Inaccessible Pore Volume Research Articles

A Relaxation Scheme for the Simulation of Two‐Phase Flows With Inaccessible Pore Volume in Polymer Flooding

ABSTRACTThe simulation of polymer injection in a reservoir is of paramount importance in enhanced oil recovery. Despite decades of research, the computation of polymer flows in porous media remains a challenging task. The main difficulty lies in the necessity to take into account the effect of inaccessible pore volumes (IPV), for which standard closure laws give rise to a weakly hyperbolic or even non‐hyperbolic system. In the latter case, exponential instabilities may appear at the continuous level, which must be addressed at the discrete level so as to prevent a premature stop of the numerical simulations. The notion of IPV was introduced by engineers in order to account for the following observation: when a polymer solution is injected into an initial core saturated with water, the breakthrough of the polymer at the exit occurs before that of the water in which it is injected. It seems that due to their large size, the polymer molecules cannot insinuate themselves into all pores as well as water. Having less volume to flood, the polymer molecules see their speed increased, hence the ad hoc acceleration factor associated with the polymer. In this work, we propose a relaxation method that guarantees some practical robustness for all IPV laws. This is achieved by replacing the original system by a relaxation model which is always hyperbolic. The designed relaxation model involves two parameters which enable us not only to adjust the correct amount of numerical dissipation, but also to ensure positivity for some critical quantities such as water saturation and polymer concentration. Extensive numerical tests are performed in order to compare the relaxation scheme to the more classical upwind scheme for several IPV laws.

Effect of a SILICA/HPAM Nanohybrid on Heavy Oil Recovery and Treatment: Experimental and Simulation Study.

The addition of nanoparticles has been presented as an alternative approach to counteract the degradation of polymeric solutions for enhanced oil recovery. In this context, a nanohybrid (NH34) of partially hydrolyzed polyacrylamide (MW ∼12 MDa) and nanosilica modified with 2% 3-aminopropyltriethoxysilane (nSiO2-APTES) was synthesized and evaluated. NH34 was characterized by using dynamic light scattering, Fourier-transform infrared spectroscopy, and thermogravimetric analysis. Fluid-fluid tests assessed its viscosifying power, mechanical stability, filterability, and emulsion behavior. Rock-fluid tests were carried out to determine the nanohybrid's adsorption in porous media, the inaccessible pore volume (IPV), and the resistance (RF) and residual resistance factors (RRF). These tests were conducted under the conditions of a Colombian field. NH34 results were compared with four (4) commercial polymers (P34, P88, P51, and PA2). The viscosifying power of NH34 was observed to be similar to that of the four commercial polymers at a lower concentration, but it exhibits more resistance to mechanical and chemical degradation. The evaluation of the emulsion behavior showed that the nanohybrid neither changed the dehydration process nor altered the crude oil viscosity, favoring its extraction at the wellhead. However, the water clarification treatment must be adjusted because the oil and grease contents and turbidity increase with the residual concentration of NH34. Incremental oil recovery factors obtained by numerical simulation (compared to waterflooding) were P51 (5.5%) > P34 (4.9%) > P88 (4.8%) > NH34 (2.6%) > PA2 (0.9%). The polymers P51, P34, and P88 had a better recovery factor than NH34 and PA2 due to their lower values of residual adsorption and IPV. Few studies have been reported on polymer nanohybrids' emulsion and flow behavior. Therefore, further research is needed to enhance our understanding of the fundamental enhanced oil recovery mechanisms associated with polymer nanohybrids.

Investigation of the Effect of Residual Oil and Wettability on Sulfonated Polymer Retention in Carbonate under High-Salinity Conditions

Summary Polymer flooding in carbonate reservoirs is greatly affected by polymer retention, which is mainly due to adsorption by polymer-rock surface interactions. Consequently, this leads to a delay in polymer front propagation and related oil recovery response. This work investigates the effects of residual oil (Sor) and wettability on sulfonated-based (ATBS) polymer retention under the conditions of high salinity and moderate temperature. Polymer single- and two-phase dynamic adsorption tests as well as bulk and in-situ rheological experiments were conducted on outcrop carbonate cores in the presence of a high-salinity brine of 243,000 ppm at a temperature of 50°C. A total of four corefloods were conducted on Indiana limestone core samples with similar petrophysical properties. Overall, polymer adsorption was found to be low and within the acceptable range for application in carbonate reservoirs in the absence and presence of Sor. Furthermore, the polymer adsorption and in-situ rheology tests highlighted the significance of oil presence in the core samples, where retention was found to be around 40–50 µg/g-rock and 25–30 µg/g-rock in the absence and at Sor, respectively. An additional 50% reduction in retention was observed on the aged core sample that is more oil-wet. Polymer retention/adsorption was measured by double slug and mass balance techniques, and the results from both methods were in agreement with less than 7% difference. Inaccessible pore volume (IPV) was also calculated based on the double slug method and was found to be in the range of 23% to 28%, which was qualitatively supported by in-situ saturation monitoring obtained from an X-ray computed tomography (CT) scanner. The ATBS-based polymer showed excellent results for applications in carbonate without considerable polymer loss or plugging. This paper provides valuable insights into the impacts of residual oil and wettability on polymer adsorption, supported by CT in-situ saturation monitoring, which is necessary to avoid unrepresentative and inflated polymer retentions in oil reservoirs.

Pressure transient characteristics of non-uniform conductivity fractured wells in viscoelasticity polymer flooding based on oil–water two-phase flow

Polymer flooding in fractured wells has been extensively applied in oilfields to enhance oil recovery. In contrast to water, polymer solution exhibits non-Newtonian and nonlinear behavior such as effects of shear thinning and shear thickening, polymer convection, diffusion, adsorption retention, inaccessible pore volume and reduced effective permeability. Meanwhile, the flux density and fracture conductivity along the hydraulic fracture are generally non-uniform due to the effects of pressure distribution, formation damage, and proppant breakage. In this paper, we present an oil–water two-phase flow model that captures these complex non-Newtonian and nonlinear behavior, and non-uniform fracture characteristics in fractured polymer flooding. The hydraulic fracture is firstly divided into two parts: high-conductivity fracture near the wellbore and low-conductivity fracture in the far-wellbore section. A hybrid grid system, including perpendicular bisection (PEBI) and Cartesian grid, is applied to discrete the partial differential flow equations, and the local grid refinement method is applied in the near-wellbore region to accurately calculate the pressure distribution and shear rate of polymer solution. The combination of polymer behavior characterizations and numerical flow simulations are applied, resulting in the calculation for the distribution of water saturation, polymer concentration and reservoir pressure. Compared with the polymer flooding well with uniform fracture conductivity, this non-uniform fracture conductivity model exhibits the larger pressure difference, and the shorter bilinear flow period due to the decrease of fracture flow ability in the far-wellbore section. The field case of the fall-off test demonstrates that the proposed method characterizes fracture characteristics more accurately, and yields fracture half-lengths that better match engineering reality, enabling a quantitative segmented characterization of the near-wellbore section with high fracture conductivity and the far-wellbore section with low fracture conductivity. The novelty of this paper is the analysis of pressure performances caused by the fracture dynamics and polymer rheology, as well as an analysis method that derives formation and fracture parameters based on the pressure and its derivative curves.

Analytical solution for chemical fluid injection into linear heterogeneous porous media based on the method of characteristics

Injection of Newtonian fluids in porous media to displace linearly another Newtonian fluid is described by the Buckley-Leverett (BL) fractional flow theory derived for incompressible, constant viscosity fluids at constant injection rate in a homogeneous and isotropic reservoir. Injection of non-Newtonian fluids can be addressed by modifying the fractional flow equation by considering the dependence of injected fluid viscosity with velocity, changes of residual oil saturation and chemical adsorption on rock. In this work, the BL fractional flow model is extended to describe injection of non-Newtonian fluids into a 1D linear heterogeneous formation accounting for fluid adsorption, permeability reduction, inaccessible pore volume, and presence of a denuded water bank developed over time ahead of non-Newtonian zone. Results from derived analytical solutions demonstrate fluids saturation and pressure drop across the formation, fluids production rate and cumulative volumes to be in close agreement with the ones from a commercial reservoir simulator.

Polymer Gel for Water Shutoff in Complex Oil and Gas Reservoirs: Mechanisms, Simulation, and Decision-Making

Summary Gel treatment is often used for water shutoff in high water-cut oil or gas wells. Although the properties and usage methods of gel have been well documented by different investigators, gel treatment performance is not always satisfactory in field application, especially in oil or gas reservoirs with complex conditions, such as strong bottomwater reservoirs, high-permeability-ratio oil reservoirs, and fractured gas reservoirs. In this work, we attempt to improve gel treatment application in complex situations according to the causes of disappointing performance, including unreliable numerical simulation and the misapplication of experiences. We propose a new numerical simulation method of gel treatment mechanisms and verify it by improving the acquiring method of inaccessible pore volume (IAPV), dynamic polymer adsorption (DPA), and the simulation method of disproportionate permeability reduction (DPR). The performance and optimization measures of gel treatment in different types of complex oil and gas reservoirs are discussed extensively. Moreover, the dominant influencing factor of the gel treatment effect is determined by gray relation analysis to provide more direct and effective suggestions for field application. The results suggest that the improved access methods for IAPV and DPA can help to obtain more precise parameters easily to construct a numerical gel model. In addition, the new DPR simulation method, which considers oil or gas blocking, reduces the overestimation of gel DPR ability obtained with the conventional method. The misapplication of gel treatment experience probably causes a disappointing response, for example, gel treatment time had opposite influences on water shutoff in strong bottomwater reservoirs and high-permeability-ratio oil reservoirs, and the experience of reservoir thickness in oil reservoirs was not suitable for gas reservoirs. Furthermore, the major factors of gel treatment are varied in different oil and gas reservoirs, demonstrating that primary evaluation indicators for candidate wells are not permanent.

Literature Review and Experimental Observations of the Effects of Salinity, Hardness, Lithology, and ATBS Content on HPAM Polymer Retention for the Milne Point Polymer Flood

Summary At the Milne Point polymer flood (North Slope of Alaska), polymer retention is dominated by the clay, illite. Illite, and kaolinite cause no delay in polymer propagation in Milne Point core material, but they reduce the effective polymer concentration and viscosity by a significant amount (e.g., 30%), thus reducing the efficiency of oil displacement until the full injected polymer concentration is regained [which requires several pore volumes (PVs) of throughput]. This work demonstrates that polymer retention on illite is not sensitive to monovalent ion concentration, but it increases significantly with increased divalent cation concentration. The incorporation of a small percentage of acrylamido tertiary butyl sulfonic acid (ATBS) monomers into hydrolyzed polyacrylamide (HPAM) polymers is shown to dramatically reduce retention. The results are discussed in context with previous literature reports. Bridging adsorption was proposed as a viable mechanism to explain our results. Interestingly, an extensive literature review reveals that polymer retention (on sands and sandstones) is typically only modestly sensitive to the presence of oil. Extensive examination of the literature on inaccessible pore volume (IAPV) suggests the parameter was commonly substantially overestimated, especially in rock/sand more permeable than 500 md (which comprises the vast majority of existing field polymer floods).

Sensitivity Study of The Effect Polymer Flooding Parameters to Improve Oil Recovery Using X-Gradient Boosting Algorithm

Implementation of waterflooding sometimes cannot increase oil recovery effectively and requires additional methods to increase oil recovery. Polymer flooding is a common chemical EOR method that has been implemented in the last few decades and provides good effectiveness in increasing oil recovery and can reduce the amount of injection fluid injected into the reservoir. Seeing the success of polymer flooding in increasing oil recovery, it is necessary to know the parameters that influence the success of polymer flooding so that it can be evaluated and taken into consideration in creating a new scheme to increase oil recovery with polymer flooding. The parameters tested in this study include Injection Rate, Injection Time, Injection Pressure, Adsorption, Inaccessible Pore Volume, Residual Resistance Factor. This research uses the X-Gardient Boosting Algorithm to look at the most influential parameters in polymer flooding. The parameters that most influence the performance of polymer flooding on the value of oil recovery with the importance level of each parameter in this study are injection time of 0.452632, injection rate of 0.430075, injection pressure of 0.064662, Adsorption of 0.025564, RRF of 0.021053, IPV of 0.006014 and produce accurate predictive modeling using x-gradient boosting where with 3 variations of the comparison ratio of training and testing data obtained at a ratio of 0.7 : 0.3 obtained an R2 train of 0.9886 and an R2 test of 0.9645, a ratio of 0.8 : 0.2 obtained an R2 train of 0.9891 and an R2 test of 0.9579, and a ratio of 0.9: 0.1 obtained R2 train of 0.9890 and R2 test of 0.9660.

Optimization of Polymer Flooding Using Genetic Algorithm

One of the methods to achieve optimal conditions in increasing oil recovery through injecting polymers is by optimizing the parameters that influence the success of injecting polymers to provide information and be considered when determining new schemes for implementation in the future. Optimization to obtain the optimum value of the recovery factor and the best value of the parameters PV, injection rate, injection time, injection pressure, adsorption, residual resistance factor (RRF), and inaccessible pore volume (IPV) using a genetic algorithm with three training ratios and testing 70: 30, 80: 20 and 90: 10 using 1000 datasets. The best value obtained for each parameter is at a ratio of 90: 10, which is the best model with the lowest reference error value with RSME of 0.241104 and MAPE value of 19.1964 classified as good prediction with the value of each adsorption parameter 0.1737 (g/l), injection rate 703 (bpd), injection pressure 1816, IPV 0.2524, RRF 4.8319 and finally the optimum value for recovery factor is 53.9557.

Transient pressure analysis of polymer flooding fractured wells with oil-water two-phase flow

The oil-water two-phase flow pressure-transient analysis model for polymer flooding fractured well is established by considering the comprehensive effects of polymer shear thinning, shear thickening, convection, diffusion, adsorption retention, inaccessible pore volume and effective permeability reduction. The finite volume difference and Newton iteration methods are applied to solve the model, and the effects of fracture conductivity coefficient, injected polymer mass concentration, initial polymer mass concentration and water saturation on the well-test type curves of polymer flooding fractured wells are discussed. The results show that with the increase of fracture conductivity coefficient, the pressure conduction becomes faster and the pressure drop becomes smaller, so the pressure curve of transitional flow goes downward, the duration of bilinear flow becomes shorter, and the linear flow appears earlier and lasts longer. As the injected polymer mass concentration increases, the effective water phase viscosity increases, and the pressure loss increases, so the pressure and pressure derivative curves go upward, and the bilinear flow segment becomes shorter. As the initial polymer mass concentration increases, the effective water phase viscosity increases, so the pressure curve after the wellbore storage segment moves upward as a whole. As the water saturation increases, the relative permeability of water increases, the relative permeability of oil decreases, the total oil-water two-phase mobility becomes larger, and the pressure loss is reduced, so the pressure curve after the wellbore storage segment moves downward as a whole. The reliability and practicability of this new model are verified by the comparison of the results from simplified model and commercial well test software, and the actual well test data.

Experimental investigation of flow diversion and dynamic retention during polymer flooding in high salinity fractured carbonates using CT imaging

The successful record of polymer flooding in improving oil production from sandstone reservoirs has encouraged the expansion of its application in carbonate reservoirs. However, the existence of natural fractures, high permeability contrast, and harsh conditions of carbonate reservoirs provide significant challenges for achieving an optimized performance of polymer flooding. It is crucial to establish an appropriate polymer that can offer an optimum flow behavior for in-depth mobility control under reservoir conditions. This study presents in-situ saturation monitoring to evaluate the mobility control effect and identify the flow diversion during polymer injection in high salinity fractured and unfractured carbonate rocks. A synthetic polymer, acrylamido tertio-butyl sulfonate (ATBS) was used and prepared in 200,000 ppm brine salinity. The flow behavior of polymer solution was investigated in bulk rheology tests followed by single-phase core flooding experiments. The flooding apparatus was coupled with a CT scanner to produce 3D images for determining the fluid saturation distribution and inaccessible pore volume (IPV) in real time. Accordingly, flow diversion across fracture-matrix system during polymer injection and the dynamic retention after brine post-flush were identified. The flow experiments showed a shear thickening behavior for the injected polymer solution in the fractured core and no degradation was noticed under in-situ conditions. Based on the fluid saturation profiles, the established flow resistance in the fracture region was prominent to induce flow diversion from the fracture into the matrix. Compared to the case in unfractured rock, the IPV in the fractured rock was approximately 2.5 times higher which was at 53% after 1 PV injection. An additional 23% of IPV was subsequently penetrated upon a continuous polymer injection for 5 PV. In post-flush stage, the fractured core retained about 87% of the injected polymer solution at 1 PV which was then minimized to 7% after 10 PV injection. The entrapped polymer in the fractured core was potentially induced by hydrodynamic retention. This work ascertained the potential of polymer flooding to effectively sweep the fractured carbonates at high salinity environment under certain circumstances for a better conformance.

Effects of trapping number on biopolymer flooding recovery of carbonate reservoirs

The effects of trapping number on enhanced oil recovery by schizophyllan biopolymer flooding in carbonate reservoirs were investigated by running several 1D simulations using measured reservoir rock and fluid data. Sensitivity analysis was performed on different uncertain parameters to history match the oil recovery obtained in the core flooding experiment. These parameters include inaccessible pore volume (IPV), biopolymer adsorption, permeability reduction factor, shear rate coefficient, hardness of injection water, and trapping number. The IPV, biopolymer adsorption, permeability reduction factor, shear rate coefficient and hardness of injection water have negligible effects on oil recovery by biopolymer flooding. Also, history matching of oil recovery data was not possible when these parameters were varied within their typical range of values. When trapping number effect was considered through capillary desaturation curve (CDC), residual oil saturation was reduced from 25.1% without considering its effect or under low trapping number to 10.0%, and the fitting effect for recovery was better. Therefore, we can't neglect the trapping number effect during biopolymer flooding simulation in the carbonate reservoirs.

A Novel Numerical Model of Gelant Inaccessible Pore Volume for In Situ Gel Treatment.

Inaccessible pore volume (IAPV) can have an important impact on the placement of gelant during in situ gel treatment for conformance control. Previously, IAPV was considered to be a constant factor in simulators, yet it lacked dynamic characterization. This paper proposes a numerical simulation model of IAPV. The model was derived based on the theoretical hydrodynamic model of gelant molecules. The model considers both static features, such as gelant and formation properties, and dynamic features, such as gelant rheology and retention. To validate our model, we collected IAPV from 64 experiments and the results showed that our model fit moderately into these lab results, which proved the robustness of our model. The results of the sensitivity test showed that, considering rheology and retention, IAPV in the matrix dramatically increased when flow velocity and gelant concentration increased, but IAPV in the fracture maintained a low value. Finally, the results of the penetration degree showed that the high IAPV in the matrix greatly benefited gelant placement near the wellbore situation with a high flow velocity and gelant concentration. By considering dynamic features, this new numerical model can be applied in future integral reservoir simulators to better predict the gelant placement of in situ gel treatment for conformance control.

Polymer Transport in Low-Permeability Carbonate Rocks

Summary The efficiency of a polymer flood depends on polymer transport and retention. Most studies on polymer transport in the literature have been focused on high-permeability sandstones. A limited number of investigations have been conducted in carbonates with permeability less than 100 md and very few in the presence of residual oil. In this work, transport of four polymers with different molecular weights (MW) and functional groups was studied in 1-ft-long Edwards Yellow outcrop cores (permeability < 50 md) with and without residual oil. The retention of polymers was estimated by both the material balance method and the double-bank method. The polymer concentration in coreflood effluents was measured by both the total organic carbon (TOC) analyzer and the capillary tube pressure drop. The results demonstrated that in tight carbonate rocks at 100% water saturation, partially hydrolyzed acrylamide (HPAM) polymers exhibited high retention (>160 µg/g), inaccessible pore volume (IPV) greater than 7%, and high residual resistance factor (RRF) (>9). The propagation of HPAM improved with the residual oil saturation and the retention was reduced by 50 µg/g because of thin oil films in pores that prevented the direct adsorption of the carboxyl group of polymers on the mineral surface. The sulfonated polyacrylamide, AN132, showed low retention (<15 µg/g) and negligible IPV in all experiments. The RRF of AN132 in the water-saturated rock was less than 2, indicating minimal blocking of pore throats in these tight rocks. The RRF of the AN132 polymer increased slightly in the presence of residual oil saturation because of partial blocking of the smaller pore throats available for polymer propagation in the oil-aged core.

Mechanistic modeling of hybrid low salinity polymer flooding: Role of geochemistry

Low salinity polymer (LSP) based enhanced oil recovery (EOR) technique is getting more attention due to its potential of improving both displacement and sweep efficiencies. Modeling LSP flooding is challenging due to the complicated physical processes and the sensitivity of polymers to brine salinity. In this study, a coupled numerical model has been implemented to allow investigating the polymer-brine-rock geochemical interactions associated with LSP flooding along with the flow dynamics. MATLAB Reservoir Simulation Toolbox (MRST) was coupled with the geochemical software IPhreeqc, which is the interface module of Phreeqc (i.e., pH-Redox-Equilibrium in C programming language). The effects of polymer were captured by considering Todd–Longstaff mixing model, inaccessible pore volume, permeability reduction, polymer adsorption as well as salinity and shear rate effects on polymer viscosity. Regarding geochemistry, the presence of polymer in the aqueous phase was considered by adding a new solution specie and related chemical reactions to Phreeqc database files. Thus, allowing for modeling the geochemical interactions related to the presence of polymer. Coupling the two simulators was successfully performed, verified, and validated through several case studies. The coupled MRST–IPhreeqc simulator allows for modeling a wide variety of geochemical reactions including aqueous, mineral precipitation/dissolution, and ion exchange reactions. Capturing these reactions allows for real time tracking of the aqueous phase salinity and its effect on polymer rheological properties. The coupled simulator was verified against Phreeqc for a realistic reactive transport scenario. Furthermore, the coupled simulator was validated through history matching a single-phase LSP coreflood from the literature. This paper provides an insight into the geochemical interactions between partially hydrolyzed polyacrylamide (HPAM) and aqueous solution chemistry (salinity and hardness), and their related effect on polymer viscosity. This work is also considered as a base for future two-phase polymer solution and oil interactions, and their related effect on oil recovery.

Experimental Study and Numerical Simulation of Polymer Flooding

The numerical simulation of polymer flooding is a complex task as this process involves complex physical and chemical reactions, and multiple sets of characteristic parameters are required to properly set the simulation. At present, such characteristic parameters are mainly obtained by empirical methods, which typically result in relatively large errors. By analyzing experimentally polymer adsorption, permeability decline, inaccessible pore volume, viscosity-concentration relationship, and rheology, in this study, a conversion equation is provided to convert the experimental data into the parameters needed for the numerical simulation. Some examples are provided to demonstrate the reliability of the proposed approach.

Injectivity and Potential Wettability Alteration of Low-Salinity Polymer in Carbonates: Role of Salinity, Polymer Molecular Weight and Concentration, and Mineral Dissolution

Summary Coupling polymer with low-salinity water (LSW) to promote enhanced oil recovery (EOR) in carbonate reservoirs has attracted significant interest in the petroleum industry. However, low-salinity polymer (LSP) application to improve oil extraction from such rocks remains a challenge because of the complex synergism between these two EOR agents. Thus, this paper highlights the main factors that govern the LSP displacement process in carbonate reservoirs in terms of wettability alteration and mobility control. A series of experiments including contact angle, spontaneous imbibition, injectivity, adsorption, and oil displacement tests were performed. The impact of mineral dissolution on the polymer/brine and polymer/rock surface interactions and its possible connection to the efficiency of the LSP in carbonates was also investigated using ζ potential analysis following an elaborative procedure. All experiments were executed at elevated temperature (75°C) using two polymers (SAV10) of different molecular weights (MWs) prepared at varying concentrations and salinities. Contact angle measurements showed that increasing the polymer concentration and MW and, at the same time, decreasing the solution salinity could effectively rend homogeneous oil-wet calcite surfaces strongly water-wet. Conversely, spontaneous imbibition tests using heterogonous oil-wet Indiana limestone cores showed that the polymer viscosity and its molecular size hinder the performance of the polymer to modify the wettability of the core samples at high concentration and MW because they could limit its penetration into the porous medium. On the other hand, the results obtained from polymer injectivities showed that LSP had better propagation with lower filtration effects in comparison with high-salinity polymer (HSP). However, polymer adsorption and inaccessible pore volume (IPV) increased with the decrease of salinity. Calcite mineral dissolution triggered by LSP, which is associated with an increase in pH and [Ca2+], considerably influenced the polymer viscosity. In addition, ζ potential measurements showed that the LSP altered the rock surface charge from positive toward negative and at the same time, the Ca2+ released due to mineral dissolution could modify the polymer molecule charge toward positive. This confirms that mineral dissolution impressively results in better wettability alteration performance; however, it could lead to undesirable high polymer adsorption at low salinity. These findings provide new insight into the influence of mineral dissolution on polymer performance in carbonates. Finally, forced oil displacement tests revealed that both HSP and LSP extracted approximatively the same amount of oil. The HSP could enhance the oil recovery through mobility control. By contrast, wettability alteration could take part in the improvement of oil recovery at LSP, as proved by spontaneous imbibition tests, along with mobility control. Despite possessing high wettability alteration potential, LSP could not yield very high recovery because of its low accessibility into the porous medium. Shearing of the LSP was found effective in improving oil recovery through enhancing the polymer accessibility. This will lead us to simply say that polymer accessibility into carbonates is crucial for the success of the wettability alteration and mobility control processes, which is remarkably important not only for this specific study but also for other various polymer EOR applications.

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.

Multi-molecular mixed polymer flooding for heavy oil recovery

Polymer flooding has its superiority in heavy oil recovery due to the improvement of the mobility ratio of oil to the injected fluids. In this work, the multi-molecular mixed polymer flooding is proposed for heavy oil recovery. Firstly, the inaccessible pore volume and resistance coefficient are measured for the multi-molecular mixed polymer. The low-field nuclear magnetic (LFNMR) resonance technique is then applied to compare the performance of conventional polymer flooding and multi-molecular mixed polymer flooding for heavy oil extraction from the pore-scale perspective. Results show that the inaccessible pore of multi-molecular mixed polymer flooding is about 5.0% lower than the single molecular polymer flooding, of which the resistance coefficient is about 6.2 higher than the single molecular polymer flooding, indicating the potential of the multi-molecular mixed polymer flooding for enhancing heavy oil recovery. Moreover, the multi-molecular mixed polymer flooding shows excellent performance for heavy oil production compared to the conventional polymer flooding. Specifically, the total oil recovery for the multi-molecular mixed polymer flooding is measured about 4.2% higher than that of the conventional polymer flooding. In addition, based on the LFNMR scanning, the multi-molecular mixed polymer flooding is more efficient in extracting oil from the smaller pores. This study is expected to inspire new strategies for heavy oil recovery; more importantly, it may provide insights into the mechanism of polymer flooding for heavy oil extraction.

A core-scale study of polymer retention in carbonates at different wettability and residual oil conditions

As an effective technique to improve oil recovery, polymer flooding has been successfully used worldwide in many fields. The retention of polymer in reservoir increases the project cost, retards polymer transport, and thus delays the incremental oil response. Therefore, low polymer retention is crucial for a successful polymer-flooding project. Accurate quantification of this parameter is accordingly essential. Polymer retention is often evaluated in the absence of oil, which is not representative of the polymer-flooded oil regions in the reservoir. There is also a lack of consensus on the wettability impact on retention in the literature. In this work, the polymer retention in carbonates is investigated at varied wettability conditions, in the presence of oil as well as in the absence of oil. A sulfonated polyacrylamide polymer is evaluated in this study, and representative reservoir fluids and core samples are used in the experiments. The results demonstrate that the studied polymer exhibits relatively low retention in the carbonate cores, ranging from 20.9 to 60.8 μg/g-rock. The inaccessible pore volume (IPV) ranges from 9.0 to 12.0% pore volume (PV). These results demonstrate a potential of this polymer for carbonate reservoir applications. More importantly, the results indicate that the polymer retention is reduced more than 50% in the presence of residual oil. In other words, the presence of oil in actual reservoir condition has a positive side in terms of polymer consumption. Accordingly, it is a factor that must be either simulated or accounted for. On the other hand, the results suggest that the wettability impact on polymer retention is small compared to the presence of oil. Furthermore, both residual oil and wettability have insignificant impact on polymer IPV. In summary, the polymer retention results from single phase displacement experiments tend to be more conservative. When using these retention estimates for designing a polymer flooding project, their conservative nature should be kept in mind or factored in.