Recent Developments in Polymer Flooding for Carbonate Reservoirs under Harsh Conditions

2019 ◽  
Author(s):  
Waleed N. Diab ◽  
Emad W. Al-Shalabi
Keyword(s):  
Polymer Flooding ◽  
Carbonate Reservoirs ◽  
Recent Developments ◽  
Harsh Conditions

Surfactant Adsorption in Surfactant-Polymer Flooding for Carbonate Reservoirs

2015 ◽  
Author(s):  
Jinxun Wang ◽  
Ming Han ◽  
Alhasan B. Fuseni ◽  
Dongqing Cao
Keyword(s):  
Polymer Flooding ◽  
Carbonate Reservoirs ◽  
Surfactant Adsorption

Polymer in-Situ Rheology in Carbonate Reservoirs

2021 ◽  
Author(s):  
Tormod Skauge ◽  
Kenneth Sorbie ◽  
Ali Al-Sumaiti ◽  
Shehadeh Masalmeh ◽  
Arne Skauge
Keyword(s):  
Polymer Solution ◽  
Carbonate Rock ◽  
High Salinity ◽  
Polymer Flooding ◽  
Resistance Factor ◽  
Carbonate Reservoirs ◽  
Permeability Reduction ◽  
Polymer Flood ◽  
Core Flood

Abstract A large, untapped EOR potential may be extracted by extending polymer flooding to carbonate reservoirs. However, several challenges are encountered in carbonates due to generally more heterogeneous rock and lower permeability. In addition, high salinity may lead to high polymer retention. Here we show how in-situ viscosity varies with permeability and heterogeneity in carbonate rock from analysis of core flood results and combined with review of data available in literature. In-situ rheology experiments were performed on both carbonate outcrop and reservoir cores with a range in permeabilities. The polymer used was a high ATBS content polyacrylamide (SAV10) which tolerates high temperature and high salinity. Some cores were aged with crude oil to generate non-water-wet, reservoir representative wettability conditions. These results are compared to a compilation of literature data on in-situ rheology for predominantly synthetic polymers in various carbonate rock. A systematic approach was utilized to derive correlations for resistance factor, permeability reduction and in-situ viscosity as a function of rock and polymer properties. Polymer flooding is applied to improve sweep efficiency that may occur due to reservoir heterogeneities (large permeability contrasts, anisotropy, thief zones) or adverse mobility ratio (high mobility contrast oil-brine). In flooding design, the viscosity of the polymer solution in the reservoir, the in-situ viscosity, is an essential parameter as this is tuned to correct the mobility difference and to improve sweep. The viscosity is estimated from rheometer/viscometer measurements or, better, measured in laboratory core flood experiments. However, upscaling core flood experiments to field is challenging. Core flood experiments measure differential pressure, which is the basis for the resistance factor, RF, that describes the increased resistance to flow for polymer relative to brine. However, the pressure is also influenced by several other factors such as the permeability reduction caused by adsorption and retention of polymer in the rock, the tortuosity of the rock and the viscosity of the flowing polymer solution. Deduction of in-situ viscosity is straight forward using Darcy's law but the capillary bundle model that is the basis for applying this law fails for non-Newtonian fluids. This is particularly evident in carbonate rock. Interpretation of in-situ rheology experiments can therefore be misleading if the wrong assumptions are made. Polymer flooding in carbonate reservoirs has a large potential for increased utilization of petroleum reserves at a reduced CO2 footprint. In this paper we apply learnings from an extensive core flood program for a polymer flood project in the UAE and combine this with reported literature data to generate a basis for interpretation of in-situ rheology experiments in carbonates. Most importantly, we suggest a methodology to screen experiments and select data to be used as basis for modelling polymer flooding. This improves polymer flood design, optimize the polymer consumption, and thereby improve project economy and energy efficiency.

Low Polymer Retention Opens for Field Implementation of Polymer Flooding in High Salinity Carbonate Reservoirs

2020 ◽  
Author(s):  
Arne Skauge ◽  
Tormod Skauge ◽  
Shahram Pourmohamadi ◽  
Jonas Solbakken ◽  
Abduljelil Sultan Kedir ◽  
...  
Keyword(s):  
High Salinity ◽  
Polymer Flooding ◽  
Carbonate Reservoirs ◽  
Polymer Retention

Recent developments on surface acoustic wave (SAW) sensors for harsh conditions

2015 ◽  
Author(s):  
Paul Schiopu ◽  
Irinela Chilibon ◽  
Neculai Grosu ◽  
Alexandru Craciun
Keyword(s):  
Acoustic Wave ◽  
Surface Acoustic Wave ◽  
Recent Developments ◽  
Harsh Conditions

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

2021 ◽  
Vol 73 (11) ◽  
pp. 60-61
Author(s):  
Chris Carpenter
Keyword(s):  
Porous Medium ◽  
High Salinity ◽  
Material Balance ◽  
Synthetic Polymers ◽  
Polymer Flooding ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Reservoir Rock ◽  
Abu Dhabi ◽  
Polymer Retention

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.

Extending Polymer Flooding Towards High-Temperature and High-Salinity Carbonate Reservoirs

2019 ◽  
Author(s):  
Shehadeh Masalmeh ◽  
Ali AlSumaiti ◽  
Nicolas Gaillard ◽  
Frederic Daguerre ◽  
Tormod Skauge ◽  
...  
Keyword(s):  
High Temperature ◽  
High Salinity ◽  
Polymer Flooding ◽  
Carbonate Reservoirs

scholarly journals Recent Developments on Surfactants for Enhanced Oil Recovery

2021 ◽  
Vol 58 (3) ◽  
pp. 164-176
Author(s):  
Xu Han ◽  
Ming Lu ◽  
Yixuan Fan ◽  
Yuxi Li ◽  
Krister Holmberg
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Polymer Flooding ◽  
Chemical Flooding ◽  
Recent Developments

Abstract This review discusses surfactants used for chemical flooding, including surfactant-polymer flooding and alkali-surfactant-polymer flooding. The review, unlike most previous reviews in the field, has a surfactant focus, not a focus on the flooding process. It deals with recent results, mainly from 2010 and onward. Older literature is referred to when needed in order to put more recent findings into a perspective.

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