Reservoirs porosity

Reservoir porosity can be measured directly from core samples or indirectly using logs. However as core coverage is rarely complete, logging is the most common method employed, and the results are compared against measured core porosities where core material is available. 

Some variables often have dependencies, such as reservoir porosity and permeability (a positive correlation) or the capital cost of a specific equipment item and its lifetime maintenance cost (a negative correlation). We can test the linear dependency of two variables (say x and y) by calculating the covariance between the two variables (o ) and the correlation coefficient (r) ... 

Kleinberg et al. (2005) and Takayama et al. (2005) show that NMR-log measurement of sediment porosity, combined with density-log measurement of porosity, is the simplest and possibly the most reliable means of obtaining accurate gas hydrate saturations. Because of the short NMR relaxation times of the water molecules in gas hydrate, they are not discriminated by the NMR logging tool, and the in situ gas hydrates would be assumed to be part of the solid matrix. Thus the NMR-calculated porosity in a gas-hydrate-bearing sediment is apparently lower than the actual porosity. With an independent source of accurate in situ porosities, such as the density-log measurements, it is possible to accurately estimate gas hydrates saturations by comparing the apparent NMR-derived porosities with the actual reservoir porosities. Collett and Lee (2005) conclude that at relatively low gas... 

The capacity of a trap to accumulate gas is constant through time and is defined by the structural height, reservoir porosity, reservoir pressure and temperature. 

Taylor, T.R. (1990) The influence of calcite dissolution on reservoir porosity in Miocene sandstones. Picaroon Field, offshore Texas Gulf Coast. J. sediment. Petrol., 60, 322-334. 

Type II calcite started to form before oil emplacement (Fig. 13), partially controlled by bioclast occurrence in the sediment. The oil migration to the reservoir occurred during or after the Early Tertiary (Rizzo etai, 1990 Soldan et a/., 1990). In the water zone, cementation of type III calcite went on occluding the reservoir porosity, as indicated by the calculated crystallization temperature of 40°C. The paragenetic relationship between type II calcite and oil staining observed in thin section, and the lack of this relationship concerning type III calcite, matches this interpretation. 

Poikilotopic carbonate cements can reduce reservoir porosity in relatively clean, massive sandstones over large areas, of the order of at least 300 km (Angel Field). Based on log characteristics, major carbonate-cemented zones can attain a cumulative thickness of at least 165 m in marine sandstones (Dampier sub-basin, Carnarvon basin) and 110 m in fluvial sandstones (Eromanga basin). The total volume of carbonate cement in petroleum fields can approach 1 km, as exemplified by. the Angel Field case study. 

Secondary porosity development as the main contributor to the present reservoir porosity in Hibernia Field is closely related to the former presence of early calcite cements. The fraction of total porosity which is secondary increases with depth, from 20% in Avalon/Ben Nevis Sandstone (Hauterivian-Albian), to 60% in Catalina Sandstone (Lower Hauterivian), and to >80% in Hibernia Formation (Berriasian to Mid-Valanginian). In the Avalon/Ben Nevis Sandstone the formation of secondary porosity may have been caused by meteoric water influx. In the deeper reservoirs it was caused by acidic pore fluids generated by organic-matter maturation. The present average geothermal gradient of 26°C/km suggests that the most deeply buried sandstone reservoirs in Hibernia (Tithonian Jeanne d Arc Formation) did not experience temperatures in excess of 130°C. 

Secondary porosity is the main contributor to the present reservoir porosity in Hibernia Field, but its significance varies considerably between different stratigraphical levels. In what follows, different ge-... 

Fig. 3.6a,b. Mechanical compaction features of Saharan reservoirs, a Contact type plot for sandstones from 1 Cambro-Ordovician, Hassi Messaoud oil field (cement content cement content <12%), 3 Triassic, Hassi R Mel gas field (cement content <16%). b Correlation curves of I reservoirs porosity,2 adjacent shales density,3 montmorillonite/illite proportion in adjacent shales, 4 potassium content in shales also... 

Fig. 3.12. Correlation curves of I reservoir porosity, 2 adjacent shales density, montmorillonite/illite proportion in adjacent shales, 4 potassium content in shales, with depth for Triassic and Palaeozoic sediments, Oued el-Mya Basin...

Assuming constant temperature and oil density, uniform reservoir porosity and permeability, and changes only along the vertical z direction, the solvent mass balance is given by... 

MOST SANDSTONE RESERVOIRS Porosity proportional to permeability... 

The results presented above indicated that some parameters can be reliably estimated for some types of reservoirs by the technique of history matching. To obtain good results from history matching especially when distinguishability and not resolution closure criterion is used, the temporal response of the matched performance data must be sensitive to variations in the description data being estimated. The permeability estimates in this study were found to be accurate and reliable in virtually all cases considered. But porosity estimates were unreliable in most cases. Notice that the reservoir considered in this study is undercompacted and stress-sensitive in which case the reservoir s temporal response of pressure, the matched performance data, is very sensitive to variations in the reservoir permeability while it is only mildly sensitive to variations in the reservoir porosity. For normally compacted and non stress-sensitive reservoirs, the temporal response of pressure is very sensitive to variations in both the... 

Mud filtrate and formation fluids form an emulsion, reducing reservoir porosity... 

Average floodable reservoir porosity 20.6 per cent 20.1 per cent... 

---