Affiliation:
1. Sultan Qaboos University
Abstract
Abstract
To increase capillary imbibition recovery rate and deplete matrix oil efficiently, surfactant and polymer solutions can be injected into naturally fractured reservoirs. Laboratory experiments are needed to understand the response of the reservoir rock and fluids to these applications and a scale-up process is required to quantify the recovery for reservoir conditions before injecting these expensive fluids.
This study tests the existing capillary imbibition scaling-up formulations in literature and proposes modifications to them for surfactant and polymer injection applications. Laboratory tests were performed using Berea Sandstone cores with different shapes, sizes and boundary conditions. The rock samples were surface-coated to create many different boundary conditions causing co- or counter-current imbibition or both. Kerosene, engine oil, mineral oil and crude oil were selected as the oleic phase. Brine and two different concentrations of surfactant and polymer solutions were the aqueous phase types. The capillary imbibition recovery curves were then used to test the existing scaling formulations.
It was observed that the scaling groups were applicable with certain modifications to the co-current flow of surfactant and polymer solution-oil pairs as well as the brine-oil cases. Modifications to the Mattax and Kyte's scaling group for the capillary imbibition of high IFT fluids (brine-oil and polymer solution-oil experiments) were introduced for the matrix boundary conditions, oil viscosity and wettability. In case of co-current flow, the gravity forces dominate recovery for low IFT experiments and modification to the gravity scaling group for the boundary conditions is required. For counter-current flow, however, the scaling groups were observed inapplicable even after the modifications.
Introduction
When the matrix part of a naturally fractured reservoir (NFR) contains great amount of oil, enhanced oil recovery methods are aimed to recover this oil effectively. Matrix-fracture interaction is required for matrix oil recovery and capillary imbibition is the underlying mechanism if the matrix is water wet and enough amount of water is supplied in fracture network.
The capillary suction of water by matrix and expelling the oil simultaneously is a phenomenon governed by numerous parameters. Matrix permeability1–4, size and shape1,3,5–7 wettability8–12, heterogeneity2,8,13, and boundary conditions3,5–7,14,15 determine the rate of the oil recovery. The properties of imbibing water16, viscosities of the phases11,12,17–19 and interfacial tension (IFT)3,15,20–23 also play a role on the capillary imbibition recovery rate. Mattax and Kyte1 first proposed a scaling equation for capillary imbibition based on the Rapoport's24 scaling laws. Later, modifications to Mattax and Kyte's scaling group were proposed3,5,6,11,12,23,25–27. Scaling equations for gravity dominated imbibition recovery were also provided for different purposes21,26–28.
On the other hand, under unfavorable conditions such as high oil viscosity, low matrix permeability, high IFT and unfavorable matrix boundary conditions, capillary imbibition recovery may be very slow and may also yield very high residual oil. Different methods can be applied to overcome these difficulties. Heat injection resulting in the reduction of oil viscosity and IFT11,12,29,30, injection of surfactant15,20–23 and polymer solutions18 have been tested in laboratory conditions previously for this purpose. Laboratory scale experiments showed that these methods yield an increase in ultimate recovery. Heat injection also gives rise an increase in the production rate. Hence, the applicability of these methods is proven but the existing scaling groups should be tested and modified, if necessary, for the field scale applications of chemical injection into NFRs. Under the tertiary recovery applications matrix fracture transfer due to capillary imbibition is more complicated than is with brine-oil pair. Additionally, the gravity forces could be effective depending on the boundary conditions and the type of injected fluid.