Effective porosity

About: Effective porosity is a research topic. Over the lifetime, 1199 publications have been published within this topic receiving 26511 citations.

Reservoir quality determination through petrophysical analysis of El Wastani Formation in Scarab Field, Offshore Nile Delta, Egypt

Abstract: The Scarab Field, in West Delta Deep Marine concession, represents deep marine slope channels in Nile Delta of Egypt. The main hydrocarbon bearing formation is the Late Pliocene El Wastani Formation. Channel-1 and channel-2 of the El Wastani Formation are considered as the main reservoirs of Scarab Field. Well log data analysis, of four wells were accomplished using computer software programs (e.g. Interactive petrophysics (I.P. V. 3.6) software was used in petrophysical evaluation Petrophysical analysis, in terms of determining the effective porosity, shale volume, and reservoir fluid saturation of Channel-1 and channel-2 of El Wastani Formation, is the primary aim of this study in order to achieve better determination of the reservoir quality in Scarab Field. We found that Channel-1 and channel-2 of El Wastani Formation are having high storage capacity properties permit them of bearing a considerable amount of hydrocarbon fluids in the Scarab Field. It was found that effective porosity in chaneel-1 ranges between 18% and 30%, shale content ranges between 20% and 30%, the water saturation ranges between 36% and 52% in channel -2 the effective porosity ranges between 22% and 25%, shale content ranges between 20% and 30%, the water saturation ranges between 40% and 52.5% It is clear that the facies effect is the main factor that is controlling the distribution of the petrophysical properties.

Petrophysical parameters and modelling of the Eocene reservoirs in the Qadirpur area, Central Indus Basin, Pakistan: implications from well log analysis

Abstract: The Eocene rock units of the Qadirpur field, Central Indus Basin (Pakistan), are investigated petrophysically for their detailed reservoir characterization. The different petrophysical parameters determined include the following: true resistivity, shale volume, total porosity, effective porosity, density and neutron porosity, water and hydrocarbon saturation, bulk volume of water, lithology, gas effect, P-wave velocity, movable hydrocarbon index and irreducible water saturation and integrated with different cross-plots. The Eocene reservoirs are excellent with high effective porosity (2–32 %) and hydrocarbon saturation (10–93 %). Among these, the Sui Upper Limestone is an overall a poor reservoir; however, it has some hydrocarbon-rich intervals with high effective porosity and better net pay. All the net pay zones identified show low and variable shale volume (5–30 %). The secondary porosity has added to the total and effective porosities in these reservoirs. The main contributors to the porosity are the chalky, intercrystalline and vuggy/fracture types. The thickness of the reservoirs zones ranges from 4.5 to 62 m. These reservoirs are gas-producing carbonates with almost irreducible water saturation (0.002–0.01) and are likely to produce water-free hydrocarbons. The lower values of moveable hydrocarbon index (0.07–0.9) show that the hydrocarbons are moveable spontaneously to the well bore. The proposed correlation model shows that the reservoirs have an inclined geometry and are a part of an anticlinal trap.

The Impacts of Nano-Micrometer Pore Structure on the Gas Migration and Accumulation in Tight Sandstone Gas Reservoirs

Abstract: The uncertainties between reservoir quality and gas migration and accumulation in tight sandstone gas reservoirs are intrinsically attributed to complex microscopic pore structures. Integrated analysis including the physical simulation experiment of gas migration and accumulation, X-ray computed tomography (X-CT), and casting thin section (CTS) were conducted on core plug samples collected from the Upper Paleozoic Permian Lower Shihezi and Shanxi tight sandstone of the Daniudi area in the Ordos Basin to investigate the impacts of pore structure on the gas migration and accumulation. Physical simulation suggested that the gas flows in migration in tight sandstone reservoirs were characterized by deviated-Darcy linear flow and non-linear flow regimes. Minimum and stable migration pressure square gradients determined by application of apparent permeability were employed as key parameters to describe gas flow. Pore structure characterization revealed that the tight sandstone reservoir was characterized by wide pore and throat size distributions and poor pore-throat connectivity. The pore–throat combinations could be divided into three types, including the macropore and coarse throat dominant reservoir, full-pore and full-throat form, and meso-small pore and fine throat dominant form. Comparative analyses indicated that pore and throat radii determined the gas flow regimes by controlling the minimum and stable migration pressure gradients. Gas accumulation capacity was dominated by the connected effective porosity, and the gas accumulation process was controlled by the cumulative effective porosity contribution from macropores to micropores. Variations in pore structures resulted in differences in gas migration and accumulation of tight sandstone reservoirs. The macropore and coarse throat-dominant and the full-pore and full-throat reservoirs exhibited greater gas migration and accumulation potentials than the small pore and fine throat dominate form.

A global acoustic impedance inversion for porosity and lithology prediction in northern Gulf of Mexico

Abstract: Summary Poststack seismic inversion based on a multitrace global optimization method was conducted as part of a large study that covered about 10,200 km 2 , consisting of 502 Outer Continental Shelf blocks, located primarily in the northern Gulf of Mexico, offshore Louisiana. Considering that seismic inversion was carried out over such a huge area with a long time window (7 s two-way time), lateral and vertical variation of the seismic data were the main concerns. Seismic data conditioning to provide consistent, zero-phase wavelets over the whole volume was done iteratively with wavelet extraction and analysis at well locations. The vertical variability of wavelets due to frequency attenuation and amplitude decays with depth were also incorporated in the inversion process. The principle objective of the seismic inversion was to transform seismic reflection data into quantitative petrophysical properties. Acoustic impedance is commonly used for porosity prediction. Over the study area, the correlation between acoustic impedance and porosity is very poor because the impedance varies substantially vertically and spatially due to varying sedimentation rates and sediment compaction. An alternative transformation was applied to use relative acoustic impedance to predict effective porosity, ϕe, and volume fraction of shale, Vc. The results show that the inverted relative acoustic impedance and predicted ϕe and Vc are in reasonable match with wells over the entire study area. The use of relative acoustic impedance efficiently produced reliable ϕe and Vc. Aside from its limitations, such as disregarding the effects of fluid variations and complex lithological variations on the porosity/impedance relation, the method provides a reliable screening tool for seismic exploration. More quantitative details of the petrophysical properties can be obtained through a more sophisticated inversion method in the prestack domain.

Hydrocarbon play assessment of X-field in an Onshore Niger Delta, Nigeria

Abstract: Hydrocarbon play assessment of any hydrocarbon reservoir unit depends on the porosity, permeability, hydrocarbon saturation and water saturation of petrophysical model distributions and seismic reflections of reservoir rocks. The objective of the study is to resolve the ambiguities that are associated with hydrocarbon play assessment of an X-field in the Niger Delta basin. This was achieved through the use of pre-conditioned attributes, fault delineating seismic attributes such as coherence, variance and quantitative definition of the reservoir units of petrophysical model distributions, through the adoption of an integrated methodology of 3D seismic and well log data. A quick look examination of the well log signatures revealed numerous reservoir sand units, but only three hydrocarbon-bearing reservoir sands were of interest to us (RS1, RS2 and RS3). From the quantitative interpretation of well logs, the three identified reservoir sands were evaluated in terms of porosity, permeability, hydrocarbon saturation, shale volume, movable hydrocarbon index and water saturation. Effective porosity values of 24.56, 23.01 and 24.00% were obtained for Well 1, Well 2 and Well 4, respectively. This supports the known or already established porosity range of Agbada Formation of Niger Delta with range 28–32%. The hydrocarbon saturation for RS2 is 68.51% for Well 4, for RS3 72.49% for Well 3 and for RS2 74.16% and for RS3 77.34% for Well 2. RS2 of 79.51% and RS3 of 80.99% for Well 1 were obtained. This shows how prolific the reservoir sand units are with hydrocarbon accumulation tendencies. Structural analysis revealed a highly faulted system that depicts a typical tectonic setting of the Niger Delta basin, and the computed attributes like coherence, and variance shows an optimum visualization of the faulting system. This implies that the trapping mechanism of the field is of both anticlinal and fault-assisted closure and also the viability of the reservoir units is high from the computed petrophysical parameters.