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.

First discovery of nano-pore throat in oil and gas reservoir in China and its scientific value

Abstract: The oil and gas reservoirs have been divided in three types: Millimeterpore,micropore and nanopore.The diameter of pore throat in conventional reservoir is generally larger than one micron.The diameter of nano-pore in shale gas reservoirs ranges between 5 and 160 nanometers in North American,mainly from 80 to 100 nanometers.Based on the field emission SEM and the nano CT reconfiguration technique,it was the first discovery of nano-pore in research of unconventional tight sandstone and shale gas reservoir in China,whose diameter is less than one micron.The nano-pore in tight sandstone gas reservoirs is mainly of grain micropore,authigenic mineral intragranular pore and microfracture,throat is sheetlike,bended platy,has poor connectivity and its diameter ranges between 10 and 1000 nanometers,mainly from 300 to 900 nanometers.The nanopore in shale gas reservoirs is mainly of organic matter nanopore,grain nanopore and authigenic mineral intragranular pore,and its diameter ranges between 5 and 300 nanometers,mainly from 80 to 200 nanometers.The nanopore is main body of connectivitive reservoir space in tight reservoirs.The discovery of nano-pore system within oil and gas reservoir has changed the traditional understanding that the micron-pore is exclusive.It also provided the significant scientific value with understanding geological characteristics of conventional oil and gas local accumulation,unconventionally continuous petroleum accumulation,develop petroleum accumulation mechanism and increase the potential of resources.

Basin-Floor Fans in the North Sea: Sequence Stratigraphic Models vs. Sedimentary Facies

Abstract: Examination of nearly 12,000 ft (3658 m) of conventional core from Paleogene and Cretaceous deep-water sandstone reservoirs cored in 50 wells in 10 different areas or fields in the North Sea and adjacent regions reveals that these reservoirs are predominantly composed of mass-transport deposits, mainly sandy slumps and sandy debris flows. Classic turbidites are extremely rare and comprise less than 1% of all cores. Sedimentary features indicating slump and debris-flow origin include sand units with sharp upper contacts; slump folds; discordant, steeply dipping layers (up to 60°); glide planes; shear zones; brecciated clasts; clastic injections; floating mudstone clasts; planar clast fabric; inverse grading of clasts; and moderate-to-high matrix content (5-30%). Many f the cored reservoirs either have been previously interpreted as basin-floor fans or exhibit seismic (e.g., mounded forms) and wireline-log signatures (e.g., blocky motif) and stratal relationships (e.g., downlap onto sequence boundary) indicating basin-floor fans within a sequence stratigraphic framework. This model predicts that basin-floor fans are predominantly composed of sand-rich turbidites with laterally extensive, sheetlike geometries. However, calibration of sedimentary facies in our long (400-700 ft) cores with seismic and wireline-log signatures through several of these basin-floor fans (including the Gryphon-Forth, Frigg, and Faeroe areas) shows that these features are actually composed almost exclusively of mass-transport deposits consisting mainly of slumps and debris flo s. Distinguishing deposits of mass-transport processes, such as debris flows, from those of turbidity currents has important implications for predicting reservoir geometry. Debris flows, which have plastic flow rheology, can form discontinuous, disconnected sand bodies that are harder to delineate and less economical to develop than deposits of fluidal turbidity currents, which potentially produce more laterally continuous, interconnected sand bodies. Our core studies thus underscore the complexities of deep-water depositional systems and indicate that model-driven interpretation of remotely sensed data (i.e., seismic and wireline logs) to predict specific sedimentary facies and depositional features should proceed with caution. Process sedimentological interpretation of conventional cor is commonly critical for determining the true origin and distribution of reservoir sands.

Oil and Gas Migration--Chemical and Physical Constraints

Abstract: Primary migration of oil in aqueous solution is not possible because the composition of dissolved hydrocarbons is vastly different from that of crude oils. Migration of oil solubilized in surfactant micelles is also rejected because of the large amount of surfactant required, and because there has been no demonstration that micelles are formed in source rocks. Migration by oil-droplet expulsion also is not feasible, because of the high interfacial forces of small droplets within fine-grained source rock; in addition, at least 7.5% organic matter by volume would need to be converted to oil to attain 30% oil saturation required for separate-phase flow; even higher oil saturations would be required for "squeezing" oil from pores. It is proposed that oil and gas are generated in, and flow from, source rock in a three-dimensional organic-matter (kerogen) network. Oil or gas flowing in this hydrophobic network would not be subject to interfacial forces until it entered the much larger water-filled pores in the reservoir rock. Oil saturation in the kerogen for oil flow to occur is indicated to be from 4 to 20%. Secondary migration of separate-phase oil and gas should occur by buoyancy, when their saturations attain 20 to 30% along the upper or lower surfaces of the reservoir rock. Oil or gas entering at the lower surface would intermittently cross the rock when the buoyancy head became sufficient. Efficient migration from source to trap could then occur as rivulets along the upper few centimeters in the reservoir rock. The volume of conducting reservoir rock attaining oil or gas saturation during secondary migration should be small, with most of the pores remaining water filled. In contrast, secondary migration of gas or oil in solution would be very inefficient and require large volumes of water. Unless all pores in the reservoir rock attained 20 to 30% gas or oil saturation, separate-phase flow could not occur, and oil and gas would remain locked in the pores and would not form reservoirs in trap positions. Attaining a 30% pore volume (PV) gas or oil saturation would require a flow of about 90 to 200 PV of gas-saturated water, and 15,000 to 200,000 PV of oil-saturated water. Residual gas and oil in cores taken along suspected secondary-migration pathways should show this residual gas or oil saturation, and recovered water should always contain equilibrium concentration of dissolved hydrocarbons, but this has seldom been observed. The proposed mechanisms of primary migration of oil and gas through a kerogen network, and secondary migration by separate-phase buoyant flow do not require the flow of water. Water flow probably disperses water-soluble constituents instead of concentrating them in reservoir traps.

Fluid flow and sand production in heavy-oil reservoirs under solution-gas drive

Abstract: The production of heavy oil in Canada has led to a number of anomalous results, most of which have been excused as high-permeability channels resulting from sand production. The methods of soil mechanics predict gross formation failure resulting from high fluid compressability, small cohesion, and high viscosity. Gross failure results in excellent productivity but reduced in-situ stress (and fracture stress). Solution-gas drive in these reservoirs involves simultaneous-mixture flow of a gas as very tiny little bubbles entrained in heavy oil. Stress, geometry, and permeability alteration resulting from matrix deformation combined with peculiar pressure-depended multiphase-flow properties result in a new model of reservoir performance. A field observation of stress modification is discussed, as are the contributions of the four components discussed previously to the observed phenomena.