TECHNICAL FIELD

Example embodiments relate to methods and systems for determining residual fluid saturation of subsurface formations.

BACKGROUND

Subterranean reservoirs of hydrocarbons, e.g., oil and natural gas, are typically found trapped in permeable subsurface geological formations beneath a layer of impermeable geological formation. In order to estimate the amount of reserves, injectivity, productivity, and to make ultimate-recovery predictions of the hydrocarbon reservoirs, certain petrophysical properties of the subterranean reservoir such as irreducible water saturation, residual oil saturation, capillary pressure, and relative permeability must be determined. Normally, these petrophysical properties are determined by taking core samples from the reservoir and carrying out well-defined measurement techniques on the samples.

Core flooding experiments play a very important role in the measurement of petrophysical properties describing the fluid flow in oil and gas reservoirs. During a conventional core flooding experiment, a cylindrical core is saturated with water or brine, then oil flooded to irreducible water saturation. Subsequently, the core is water flooded or brine flooded and the pressure drop across the core is measured along with the oil and water or brine production. The average fluid saturations within the core are determined from the overall material balance. Similar experiments can also be carried out for gas flooding and enhanced oil recovery (EOR) processes where the core is being flooded by a gas and an EOR agent, respectively.

Capillary end effect can have a significant impact on data acquisition and interpretation of core flooding experiments because it can cause errors in the calculation of saturation and relative permeabilities from pressure drop and production data. Capillary end effects originate from the discontinuity of capillarity at the outlet end of the core sample. The outlet of the core is characterized by a zero capillary pressure which can trap wetting phase in a region near the outlet of the core, potentially leading to a wrongful estimation of parameters. Capillary end effects commonly appear in core flooding processes of oil displacing water in water-wet cores, water displacing oil in oil-wet or mixed-wet cores, and gas-displacing-oil cases. In other displacement processes, capillary end effects are less pronounced than these processes. Experiments of oil displacing water in a water-wet core, or a drainage process, are important, because they establish the end-point oil relative permeability at the irreducible water saturation, which is the starting point of a water flooding (or an imbibition) process. Experiments of water displacing oil in oil-wet or mixed-wet cores are extremely important because they represent water flooding in oil reservoirs, and water flooding is the most common oil recovery method in oil reservoirs. Experiments of the gas-displacing-oil cases are also important, because they represent pattern gas injection and crestal gas injection in oil reservoirs. Capillary end effects in core flood experiments, in some cases, can significantly influence the computation of end-point relative permeabilities and final fluid saturation levels.

SUMMARY

Residual fluid saturations such as residual oil saturation and irreducible water saturation are often determined by core flooding experiments in the laboratory. However, the determined residual oil saturation and irreducible water saturation are often not representative of the reservoir. Because the size of rock core sample is much smaller than the size of a reservoir and an artifact from end effect is induced due to the capillary discontinuity at the outlet end of the rock core sample, without proper correction, the capillary end effect artifact can introduce significant error in residual fluid saturations which has a major impact on evaluating the performance efficiency of different recovery technologies.

In the present disclosure, several methods are disclosed for determining the capillary end effect corrected and reservoir representative residual fluid saturation, such as residual oil saturation during water flooding, gas flooding, and enhanced oil recovery processes, as well as irreducible water saturation during oil displacing water process. The proposed methods include conducting core flooding experiments in steps of increasing injection rate and measuring stabilized average remaining fluid saturation of displaced fluid and differential pressure across the rock core sample for each of the different injection rates. The measured experimental data can be applied using the proposed mathematic formulas and linearly fitted to determine the more realistic residual fluid saturation by the disclosed methods. The disclosed methods can be widely applied to core flooding experiments using a single core or a composite core in the laboratory for determining reservoir representative residual oil saturation and irreducible water saturation.

One example embodiment is a method for determining residual fluid saturation of a subsurface formation includes acquiring a preserved core sample of the oil-bearing subsurface formation, determining a first residual oil saturation during a water flooding process, determining a second residual oil saturation during a gas flooding process, determining a third residual oil saturation during an enhanced oil recovery (EOR) processes, and determining irreducible water saturation during an oil displacing water process.

