Relative Permeability Modifiers as a Chemical Means to Control Water Production in Oil and Gas Reservoirs

It is challenging to control water production in horizontal wells or in vertical wells having oil and water produced from the same zone using conventional methods such as through-tubing bridge plugs or other mechanical means. Relative permeability modifiers (RPMs), known to selectively reduce the relative permeability to water with minimum impact on the relative permeability to oil or gas, are considered a promising technology for solving this problem. The current generation of RPMs, unlike the old ones, can tolerate high hardness and so have higher success rates. An extensive experimental work was carried out to evaluate three RPMs for water control in gas and oil wells. Test conditions included gas flow in sandstone cores with temperatures of up to 300°F, and oil flow in carbonate cores with temperatures as high as 220°F. The effect of initial core permeability to brine, RPM concentration, flow rate, and water-wetting surfactants on the effectiveness of RPM to reduce water production was investigated using sandstone and carbonate cores. Coreflood experiments were undertaken at downhole conditions. The end-point relative permeabilities to various phases were measured. A back pressure of 500 psi, an overburden pressure of 3,500 to 5,000 psi and flow rates of 0.1 to 5 cm3/min were used. The concentration of RPM polymers was monitored in the core effluent using total organic carbon (TOC) analyzer to determine polymer retention in the core. The results revealed that temperature adversely affected the effectiveness of all RPMs evaluated. A better reduction in permeability to water was obtained at 220°F compared to that obtained at 300°F. The use of RPM at the right concentrations was found to significantly reduce permeability to water. A better water reduction was obtained at higher polymer injection rates, which was attributed to flow-induced polymer retention. Adsorption of RPM polymer tended to alter wettability of a carbonate rock to more water-wet. This paper discusses the effects of the above parameters on the performance of RPM in sandstone and carbonate reservoirs, and it gives some recommendations for improving the success rate of these chemical applications in the field.

Improved EOR Polymer Selection Using Field-Flow Fractionation

Various polyacrylamide polymers have been successfully applied in chemical EOR projects. These polymers are characterised by high molecular weights (MW) to achieve high viscosifying power. The molecular weight distribution (MWD) of the polymers has a major impact on polymer properties and performance. Measuring the molecular weight distribution is challenging using conventional methods. Field-Flow Fractionation (FFF) enables the determination of the distribution to select and quality check various polymers. Polymers with high molar masses (> 1 MDa) are used for EOR to obtain highly viscous aqueous solutions. The MWD of the polymers is crucial for the solution characteristics. Conventional analysis of polymers is performed using either viscometry – which is able to determine the average MW but does not give information on MWD, or size-exclusion chromatography – which is restricted to molecular weights of < 20 MDa. FFF is based on the analytes flowing at different speeds in a channel dependent on their size and mass. This effect leads to separation, which is then used to determine the MWD. FFF allows to determine the MW and MWD of various ultra-high molecular weight polyacrylamides (HPAAMs). The FFF measurements showed, that despite similar MWs are claimed, substantial differences in MWD are observed. This technology offered the quantification the MWD of HPAAMs up to a MW of 5 GDa. Furthermore, gyration radii of the HPAAM molecules were determined. Selecting polymers on viscosifying power only is not addressing issues related to different MW and MWDs such as selective polymer retention and degradation of the high molar mass part of the distribution. The results were used to improve the polymer selection for chemical EOR projects. Overall, this work presents a new technique for analysis of ultra-high molecular weight EOR polymers, which enables the possibility to determine the full range of polymer MWD. This available information enhances the EOR polymer selection process addressing selective polymer retention and mechanical degradation in addition to the viscosifying power of polymers.

Investigation of Oil Presence and Wettability Restoration Effects on Sulfonated Polymer Retention in Carbonates Under Harsh Conditions

Polymer flooding in carbonate reservoirs is greatly affected by polymer retention, which is mainly due to polymer-rock surface interactions. Consequently, this leads to a delay in polymer front propagation and related oil recovery response. This work investigates the effect of oil presence and wettability restoration on polymer retention under harsh reservoir conditions of high temperature and high salinity (HTHS). An ATBS-based polymer was used for this study. Polymer single- and two-phase dynamic retention tests as well as bulk- and in-situ rheological experiments were conducted on Indiana limestone outcrops and in the presence of high salinity brine of 243,000 ppm at temperature of 50 °C. A total of four coreflooding experiments were conducted on core samples with similar petrophysical properties. Bulk rheology tests showed that the polymer is stable at HTHS conditions. Also, polymer retention and in-situ rheology tests highlighted the significance of oil presence in the core samples where retention was found to be around 40-50 and 25-30 μg/g-rock in the absence and presence of oil, respectively. An additional 50% reduction in retention was further observed on a restored wettability (aged) core sample. Polymer inaccessible pore volume (IPV) was found to be high in the range of 23 to 28%, which was supported by the 1D saturation profiles obtained from the CT scanner. The ATBS-based polymer shows excellent results for applications in carbonates under harsh conditions without considerable polymer loss or plugging. This paper also provides valuable insights into the impact of oil presence and wettability restoration on polymer retention. Furthermore, this study shows that careful consideration of the latter factor is necessary to avoid unrepresentative and inflated polymer retention values in oil reservoirs.

Low Polymer Retention Possible in Flooding of High-Salinity Carbonate Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202809, “Low Polymer Retention Opens for Field Implementation of Polymer Flooding in High-Salinity Carbonate Reservoirs,” by Arne Skauge, SPE, and Tormod Skauge, SPE, Energy Research Norway, and Shahram Pourmohamadi, Brent Asmari, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Polymer flooding has been a successful enhanced-oil-recovery method in sandstone reservoirs for decades. Extending polymer flooding to carbonate reservoirs has been challenging because of adsorption loss and polymer availability for high-temperature, high-salinity (HT/HS) reservoirs. In this study, the authors establish that HT/HS polymers can exhibit low adsorption and retention in carbonate reservoir rock at ultrahigh salinity conditions. Introduction Retention is a key factor for polymer propagation and acceleration of oil production by polymer flooding. In the complete paper, the authors consider HT/HS applications for carbonate reservoirs. Synthetic polymers such as partially hydrolyzed polyacrylamide are not thermally stable at temperatures above 60°C. The thermal stability of the synthetic polymers can be improved by incorporating monomers. To evaluate the retention of polymer in reservoir rock, dynamic retention experiments were performed in the presence and absence of oil. In homogeneous rock, the presence of residual oil typically will reduce the retention proportional to the surface covered by the oil saturation. Strongly heterogeneous rock containing fractures also may have low retention because the fluid flow mainly may be through highly permeable fractures or channels and, consequently, only part of the porous medium will contact polymer. Retention in carbonate matrix displacement (homogeneous rock) was performed on outcrop Indiana limestone for reference, but most experiments were made on reservoir rock material. The polymer used is SAV 10. Experimental Methods The easiest and, in many cases, most-accurate method for quantifying retention in dynamic coreflow experiments is by material balance. This refers to the measurement of the polymer in the effluent. The injected amount minus the backproduced amount of polymer gives the loss caused by transport through the porous medium. The retention includes both adsorption of polymer onto the rock and dynamic loss as the result of mechanical entrapment such as molecular straining and concentration blocking. In most cases, the authors used a passive tracer injected with the polymer and applied two slugs. The first slug quantifies the retention by material balance, but the difference in effluent of the second slug minus the first slug also can give an alternative measurement of the polymer retention. Comparing tracer and polymer effluent concentrations from the second polymer slug quantifies the inaccessible pore volume (IPV). The experimental setup is illustrated in Fig. 1.

Polymer Retention Determination in Porous Media for Polymer Flooding in Unconsolidated Reservoir

Polymer flooding is a well-established technique aimed at improved recovery factors from oilfields. Among the important parameters affecting the feasibility of a large deployment, polymer retention is one of the most critical since it directly impacts the oil bank delay and therefore the final economics of the project. This paper describes the work performed for the East-Messoyakhskoe oilfield located in Northern Siberia (Russia). A literature review was first performed to select the most appropriate methodology to assess polymer retention in unconsolidated cores at residual oil saturation. 4 polyacrylamide polymers were selected with molecular weights between 7 and 18 M Da and sulfonated monomer (ATBS) content between 0 and 5% molar. An improved 2-fronts dynamic retention method along with total organic carbon—total nitrogen analyzers were used for concentration measurement. Retention values vary between 93 and 444 The sentence could be rephrased μg/g, with the lowest given by the polymers containing ATBS, corroborating other publications on the topic. This paper also summarizes the main learnings gathered during the adaptation of laboratory procedures and paves the way for a faster and more efficient retention estimation for unconsolidated reservoirs.

Chemical EOR in Low Permeability Sandstone Reservoirs: Impact of Clay Content on the Transport of Polymer and Surfactant

Application of chemical enhanced oil recovery (C-EOR) processes to low-permeability sandstone reservoirs (in the 10-100 mD range) can be very challenging as strong retention and difficult in-depth propagation of polymer and surfactant can occur. Transport properties of C-EOR chemicals are particularly related to porous media mineralogy (clay content). The present experimental study aimed at identifying base mechanisms and providing general recommendations to design economically viable C-EOR injection strategies in low permeability clayey reservoirs. Polymer and surfactant injection corefloods were conducted using granular packs (quartz and clay mixtures) with similar petrophysical characteristics (permeability 70-130 mD) but having various mineralogical compositions (pure quartz sand, sand with 8 wt-% kaolinite and sand with 8 wt-% smectite). The granular packs were carefully characterized in terms of structure (SEM) and specific surface area (BET). The main observables from the coreflood tests were the resistance and residual resistance factors generated during the chemical injections, the irreversible polymer retention and the surfactant retention in various injection scenarios (polymer alone, surfactant alone, polymer and surfactant). A first, the impact of the clay contents on the retention of polymer and surfactant considered independently was examined. Coreflood results have shown that retention per unit mass of rock strongly increased in presence of both kaolinite and smectite, but not in the same way for both chemicals. For polymer, retention was about twice higher with kaolinite than with smectite, despite the fact that the measured specific surface area of the kaolinite was about 5 times less than that of the smectite. Conversely, for surfactant, retention was much higher with smectite than with kaolinite. Secondly, the impact of the presence of surfactant on the polymer in-depth propagation and retention was investigated in pure quartz and kaolinite-bearing porous media. In both mineralogies, the resistance factor quickly stabilized when polymer was injected alone whereas injection of larger solution volumes was required to reach stabilization when surfactant was present. In pure quartz, polymer retention was shown, surprisingly, to be one order of magnitude higher in presence of surfactant whereas with kaolinite, surfactant did not impact polymer retention. The results can be interpreted by considering adsorption-governed retention. The mechanistic pictures being that (a) large polymer macromolecules are not able to penetrate the porosity of smectite aggregates, whereas surfactant molecules can, and (b) that surfactant and polymer mixed adsorbed layers can be formed on surfaces with limited affinity for polymer. Overall, this study shows that C-EOR can be applied in low permeability reservoirs but that successful injection strategies will strongly depend on mineralogy.