Paul H. Nadeau

Sandstone vs. carbonate petroleum reservoirs: A global perspective on porosity-depth and porosity-permeability relationships

Plots are presented comparing average porosity vs. depth for 30,122 siliciclastic petroleum reservoirs and 10,481 carbonate petroleum reservoirs covering all petroleum-producing countries except Canada. However, separate plots cover 5534 siliciclastic and 2830 carbonate reservoirs of the Alberta basin in Canada. Average permeability vs. average porosity is shown for the non-Canadian reservoirs. Key similarities and differences between sandstones and carbonates are noted, and implications are discussed regarding the dominant factors controlling reservoir quality in each lithology. Trends of steadily decreasing median and maximum porosity with increasing depth reflect burial diagenetic porosity loss in response to increasing thermal exposure with depth. These trends seem inconsistent with the suggestions that both sandstones and carbonates commonly increase in porosity by dissolution during deeper burial. Carbonate reservoirs have lower values of median and maximum porosity for a given burial depth, probably because of greater chemical reactivity of carbonate minerals relative to quartz and the resulting lower resistance to chemical compaction and associated cementation. Relative paucity of low-porosity (0–8%) siliciclastic reservoirs at all depths compared with carbonates may reflect the more common occurrence of fractures in carbonates and the effectiveness of these fractures for facilitating economic flow rates in low-porosity rock. Overall, carbonate reservoirs do not have lower permeability for a given porosity compared with sandstones but do have strikingly lower proportions of both high-porosity and high-permeability values. The data presented can serve as a general guide for the distribution of reservoir quality that can reasonably be expected in exploration wells drilled to any given depth in the absence of detailed geologic information, such as burial and thermal history.

Porosity Prediction in Quartzose Sandstones as a Function of Time, Temperature, Depth, Stylolite Frequency, and Hydrocarbon Saturation

The variation of porosity in quartzose sandstones is calculated as a function of depth, temperature gradient, burial rate, stylolite frequency, and hydrocarbon saturation. Calculations were performed by considering the effects of both mechanical compaction and chemical compaction/cementation. This latter process dominates at temperatures greater than approximately 90°C and is due to quartz redistribution within the sandstone. Quartz redistribution stems from clay-induced quartz dissolution at stylolite interfaces, coupled with diffusional transport of aqueous silica into the interstylolite sandstone and precipitation on quartz surfaces as cement. Many model parameters are obtained from theoretical calculations or laboratory measurements, and few basin-dependent parameters are required to make porosity predictions. A set of porosity predictions is presented in porosity/depth figures. Close correspondence between computed results and measured porosities in cores from a variety of sedimentary basins demonstrates the accuracy of the predictions.

The Effect of Grain-Coating Microquartz on Preservation of Reservoir Porosity

Clay coatings have been widely accepted by many workers as an explanation for preserving high porosity in deeply buried sandstones, but few workers have realized that similar effects can be produced by microcrystalline quartz coatings. This phenomenon can be expected only under special circumstances, but in such cases it can have profound consequences for exploration. In the Central Graben area of the southern North Sea, unusually high porosity (20-27%) and permeability (100-1000 md) are found in certain zones in Upper Jurassic sandstones at depths of 3.4-4.4 km. The porosity in these zones is 5-15% higher than expected based on average porosity-depth trends from Brent and Haltenbanken sandstones. We propose that the high porosity is due to continuous grain coatings of euhedral microcrystalline quartz crystals that are 0.1-2 µm thick. The distribution of microcrystalline quartz coatings is controlled by the presence of siliceous sponge spicules (Rhaxella), which implies a sedimentological control on the reservoir quality. We present a thermodynamic model showing how continuous microcrystalline quartz coatings inhibit development of no mal macrocrystalline quartz overgrowths sourced mainly from stylolites. High porosities in parts of various Upper Jurassic oil fields (Ula and Gyda) have previously been explained by inhibition of quartz cementation by early hydrocarbon charge. We suggest that the microcrystalline quartz coatings provide a more plausible explanation.

A comparison of Khuff and Arab reservoir potential throughout the Middle East

A compilation of average porosity and permeability data for petroleum reservoirs in the Permian–Triassic Khuff Formation and the Jurassic Arab Formation shows that most Khuff reservoirs have an average porosity of less than 12%, whereas most Arab reservoirs have an average porosity of 12–26%. Higher porosity correlates with shallower depth, suggesting that burial diagenesis is the main cause of the overall porosity difference between these units. Deeper burial of Khuff reservoirs is inferred to have resulted in greater porosity loss by chemical compaction and associated cementation. A broad correlation also exists between average porosity and average permeability, suggesting that deeper burial and the resulting porosity decrease are also a primary cause of the lower permeabilities of the Khuff reservoirs. In addition to greater burial depth, however, a combination of depositional and early diagenetic factors is also reflected in the lower average porosity and permeability values of the Khuff reservoirs. Khuff strata were deposited on an extensive, poorly circulated, very low-relief shelf and consist in large part of interbedded mudstones and grainstones having relatively fine grain size, with major amounts of depositional calcium sulfate present. Arab reservoirs were deposited under better circulated conditions near platform margins facing deep, intracratonic basins and, thus, have coarser, more grain-dominated fabrics and lesser overall content of chemically precipitated grains, calcium sulfate, and dolomite. Khuff deposits were likely composed of less stable mineralogy than Arab sediments because the Late Permian was a time of aragonite seas, whereas the Late Jurassic was a time of calcite seas. The combined result of these factors is that Arab reservoirs are characterized by greater preservation of primary depositional pore types, more coarsely crystalline dolomite fabrics, and lesser plugging by anhydrite. Finally, a possible factor affecting the average porosity and permeability values is petroleum composition, which is gas in most Khuff reservoirs and oil in Arab reservoirs. Lower economic cutoff values for gas production would favor inclusion of low-permeability zones in Khuff reservoirs, thus reducing average reservoir values. Two main aspects of these results are innovative. This is the first time that porosity and permeability values for either Khuff or Arab reservoirs have been examined regionally. Second, the conclusion that thermal exposure is the primary control on average porosity and permeability in these units is consistent with previous work from other carbonates, but is new for the Middle East.

Clay Microporosity in Reservoir Sandstones: An Application of Quantitative Electron Microscopy in Petrophysical Evaluation

Clay mineral microporosity in sandstones is measured using computer-assisted image analysis of back-scattered electron micrographs of petrographic sections. Diagenetic kaolinite has a variety of textures with microporosity values ranging from 15 to 61%. Diagenetic chlorite has a generally uniform grain-coating texture and microporosity of about 50%. Fibrous illitic clays are difficult to characterize by the same method (an average value of 63% microporosity was recorded), but analysis of stereo-pair micrographs from scanning-electron microscopy analyses reveals that illite commonly has microporosity of approximately 90%. Clay microporosity data are used to calculate effective pore volumes and volumes of clay-bound water for clay minerals in sandstones. Converting from wei ht percent clay to volume percent clay is important. Microporosity data are valuable input to Vshale evaluation where water saturation is associated with clay mineral type, texture, and volume.

Physical constraints on hydrocarbon leakage and trapping revisited

In a water-wet petroleum reservoir with a water-wet seal, a continuous water phase will extend from the reservoir into the seal, and the pressure difference between the water phase in the uppermost pores of the reservoir and the water phase in the lowermost pores of the seal can therefore only be of an infinitesimal magnitude. This implies that any overpressure in a water-wet reservoir will not contribute to pushing the hydrocarbons through a water-wet seal, and overpressured water-wet reservoirs should therefore not be considered more prone to capillary leakage than normally pressured reservoirs. Within a water-wet petroleum reservoirs, the overpressure in the hydrocarbon phase relative to the water phase is balanced by the elastic forces at the fluid interface (interfacial tension). The overpressure in the hydrocarbon phase relative to the water phase therefore does not increase the risk of hydrofracturing the reservoirs seal. This implies that the risk of hydrofracturing should not be increased as a function of hydrocarbon column height, and should not be considered to be higher for gas than it is for oil. When an upward-directed hydraulic gradient is present from a reservoir unit into the overlying seal, water will continuously move upwards from the reservoir unit and into the seal if both rocks are water-wet. This movement of water may lead to exsolution of gas above the reservoir unit, and the presence of free gas may be detected as gas chimneys on seismic sections. This mechanism will operate regardless of whether or not a hydrocarbon accumulation is present below the gas chimneys, and fracturing of the reservoir units seal or capillary leakage of hydrocarbons are therefore not necessary conditions for the development of gas chimneys.

Making diagenesis obey thermodynamics and kinetics : the case of quartz cementation in sandstones from offshore mid-Norway

Calculation of the quantity and distribution of quartz cement as a function of time and temperature/depth in quartzose sandstones is performed using a coupled dissolution/diffusional–transport/precipitation model. This model is based on the assumptions that the source of the silica cement is quartz surfaces adjoining mica and/or clay grains at stylolite interfaces within the sandstones, and the quantity of silica transport into and out of the sandstone by advecting fluids is negligible. Integration of the coupled mass transfer/transport equations over geologically relevant time frames is performed using the quasi-stationary state approximation. Results of calculations performed using quartz dissolution rate constants and aqueous diffusion coefficients generated from laboratory data, are in close agreement with both the overall porosity and the distribution of quartz cement in the Middle Jurassic Garn Formation only after optimizing the product of the effective surface area and quartz precipitation rate constants with the field data. When quartz precipitation rate constants are fixed to equal corresponding dissolution rate constants, the effective surface area required to match field data depends on the choice of laboratory generated quartz rate constant algorithm and ranges from 0.008 cm−1 to 0.34 cm−1. In either case, these reactive surface areas are ∼2 to 4 orders of magnitude lower than that computed using geometric models.

I-S precipitation in pore space as the cause of geopressuring in Mesozoic mudstones, Egersund Basin, Norwegian continental shelf

Abstract The role of clay diagenesis in pressure-ramp (overpressure) development is evaluated from Mesozoic mudstone well cuttings in the Egersund Basin, Norwegian Continental Shelf. Major changes in the mineral assemblage over the range of increasing geopressure include ~50% decrease in detrital kaolinite in bulk material, and increases in the proportions of illite, I-S, and percent of nonexpandable illite-like layers in I-S. SEM and TEM observations confirm that pore space is defined primarily by intersecting clay-mineral packets at the scale of tens or hundreds of nanometers (0.01-0.1 μm). TEM data document the reactions of kaolinite and detrital mica to form I-S. The principal reaction that occurred over the geopressure ramp was dissolution of kaolinite and precipitation of neoformed I-S in pore space of these mudstones. These changes also correspond to changes in <0.1 μm particle populations, as determined by Pt/C shadowed TEM measurements, as well as high-resolution TEM lattice-fringe observations. The neoformed I-S has dimensions similar to those of the pore space in the mudstones. The results support a mineralogical model of precipitation of diagenetic clay, resulting in severe permeability reduction, which can be related to the observed pressure ramp. These observations and results provide an integrated petrologic framework for modeling pressure-ramp development, which had been difficult to achieve using conventional basin models of porosity and permeability evolution based on mechanical compaction.

An overview of reservoir quality in producing Cretaceous strata of the Middle East

ABSTRACT A compilation of average porosity and permeability data for Cretaceous petroleum reservoirs of the Middle East reveals important differences between the two main tectonic provinces. The Arabian Platform is characterized by inverse correlation of average porosity with burial depth in both carbonates and sandstones, whereas the Zagros Fold Belt (almost exclusively carbonates) has distinctly lower porosity and no depth correlation. These contrasts are suggested to reflect the fact that Arabian Platform strata are mostly near their maximum burial depth, whereas Zagros strata have experienced varying uplift and erosion following maximum burial in mid-Tertiary time. The carbonate reservoirs show no correlation between average porosity and average permeability, probably because of wide differences in the dominant pore types present, and permeabilities tend to be much higher for sandstones than for carbonates. Existence of the Arabian Platform porosity–depth correlation, despite an apparently wide diversity of depositional settings and early diagenetic porosity modifications among the individual reservoirs, illustrates and confirms some fundamental generalities about how burial diagenesis controls the overall porosity evolution of reservoir rock bodies. Although porosity commonly shows enormous small-scale heterogeneity in both carbonates and sandstones, the average pre-burial porosity of larger stratigraphic intervals tends to be very high. Burial diagenesis progressively destroys this porosity by chemical compaction and associated (stylolite-sourced) cementation. Thus, all portions of the affected rock body move toward the zero limit as depth increases, although the rates of porosity occlusion vary greatly, depending on rock fabric and early diagenesis. Average reservoir porosity therefore tends to correlate inversely with maximum burial depth, regardless of initial lithological heterogeneity.

Quantitative modelling of basin subsidence caused by temperature-driven silica dissolution and reprecipitation

Equations describing the rate of vertical thinning of sandstones due to precipitation of quartz cement produced at stylolites are derived for constant temperature and for a linear temperature change. All temperature histories can be approximated by a series of linear segments, and the equations therefore enable the diagenetic thinning of sandstones undergoing quartz cementation to be calculated as a function of temperature history. Application of the equations to interbedded sandstone–shale sequences indicate that for heating rates and geothermal gradients commonly encountered in sedimentary basins, thermally driven diagenesis leads to cumulative rates of sandstone thinning in the range of 1–10 m Ma−1. This implies that when effects of thermally driven shale diagenesis, mechanical compaction and isostatic adjustment are taken into account, thermochemical diagenetic thinning may explain a large proportion of the total generation of accommodation space in many basins. The equations describing the rate of sandstone volume reduction and, therefore, rate of fluid expulsion, could also be utilized for calculating overpressure development.