Around 55%, or 3 Tbbl, of the world’s total conventional oil resources have so far been left untouched as current technologies are not advanced enough to reach them. At the same time, the rate of replacement of the produced reserves by new discoveries has declined steadily over the last decade. As a result, optimizing mature oil fields through the use of EOR technologies presents a profitable opportunity for oil companies.

In this study, different chemical EOR techniques (such as polymers, surfactants and low-salinity waterflooding) have been tested in a turbiditic oil field offshore, with a medium-heavy gravity oil and a high formation water salinity of between 80,000 parts per million (ppm) to 90,000 ppm. Repsol is developing new technologies to increase the field recovery factor and will carry out a field pilot test to demonstrate these technologies and to extend their application to other areas of the field.

The investigations are supported by chemical screenings and lab core flood at reservoir conditions with rocks and fluids from each reservoir. The investigation is indicated clearly in the case study, and the promising techniques are lowsalinity water and polymer floodings. These show an increment of the recovery factor between 15% and 25% of stock tank oil initially in place at laboratory scale above waterflooding. The case study also describes the basic methods used in numerical simulation at the lab core level and the scale-up parameters required at field scale simulation to determine the best EOR strategy.

Range of applications
The average recovery factor (RF) of light and medium crude oil deposits is around 30% to 35% after conventional recovery. Figure 1 shows that a tertiary step can be added to increase the amount of oil recovered through various EOR technologies and indicates the range of applications of EOR technologies based on viscosity, depth and lithology with more than 1,500 projects being evaluated.

In general, thermal methods apply for heavy crudes, and gas and chemical injections apply more for light and medium crudes. To increase the RF, the most appropriate EOR technology must be used. This requires a detailed evaluation of the reservoir and fluid characteristics and the identification of production mechanism. In this context, parameters such as viscosity, mobility ratio and residual oil saturation (ROS) are critical for the effectiveness of EOR.

Typically, steam and miscible gases impact viscosity and ROS, while polymers improve the mobility ratio and sweep efficiency but do not impact the ROS. Usually, the RF increase in chemical EOR projects is between 5% and 10% for polymers and between 10% and 20% for surfactant projects. The operating costs of polymer EOR ranges between $1.50/bbl and $4/bbl of incremental oil recovered. Meanwhile, the cost of surfactant-polymer and alkaline-surfactant-polymer projects ranges from $4/bbl to $8/bbl of incremental oil recovered.

In addition, the quality of commercial chemicals such as polymers and surfactants has dramatically improved, and the ratio of chemicals/crude oil prices has drastically decreased.

EOR technology screening
The case study explores deepwater to evaluate the feasibility of increasing production and the RF with the use of EOR technology. The aim is to determine at field scale the best EOR technology through a pilot test in a selected area of the reservoir. To assess the potential EOR technologies that may be used in this case study, a prescreening methodology using average properties based on a pass/no-pass gate was used.

The reservoir is a turbidite at a depth of 2,300 m (7,545 ft), with a pressure of 2,650 psi, temperature of 54 C (129 F) and very high-salinity production water. The crude oil is medium-heavy from 16°API gravity to 22°API. Viscosity is between 7 centipoise (cp) and 22 cp at reservoir conditions, and the water table is between 800 m and 1,500 m (2,625 ft and 4,921 ft). The EOR pre-screening results are shown in Figure 2, where technologies that may be applied include EOR chemical
processes and gas injection. However, as gas availability in the field for reinjection is limited, this option was not considered. Steam injection was not applicable because of the high pressure and depth.

Program, field pilot modeling
EOR laboratory water and chemical core flood experiments have been conducted using core plugs and oil samples from the field to assess the feasibility of increasing its RF. Core plug samples have air permeability ranging from 2,123 millidarcy (mD) to 3,434 mD and porosity from 29% to 35.1%. All core samples selected were prepared by restoring them to their native wettability condition in the reservoir. Formation brine salinity for the plugs’ restoration was 86,000 ppm of sodium chloride.

Two stacks of four plug samples each were mounted to conduct the core displacement tests. The oil from the reservoir shows 20°API, high total asset number and dead oil viscosity of 47 cp at 54 C. The injection water available in the platform is
desulfide seawater. Chemical screening outside the porous medium was performed to select the best formulation (polymer, surfactant/polymer and crosslinked polymer [CLP]) for a chemical EOR process.

Conventional polymer has been selected for working at high salinity as well as CLP that generates its properties as polymer inside the reservoir at high temperature but shows low viscosity during preparation and injection. Three different surfactants were evaluated with an interfacial surface tension close to 10-2 to 10-3 Dynes/cm at a concentration of 2,000 ppm into brine.

Polymer, CLP and low-salinity water (LSW) have demonstrated their technical feasibility as potential chemical EOR methods at field case conditions. LSW has shown very good results, increasing oil recovery by more than 15.5% when compared to the brine injection. Meanwhile, with 4 pore volume (PV) of polymer (1,000 ppm and 2,000 ppm), 14.5% incremental oil recovery has been obtained.

CLP incremental oil recovery was 8.8% but with only 1-PV 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. A good match of an
experimental displacement test was obtained using a CMGSTARS program.

The incremental oil recovery factor of the pilot area was 7.4% for LSW, 6% for CLP, 5.4% for polymer and 6.9% for surfactant
polymer for the pilot area. The cost of chemicals per incremental barrel shows the lower value with $2/bbl for CLP, $3.50/bbl
for polymer and $6.50/bbl for surfactant polymer. No chemicals have been injected with the LSW due to the limited space
available on the platform to install the required equipment to desalt the seawater.

Results
For the experimental program, the main results were:
• Selected surfactants were able to reduce the interfacial tension, but the additional recovery is marginal when compared with the cost of the chemical;
• CLP and conventional polymer present a promising performance in mobility control under reservoir conditions; and
• Synergy effects were observed for LSW-polymer and LSW-CLP. Additional research needs to be carried out to optimize these phenomena.

The experiments obtained key results that were used to improve the modeling and support the scale-up from the lab to the field. Field simulation results showed that the most promising techniques are the CLP, polymer and LSW. CLP has increased RF of 6% over waterflooding with an injected chemicals cost of $2/bbl of incremental oil. Polymer has incremental RF of 5.4% and a chemicals cost of $3.50/bbl of incremental oil. LSW has resulted in incremental RF of 7.4% without chemicals injected; however, additional surface facilities in production platforms and capex need to be evaluated further.

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