Petroleum reservoir

About: Petroleum reservoir is a research topic. Over the lifetime, 5403 publications have been published within this topic receiving 83535 citations. The topic is also known as: petroleum deposit.

The Perdido Fold Belt, Northwestern Deep Gulf of Mexico, Part 2: Seismic Stratigraphy and Petroleum Systems

Abstract: Analysis of 12,000 km of two-dimensional multifold seismic data shows a thick succession of Mesozoic and Cenozoic deep-water strata in the Perdido fold belt, northwestern deep Gulf of Mexico. These strata differ in seismic facies, areal distribution, and reservoir/petroleum potential. Mesozoic strata are interpreted as dominantly fine-grained carbonates and show minor thickness changes. Cenozoic strata are largely mud-dominated siliciclastic turbidite deposits and vary considerably in thickness across the fold belt. These changes reflect the shifting position of Cenozoic marginal-marine depocenters. Mesozoic reservoir potential consists of fractured Upper Jurassic and Cretaceous deep-water carbonates. Cenozoic reservoir potential consists of siliciclastic deep-water turbidites. Portions of the Paleocene to lower Eocene strata are sand-prone and are the downdip equivalents of the lower and upper Wilcox shallow-marine depocenters. These strata are all incorporated within the folds. Lower to middle Oligocene strata coincide with the main growth phase of the fold belt. Potentially sand-prone middle Oligocene to lower Miocene strata are the downdip equivalents of the Vicksburg (early Oligocene), Frio (Oligocene), and Oakville (early Miocene) shallow-water depocenters. These strata form potential stratigraphic traps against the folds. Mesozoic source potential was modeled assuming Oxfordian, Tithonian, Barremian, and Turonian source beds. One-dimensional thermal maturation modeling showed these sources reached peak oil generation between 51 and 39 Ma, 39 and 8 Ma, 32 and 2 Ma, and 26 and 8 Ma, respectively. Cenozoic source potential was modeled using an Eocene source. Modeling showed this source reached only early oil generation in the basinward half of the fold belt. Thermal maturation was reached by source beds at different times in different locations due to changes in burial depth, amount of structural uplift, and underlying thickness of autochthonous salt. All of these factors indicate that seal and reservoir carry significant risk, but that the potential exists for large petroleum accumulations.

Stable isotope geochemistry and origin of waters in sedimentary basins

Abstract: Formation waters with salinit~es ranging from about 5,000 mg/1 to more than 350,000 mg/l dissolved solids play a fundamental role in the physical and chemical processes that occur in sedimentary basins. These waters are particularly important in: (a) the generation, transport, accumulation and production of petroleum, (b) the chemical aspects of mineral diagenesis, including dissolution, precipitation and mineral transformations leading to major increases and/or decreases in the porosity and permeability of reservoir rocks, (c) the transport and precipitation of Cu, U, and especially sediment-hosted Mississippi Valley-type Pb-Zn ore deposits, (d) tectonic deformations, (e) the transport of thermal energy for the geothermal and geopressured-geothermal systems, and (f) the interaction, movement and ultimate fate of large quantities of hazardous wastes injected into the subsurface. Despite clear economic and scientific importance, and about a century of investigations, there is still controversy regarding the origin and evolution of these saline waters (Hanor et al., 1988).

Quantitative geophysical pore-type characterization and its geological implication in carbonate reservoirs

Abstract: This paper discusses and addresses two questions in carbonate reservoir characterization: how to characterize pore‐type distribution quantitatively from well observations and seismic data based on geologic understanding of the reservoir and what geological implications stand behind the pore‐type distribution in carbonate reservoirs. To answer these questions, three geophysical pore types (reference pores, stiff pores and cracks) are defined to represent the average elastic effective properties of complex pore structures. The variability of elastic properties in carbonates can be quantified using a rock physics scheme associated with different volume fractions of geophysical pore types. We also explore the likely geological processes in carbonates based on the proposed rock physics template. The pore‐type inversion result from well log data fits well with the pore geometry revealed by a FMI log and core information. Furthermore, the S‐wave prediction based on the pore‐type inversion result also shows better agreement than the Greensberg‐Castagna relationship, suggesting the potential of this rock physics scheme to characterize the porosity heterogeneity in carbonate reservoirs. We also apply an inversion technique to quantitatively map the geophysical pore‐type distribution from a 2D seismic data set in a carbonate reservoir offshore Brazil. The spatial distributions of the geophysical pore type contain clues about the geological history that overprinted these rocks. Therefore, we analyse how the likely geological processes redistribute pore space of the reservoir rock from the initial depositional porosity and in turn how they impact the reservoir quality.

Alteration of Rock Properties by Adsorption of Petroleum Heavy Ends: Implications for Enhanced Oil Recovery

Abstract: The purpose of this paper has been to point out a phenomenon which may exist or may be induced in petroleum reservoirs and discuss its relevance to EOR. The presence or absence of an adsorbed layer of petroleum heavy ends can have a significant impact on oil recovery from the reservoir. Specifically, an adsorbed layer of petroleum heavy ends can stabilize potentially damaging formation clay minerals against dispersion and subsequent migration. Surfactant additive adsorption is reduced when this adsorbed layer is present on clay mineral surfaces. Also rock wettability changes upon adsorption, but this wettability change may be less important to oil recovery than the stabilization of the clay minerals. 5 refs.

The Effect of Mixed Wettability on Pore-Scale Flow Regimes Based on a Flooding Experiment in Ketton Limestone

Abstract: Darcy-scale multiphase flow in geological formations is significantly influenced by the wettability of the fluid-solid system. So far it has not been understood how wettability impacts the pore-scale flow regimes within rocks, which were in most cases regarded as an alteration from the base case of strongly water-wet conditions by adjustment of contact angles. In this study, we directly image the pore-scale flow regime in a carbonate altered to a mixed-wet condition by aging with crude oil to represent the natural configuration in an oil reservoir with fast synchrotron-based X-ray computed tomography. We find that the pore-scale flow regime is dominated by ganglion dynamics in which the pore space is intermittently filled with oil and brine. The frequency and size of these fluctuations are greater than in water-wet rock such that their impact on the overall flow and relative permeability cannot be neglected in modeling approaches.