FRACTURE FORMATION AND FLUID FLOW IN THE PALM VALLEY GAS FIELD, CENTRAL AUSTRALIA

2001 ◽  
Vol 41 (1) ◽  
pp. 165 ◽  
Author(s):  
P.J. Hamilton ◽  
P.J. Eadington ◽  
M. Lisk ◽  
N.A. Milne
Keyword(s):  
Fluid Flow ◽  
Fluid Inclusion ◽  
Gas Flow ◽  
Vertical Component ◽  
Fracture Network ◽  
Gas Field ◽  
Wet Gas ◽  
Fracture Development ◽  
Central Australia ◽  
Matrix Porosity

Palaeo-fluid flow in the fracture network in the Palm Valley gas field (Amadeus Basin, central Australia) was investigated using fluid inclusion, isotopic and petrographic methods. The Ordovician Pacoota and Stairway Sandstone reservoir rocks have exceedingly low matrix porosity and permeability and economic gas flow rates, therefore, depend on the fracture network.Pre-fracture cementation of the matrix involved precipitation of pyrite, haematite, chlorite, illite and quartz. However, matrix cementation, as well as the fracture mineralisation, is now dominated by barite, ankerite and quartz. This indicates that subsequent to being fractured, connectivity between matrix porosity and fractures allowed invasion of the host sandstones by mineralising fluids from the fracture network. Fluid inclusion palaeo-temperature analyses indicate temperatures of 90–115°C prevailed at the time of formation of these minerals which was contemporaneous with maximum burial estimated to have occurred during the Alice Springs orogeny at ~340–240 Ma.Aqueous fluids in the sandstones were derived from three sources. Connate waters comprise one source and were parental to pre-fracture diagenetic minerals. The reservoir was accessed by two other fluids via the fracture network. Basinal brines comprise one source, whilst low salinity waters of surface meteoric origin comprise the other. One component of the basinal brine had had prior contact with Precambrian Bitter Springs Formation evaporites whilst another had been in contact with rocks characterised by high barium contents and radiogenic strontium isotope ratios. The total vertical component of fluid flow appears to have been ~7–8 km.Hydrocarbon migration was in part synchronous with fracture development and was accompanied by migration of basinal brines. Liquid hydrocarbons and wet gas migrated during cementation of the fractures. Temperatures continued to rise and dry gas was generated which displaced the wet gas now only observed in fluid inclusions in the mineral cements.

THE DETECTION AND SIGNIFICANCE OF FRACTURES IN THE PALM VALLEY GAS FIELD

1987 ◽  
Vol 27 (1) ◽  
pp. 264
Author(s):  
R.F. Do Rozario ◽  
B.W. Baird
Keyword(s):  
Gas Flow ◽  
Fracture Network ◽  
Log Analysis ◽  
Fracture Density ◽  
Gas Flow Rate ◽  
Gas Field ◽  
Bedding Planes ◽  
Fractured Zones ◽  
Resultant Data ◽  
Interference Tests

The Palm Valley Gas Field was discovered in March 1965 when the Palm Valley 1 well flowed up to 11.7 million cubic feet of gas/day from Ordovician sandstones and carbonates. Since then, a further five wells have been drilled, with a wide variation in gas flow rate, from less than one million, to over 130 million cubic feet/day.Matrix porosities and permeabilities are generally very poor to poor; however, cores, log analysis, and interference tests confirm the presence of an extensive fracture network providing the main permeability conduit for gas production.Recent drilling (Palm Valley 4, 5 and 6) has enabled a comprehensive suite of modern wire-line logs to be run with the specific aim of identifying the location and orientation of fractures. From analysis of the resultant data, it can be demonstrated that both fracture direction and concentration vary significantly from well to well, giving rise to corresponding differences in productivity. Fracture occurrence also varies from fractured zones that parallel bedding planes and may be correlatable from one well to another, to vertical or semi-vertical fractures that intersect the borehole diagonally.High well productivity can be correlated with greater fracture density, which in the Palm Valley Field has so far been proven to occur along the axis of the anticline, as well as with the intersection of major fractured 'zones' displaying a dominant fracture orientation sub-parallel to parallel to that of the principal residual stress.

Numerical Simulation of Complex Fracture Network Development by Hydraulic Fracturing in Naturally Fractured Ultratight Formations

2013 ◽  
Author(s):  
Hannes Hofmann ◽  
Tayfun Babadagli ◽  
Günter Zimmermann
Keyword(s):  
Fracture Network ◽  
Natural Fracture ◽  
Fracture Networks ◽  
Network Development ◽  
Complex Fracture ◽  
Fracture Patterns ◽  
Fracture Systems ◽  
Fracture Development ◽  
Complex Fracture Network ◽  
Treatment Designs

The creation of large complex fracture networks by hydraulic fracturing is imperative for enhanced oil recovery from tight sand or shale reservoirs, tight gas extraction, and Hot-Dry-Rock (HDR) geothermal systems to improve the contact area to the rock matrix. Although conventional fracturing treatments may result in bi-wing fractures, there is evidence by microseismic mapping that fracture networks can develop in many unconventional reservoirs, especially when natural fracture systems are present and the differences between the principle stresses are low. However, not much insight is gained about fracture development as well as fluid and proppant transport in naturally fractured tight formations. In order to clarify the relationship between rock and treatment parameters, and resulting fracture properties, numerical simulations were performed using a commercial Discrete Fracture Network (DFN) simulator. A comprehensive sensitivity analysis is presented to identify typical fracture network patterns resulting from massive water fracturing treatments in different geological conditions. It is shown how the treatment parameters influence the fracture development and what type of fracture patterns may result from different treatment designs. The focus of this study is on complex fracture network development in different natural fracture systems. Additionally, the applicability of the DFN simulator for modeling shale gas stimulation and HDR stimulation is critically discussed. The approach stated above gives an insight into the relationships between rock properties (specifically matrix properties and characteristics of natural fracture systems) and the properties of developed fracture networks. Various simulated scenarios show typical conditions under which different complex fracture patterns can develop and prescribe efficient treatment designs to generate these fracture systems. Hydraulic stimulation is essential for the production of oil, gas, or heat from ultratight formations like shales and basement rocks (mainly granite). If natural fracture systems are present, the fracturing process becomes more complex to simulate. Our simulation results reveal valuable information about main parameters influencing fracture network properties, major factors leading to complex fracture network development, and differences between HDR and shale gas/oil shale stimulations.

Laminar Forced Convection in Annular Microchannels With Slip Flow Regime

2009 ◽  
Author(s):  
Arman Sadeghi ◽  
Abolhassan Asgarshamsi ◽  
Mohammad Hassan Saidi
Keyword(s):  
Nusselt Number ◽  
Fluid Flow ◽  
Aspect Ratio ◽  
Boundary Conditions ◽  
Knudsen Number ◽  
Gas Flow ◽  
Slip Flow ◽  
Outer Wall ◽  
Graphical Form ◽  
Uniform Temperature

Fluid flow and heat transfer at microscale have attracted an important research interest in recent years due to the rapid development of microelectromechanical systems (MEMS). Fluid flow in microdevices has some characteristics which one of them is rarefaction effect related with gas flow. In this research, hydrodynamically and thermally fully developed laminar rarefied gas flow in annular microducts is studied using slip flow boundary conditions. Two different cases of the thermal boundary conditions are considered, namely: uniform temperature at the outer wall and adiabatic inner wall (Case A) and uniform temperature at the inner wall and adiabatic outer wall (Case B). Using the previously obtained velocity distribution, energy conservation equation subjected to relevant boundary conditions is numerically solved using fourth order Runge-Kutta method. The Nusselt number values are presented in graphical form as well as tabular form. It is realized that for the case A increasing aspect ratio results in increasing the Nusselt number, while the opposite is true for the case B. The effect of aspect ratio on Nusselt number is more notable at smaller values of Knudsen number, while its effect becomes slighter at large Knudsen numbers. Also increasing Knudsen number leads to smaller values of Nusselt number for the both cases.

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