoring
Monitoring of the underground distribution of injected CO2 by time-lapse seismics has been successfully achieved in the Sleipner injection case (Eiken et al. 2000). There, reservoir conditions and petrophysical parameters (Zweigel et al. 2000) were favourable for monitoring, e.g. reservoir depth is low (approx. 800 – 900 m), porosity is high (>30%), rock strength is low (as indicated by low Vp of approx. 2150 m/s prior to injection). The effect of pore water being replaced by CO2 on acoustic properties was therefore expected to be clearly detectable by seismic monitoring (Lindeberg et al. 1999).
A quantitative evaluation of the expected effect of injected CO2 on acoustic properties in the Gippsland basin case was not possible now because most relevant parameters were not publicly accessible. Qualitatively, conditions in this case are expected to be less favourable than in the Sleipner case.
Porosity in the best-suited reservoir rocks (Latrobe ‘coarse siliciclastics’) is less than in the Sleipner case (around 20%; Rahmanian et al. 1990). Burial is deeper in the Gippsland basin (approx. 1000 m in the western part and more than 2000 m in the eastern part of the central basin; Rahmanian et al. 1990) and accordingly, stronger compaction and increased rock strength are expected. The presence of carbonate material in the Latrobe Group sediments (Kanen 1993) may have improved cementation during diagenesis. However, Kanen (1993) reports immature diagenesis of the upper
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parts of the Latrobe Group and describes the rocks as friable. Rock strength may therefore be lower than usual for rocks at this depth.
Very important for quantitative monitoring is the ability to map precisely the upper and lower margins of the underground CO2-accumulations. The upper margin is likely to be located at the formation top and to be sharp, i.e. with a high saturation gradient from water to CO2. The nature of the lower margin depends – in cases of depleted oil fields – on the relative permeability in the system oil-water-CO2. If the oil in the reservoir remains largely stationary during CO2 injection, i.e. if no oil layer develops below the accumulating CO2, we expect a high saturation gradient from nearly pure CO2 downwards into pure water due to the presence of residual oil which causes at least partly oil-wet conditions. In that case, the saturation gradient would be higher than in the Sleipner case. The presence of a single interface with a strong contrast in acoustic properties would be favourable for good imaging of the base of the CO2 accumulation.
In the case of good oil mobility (i.e. when CO2 will contribute to enhanced oil recovery – see Chapter 5.6), we expect generation of an oil accumulation between the CO2 and the underlying water. In that case, saturation gradients will be smaller and two interfaces in close neighbourhood (a few m in distance) will be generated. The seismic responses to these interfaces are expected to be weaker than in the previous case and to interfere with each other. Imaging of the lower margin of the CO2 accumulation may thus be hampered.
For a sharp contrast between a water filled reservoir rock on the top and a partly CO2- filled rock beneath, reflection coefficients have been calculated (Figure 5.2; for calculation procedure, see Appendix B), employing density, bulk modulus, and calculated velocity data corresponding to the Kingfish field reservoir conditions (see Chapter 4.6; Figure 5.1). The calculations show that a relatively strong reflection can be expected if the p-wave velocity in the fully water filled rock is approximately 3000 m/s. In the case of 4000 m/s of the fully water filled rock, the reflection will be much weaker and may be difficult to detect. However, we expect p-wave velocity to be rather closer to 3000 m/s than to 4000 m/s, which would imply good chances for monitoring of subsurface CO2.
A major additional objective of monitoring is the detection of CO2 migrating into the cap rock. Expected very low porosity and reported high acoustic velocities (Holdgate et al. 2000) of the intensively carbonate cemented seal rocks in the Gippsland basin case may hamper monitoring of leakage.
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(a) 2350 3200
2325 Density 3000 ] 3 Vp]
m 2300 2800 / ] g /s k m [ 2275 2600 [ y p t i V s
n 2250 2400 De 2225 2200
2200 2000 0 0.2 0.4 0.6 0.8 1 Water saturation
(b) 2350 4500
2325 4000 ] 3
m 2300
Density ]
g/ 3500 /s k m [ 2275 [ y
Vp] p t i
3000 V 2250 ns e D 2225 2500
2200 2000 0 0.2 0.4 0.6 0.8 1 Water saturation
Figure 5.1 Density and acoustic p-wave velocity as a function of water saturation, where CO2 replaces water as the pore fluid. (a) for a p-wave velocity of 3000 m/s and (b) of 4000 m/s of the water-saturated rock. Note that Vp does not change much in case (b). Parameters for the calculations correspond to the Kingfish field (99º C case; 83º C case is not much different) and are given in Table 9.
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0.4
Calculated reflection coefficient 0.3 Refl. coeff. for comparison
0.2
0.1 Reflection coefficient 0 2000 3000 4000 5000
Vp [m/s]
Figure 5.2 Reflection coefficient for the Kingfish case (reservoir temperature 99º C) for a boundary between a water-filled rock with p-wave velocity Vp and density 2300 kg/m3, and an identical rock with 80% of water replaced by CO2. The higher the pre-injection acoustic velocity is, the weaker will the reflection at the top of a CO2 accumulation be. The stippled line indicates the reflection coefficient for a simultaneous 90 % reduction of Vp and density across a rock interface.
Table 9 Input for calculations of parameters shown in Figure 5.1.
Density of rock (incl. pore filling) at water saturation = 1 2300 kg/m3 Vp, P-wave velocity at water saturation = 1 3000 m/s & 4000 m/s Vs, S-wave velocity 0.6 * Vp Porosity 0.2 Bulk modulus of grains (quartz) 36.9 GPa
Bulk modulus of CO2 at reservoir condition 0.064 GPa
Bulk modulus of H2O at reservoir condition 2.416 GPa 3 Density of CO2 at reservoir condition 544 kg/m 3 Density of H2O at reservoir condition 990 kg/m
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5.5 Additional precautions
Underground storage of CO2 in the Gippsland basin should be designed such that it affects future hydrocarbon exploration and production as little as possible. There exist a number of plays beneath the uppermost Latrobe Group, e.g. internal in the Latrobe siliciclastics, in the Golden Beach Subgroup and in the Strzelecki Group (Bishop 2000). Investigations of potential CO2-storage sites should therefore include an evaluation of the prospectivity of the underlying strata.
Freshwater reservoirs in landward offshore parts of the basin (Bishop 2000) should not become contaminated by CO2-brine.
5.6 Use of CO2 for enhanced oil recovery (EOR)
CO2 has for a long time been injected into oil reservoirs, and through a large number of projects CO2-injection has proven its effectiveness as an injection fluid for enhanced oil recovery. In a review of the performance of 25 CO2 injection projects, pilots and field scale, the average incremental oil recovery obtained was 13% of original oil in place (Holt et al. 1995). Brock and Bryan (1989) briefly describe most of these projects as well as others. Of 60 miscible CO2 projects in North America all were evaluated by the operators as successful, promising or “too early to tell” (Moritis 1992).
The displacement of oil with gas can follow one of two major displacing mechanisms: either multicontact miscible or immiscible displacement. In multicontact miscible displacement a continuous changing transition zone between oil and injectant will develop after injection. This makes the interfacial tension between gas and oil to vanish and thus reducing the residual oil saturation to almost zero in the swept zones. During immiscible displacement interfacial tension between the phases will remain and this will determine the residual oil saturation that can be significant depending on the recovery mechanisms and rock and wetting properties. Whether miscibility will develop or not will depend on the type of injection gas, pressure, temperature, and oil composition. The lack of relevant data, especially on oil composition and pressure, in the public domain precludes any predictions for the Gippsland Basin.
Prediction of field scale gas injection recovery processes are often complicated due to the nature of the fluid systems often exhibiting extensive mass transfer between oil and gas, the unfavourable mobility ratio between the oil and injected gas and the tendency of the phases to segregate. Reservoir heterogeneities on different scales complicate the picture further. In some situations gas will be injected together with water (either alternating, WAG, or simultaneously, SAG) with the purpose to control the flow of gas and to reduce the amount of injection gas. WAG or SAG injection will introduce additional challenges in the reservoir simulations.
Today practically all geo-stored CO2 is injected into oil reservoirs for EOR. The value of CO2 as injection gas will increase with the oil price. For the US the following equation has been proposed (Taber 1994):
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V =+97..039P (1) CO2 oil where VCO2 is the value of CO2 in USD/ton and Poil is the oil price in USD/bbl.
From Figure 5.3 it is seen that the value of CO2 covers significant parts of the deposi- tion costs. For oil prices in the range 20-25 USD/bbl, the value of CO2 amounts to approximately half the cost of CO2 separation, transport and deposition if an average cost estimate is used. The first CO2 deposition projects should therefore concentrate on the use of CO2 in connection with oil production, and the most promising reservoirs should be flooded first.
50
45
] 40 2 O
C 35
n o t
/ 30 D S
U 25 [ e u l 20 a v r 15 o EOR Value st
o 10 Lower cost estimate C 5 Upper cost estimate
0 10 15 20 25 30 35 Oil price [USD/bbl]
Figure 5.3 Value of CO2 for improved oil recovery vs. oil price according to Equation (1) from Taber (1994) compared to cost estimate of CO2 capture from Audus (2000)
As mentioned above, the CO2 value indicated in Figure 5.3 is based on experience from oil regions in the mid-west US. For any given oil province the value of CO2 will depend on the type of oil reservoirs in the area, and on the actual benefit of CO2 injection. In a planning phase the CO2 value for a given reservoir has to be assessed through reservoir simulation studies where the behaviour of CO2 in the oil/reservoir rock system in question is described as precise as possible. Accurate production estimates will be of utmost importance in the planning phase of any potential CO2 injection projects in Gippsland Basin reservoirs due to the size of the projects and the large investments thus involved.
CO2 injection into gas reservoirs will have only marginal or no effect on the economy of the exploitation project. Since the gas reservoirs have proven their ability for long term gas storage, the use of gas reservoirs should be considered especially in cases where infrastructure from the gas production still can be used.
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6. Conclusions and recommendations
The literature-based evaluation of the Latrobe Group in the Gippsland basin (offshore Victoria, Australia) shows that it is most likely suitable for long-term (> 5000 years) underground CO2 storage with the purpose to reduce CO2- emissions from fossil fuel combustion.
The potential deposition sites are in approximately 90 to 150 km distance to coal-fired and other fossil-fuel based power plants (approximately 60 km onshore and 30 to 90 km offshore). CO2 in the flue gas of some of these existing and/or planned point sources may become captured and transported through pipelines to the offshore deposition site. Assuming a daily quantity of approximately 30 000 tons CO2 (equivalent to almost a fourth of Victoria’s emissions from coal fired electricity and heat production in 1995) 6 and an injection period of 20 years, approximately 200·10 tons CO2 would have to be stored.
The reservoir properties of large parts of the Cretaceous to Eocene Latrobe Group are likely to be suitable for CO2-injection. This is especially the case for the uppermost part of the Group, i.e. the so-called ‘coarse siliciclastics’. Reported high porosity and permeability will probably allow injection at high rates per well, thus keeping the needed number of wells small.
The relevant parts of the Latrobe Group are overlain by shaly and carbonaceous sediments of the Seaspray Group. The existence of numerous hydrocarbon accumula- tions at the top of the Latrobe Group and published rock properties of the Seaspray Group indicate that it has very good seal properties, at least in the central parts of the Gippsland basin. At the margins of the basin, its seal efficacy may be reduced by the potential presence of non-healed faults, by the reduced thickness of the unit, and as a consequence of facies changes. Also in the most favourable, central parts of the basin, a quantitative assessment of potential leakage rates is recommended, based e.g. on sample studies and on comparisons of simulated hydrocarbon production and migration with actual accumulations.
The storage sites with the highest likelihood to be tight are traps that contain hydro- carbons. The basin contains several large oil fields and some of them are already strongly depleted. It is recommended here that these shall be the primary targets for underground CO2 storage. Based on experience from these traps, and using the likely public credit from successful storage in them, storage in non-hydrocarbon bearing trap structures may then be explored as an additional, future option.
Our preliminary analysis shows that monitoring of CO2 in the Latrobe Group by seismic methods is likely to be feasible. Further, quantitative studies based on available data in the local hydrocarbon industry are suggested prior to injection. This is especially important to investigate the possibility to monitor potential CO2 escape into the seal formation.
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In some cases, CO2 injection may help to improve oil recovery (enhanced oil recovery, EOR). In those cases, costs for underground storage will be reduced by the income from additional hydrocarbon production.
The volume of oil produced from the Gippsland basin is more than 550 million scm (Bishop 2000). At an estimated average CO2-density at reservoir conditions of approx. 0.5 tons/m3, the underground trap space provided by the produced oil, would 6 correspond to more than 250·10 tons CO2. Filling by CO2 will not exactly mirror the hydrocarbon depletion history and not all trap space provided by the produced hydrocarbons may thus become filled by CO2. Detailed reservoir simulations are recommended, based on 3D seismic data, wire-line log and sample data, and supplemented by a depositional model, to assess the accessible trap space. It is qualitatively estimated here that the existing traps will provide a large enough volume 6 to store at least 200·10 tons CO2. Further hydrocarbon production, not the least aided by CO2-based enhanced oil recovery, and use of empty, but tight traps may provide additional storage space.
Dissolution of CO2 in formation water will produce acid brine that is likely to react with rock constituents. The reservoir rocks, but especially the seal rocks, are reported to contain carbonate minerals, which are especially prone to reaction with acid brine. It is recommended that chemical experiments and geochemical simulations be carried out prior to injection in which brine-rock reactions become quantified. Based on this, the likelihood for dissolution-induced subsidence and of risk for and degree of potential seal deterioration should be assessed.
This study could not address the economics of CO2 storage in the Gippsland basin. Anyhow, this will depend much on national and international steering mechanisms to reduce CO2 emissions, such as emission taxes. A major obstacle for economic viability could be the distance between CO2 producers and storage sites. However, the potential economic value of CO2 to increase hydrocarbon recovery may substantially counteract this.
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7. References
Abele, C., Gloe, C.S., Hocking, J.B., Holdgate, G., Kenley, P.R., Lawrence, C.R., Ripper, D., Threlfall, W.F., & Bolger, P.F., 1988: Tertiary. In: Douglas, J.G. & Ferguson, J.A., (eds.): Geology of Victoria. Victoria Division of the Geological Society of Australia Inc. (Melbourne, AU), pp. 251-350. AGI (Australian Greenhouse Office), 1998: National Greenhouse Gas Inventory 1995, State inventory Victoria. http://www.greenhouse.gov.au/inventory/inventory/stateinv/ stateinvpdfs/vic/vic95.pdf AGI (Australian Greenhouse Office), 2001: National Greenhouse Gas Inventory 1999. Overview: http://www.greenhouse.gov.au/inventory/facts/pdfs/nggifs1s.pdf; Energy: http://www.greenhouse.gov.au/inventory/inventory/pdfs/Invenstat_txt.pdf and: http://www.greenhouse.gov.au/inventory/inventory/pdfs/Invenstat1.pdf.
Audus, H., 2000, “Leading Options for the Capture of CO2 at Power Stations”, GHGT-5 Proceedings edited by William, D, Durie, B., McMullan, P., Paulson, C., Smith, A., CSIRO Publishing: Seismic properties of pore fluids, Geophysics, 57 pp. 1396 - 1408. Batzle, M. and Wang,Z., 1992: Seismic properties of pore fluids. Geophysics, 57, pp. 1396-1408.
Baklid, A., Korbøl, R., & Owren, G., 1996: Sleipner Vest CO2 disposal, CO2 injection into a shallow underground aquifer. Paper presented on the 1996 SPE Annual technical Conference and Exhibition, Denver, Colorado, USA, SPE paper 36600, pp. 1-9. Bishop, M.G., 2000: Petroleum System of the Gippsland Basin, Australia. U.S. Geological Survey Open-File Report 99-50-Q, ftp://energy.cr.usgs.gov/pub/WEnergy/OF99-50.pdf Bodard, J.M., Wall, V.J., & Cas, R.A.F., 1984: Diagenesis and the evolution of Gippsland basin reservoirs. The APEA Journal, 24 (1), pp. 314-335. Brock, W.R. and Bryan, L.A., 1989: Summary results of CO2 EOR field tests. SPE paper 18977 presented at the Joint Rocky Mountain regional/low permeability reservoir Symp. and Exhib., Denver, Co., March 6-8. Cowley, R. & O’Brien, G.W., 2000: Identification and interpretation of leaking hydrocarbons using seismic data: a comparative montage of examples from the major fields in Australia’s North west Shelf and Gippsland basin. APPEA Journal, 40, pp. 121-150. Available online at: http://www.explorationist.com/APPEA_Abstract.htm DISR (Department of Industry, Science and Resources), 2000: Release of offshore petroleum exploration areas 2000. Geology and data availability. http://www.isr.gov.au/resources/petr_exploration/releases-2000/reports/gda.pdf Chapters on Gippsland Basin are separately available at http://www.isr.gov.au/resources/petr_exploration/releases-2000/reports/v3-5.pdf DISR (Department of Industry, Science and Resources), 2001: Release of offshore petroleum exploration areas Australia 2001. Geology and data availability. V01-4 – Gippsland Basin 8VIC). http://www.isr.gov.au/resources/petr_exploration/2001/Gold_Book/Gippsland.pdf Douglas, J.G. & Ferguson, J.A., (eds.) 1988: Geology of Victoria. Victoria Division of the Geological Society of Australia Inc. (Melbourne, AU), 665 pp. Eiken, O., Brevik, I., Arts. R., Lindeberg, E., & Fagervik, K., 2000: Seismic monitoring of CO2 injected into a marine aquifer. SEG Calgary 2000 International conference and 70th Annual meeting, Calgary. http://www.iku.sintef.no/projects/IK23430000/Publications/Eiken_et_al_2000_GHG T5.pdf
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Gallagher, S.J., Smith, A.J., Jonasson, K., Wallace, M.W., Holdgate, G.R., Daniels, J., & Taylor, D., 2001: The Miocene palaeoenvironmental and palaeoceanographic evolution of the Gippsland Basin, Southeast Australia: a record of Southern Ocean change. Palaeogeography, Palaeoclimatology, Palaeoecology, 172, pp. 53-80. Glenton, P.N., 1991: Snapper Field – Australia. In: Foster, N.H. & Beaumont, E.A. (eds.): Structural Traps V, pp. 227-250. American Association of Petroleum Geologists, Tulsa, Oklahoma. Hendrich, J.H., Palmer, I.D., & Schwebel, 1992: Fortescue Field, Gippsland Basin, Offshore Australia. in: Halbouty, M.T. (ed.): Giant Oil Fields of the Decade 1978- 1988; American Association of Petroleum Geologists Memoir 54, pp. 483-492. Hocking, J.B., 1998: Tertiary – Gippsland Basin. in: Economic geology – Oil and Gas. in: Douglas, J.G. & Ferguson, J.A., (eds.): Geology of Victoria. Victoria Division of the Geological Society of Australia Inc. (Melbourne, AU), pp. 322-347. Holdgate, G.R., Wallace, M.W., Daniels, J., Gallagher, S.J., Keene, J.B., & Smith, A.J. (2000): Controls on Seaspray Group sonic velocities in the Gippsland basin – A multidisciplinary approach to the canyon seismic velocity problem. Australian Petroleum Production & Exploration Association (APPEA) Journal, 40, pp. 295-313. Holloway, S. (ed.), 1996: The underground disposal of Carbon Dioxide. British Geological Survey Report for JOULE II project CT92-0031. 355 pp.
Holt, T., Jensen, J.I., Lindeberg, E., 1995: Underground storage of CO2 in aquifers and oil reservoirs. Energy Conv. Mgmt., 36, pp. 335-338. Kanen, R., 1993: The offshore Gippsland Basin, Victoria. Mineral Services (Wantirna, Victoria, Australia), 101 pp. (Short version without figures available at http://www.geologyone.com/gipps1.htm).
Lindeberg, E., 1997: Escape of CO2 from Aquifers. Energy Convers. Mgmt. Vol. 38 Suppl., pp. 235-240. Lindeberg, E., Causse, E., & Ghaderi, A., 1999: Evaluation of to what extent CO2 accumulations in the Utsira formations are possible to quantify by seismic by August 1999. SINTEF Petroleum Research report, 13p, confidential. Moritis, G., 1992: EOR increases 24% worldwide; claims 10% of U.S. production. Annual Production Report, Oil & Gas Journal, April 20, OGJ Special, pp. 51-79. Ofei-Mensah, A., 1998: Energy efficiency services trends. Australian Energy News, 9. http://www.isr.gov.au/resources/netenergy/aen/aen9/9services.html. Rahmanian, V.D., Moore, P.S., Mudge, W.J., & Spring, D.E., 1990: Sequence stratigraphy and the habitat of hydrocarbons, Gippsland basin, Australia. In: Brooks, J. (ed.): Classic Petroleum Provinces, Geological Society Special Publication, 50, pp. 525-541. Samarin, A., 1999: Utilisation of waste from coal-fired power plants – an important factor in the abatement of greenhouse gas emissions. ATSE Focus, 106. http://www.atse.org.au/publications/focus/focus-samarin2.htm. Smith , G.C., 1988: Economic geology – Oil and Gas. in: Douglas, J.G. & Ferguson, J.A., (eds.): Geology of Victoria. Victoria Division of the Geological Society of Australia Inc. (Melbourne, AU), pp. 515-546. Span, W. and Wagner, W. 1996: A New Equation of State for Carbon Dioxide Covering the Fluid Region from the Triple-Point Temperature to 1100 K at pressures up to 800 MPa. J. Phys. Ref. Data 25, 6, pp. 1509-1596 Taber, J., 1994: Enhanced oil recovery. In: Riemer, P. (ed.): The utilisation of carbon dioxide from fossil fuel fired power stations, IEA-GHG/SR4, IEA Greenhouse Gas R&D Programme, Cheltenham.
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Zweigel, P., Lothe, A., Arts, R., & Hamborg, M. 2000: Reservoir geology of the storage units in the Sleipner CO2-injection case - A contribution to the Saline Aquifer CO2 Storage (SACS) project. SINTEF Petroleum Research report (CD) 23.4285.00/02/00, 79 pp., 3 app., confidential. Zweigel, P., Arts, R., Bidstrup, T., Chadwick, A., Eiken, O., Gregersen, U., Hamborg, M., Johanessen, P., Kirby, G., Kristensen, L., Lindeberg, E., 2001: Results and experiences from the first Industrial-scale underground CO2 sequestration case (Sleipner Field, North Sea). American Association of Petroleum Geologists, Annual Meeting, June 2001, Denver, abstract volume (CD) 6pp. http://www.iku.sintef.no/projects/IK23430000/Publications/Zweigeletal_2001_AAPG _extabstr.pdf
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Appendix A Calculation of CO2 density and bulk modulus at reservoir conditions
CO2 density, ρ, and bulk modulus, K, is calculated from an equation of state (EOS) specially developed for CO2 (Span and Wagner 1996). The EOS is based on about 2000 pVT data, heat capacitance, and sound of velocity data. Since the temperature, T, and pressure, p, vary with depth, a model for the pressure and temperature depth gradient is needed. The temperature gradient is discussed in Chapter 3. The temperature is calculated from the constant gradient and sea floor temperature of 10 °C at the water depth given for each hydrocarbon field, or for a water depth of 100 m below mean sea level (msl) for general calculations. The pressure is assumed to be the hydrostatic pressure for a brine solution. The density of brine as function of pressure and temperature is calculated from an equation of state for brine at the prevailing pressure and temperature depth profiles and salt concentration. The pressure and temperature gradients are then used to calculate the density of CO2 as function of depth.
Examples for density calculations are given in Figure 7.1.
The bulk modulus is calculated from the speed of sound, w, which is calculated from the EOS mentioned above:
2 cp ∂p w = cv ∂ρ T where specific heat capacity at constant volume, cv, respectively at constant pressure, cp, are also calculated from the EOS:
2 2 ρ ∂ pTid ()∂∂p / T cdvp=+ρ c, cp=cv+ ∫0 ∂∂Tp22ρ / ∂ρ ρ ()T
Finally the bulk modulus is calculated from
Kw= 2 ρ
The bulk modulus of brine is calculated from the speed of sound in brine as function of temperature, pressure and salinity given by Batzle and Wang (1992).
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800.000
700.000
600.000 ] 500.000 m3 g/
k 30 degC/km [ 400.000 y t
i 33 degC/km
ns 300.000 35 degC/km e
D 37.5 degC/km 200.000 40 deg C/km 42.5 deg C/km 100.000 45 deg C/km 0.000 0 500 1000 1500 2000 2500 3000 3500 Depth bsl [m]
700
650
600 ] 3 m / 550 g
k 1000m [ y t i 500 1500m s
n 2000m De 450 2500m
400
350 30 32.5 35 37.5 40 42.5 45 Geothermal gradient [degC/km]
Figure 7.1 Density of pure CO2 as a function of geothermal gradients and reservoir depth. A water depth of 100m with a sea floor temperature of 10º C was assumed.
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Appendix B Calculation of acoustic velocity and reflection coefficient
Acoustic velocity and reflection coefficient as functions of CO2-saturation were calculated using the procedure outlined below. The following parameters are assumed to be given (for values see Table 9; see also Appendix A for bulk moduli and densities for water and CO2):
ρSw=1 Rock density (incl. pore filling) at 100 % water saturation
VpS,1w= Vp, P-wave velocity at water saturation = 1
Vs,1Sw= Vs, S-wave velocity at water saturation = 1 φ Porosity
Kgrain Bulk modulus of grains (quartz)
KCO2 Bulk modulus of CO2 at reservoir condition
KH 2O Bulk modulus of H2O at reservoir condition
ρCO2 Density of CO2 at reservoir condition
ρH 2O Density of H2O at reservoir condition
The shear modulus, G , at 100 % water saturation ( Sw = 1) can be calculated by
2 (0.1) GVSw==1,=s Sw 1⋅ρSw=1 which is the standard equation for S-wave acoustic velocity, solved for G.
The bulk modulus , KSw=1 , at 100 % water saturation ( Sw = 1) can then be calculated by
4 (0.2) KV=⋅2 ρ −⋅G Sw==1,p Sw 1Sw=13 Sw=1 which is the standard equation for P-wave velocity, solved for K.
The Biot-Gassman equation, solved for the frame bulk modulus, K frame , is:
KKK HO22−+(1 HO −HO2) ⋅K φφ⋅ KK Sw=1 (A.3) K = grain grain frame K1 K HO21⋅+(1 − Sw= ) −1 KKgrain φφ⋅ grain
Thereby, all relevant rock parameters for the fully water saturated case have been calculated.
The bulk modulus of the mixed fluid, K fluidmix , with water saturation Sw and CO2- saturation SCO2 =−1 Sw can be calculated by the fluid mixture formula:
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−1 Sw 1− Sw (A.4) K fluidmix =+ KKHO22CO
Inserting K fluidmix into the Biot-Gassman equation yields the bulk modulus for the rock saturated with the mixed fluid, Krock , fluidmix :
2 K 1− frame K K (A.5) KK=+fluidmix ⋅ grain rock, fluidmix frame φ KK 11+⋅fluidmix −φ −frame φ ⋅ KKgrain grain
The density of the rock, saturated with the mixed fluid, ρrock, fluidmix , is derived from
(A.6) ρρrock,1fluidmix =+Sw= φ⋅()1−Sw ⋅(ρCO2−ρH 2O )
The acoustic P-wave velocity, Vp,,rock fluidmix , and S-wave velocity, Vs,,rock fluidmix , for rock saturated with the fluid mix can be calculated using the standard formulae for acoustic P- and S-wave velocities:
4 KG+ ⋅ rock, fluidmix 3 (A.7) Vp,,rock fluidmix = and ρrock, fluidmix
G (A.8) Vs,,rock fluidmix = ρrock, fluidmix
Seismic impedance, I, is defined as the product of seismic p-wave velocity and rock density and is therefore:
(A.9) IVrock,,fluidmix =⋅p rock ,fluidmix ρrock,fluidmix
The reflection coefficient is given by the contrast of seismic impedances of neighbouring rocks. In the present case, only water (and CO2) saturation are assumed to be different for the rock parts. The reflection coefficient, R , is accordingly:
II− (A.10) R = rock,,fluidmix rock Sw=1 IIrock ,,fluidmix + rock Sw=1
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