Effective porosity

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

Hydrocarbon reservoir characterization of “AY” field, deep-water Niger Delta using 3D seismic and well logs

Abstract: Three-dimensional seismic and well log data from nine wells were used for the characterization of “AY” field in the deep-water, Niger Delta. Result shows that the field has a complex structural arrangement consisting of series of northeast-southwest-trending and northwest-dipping synthetic faults. Petrophysical evaluation of the available well logs helped in identifying 11 hydrocarbon-bearing sands noted as A1000, A1100, A1200, A2000, B2000, B2100, C3000, C3100, D4000, D4100, and E5000. Reservoirs A1000, A1100, A1200, A2000, B2000, C3000, and D4000 are gas-bearing sands while reservoirs B2100, C3100, D4100, and E5000 are oil bearing. The average effective porosity of these reservoirs ranges from 0.168 to 0.292; water saturation is estimated to be between 0.177 and 0.59 and net-to-gross (NTG) ratio from 0.081 to 0.734. Considering the uncertainty in the input petrophysical parameters as well as structural uncertainty particularly in fluid contact, the total hydrocarbon reserves in the field were estimated to vary between 266.942 and 334.457 Bscf and 132.612 and 150.036 MMbbl for gas and oil volumes, respectively.

Regional Trends of Sandstone Porosity Versus Vitrinite Reflectance—A Preliminary Framework

Abstract: The porosity of sandstones is commonly observed to decrease during burial. Such decrease is frequently treated as a function of burial depth, but depth is a position coordinate that may not reflect the time-temperature history by which all subsurface processes are influenced. An alternative approach that is adapted in this study is to consider porosity decrease during burial as a function of thermal maturity. Such an approach links porosity evolution in the subsurface and the maturation of kerogen and petroleum, in that the vitrinite-reflectance measurements used to define porosity trends can also be used to characterize petroleum generation and destruction. Trends of porosity versus vitrinite reflectance (Rm) of the form f=ARmB (where B is a negative number), characterizing both typical and highest sandstone porosities, are derived from 131 measurement suites incorporating 4,353 individual porosity measurements. Diverse sandstone facies and geologic settings are represented, and the data span a maturity range of Rm=0.25-1.7%. The porosity-Rm data form trends which are projected to maturities as high as Rm=7% in order to speculate upon the distribution of sandstone porosities in the very deep (mature) portions of sedimentary basins.

A Note on the Fractal Behavior of Hydraulic Conductivity and Effective Porosity for Experimental Values in a Confined Aquifer

Abstract: Hydraulic conductivity and effective porosity values for the confined sandy loam aquifer of the Montalto Uffugo (Italy) test field were obtained by laboratory and field measurements; the first ones were carried out on undisturbed soil samples and the others by slug and aquifer tests. A direct simple-scaling analysis was performed for the whole range of measurement and a comparison among the different types of fractal models describing the scale behavior was made. Some indications about the largest pore size to utilize in the fractal models were given. The results obtained for a sandy loam soil show that it is possible to obtain global indications on the behavior of the hydraulic conductivity versus the porosity utilizing a simple scaling relation and a fractal model in coupled manner.

Formation MicroScanner Providing Better Answers for Carbonate Secondary Porosity in Alamein Dolomite Formation, NW Desert, Egypt

Abstract: The use of borehole imaging tools has become widespread in recent years with more specialized studies of reservoir properties, particularly in highly-porous and fractured carbonate systems. In this study, the Formation MicroScanner (FMS) borehole imaging tool and conventional well log data have been used to study the secondary porosity of the dolomitic Alamein Formation in the Alamein Field, north Western Desert, Egypt. Based on well log analyses of the formation from Tourmaline-1X and N.Alamein-6X wells, we show that secondary porosity occurs across the formation, and is filled mostly with hydrocarbon. We also show that the formation has good average effective porosity and hydrocarbon saturation. FMS images of the Tourmaline-1X well confirms that the formation is intermittently vuggy with solution-filled channels from the top to its base. The vug pores are observed to be well-connected, which supports good effective porosity values interpreted from petrophysical data. An additional set of core photographs of the Alamein Formation from N.Alamein-5X well confirms the presence of secondary pores, which are filled by hydrocarbon, and exhibit intense fluorescence under UV light. Our results show that the abundance of secondary porosity in Alamein Formation would play a key role in evaluating its reservoir quality and reservoir performance.