Álvaro Fernández, Repsol-Sinopec Brasil; José Guitián, and Sonia Embid, Repsol Technology Center
According to the most recent International Energy Agency (IEA) World Energy Outlook, global energy demand is set to grow by 37% by 2040. In an effort to find solutions to meet this increasing demand, operators are turning to solutions such as enhanced oil recovery (EOR) technologies that have played a crucial part in optimizing mature oil fields and increasing their recovery factor (RF).
EOR processes are defined as the injection of fluids into the reservoir in order to reduce the residual oil saturation and increase the oil recovery factor. The most common EOR recovery processes are the injection of thermal fluids, such as steam, to reduce the viscosity of heavy oils into the reservoirs; as well as the injection of water soluble chemicals such as polymer, surfactant and alkali to improve the recovery factor mainly in medium and light oil reservoirs.
The average recovery factor of light and medium crude deposits after conventional recovery lies at around 30% to 35%. Figure 1 shows that a tertiary step could be added to increase the percentage of oil recovered with the help of various EOR technologies. It is estimated that current technologies might have the potential to increase conventional crude oil recovery by 15% to 30%. Hence, developing and investing in EOR technologies will continue to play an important role in slowing down the decline of conventional oil production.
Figure 1. Typical range of EOR technologies application.
In a recent study carried out by Repsol, different chemical EOR techniques, such as polymers, surfactants and low-salinity water flooding, have been tested in a turbiditic oil field offshore, with a medium-heavy oil gravity crude and a high formation water salinity between 80 000 and 90 000 ppm.
The aim of the study was to evaluate the feasibility of increasing oil production as well as the recovery factor by using EOR technology. In order to determine which EOR technologies would be suitable for the case study, a pre-screening methodology using average properties based on a Pass/No Pass gate was used.
The reservoir used in this pilot study was a turbidite at a depth of 2300 m, 54°C, with a pressure of 2650 psi, with very high salinity production water (60000 - 70000ppm NaCl, 300 – 1500 ppm Ca++, 200 – 750 ppm Mg++). The crude oil shows 16° to 22° API gravity, with viscosity between 7 and 22 cP at reservoir conditions and water table between 800 and 1500m. Figure 2 shows the EOR pre-screening results and technologies that may be applied including EOR chemical processes and gas injection.
Figure 2. EOR case study pre-screening results.
Water and chemical core flood experiments have been conducted using core plugs and oil samples from the field to assess the feasibility of increasing the RF. Core plug samples have air permeability ranging from 2123 to 3434 mD with a porosity between 29.0% and 35.1%. All selected core samples were prepared by restoring them to their native wettability condition in the reservoir.
Experimental core flooding at our field condition indicated that Polymer (P), Cross Linked Polymer (CLP) and low salinity water (LSW) have demonstrated their technical feasibility as potential chemical EOR methods. LSW in particular has shown a very relevant result as it has increased oil recovery by more than 15.5% when compared to the brine injection. In addition, with 4PV of polymer (1000 ppm and 2000 ppm), oil recovery has been increased by 14.5%. CLP incremental oil recovery was 8.8% but with only 1PV CLP slug (600 ppm), resulting in a more effective chemical than the conventional polymer. CLP in brine followed by LSW recovery has been 18.7%. LSW followed by polymer shows an incremental recovery of 27.3%, which is much higher than the conventional polymer and brine.
This study showed that selected surfactants were able to reduce the interfacial tension, but the additional recovery was marginal when compared with the cost of the chemical. CLP and conventional polymer present a promising performance in mobility control under reservoir conditions. Moreover, synergy effects were observed for LSW-Polymer and LSW-CLP, but additional research is needed in order to optimize these phenomena. The experiments conducted obtained key results that were used to improve the modeling and support the scale-up from the lab to the field.
Figures 3 & 4 show the structure of the dynamic model (25875 blocks) of the pilot selected area and the summary of the chemical EOR simulation results. The incremental oil recovery factor of the pilot area has been 7.4% for LSW, 6.0% for CLP, 5.4% for P and 6.9% for SP for the pilot area. The cost of chemicals per incremental barrel shows the lower value with US$2.0/bbl for CLP, US$3.5/bbl for P and US$6.5/bbl for SP. No chemicals have been injected with the LSW, but limitation of this process for an offshore facility is the availability of space in the platform to install the required equipment to desalt the sea water.
Figure 3 Structural model of the pilot area.
Figure 4. Chemical EOR simulation results.
Those results indicate the potential value to apply Chemical EOR on offshore reservoirs considering the operation conditions and the space limitations on platforms.
Adapted for OilfieldTechnology.com by David Bizley