Low Salinity Polymer Research Articles

Low Salinity Polymer Flooding: Effect on Polymer Rheology, Injectivity, Retention, and Oil Recovery Efficiency

Synergism between different enhanced oil recovery (EOR) methods has always been a subject of paramount interest for oil industries as it led to the development of many successful EOR methods in the...

Economic Analysis of Low Salinity Polymer Flooding Potential in the Niger Delta Oil Fields

With the current growing demand for oil, oil price and the concerns about future oil supplies increases the pressure in securing oil resources. Enhanced oil recovery processes are applied to recover oil not produced by natural and secondary energy drive of the reservoir. In this study, Simulation has been carried out on a hypothetical model using (ECLIPSE 100) as the simulator. Three cases natural depletion, waterflooding, and injection of low saline polymer were considered.5-spot pattern of four vertical producers wells and one vertical injector well was used as a hypothetical well model. Economics analysis were carried out in this three scenario to determine their net present value, profit per dollar invested, payout and Discounted flow-rate of return. The results shows that low salinity polymer flooding has the highest recovery of 62% and profit with NPV @ 10 ($412.9MM), payout 0.9 years, profit per dollar invested $25.9 and dcf-ror 82%. However, waterflooding gave recovery of 42%. NPV @10 ($ 317.3MM), payout 1.2 years, profit per dollar invested $20.8, dcf-ror 78%. Natural depletion gave recovery of 16.5 %, profit with NPV @10 (230.0MM), payout 1.0 years, profit per dollar invested $9.3, dcf-ror 78%. Decision rule was applied using NPV, DCF-ROR, NCR and payout which states that project with higher NPV, DCF-ROR, NCR and less Payout are more economically viable. The result of the three cases considered shows that low salinity polymer injection is more profitable followed by waterflooding and natural depletion.

Simulation Study of Salinity Effect on Polymer Flooding in Core Scale

In this study, simulation of low salinity polymer flooding in the core scale is investigated using Eclipse-100 simulator. For this purpose, two sets of data are used. The first set of data were adopted from the results of experimental studies conducted at the University of Bergen, performed using Berea sandstone and intermediate oil. The second data set, related to sand pack and heavy oil system, was obtained from experiments performed at Sahand Oil and Gas Research Institute. To obtain relative permeability and capillary pressure curves, automatic history matching is implemented by coupling Eclipse-100 and MATLAB software. Three different correlations are used for relative permeability. The parameters of each model are calculated using four different optimization algorithms, including Levenberg-Marquardt, Trust-region, Fminsearch, and Pattern search. The results showed that regardless of the optimization algorithm being used, applying relative permeability model of Lomeland et al., known as LET model, best matches the experimental oil recovery data in comparison with those of Corey and Skjeaveland et al.’s relative permeability correlations. The LET model and the Trust-region algorithm were selected for simulation of low salinity polymer flooding process. Simulation of the first set of data showed that using low salinity water flooding before polymer flooding, oil recovery was increased about 16%. In addition, using the second set of data, simulation of low salinity polymer flooding scenario is investigated in a long core model, taken from one of the southwestern fields of Iran. Simulation results show an increase of about 34% in the recovery of low salinity polymer flooding compared to the water flooding scenario.

Mechanisms of Microscopic Displacement During Enhanced Oil Recovery in Mixed-Wet Rocks Revealed Using Direct Numerical Simulation

We demonstrate how to use numerical simulation models directly on micro-CT images to understand the impact of several enhanced oil recovery (EOR) methods on microscopic displacement efficiency. To describe the physics with high-fidelity, we calibrate the model to match a water-flooding experiment conducted on the same rock sample (Akai et al. in Transp Porous Media 127(2):393–414, 2019. https://doi.org/10.1007/s11242-018-1198-8). First we show comparisons of water-flooding processes between the experiment and simulation, focusing on the characteristics of remaining oil after water-flooding in a mixed-wet state. In both the experiment and simulation, oil is mainly present as thin oil layers confined to pore walls. Then, taking this calibrated simulation model as a base case, we examine the application of three EOR processes: low salinity water-flooding, surfactant flooding and polymer flooding. In low salinity water-flooding, the increase in oil recovery was caused by displacement of oil from the centers of pores without leaving oil layers behind. Surfactant flooding gave the best improvement in the recovery factor of 16% by reducing the amount of oil trapped by capillary forces. Polymer flooding indicated improvement in microscopic sweep efficiency at a higher capillary number, while it did not show an improvement at a low capillary number. Overall, this work quantifies the impact of different EOR processes on local displacement efficiency and establishes a workflow based on combining experiment and modeling to design optimal recovery processes.

Oil recovery by low-salinity polymer flooding in carbonate oil reservoirs

Low-salinity polymer flooding (LSPF) is a promising enhanced oil recovery (EOR) method with a synergetic effect of combining the polymer injection and low-salinity water injection methods. To maximize EOR efficiency, it is essential to design the compositions of low-salinity water appropriately while considering polymer properties. The goal of this study was to investigate the effects of pH and potential determining ions (PDI; SO42− and Ca2+) in low-salinity polymer solution used as injection water on oil production when applying LSPF to a carbonate oil reservoir. From the experimental results, the SO42− ions interfered with polymer adsorption in the neutral SO42--containing polymer solution, while the adsorption was greatly promoted in the acidic conditions, reducing the permeability. In the Ca2+-containing polymer solution, the adsorption trend was different from the SO42− case. In examining the wettability alteration, the change in residual oil saturation between after-LSWF and after-LSPF (ΔSor) was greater with higher SO42− concentration under the neutral state. This means that the end-point of the relative permeability-saturation curves shifted to the right, indicating that wettability was altered to a more water-wet state. Under acidic conditions, ΔSor was smaller compared to the neutral state due to greater polymer adsorption. A small ΔSor was observed when Ca2+ ions were contained in the neutral polymer solution, causing less wettability alteration. This is because Ca2+ ions are involved in precipitation as well as adsorption, thus reducing the permeability more than SO42--containing case. We confirmed these changes also in the contact angle analysis. In conclusion, since SO42− ions interfered with adsorption of polymer molecules and adsorption occurred less in the neutral state, a neutral polymer solution with high SO42− ion concentration as an injection water provided the highest enhancement in the EOR efficiency.

Low salinity polymer flooding: Lower polymer retention and improved injectivity

Delayed arrival of the oil bank and reduced injectivity are risks which are commonly associated with low salinity polymer (LSP) flooding. In this study, experimental work was carried out to address these risks; the polymer retention and the cationic exchange in the presence of polymer were the main subjects of investigation. Single phase coreflood experiments were performed, where low and high salinity polymer (HSP) solutions, i.e., conventional polymer flood using formation brine, were injected in reservoir core plugs. The performance of the two polymer solutions were analyzed for polymer retention, injectivity and polymer acceleration. Compared to the HSP coreflood, the LSP coreflood showed considerably lower polymer retention and better long-term injectivity. There was no delay in polymer breakthrough, and the polymer acceleration was comparable to HSP floods. Analysis of produced effluent of the LSP coreflood detected divalent ion concentrations higher than the injected solution, and the solution which was already in equilibrium with the rock. This suggested that the divalent ions were released from the rock into the solution because of cation exchange in the presence of the LSP solution. Such increase in divalent ion concentration increased the polymer solution salinity and resulted in a viscosity loss. The results of the experimental study indicated that LSP flooding can be an attractive alternative to conventional polymer flooding, although viscosity loss due to cation exchange is a subject for further de-risking work. A numerical model which couples the cation exchange in presence of polymer with flow dynamics in core scale has also been developed. The flow field was used to advect the polymer which influenced the equilibrium condition between the rock surface and the solution. We present preliminary results obtained using the model which can be used to gain insights and study sensitivities around different geochemistry coupled flow processes.

Equation of State for Relative Permeability, Including Hysteresis and Wettability Alteration

SummaryCommercial compositional simulators commonly apply correlations or empirical relations that are based on fitting experimental data to calculate phase relative permeabilities. These relations cannot adequately capture the effects of hysteresis, fluid compositional variations, and rock-wettability alteration. Furthermore, these relations require phases to be labeled, which is not accurate for complex miscible or near-miscible displacements with multiple hydrocarbon phases. Therefore, these relations can be discontinuous for compositional processes, causing inaccuracies and numerical problems in simulation.This paper develops for the first time an equation-of-state (EOS) to model robustly and continuously the relative permeability as a function of phase saturations and distributions, fluid compositions, rock-surface properties, and rock structure. Phases are not labeled; instead, the phases in each gridblock are ordered on the basis of their compositional similarity. Phase compositions and rock-surface properties are used to calculate wettability and contact angles. The model is tuned to measured two-phase relative permeability curves with very few tuning parameters and then is used to predict relative permeability away from the measured experimental data. The model is applicable to all flow in porous-media processes, but is especially important for low-salinity polymer, surfactant, miscible gas, and water-alternating-gas (WAG) flooding. The results show excellent ability to match measured data, and to predict observed trends in hysteresis and oil-saturation trapping, including those from Land's model and for a wide range in wettability. The results also show that relative permeabilities are continuous at critical points and yield a physically correct numerical solution when incorporated within a compositional simulator (PennSim 2013). The model has very few tuning parameters, and the parameters are directly related to physical properties of rock and fluid, which can be measured. The new model also offers the potential for incorporating results from computed-tomography (CT) scans and pore-network models to determine some input parameters for the new EOS.

Efficiency of enhanced oil recovery using polymer-augmented low salinity flooding

Oil recovery from heavy oil resources has always been a challenging task. This work is aimed at investigating the recovery efficiency of polymer-augmented low salinity waterflooding in heavy oil reservoirs. The main recovery mechanism behind low salinity waterflooding is wettability alteration to more water-wet state. On the other hand, polymer flooding is performed to control fluids mobility and hence improve displacement efficiency. Combining both recovery methods is expected to add to recovery efficiency obtained by individual methods, and the aim of this work is to explore this experimentally. In this study, several laboratory experiments were conducted using Berea and Bentheimer sandstone cores starting with base runs of continuous secondary seawater and tertiary twice and 10 times diluted seawaterflooding (low salinity). Significant incremental oil recovery was obtained when flooded with low salinity water, and 10 times diluted seawater was determined to be used as low salinity water. Contact angle and Zeta potential measurements indicate wettability alteration due to clay detachment as the main recovery mechanism. Synergy of water secondary flooding and polymer tertiary flooding at different water salinity levels proved the efficiency of hybrid low salinity polymer flooding process in Berea sandstone. Low water salinity during secondary injection mode played a major role on ultimate recovery with less contribution to tertiary polymer slug injection. High salinity waterflooding provided lower secondary recovery leaving more residual oil for polymer slug to act on at that cycle. Smaller polymer slug of 0.1 pore volume was found to be sufficient in tertiary flooding with low salinity water but with slightly slower recovery rate. Bentheimer sandstones known for its low clay content were subjected to polymer-augmented waterflooding at high and low salinity levels. Close secondary and tertiary recoveries were obtained for the two salinity levels with slower recovery rate for low salinity run. Minute clay content and water-wet characteristic as determined by contact angle measurements may explain the lack of water salinity effect on recovery. The lack of salinity role and the two shock fronts with connate water bank in between known to exist during low salinity flooding may explain the slower recovery rate encountered. Comparison of both sandstones indicates that less ultimate recovery from Berea rocks, and this can be attributed to their initial intermediate wet state in contrast to the water-wet Bentheimer sandstone rocks.

Displacement Efficiency for Low-Salinity Polymer Flooding Including Wettability Alteration

SummaryPolymer flooding can significantly improve sweep and delay breakthrough of injected water, thereby increasing oil recovery. Polymer viscosity degrades in reservoirs with high-salinity brines, so it is advantageous to inject low-salinity water as a preflush. Low-salinity waterflooding (LSW) can also improve local-displacement efficiency by changing the wettability of the reservoir rock from oil-wet to more water-wet. The mechanism for wettability alteration for LSW in sandstones is not very well-understood; however, experiments and field studies strongly support that cation-exchange (CE) reactions are the key elements in wettability alteration. The complex coupled effects of CE reactions, polymer properties, and multiphase flow and transport have not been explained to date.This paper presents the first analytical solutions for the coupled synergistic behavior of LSW and polymer flooding considering CE reactions, wettability alteration, adsorption, inaccessible pore volume (IPV), and salinity effects on polymer viscosity. A mechanistic approach that includes the CE of Ca2+, Mg2+, and Na+ is used to model the wettability alteration. The aqueous phase viscosity is a function of polymer and salt concentrations. Then, the coupled multiphase-flow and reactive-transport model is decoupled into three simpler subproblems—the first in which CE reactions are solved, the second in which a variable polymer concentration can be added to the reaction path, and the third in which fractional flows can be mapped onto the fixed cation and polymer-concentration paths. The solutions are used to develop a front-tracking algorithm, which can solve the slug-injection problem of low-salinity water as a preflush followed by polymer. The results are verified with experimental data and PennSim (2013), a general-purpose compositional simulator.The analytical solutions show that decoupling allows for estimation of key modeling parameters from experimental data, without considering the chemical reactions. Recovery can be significantly enhanced by a low-salinity preflush before polymer injection. For the cases studied, the improved oil recovery (IOR) for a chemically tuned low-salinity polymer (LSP) flood can be as much as 10% original oil in place (OOIP) greater than with considering polymer alone. The results show the structure of the solutions, and, in particular, the velocity of multiple shocks that develop. These shocks can interact, changing recovery. For example, poor recoveries obtained in corefloods for small-slug sizes of low salinity are explained by the intersection of shocks without considering mixing. The solutions can also be used to benchmark numerical solutions and for experimental design. We demonstrate the potential of LSP flooding as a less-expensive and more-effective way for performing polymer flooding when the reservoir wettability can be altered with chemically tuned low-salinity brine.

Assessment on synergic potential of hybrid gel treatment with low salinity waterflood

With gel treatment, application of low salinity waterflood recovers significant amount oil from mixed- or oil-wet and severely heterogeneous reservoirs due to wettability alteration. In order to assess the performance of hybrid gel treatment with low salinity waterflood, numerical simulations has been performed for various injection schemes including low salinity polymer flood and hybrid gel treatment with low salinity waterflood. While injectivity in polymer process is significantly reduced by injection of low salinity water, that of gel treatment process is not highly influenced. In addition, optimization algorithm maximizing net present value (NPV) is applied to injection scheme under consideration of injectivity to clarify the assessment of potential of hybrid gel treatment with low salinity waterflood comparing with low salinity polymer flood. Restricted constraint condition of injection makes hybrid gel treatment with low salinity waterflood to become efficient recovery method with respect to not only NPV but also injectivity comparing with low salinity polymer flood. A thorough understanding of dramatic synergic effect from hybrid gel treatment with low salinity waterflood helps to determine appropriate hybrid EOR with low salinity waterflood corresponding to specific characteristics of reservoirs.

Similarities and Differences of Low Salinity Polymer and Low Salinity LPS (Linked Polymer Solutions) for Enhanced Oil Recovery

Linked polymer solution (LPS) is nano-size particles made of hydrolyzed polyacrylamide (HPAM) cross-linked with aluminum citrate. The propagation of LPS has been compared to non-cross-linked polymers at low brine salinity condition. The possible differences in properties and potentials for oil recovery have been investigated using water-wet and intermediate-wet cores. The target oil for polymer flooding (PF) is assumed to be the portion of the reservoir that has been bypassed by water during waterflooding and not the residual oil saturation in flooded zones. Our recent studies have shown that a positive synergy can be obtained by combining low salinity and PF. It has been claimed in the literature that cross-linking polymer such as colloidal dispersion gels (colloidal dispersion gels (CDG), micron-size aggregates) or LPS (nano-size particles) would extend the application of polymers to also include change in residual oil saturation. The results of this study indicated higher pressure buildup when low salinity LPS was propagated through brine saturated cores compared to low salinity polymer solution. The pressure buildup was even stronger for high salinity LPS injection. In two phase flow experiments, both polymer and LPS under low salinity condition, showed approximately similar propagation and oil recovery potential when injected into water-wet and intermediate-wet cores.

Improving Polymer Injectivity at West Coyote Field, California

Summary This paper presents a case history where laboratory and simulation results were used to model a single-well polymer injectivity field test in the West Coyote field and to improve injectivity in a subsequent field test. The polyacrylamide used in the first test exhibited low injectivity. Laboratory studies were performed to identify the causes of low injectivity and to model the field test physically. Laboratory core data and reservoir properties were used in a mathematical model to calculate the polymer injectivity, which closely matched that observed in the field. The low polymer injectivity at West Coyote was a result of formation damage caused by the polymer and low-salinity polymer makeup water and the high resistance factor developed by the polymer. These problems were overcome by using a lower-molecular-weight polyacrylamide, preshearing the polymer solution before injection, and increasing the salinity of the polymer makeup water. These improvements resulted in a 50% increase in injectivity during the second polymer injectivity field test at West Coyote.

Mechanical Degradation of Polyacrylamide Solutions in Core Plugs From Several Carbonate Reservoirs

SummaryThis paper presents results of laboratory studies on mechanical degradation of partially hydrolyzed polyacrylamide (HPAM) solutions in core samples from several different carbonate reservoirs. Studies in carbonates are of particular importance because several of the larger polymer projects are in carbonate reservoirs and because data on carbonate rocks have not previously been available. Many of the data in the literature were obtained with solutions of polymer-in-brine. Because HPAM polymers are generally more efficient in fresh waters, lower-salinity waters were used for the bulk of the present study. Investigated variables included polymer molecular weight, polymer concentration, and salinity of the aqueous solvent. HPAM samples used were commercial products of various molecular weights. Results were compared with correlations previously developed for sandstone core plugs and unconsolidated sands. The extent of induced degradation was monitored by comparison of viscosities and screen factors before and after flow through the core plugs at various flow rates.During injection of low-salinity polymer solutions through low-permeability carbonate core plugs, the extent of induced mechanical degradation was higher than values estimated with existing correlations obtained with higher-permeability porous media. Severe nonuniformities in the low-permeability carbonate core caused difficulties in our attempts to relate the degradation of existing correlations. Thin sections of the core materials were very helpful in the qualitative understanding of the differences in injectivity and mechanical degradation for cores from the various reservoirs. Cores with relatively uniform porosity performed differently from those that were very nonuniform, even though the permeabilities were similar.The induced mechanical degradation of the polymer reduced the viscoelastic and pseudoplastic nature of the HPAM solutions. As expected, the extent of mechanical degradation increased as the polymer molecular weight increased. Residual viscosities and screen factors of the sheared solutions, however, were often greater for the higher-molecular-weight HPAM polymers. Higher salinities or calcium concentrations of the solvent resulted in increased degradation. Thus, use of low-salinity water or softened fresh water can reduce the level of irreversible shear degradation.

Separation of Oil and Water Produced by Micellar-Solution/ Polymer Flooding

Summary The phase behavior of produced fluids from a micellar/polymer project is dominated by produced sulfonate equivalent-weight distribution, total sulfonate production, and aqueous-phase salt concentration and type. Produced fluids at Marathon Oil Co.'s 219-R Project showed evidence of having passed through a salinity gradient created by reservoir brine at the leading edge of the displacement and fresh polymer water behind the micellar solution. During early production, when aqueousphase salt concentration was relatively high, highequivalent-weight sulfonates were permanently entrained in produced oil. Significant amounts of water also remained. As the salt content of produced water declined, high-equivalent-weight sulfonates moved to middle and aqueous phases. The middle and aqueous phases carried significant quantities of oil during these periods. All three problems-water in oil, oil in the middle phase, and oil in water-were corrected by treatment with demulsifying chemicals that rendered all sulfonates highly water- soluble. Water-soluble amines and alcohols were effective. Because of large quantities of sulfonate production and resulting low oil/water tensions, extended retention times were needed in separation vessels. In the absence of adequate retention (highest sulfonate production), a freshwater wash of the oil with an appropriate demulsifying chemical after initial oil/water separation removed the remaining sulfonate (and water) from the oil. All production from the 219-R Project was successfully treated and sold with strict quality control. Data from laboratory corefloods pertinent to the characterization of produced-fluid phase behavior are presented. Introduction Vinatieri has described emulsions that can be produced as a result of micellar-solution/polymer flooding. Characteristics of these emulsions depended on salinity of the aqueous phase when significant amounts of sulfonate were present. Nelson and Pope have presented detailed descriptions of phase behavior of fluids produced from laboratory corefloods. Given the proper salinity gradient, ". . high-salinity formation brine, moderate-salinity chemical slug, and low-salinity drive. . . "produced fluids exhibited the phase behavior noted by others when sulfonate-containing microemulsions are equilibrated with brine and oil. Phase behavior of produced fluids observed by Nelson and Pope included (1) one phase (brine), (2) two phases (oil and brine), (3) two phases (upperphase microemulsion and brine), (4) three phases (oil, middle-phase microemulsion, and brine), and (5) two phases (oil and lower-phase microemulsion). This sequence of phase behavior in produced fluids resulted from injection of a small (10%PV) chemical slug of moderate salinity followed by low-salinity polymer solution. The foregoing indicates that emulsion problems may occur in a field project. At Marathon Oil Co.'s 219-R Project, crude-oil sulfonate, p-amyl alcohol, and n-butanol were used to formulate the displacing micellar solution. Dow Chemical Pusher Tm 700 was used in the mobility buffer. Appearance of sulfonate in produced water coincided with increased oil production. As sulfonate and oil production increased, water carry-over in oil and oil carryover in water at the initial point of oil/water separation became excessive. Significant amounts of emulsion formed in chem-electric heater treaters, and the water content of oil could not be reduced to pipeline quality. These problems persisted in the presence of excessive demulsifying chemical. Upper-phase microemulsion produced at the 219-R Project was successfully upgraded (enough sulfonate was removed) to meet pipeline and refinery standards by proper application of a treatment chemical to make sulfonates more water-soluble and by introduction of a freshwater wash. The oil in lower-phase microemulsion was separated by extended retention and treatment with the same chemical. Middle-phase microemulsion was collected in a separate system. Oil was recovered from these emulsions by treatment with fresh water, caustic treating, chemical, and heat. All oil, whether in upper-, middle-, or lower-phase microemulsion, was recovered and sold. Laboratory Data The phase behavior of micellar solutions with reservoir brine and oil has been represented in pseudoternary diagrams. When surfactant, oil, and brine are used as pseudocomponents, distinct regions appear in ternary representation. The regions may include single- and multiple-phase areas. Compositions that are in the single-phase region are microemulsions that are undersaturated with respect to both brine and oil. JPT P. 1459^