Stimulation method and system for enhancing oil production

Abstract

A method of recovering in situ hydrocarbons from a subterranean formation includes injecting a volume of fluid with composition comprising 0.01 mass % or more of at least one ketone and 50 mass % or more of water into an injection well completed in the subterranean formation; and producing at least a fraction of the injected volume of fluid and in situ hydrocarbons from the subterranean formation through a production well completed in the subterranean formation. A hydrocarbon recovery system includes an injection apparatus connected to a well formed in a subterranean formation and a storage container in fluid communication with the injection apparatus. The container includes the at least one ketone and water.

Description

BACKGROUND OF THE INVENTION[0001]1. Field of the Invention[0002]The present invention is directed to a stimulation method and system for enhancing oil production.[0003]2. Description of Background Art[0004]Over the years, enormous strides in various oil extraction and oil recovery (also referred to as “oil production”) methods have been achieved, ranging from improved oil recovery methods (also known as IOR), incorporating technologies such as water injection into subterranean oil bearing formations, to enhanced oil recovery (“EOR”) methods, incorporating technologies such as gas injection into subterranean oil bearing formations.[0005]Mature EOR technologies include gas injection based methods, microbial based methods, chemical based methods, and thermal based methods. Thermal methods and gas injection are the two most commonly applied EOR technologies commercially. Thermal methods include technologies such as Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS...

AI Technical Summary

Benefits of technology

[0017]According to a further embodiment, the present invention is directed to a method of altering the wettability of a subterranean formation containing in situ hydrocarbons, the method comprising the steps of: injecting a volume of fluid with a composition comprising 0.01 mass % or more of at least one ketone and 50 mass % or more of water into an injection well completed in the subterranean formation, wherein the subterranean formation is comprised of at least 10 mass % carbonate rock, thereby contacting the carbonate rock of the subterranean formation with at least a fraction of the injected volume of fluid; and permitting the injected volume of fluid to reside for a period of time in the subterranean formation.

Problems solved by technology

Horizontal drilling results in increased reservoir contact with the production well.

These high rates result in substantial pressure drops through the well due to friction.

Another challenge with hydraulic fracturing is effectively transporting and placing proppant.

It is largely accepted that low viscosity fluids create more complex fracture networks with more effective connectivity to the formation, but these fluids cannot effectively transport or place proppant deep in the formation.

Oil production rates from such reservoirs under primary depletion often dramatically decline, resulting in oil rates that are only a small fraction of the initial production rates in a relatively short time.

Oil recovery is further impeded by large water cuts (that is, the ratio of water produced in comparison to the total volume of liquids produced) during primary depletion, which can range upwards of 80% in some cases.

This presents several problems with efficiently recovering oil from the reservoir.

First, many of these reservoirs are hydraulically stimulated to maintain pressure, increase their production potential, and open up access to additional parts of the formation; however, this stimulation often injects large volumes of water, which do not readily imbibe into oil-wet or mixed-wet ultra-tight formations.

Currently, some chemicals may be injected along with the hydraulic fracturing fluid, but they are in large part in very low concentrations, and likely have a minimal impact on a vast majority of the formation's wettability.

Surfactants, while effective, are also expensive compared to some other chemicals.

They also have a propensity to adsorb to the rock surface, which does not necessarily utilize the surfactant most effectively and they have potential to degrade with time, shear, and temperature.

In addition, there is a challenge in the industry to improve the predictive capability of hydrocarbon recovery, including finding relations between surface chemistry, wettability, capillary pressure, and relative permeability.

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