Abstract

To increase productivity from crude oil reservoirs, carbondioxide (CO2) is usually injected during secondary and/or tertiary recovery. While CO2 injection significantly increases the amount of oil recovered, it causes asphaltene deposition at high concentrations. However, the presence of water reduces the extent to which asphaltene is precipitated. Thus, the aim of this report is to determine why the presence of water reduces the amount of asphaltenes precipitated during CO2 injections. Results from CT scan data on water and gas injections are also provided and are accompanied with scanned images.

Introduction

In attempts to improve the amount of oil produced, CO2 and light hydrocarbon gases are used as injection and reservoir pressure maintenance fluids. Heavy organic (asphaltenes, resins and waxes) depositions are usually encountered in Enhanced Oil Recovery (EOR) or Improved Oil Recovery (IOR) processes when these gases are used as injection fluids. Analytical data suggest that asphaltenes can precipitate in CO2/crude oil mixtures within the reservoir. The extent of deposition depending on the crude oil, brine, formation rock compositions and also whether reservoir conditions favor multiple - contact miscibility[1]. Asphaltene precipitation causes plugging of pore throats in the reservoir, reducing core permeability and the anticipated rate of production. In addition, CO2 causes considerable effects on reservoir fluids (formation water and crude oil) and reservoir rocks. Figure 1illustrates the various effects of CO2 on crude oil reservoirs. As shown in the figure, CO2 reacts with formation or saline water containing carbonates to precipitate calcite (CaCO3). CO2 can also react with water to form the bicarbonate ion (HCO3-) which has the potential to dissolve calcium containing minerals in reservoir rocks to produce calcium ion (Ca2+) which further react with excess CO2 to precipitate calcite[4]. Calcite precipitation in reservoir formations leads to "fines migration" which in turn causes pore blockages. Asphaltene precipitation also leads to rock wettability reversal in reservoir rocks.

Thus, the adverse effects of both calcite and asphaltene precipitation jointly lead to permeability reduction and subsequently reduction in anticipated rate of production.

Organic depositions are also observed within production tubings at depths corresponding to the bubble pressure of the produced crude oil. This implies that as the reservoir depletes with subsequent loss of reservoir pressure, asphaltene deposition extends further down due to phase separation. This makes it difficult to remove the deposits chemically or mechanically. This situation can be remedied by injecting gas (CO2 or natural gas) into the reservoir to increase the reservoir pressure. This in turn reduces the depth at which asphaltene precipitate along the tubings. Thus, facilitating chemical and mechanical cleaning along the oil well3. Asphaltene deposition also leads to production problems like; seizure of downhole valves, submersible pumps and hindrance in wire line operations leading to production restrictions[2]. While asphaltene precipitation in tubings is easily solved as described above, no reliable solution has been developed to solve asphaltene deposition in crude oil reservoirs. Therefore, it is necessary to develop techniques to increase oil recovery while reducing asphaltene deposition in the reservoir.

It is common for researchers to focus on physical parameters such as mobility ratio (M) and interfacial tension (IFT) to describe the effect of the presence of water during tertiary recovery with CO2. A more holistic approach is to include the chemical characteristics of formation water that influence the recovery process. Formation water is unique in that it acts as a buffer by dissolving CO2 thus reducing the available gaseous concentration. Andersen (2003) found that when natural gas, another common injectant, was used asphaltene flocculation in ASH77 crude oil was not reduced[7].

This paper addresses the chemical influence of formation water in decreasing the rate or amount of asphaltene deposited during CO2 injection and suggests the relevant parameters necessary to determine the formation type that is appropriate for CO2 injection.

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