Enhanced Oil Recovery Engineering Services

EOR Process Overview

Carbon dioxide (CO2) injection is considered to be the most promising enhanced oil recovery (EOR) technique in the near future because it not only greatly enhances oil recovery but also considerably reduces greenhouse gas emissions. CO2 EOR has gained tremendous momentum in the oil and gas industry due to its potential for mitigating greenhouse gas emissions. It has been found that CO2 EOR processes can enhance oil recovery by 8-16% (based on the original oil in place (OOIP). It is estimated by the U.S. DOE that about 80% of oil reservoirs worldwide might be suitable for CO2 injection based on the oil recovery criteria alone.

HTC has been developing techniques that will increase oil recovery and subsequently CO2 storage in a CO2 injection process and has the trained personnel that can provide the following EOR engineering services:

Initial screening reservoir candidates for CO2 EOR and storage

In general, CO2 is not miscible at first contact with reservoir oils but may achieve dynamic miscibility through multiple contacts. CO2 injection can be very efficient in improving oil recovery, especially when miscibility develops during the displacement processes. The lowest pressure at which CO2 should be injected into the reservoir to obtain multi-contact miscible displacement is termed the minimum miscibility pressure (MMP). By using the oil recovery screening criteria, including residual oil saturation and MMP, suitable reservoir candidates are selected for implementing CO2 EOR and storage.

Reservoir characterization

Once a reservoir candidate is found to be suitable for CO2 EOR and storage, the reservoir needs to be well characterized. HTC has techniques which can be used to characterize the reservoir in terms of geological structure including cap and base rock integrity, heterogeneity and continuity, production history, oil concentration, and reservoir temperature. This task is to make sure the reservoir is not only sound for CO2 EOR, but also allows maximization of CO2 storage capacity with consideration of factors pertaining to protection of the environment as well as the health and safety of the public.

Reservoir Engineering

Reservoir fluid characterization and phase behaviour

Phase behaviour is a critical factor in determining both oil recovery and displacement efficiency by CO2 injection and the suitability of a reservoir for storing CO2. In particular, the MMP and minimum miscibility composition (MMC) are key parameters affecting oil recovery, which can be determined by using the available slim tube method. Furthermore, experimental determination of the MMP and MMC are to be used in building equation of state model for accurate EOR performance evaluation. Also, the oil viscosity reduction, oil swelling effect, and CO2-induced asphaltene precipitation can be accurately quantified under high pressures and elevated temperatures with our existing PVT facilities.

Measurement of interfacial tension, wettability, and diffusion coefficient

Interfacial tension is one of the most important factors that causes over one-third of the total oil in place to be unrecoverable by gas drive or waterflooding alone. Low interfacial tension decreases the residual oil saturation so as to create the conditions for enhancing oil recovery. Wettability has a dominant effect on the distributions of phases and can cause dramatic change in the displacement mechanisms. The diffusion coefficient (i.e., diffusivity) of CO2 in either the crude oil or the reservoir brine at high pressures and elevated temperatures becomes the most important parameter in determining the mass transfer rate of CO2 in crude oil/reservoir brine under reservoir conditions. A state-of-the-art experimental setup has been established to accurately determine the interfacial tension, wettability, diffusion coefficient, and interface mass transfer coefficient at high pressures and elevated temperatures. It has been found that the measured interfacial tension, wettability, diffusion coefficient, and interface mass transfer coefficient changed significantly when CO2 is dissolved in the crude oil and/or reservoir brine under reservoir conditions.

Determination of relative permeability

Relative permeability is a direct measure of the ability of the porous system to conduct one fluid when one or more fluids are present. The existing rock-fluid centrifuge will allow us to measure relative permeability in CO2 EOR and storage processes at high pressures and elevated temperatures.

Determination of the onset of CO2-induced asphaltene precipitation and aggregation

Asphaltene precipitation can be induced from the crude oil once it has come into contact with CO2 at a constant threshold pressure and temperature. The precipitated asphaltene may block the pore spaces, reduce permeability and thus adversely affect oil recovery and subsequent CO2 storage. HTC has the capabilities for determining the onset of asphaltene precipitation and aggregation of asphaltene.

Near-wellbore conformance control

The near-wellbore conformance is a key for the fluid to be injected into the injection well to achieve high sweep efficiency and into production well to avoid early breakthrough. HTC has expertise and techniques that can be used to block and seal off high permeability zones and to improve the mobility of the injected agents for achieving high oil recovery.

Reservoir simulation

Reservoir simulation is still the most flexible and widely used tool in reservoir engineering. By using reservoir simulation, reservoir engineers can use the behavior of a reservoir model to represent or approximate the behavior of the true reservoir. The accuracy of reservoir simulation strongly depends on the reservoir geological model used in the simulation process. In order to improve the reliability of the reservoir geological model, history matching is generally employed to calibrate the geological model in terms of the field performance data. HTC has developed techniques to generate multiple solutions for history matching and to dynamically update the reservoir geological models that are much more geologically realistic, and thus the accuracy of reservoir simulation can be significantly improved.

Co-optimization of CO2 EOR and storage

It has been well-accepted that the water-alternating-CO2 process can achieve a higher oil recovery factor than continuous CO2 flooding or water flooding alone. However, the water-alternating-gas (WAG) process creates a considerable challenge in maintaining injection rates. Oil response in the WAG area is slower, but the CO2 production is also lower compared to the continuous injection areas. CO2 storage is implemented after the reservoir life is ended for oil recovery in a CO2 injection process. This is contradictory to the existing commercial CO2 EOR projects in which the main purpose is to maximize oil recovery with a minimum amount of CO2. For a CO2 storage process, we need to maximize the CO2 storage capacity and to consider factors pertaining to protection of the environment as well as the health and safety of the public. HTC has expertise for determining the optimal WAG slugs and alternating time. In addition, HTC is developing techniques for co-optimizing CO2 EOR and storage under uncertainty.

Production Operations

Reservoir monitoring and performance control

Successful CO2 EOR and CO2 storage processes result from continuous monitoring and control over the reservoir performance. Techniques available for monitoring the CO2 EOR and storage processes include the pressure monitoring method, geochemical methods (tracer survey), geophysical methods (3D and 4D seismic), and electrical methods. Usually, in situ downhole pressure gauges are preferred in the pressure monitoring process. As for tracer survey, sampling fluids from producer or the atmosphere in the CO2 EOR or CO2 storage reservoir will provide value information about the migration rate of the tracer, well connectivity, and caprock leakage. By performing careful high-resolution 3D seismic surveys before and after CO2 injection, it is possible to obtain a time-lapsed picture of the movement of fluids in the subsurface (this type of imaging is called 4D seismic in which the added dimension is time). At present, 4D seismic becomes a powerful tool for monitoring reservoir performance because 4D seismic provides unique spatial and temporal information of the reservoir. HTC is now developing techniques that can be used to integrate reservoir monitoring and surveillance data with reservoir simulation for improving reservoir characterization, history matching, production prediction and optimization, and reservoir management.

Corrosion prevention and treatment

CO2 will react with the pipeline once it is mixed with water, which is an inevitable issue. HTC can provide cost-effective batch and continuous corrosion inhibitors for preventing and treating corrosions. In the autoclave test, it is found that these two types of corrosion inhibitors showed a protection of 95% or better as compared to the blank coupon method.

CO2 recycling and re-injection

Since CO2 is always recycled and reinjected with the produced hydrocarbon gases in the reservoirs, the MMC is the key parameter that needs to be reevaluated and optimized. HTC has experimental techniques to determine and optimize the MMC for a given CO2-hydrocarbon gas-crude oil mixture. This will ensure the CO2 EOR is a miscible or near-miscible process for achieving high oil recovery.