Modelling the Evolution of Formation Water Salinity and Impacts of CO2 Injection in the Gippsland Basin

Basin-scale Impacts of Industrial-scale CO2 Injection on Petroleum and Groundwater Resources in the Gippsland Basin, Australia

Assessment of CO2 storage capacity and injectivity in saline aquifers – comparison of results from numerical flow simulations, analytical and generic models

Simulation of the cumulative impacts of CO2 geological storage and petroleum production on aquifer pressures in the offshore Gippsland Basin

A new technique has been developed that allows determination of the resistivity of a pristine sample of irreducible water trapped during oil accumulation, This fluid inclusion technique, termed ROI, is directly applicable to the evaluation of oil accumulations where the salinity of present day formation waters below the OWC differs from that of irreducible water trapped during oil accumulation. Determination of oil saturation for calculation of oil reserves is critically dependent on the resistivity of formation water (Rw). Water saturations calculated from logs require an Rw value for irreducible water in the oil zone. In conventional log analysis the formation water salinity in the oil zone and therefore the Rw is assumed to be the same as that below the OWC. This relies on the assumption that the water below the OWC has not changed following oil charge. Irreducible water is trapped with oil in microscopic fluid inclusions within reservoir grains. Resistivity of this water can be derived from an ice melting temperature using the correlation between colligative and transport properties of aqueous solutions. Measurements are made on core or cuttings samples from the oil zone and exclude contamination from mud filtrate invasion. Introduction Water below the OWC may change after oil charge in basins which are exposed at the land surface. This may allow recharge of meteoric water, potentially resulting in lower salinity water below the OWC than in the oil zone e.g. in more shoreward oil filled reservoirs underlain by freshwater aquifers in the Gippsland Basin, calculated water saturations using the salinities from water below the OWC are inconsistent with RFT, capillary pressure and production test data. The opposite situation can also occur where tectonic movements cause relatively deep saline water to flow into reservoir rocks below the OWC. In these situations the water below the OWC will differ in salinity and Rw from irreducible water in the oil zone which is shielded from later flow of formation water by high oil saturation. The timing of changes in hydrology relative to oil charge has major implications because use of an inappropriate formation water resistivity value can result in incorrect reserves estimation. Decisions regarding field development are linked to reserves estimates and accurate Rw values are essential. Current Methods for Determination of Rw The most direct way of finding water resistivity (Rw) is to obtain a sample of formation water and measure its resistivity. However, this is seldom possible, as formation water samples are usually contaminated by mud filtrate. Rw is therefore usually calculated by one of two methods:SP methodArchie equation Reliable determination of oil saturation from logs requires a determination of Rw from a measurement directly on a sample of the irreducible water. Calculated Rw relies on a number of assumptions which may result in erroneous values - the SP method does not work for oil based muds and does not give correct estimations of Rw in hydrocarbon bearing zones while the Archie equation method only works in clean, water-bearing reservoirs and is typically unreliable in highly fractured or vuggy reservoirs. Capillary Pressure and Relative Permeability For practical purposes, the value of the irreducible or minimum water saturation in the oil zone is usually assumed to represent the interstitial water content of the pay section of the reservoir. Interstitial water in this zone is held in place by capillary forces, and flow differentials will not remove it. P. 137

Flow of variable-density formation water in deep sloping aquifers: review of methods of representation with case studies

Geological storage of CO2 in the offshore Gippsland Basin, Australia, is being investigated by the Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) as a possible method for storing the very large volumes of CO2 emissions from the nearby Latrobe Valley area. A storage capacity of about 50 million tonnes of CO2 per annum for a 40-year injection period is required, which will necessitate several individual storage sites to be used both sequentially and simultaneously, but timed such that existing hydrocarbon assets will not be compromised. Detailed characterisation focussed on the Kingfish Field area as the first site to be potentially used, in the anticipation that this oil field will be depleted within the period 2015–2025. The potential injection targets are the interbedded sandstones of the Paleocene-Eocene upper Latrobe Group, regionally sealed by the Lakes Entrance Formation. The research identified several features to the offshore Gippsland Basin that make it particularly favourable for CO2 storage. These include: a complex stratigraphic architecture that provides baffles which slow vertical migration and increase residual gas trapping and dissolution; non-reactive reservoir units that have high injectivity; a thin, suitably reactive, lower permeability marginal reservoir just below the regional seal providing mineral trapping; several depleted oil fields that provide storage capacity coupled with a transient production-induced flow regime that enhances containment; and long migration pathways beneath a competent regional seal. This study has shown that the Gippsland Basin has sufficient capacity to store very large volumes of CO2. It may provide a solution to the problem of substantially reducing greenhouse gas emissions from future coal developments in the Latrobe Valley.

The Latrobe aquifer in the Gippsland Basin in southeastern Australia is a prime example for emerging resource conflicts in Australian sedimentary basins. The Latrobe Group forms a major freshwater aquifer in the onshore Gippsland Basin, and is an important reservoir for oil and gas in both onshore and offshore parts of the basin. The Latrobe Group and overlying formations contain substantial coal resources that are being mined in the onshore part of the basin. These may have coal-seam-gas potential and, in addition, the basin is considered prospective for its geothermal energy and CO2 storage potential. The impacts of groundwater extraction related to coal-mine dewatering, public water supply, and petroleum production on the flow of variable-density formation water has been assessed using freshwater hydraulic heads and impelling force vectors. Groundwater flows from the northern and western edges towards the central part of the basin. Groundwater discharge occurs mainly offshore along the southern margin. Post-stress hydraulic heads show significant declines near the petroleum fields and in the coal mining areas. A hydrodynamic model of the Latrobe aquifer was used to simulate groundwater recovery in the Latrobe aquifer from different scenarios of cessation of groundwater and other fluid extractions.

Origin, chemistry and flow of formation waters in the Mississippian–Jurassic sedimentary succession in the west-central part of the Alberta Basin, Canada

Rapid evaluation of the hydrochemistry of a sedimentary basin using only ‘standard’ formation water analyses: example from the Canadian portion of the Williston Basin

The risk of fault reactivation in the Gippsland Basin was calculated using the FAST (Fault Analysis Seal Technology) technique, which determines fault reactivation risk by estimating the increase in pore pressure required to cause reactivation within the present-day stress field. The stress regime in the Gippsland Basin is on the boundary between strike-slip and reverse faulting: maximum horizontal stress (~ 40.5 MPa/km) > vertical stress (21 MPa/km) ~ minimum horizontal stress (20 MPa/km). Pore pressure is hydrostatic above the Campanian Volcanics of the Golden Beach Subgroup. The NW-SE maximum horizontal stress orientation (139°N) determined herein is broadly consistent with previous estimates, and verifies a NW-SE maximum horizontal stress orientation in the Gippsland Basin. Fault reactivation risk in the Gippsland Basin was calculated using two fault strength scenarios; cohesionless faults (C = 0; μ = 0.65) and healed faults (C = 5.4; μ = 0.78). The orientations of faults with relatively high and relatively low reactivation potential are almost identical for healed and cohesionless fault strength scenarios. High-angle faults striking NE-SW are unlikely to reactivate in the current stress regime. High-angle faults oriented SSE-NNW and ENE-WSW have the highest fault reactivation risk. Additionally, low-angle faults (thrust faults) striking NE-SW have a relatively high risk of reactivation. The highest reactivation risk for optimally oriented faults corresponds to an estimated pore pressure increase (Delta- P) of 3.8 MPa (~548 psi) for cohesionless faults and 15.6 MPa (~2262 psi) for healed faults. The absolute values of pore pressure increase obtained from fault reactivation analysis presented in this paper are subject to large errors because of uncertainties in the geomechanical model (in situ stress and rock strength data). In particular, the maximum horizontal stress magnitude and fault strength data are poorly constrained. Therefore, fault reactivation analysis cannot be used to directly measure the maximum allowable pore pressure increase within a reservoir. We argue that fault reactivation analysis of this type can only be used for assessing the relative risk of fault reactivation and not to determine the maximum allowable pore pressure increase a fault can withstand prior to reactivation.

Based on the wealth of data generated by the oil industry, the regional-scale characteristics of rocks, the flow of formation waters, and their relation to hydrocarbon accumulations were analyzed for the northern Alberta basin. The flow of formation waters in several aquifers and aquifer systems separated by intervening aquitards is at steady state and is driven by the present-day topography both on a regional and a local scale. The flow is generally from a recharge area in the southwest at the fold belt and Bovie Lake fault, to discharge in the northeast at the Great Slave Lake, the lowest point in the basin. The flow in Devonian aquifers is in open systems from recharge to discharge areas, whereas the flow in Carboniferous and Cretaceous aquifers is in semi-open systems, discharging into adjacent aquitards. Very high porosity and permeability in places in the Devonian Elk Point aquifer system are due to reefs, fracturing, dolomitization, and karst processes. Very high permeability probably leads to relatively high flow rates along the Presqu'ile barrier reef, resulting in local advective effects on the terrestrial heat transport to the surface. On a regional scale, all of the aquifers are underpressurized due to upstream propagation through high-permeability zones of low hydraulic heads at discharge elevations. The flow pattern is corroborated by salinity distributions, with comparatively lower salinity in each aquifer at recharge in the southwest and at discharge in the northeast caused by mixing with fresher meteoric water, and higher salinity between recharge and discharge areas. Salinity distributions show that the aquifers are not completely flushed of the original formation waters. Dissolution of salt and anhydrite from adjacent strata leads to high salinity in the Elk Point aquifer system and Beaverhill Lake aquifer. Hydrocarbons generated in the southwest in Devonian and Carboniferous strata, at maximum burial depth during the Laramide orogeny, migrated updip to the northeast driven by their own buoyancy and entrained by the flow of formation waters. Unless stratigraphically trapped by reefs and at the edge of semi-open aquifers, migration to the discharge areas led to loss of the volatile components and biodegradation into altered bitumens. The hydrostratigraphy and direction of the flow of formation waters in the northern part of the Alberta basin indicate that hydrocarbons generated in this region did not contribute to the formation of the giant Athabasca oil sand deposit located southeast of the study area.

Geothermal exploitation from depleted high temperature gas reservoirs via recycling supercritical CO2: Heat mining rate and salt precipitation effects

Hydrodynamic considerations for carbon storage design in actively producing petroleum provinces: An example from the Gippsland Basin, Australia

Palaeo‐formation water evolution in the Latrobe aquifer, Gippsland Basin, south‐eastern Australia continental shelf

Scoping Study of the Economics of CO2 Transport and Storage Options for Steel Manufacturing Emissions in Eastern Australia