Pedro Diaz

Comparative Study of Polyacrylamide Co-polymers for EOR at High Salinity Conditions “Laboratory and Simulation"

Summary: The success of polymer flooding as a method of oil recovery has been attributed to a profile control mechanism of the displacing fluid (polymer solutions) related to the displaced fluid (crude oil), depending on properties such as polymer viscosity and its dependence with reservoir and flow conditions. The viscosity of polymer flow depends not only on the size of the molecules or molecular weight but it is further affected by salinity and divalent content on the brine used for the preparation of the polymer slug. The effect of salinity on polymer viscosity is more critical in presence of divalent ions Ca2+ and Mg2+ and high salinity conditions, which limits the use high salinity produced water for re-injection in polymer flooding processes where high salinity is involved. A series of salinity resistant polymers have been developed by incorporating co-monomers including hydrophilic and hydrophobic groups or combination of them along the chain of polyacrylamide which has made the viscosity behavior more complex and affected by ionic interactions both intra-molecular and inter-molecular. Therefore, an extensively screening process that includes evaluation of variables such as: stability of polymer solutions under salinity and ion composition, flow conditions and sensitivity analysis using simulation according to specific applications, is required for the selection of any specific system. A systematic comparative study of the screening of commercial partial hydrolysed polyacrylamide (PHPA), and co-polymers of acrylamide and hydrophobic modified Comb-polymers (HMPAM) under high salinity conditions is investigated. Synthetic high salinity and multi-component (with divalent ions) produced water from a North Sea reservoir was used on Bernheimer sandstone core samples using a crude oil from the North Sea with specific gravity 21 oAPI. Results from core flooding and rheology were matched to obtain required mathematical correlations to simulate core flooding experiments numerically and compare the efficiency of the different polymers. While polymers PHPA and co-polymers AM-AMPS and AM-nVP showed typical Newtonian behavior at low shear rates and non- Newtonian at high shear rates, HMPAM polymers have shear thinning behavior. Newtonian behavior on PHPA-3 seems to support its higher recovery factor comparing with PHPA-6 (higher MW). Viscosity of HMPAM solutions is more sensitive to changes of the polymer concentration and more sensible to flow conditions. Additionally, ionic interactions and steric effects in the co-polymers contribute the efficiency of the oil recovery at high salinity. Therefore, their viscosity behavior needs to be evaluated.

Application of Low Concentration Surfactant Enhanced Water-Alternating-Gas Flooding

Large amounts of oil left in the petroleum reservoir after primary and secondary enhanced oil recovery methods have brought about the implementation of several tertiary means of oil recovery. Increment of oil recovery can support the world’s oil supply. Water alternating gas injection has been a very popular method of gas injection to improving volumetric sweep efficiency. Although water alternating as injection has been shown to improve oil recovery, this process suffers inherent challenges such as water blocking, mobility control in high viscosity oil and gravity segregation. To combat these problems associated with water alternating gas flooding, the use of surfactant has been employed in water alternating gas injection. Due to the high operational cost arising from chemical cost in surfactant alternating gas injection, a new technique which involves the injection of low concentration surfactant before water alternating as flooding has been proposed. This work investigates experimental and numerical oil recovery potential of surfactant enhanced water alternating gas flooding. The distinctive feature of this technique is that instead of injecting surfactant slugs alternatively with gas, which will result to using a greater amount of surfactant, a low concentration surfactant is injected into the reservoir before water alternating gas flooding. The aim is to evaluate the performance of this technique as a low cost and effective means of chemically enhanced oil recovery by combining both mechanisms of surfactant reduction of water-oil interfacial tension and creation of foam with gas. This study begins with surfactant evaluation to characterise surfactants compatibility with reservoir brine and oil. Then followed by series core flooding experiments which include waterflooding, gas flooding, water alternating gas flooding and surfactant-enhanced water alternating gas flooding. Core flood data was history matched for water alternating as flooding and surfactant-enhanced water alternating as flooding via commercial simulator by inputting relative permeability curves, rock, fluid properties and interfacial tension. The results showed that experimentally, surfactant enhanced water alternating as flooding had the highest oil recovery when compared to conventional enhanced oil recovery methods. History matching of core flood experiment predicted similar increment in oil recovery during surfactant enhanced WAG. The effectiveness of this technique is based on the injection pattern after the initial surfactant injection and oil recovery potential is similar to that of surfactant alternating gas flooding.

Experimental study on the effect of inhibitors on wax deposition

A challenge facing offshore oil production is wax deposition. It leads to increases in operational and remedial costs while suppressing oil production. Wax inhibitors are one of the mitigation technologies that had been examined its influence on crude oil viscosity, pour point and wax appearance temperature (WAT). The performance of some of wax inhibitors was evaluated to determine their effects on the pour point, wax appearance temperature and the viscosity of the crude oil using the programmable Rheometer rig at gradient temperatures (55°C) and shear rate 120 1/s before and after adding 1000 ppm and 2000 ppm of inhibitors to the crude oil. Three different inhibitors which were not tested before were prepared in the lab of this study. These inhibitors works well compared with its original components. The first inhibitor was coded Mix01 by mixing polyacrylate polymer (C16-C22), and copolymer + acrylated monomers. The reduction of pour point of the waxy crude oil was up to a 16.6oC at 2000 ppm concentration and this reduces the crude oil viscosity to about 61.9% at a seabed temperature of 4oC. The second inhibitor was coded Mix02, by mixing polyacrylate polymer (C16-C22), alkylated phenol in heavy aromatic naphtha, and copolymer dissolved in solvent naphtha. At 2000 ppm, the reduction of pour point of the crude oil up to a 15.9oC and decreases the viscosity to 57% at a seabed temperature of 4oC. Finally, the third inhibitor was Mix03, by mixing polyacrylate polymer (C16-C22), and brine (H2O + NaCl). At 1000 ppm concentration, the reduction of pour point of the oil was up to a 14.4oC and reduced the viscosity to 52.5% at a seabed temperature of 4oC. This unique blend of the inhibitory properties and significant reduction in pour point temperatures and crude oil viscosity is providing an original development in wax mitigation technology.

Evaluation of Ultra Low Concentration Surfactant System for Chemical Flooding

In order to select a surfactant formulation for chemical flooding, the surfactant has to be evaluated at reservoir conditions to determine its compatibility with the reservoir to be injected in. This is to avoid formation of gels and precipitation in the reservoir which can make surfactant enhanced oil recovery unsuccessful. In several studies, surfactants have been tested in the laboratory at room temperature using only sodium chloride salt in the brine. While in oilfield scenario, the temperature is higher and the reservoir brine contains divalent ions. In this study, very low concentration alcohol alkoxy sulfate with and without a co-surfactant in hard brine and medium crude oil has been evaluated. The results from the salinity scan, phase behaviour and core flooding experiments at 60°C shows that alcohol alkoxy sulfate is tolerant to divalent ions and its stability can be improved with the addition of methyl ester sulfonate and internal olefin sulfonate as co-surfactants. These co-surfactants were able to reduce the viscosity of microemulsion phase, create a lower interfacial tension by increasing solubilisation ratio and also increase oil recovery by at least 20%.

Experimental Study on the Effect of Spiral Flow on Wax Deposition Volume

One of the main flow assurance challenges in the oil industry is wax deposition. It can result in the restriction of crude oil flow in the pipeline, creating pressure abnormalities and causing an artificial blockage leading to a reduction in the production. Wax can precipitate as a solid phase on the pipe wall when its temperature drops below the Wax Appearance Temperature. The objective of this study is using spiral flow to mitigate wax deposition. An experimental flow loop system was built in the lab to study the variation of wax deposition thickness under the single phase transport. A series of experiments were carried out at different flow rates (2.7 and 4.8 L/min) to study wax deposition and measure the wax thickness. The effect of factors on wax formation such as spiral flow, inlet coolant temperature, pressure drop, temperature drop, flow rates, time and shear stress have been examined. The spiral flow created inside the pipe by inserting a twisted metal along the pipe, which will create high shear stress affecting to wax deposition. The results show that the wax inhibition percentage WI % by using the spiral flow at flow rate 2.7 L/min, inlet coolant temperature14 oC, was 65%. At flow rate 4.8 L/min, inlet coolant temperature 14 oC the wax inhibition percentage was 73%. Experimentally, it was found the spiral flow more efficient than the chemical inhibitors. The WI % increased, by merging the effect of the spiral flow and the inhibitor at flow rate 2.7 L/min, to 75, 92.2 and 100 % at inlet coolant temperatures 14, 24 and 33 oC, respectively. The WI % was increased by combining the influence of the spiral flow and the inhibitor to 4.8 L/min, to 83.5% at inlet coolant temperature 14 oC, 94.3% at 24 oC and to 100% at temperature 33 oC. This percentage of inhibition will increased rapidly by increasing the inlet coolant temperature and decreased by reducing the inlet coolant temperature. This technique of creating spiral flow inside the test section of the pipe will provide a step forward in flow assurance technology to mitigate the deposition of wax.