Polymer Flooding Projects Research Articles

Polymer-Injection Pilot in Colombian Field Indicates Reduced Carbon Footprint

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 218169, “Carbon Footprint and Energy Intensity Assessment for Enhanced Oil Recovery (EOR) Based on Polymer Injection: A Colombian Case Study,” by Henderson I. Quintero, SPE, Pedro L. Solorzano, SPE, and Carolina Barbosa, Ecopetrol, et al. The paper has not been peer reviewed. _ Chichimene is an oil field in eastern Colombia. Since 2014, enhanced oil recovery (EOR) using a water-injection process has been performed successfully in part of this field. A polymer-injection pilot was executed over five injection patterns to optimize this process as a promising strategy for polymer-based EOR in challenging reservoir conditions with high temperatures and heavy oil. Field Background Included in Colombia’s energy-transition strategy are EOR technologies that, through the acceleration of oil production even with low energy consumption, increase the efficiency and carbon intensity of conventional oil-production processes. Several studies in the literature have reported improved energy and carbon indicators as a result of implementing EOR using thermal and chemical methods. Among these, polymer injection promises higher incremental oil production with lower energy consumption. The polymer-flooding (PF) pilot in the Chichimene field was performed to evaluate this technology’s ability to displace the heavy crude oil of the Fm1 formation (350–700 cp). The reservoir is more than 20 km long by 6 km wide and features 250–300 ft of thickness, with permeability between 100 md and 10 D and a depth of approximately 6,200 ft true vertical depth subsea. Polymer injection began at the end of 2015 in an extensive pattern (N1), followed by a smaller pattern (N2) in 2018 after a short water-injection stage. The polymer injection in medium patterns (N3 and N4) and a second small pattern (N5) began in 2019, being considered early chemical EOR because they were performed after the primary production stage. The well spacing of the patterns is 10 and 40 acres, respectively. The producer wells of each pattern are displayed in Table 1 of the complete paper. The PF project injected 21.65 thousand STB of polymer solution. At the end of 2022, incremental oil production was 4.9 billion bbl. At the time of writing, patterns show incremental recovery factors of between 4 and 9%. The reservoir showed strong signals of repressurization, gas/oil ratio reduction, water/oil ratio control, and oil incremental recovery. Energy consumption and carbon intensity were calculated for the oil production baseline case [waterflooding (WF) or primary production] and PF, considering the field’s energy matrix. The results were compared to quantify the effect of PF on these efficiency indicators. Evaluation of Product System Energy consumption was calculated for each phase involved in the processing system: lifting fluids, oil dehydration, water-clarification treatment, water reinjection, and PF. The evaluation did not include solvent or facilities to dilute the crude oil or the pumping energy used to deliver the oil to the pipeline system. Currently, the total volume of water produced is reinjected into the reservoir for pressure maintenance and oil-recovery purposes. Also, part of the produced gas is used in heaters and fire tubes for dehydration, but most is burned in a gas flare.

Assessment of World’s First Two Polymer Injectivity Tests Performed in Two Giant High-Temperature/High-Salinity Carbonate Reservoirs Using Single-Well Simulation Models and Pressure Falloff Tests Analysis

Summary Polymer flooding is a mature enhanced oil recovery (EOR) technology that has been widely implemented around the world for more than 60 years. Polymer flooding mostly targets medium- to high-permeability sandstone reservoirs with moderate salinity, hardness, and temperatures. However, in the last few years, the envelope of polymer flooding has been expanded to harsher reservoir conditions of high-temperature and high-salinity mixed-wet to oil-wet heterogeneous carbonate reservoirs. Development of novel polymers and innovative field application concepts has allowed for the reconsideration of polymer-based EOR as a promising technology to improve sweep efficiency for these challenging reservoirs. Polymer injectivity is one of the key challenges for polymer flooding projects and requires a rigorous derisking program that includes laboratory and field testing. A comprehensive laboratory program was designed to assess and investigate polymer thermal stability, polymer rheology in porous media, adsorption, and injectivity using reservoir core samples. In addition, two polymer injectivity tests (PITs) were performed in two giant light oil (0.3 cp) carbonate reservoirs in onshore Abu Dhabi under harsh conditions of high salinity (>200 g/L), high divalent ions (>20 g/L), high temperature (>250°F), and H2S concentration of up to 40 ppm. The polymer used during the two PITs (PIT 1 2019 and PIT 2 2021) is a new generation of EOR polymer (SAV 10) with high 2-acrylamido-tertiary-butyl sulfonic acid content that was specifically developed to tolerate such harsh conditions. This paper is focused on the interpretation of the PITs and lessons learned for future polymer-based EOR projects. The detailed data acquired in both tests were used to evaluate the polymer injectivity at representative field conditions and in-depth mobility reduction. The PITs together with the extensive laboratory studies are part of a thorough derisking program for the upcoming world’s first innovative hybrid EOR multiwell pilots—simultaneous injection of miscible gas and polymer (SIMGAP) and simultaneous injection of water and polymer (SIWAP). Both PITs are composed of three stages that include a multirate waterflood baseline, polymer injection using different rates, and polymer concentrations followed by extended chase waterflooding. In addition, a sequence of multiple pressure falloff (PFO) tests was acquired during the PIT executions and analyzed to obtain the required uncertainty parameters for the history-matching exercise. Polymer preshearing was considered as part of both PIT programs with the aim to homogenize the polymer molecular weight distribution and reduce possible shear-thickening effects near the wellbore as per laboratory measurements. Two single-well 3D simulation models were built to incorporate the information from polymer laboratory studies and to interpret the large field data sets acquired during the PITs. Lessons learned from PIT 1 allowed us to optimize the PIT 2 design program and achieve better understanding of polymer characteristics. The interpretation of the pressure transient analysis (PTA) of the PFO tests and the 3D simulation models of the two PITs confirmed the generation of polymer banks and demonstrated effective propagation of the polymer into the reservoirs at target concentrations and representative rates of the future SIWAP and SIMGAP interwell pilots.

ОЦЕНКА КРИТЕРИЕВ ПРИМЕНЕНИЯ ПОЛИМЕРНОГО ЗАВОДНЕНИЯ В ОСЛОЖНЕННЫХ ПЛАСТАХ. ОБЗОР

Selection of the enhanced oil recovery method is based on applicability criteria, which are referred to in foreign literature as screening. To select the technology, the geological and physical parameters of the field are compared with the existing limits of applicability of the technology. Polymer flooding is a physical and chemical method of enhanced oil recovery, which has been used on an industrial scale for more than 60 years. The paper compares the applicability criteria of classical polymer flooding, adopted in the literature from 1985 to 1997, with modern projects carried out in the world. The main criteria, in terms of stability of polymer solution in reservoir conditions, key criteria determining the possibility of injecting the solution and additional criteria are highlighted. The main emphasis is made on the expediency of polymer flooding in high-temperature reservoirs containing low-viscosity oil or water of high mineralisation. Realised projects of enhanced oil recovery using polymers over the last 10 years are presented. Due to the appearance of modified representatives of high molecular weight compounds a large number of polymer flooding projects have been carried out in a wide range of conditions, which are presented in this paper: at reservoir temperature up to 140˚C, oil viscosity from 0.07 to 10000 mPa*s, as well as with highly mineralised formation water up to 250 g/l. Considering the implemented projects, it was revealed that the impact on increasing waterflood coverage is achieved not only by equalising the mobility of oil and displacing agent, but also by redistributing filtration flows of injected fluid from highly permeable and, consequently, already flushed zones to less permeable zones containing a large amount of residual reserves.

Evaluating Factors Impacting Polymer Flooding in Hydrocarbon Reservoirs: Laboratory and Field-Scale Applications.

Polymer flooding is an enhanced oil recovery (EOR) method used to increase oil recovery from oil reservoirs beyond primary and secondary recovery. Although it is one of the most well-established methods of EOR, there are still continuous new developments and evaluations for this method. This is mainly attributed to the diverse polymers used, expansion of this method in terms of application, and the increase in knowledge pertaining to the topic due to the increase in laboratory testing and field applications. In this research, we perform a review of the factors impacting polymer flooding in both laboratory studies and field-based applications in order to create guidelines with respect to the parameters that should be included when designing a polymer flooding study or application. The main mechanism of polymer flooding is initially discussed, along with the types of polymers that can be used in polymer flooding. We then discuss the most prominent parameters that should be included when designing a polymer flooding project and, based on previous laboratory studies and field projects, discuss how these parameters impact the polymer itself and the flooding process. This research can provide guidelines for researchers and engineers for future polymer flooding research or field applications.

Demulsification of o/w emulsion produced by polymer flooding injecting anionic polymeric surfactant

Anionic amphiphilic polymers (polymeric surfactant) have been applied in polymer flooding to improve its adaptability to reservoirs of low permeability, high salinity and high temperature. Some pilot and extended polymer flooding projects injecting anionic polymeric surfactants with interfacial activities produced very stable o/w emulsion, bringing about high oil carry-over in produced water which was very difficult to remove to meet re-injection specifications. Factors contributing to the stability of o/w emulsion produced by a polymer flooding project injecting an anionic amphiphilic polymer were investigated by means of phase separation test, interfacial tension and Zeta potential measurements, emulsion microscopic structure observation and determination, and identification of interfacial active species. Major mechanisms hindering the aggregation and coalescence of oil droplets in the stable o/w emulsion were identified as the electrostatic repulsion and steric repulsion exerted by the polymer coils attached to the surfaces of oil droplets. A novel combination of a nonionic block polyether SP-2002 and a low molecular weight anionic surfactant AS-2001was designed to effectively demulsify the stable o/w emulsion produced by the polymer flooding project. Field trial of SP-2002 and AS-2001, together with a chelating agent WS-2001, brought about much looser o/w emulsion and significantly reduced oil carry over in produced water separated by field 3-phase production separators and skim tanks. The average OIWs of produced water dropped from 790 ppm before the trial to 482 ppm during the second stage of the trial. OIW of the produced water at the end of the trial dropped from 426 ppm to 90 ppm after 24 h static settling at 35 °C and further reduced to 17 ppm after bench-top media filtration.

A Systematical Review of the Largest Polymer Flood Project in the World: From Laboratory to Pilots and Field Application

Summary This paper presents a systematical review of the largest polymer flood project in the world, applied to multilayered, heterogeneous sandstone reservoirs in the giant Daqing Oilfield in China. First, reservoir and fluid characteristics are highlighted to understand the heterogeneity of the reservoir. Next, the project history is summarized, including laboratory studies, pilot tests, commercial tests, and fieldwide applications. Third, typical polymer flood performance and reservoir management measures are presented. Finally, key understandings and lessons learned from more than 50 years of experience are summarized. The La-Sa-Xing Field in the Daqing Field Complex contains three types of reservoir sands: Type I sand with high permeability, Type II sand with medium permeability, and Type III sand with low permeability. Polymer flood was studied in the laboratory in the mid 1960s, followed by small-scale pilots beginning in 1972 and industrial-scale pilots starting in 1993, all of which successfully reduced water cut and enhanced oil recovery. Fieldwide application commenced in 1996, targeting the Type I sand. With Type II sand being brought onstream in 2003, the project achieved a peak production of 253,000 BOPD in 2013. Polymer flood reduced water cut by 24.8%. Reservoir management measures, such as zonal injection, profile modification, hydraulic fracturing in low-permeability sand, and injection optimization, proved to be effective. Based on the water-cut performance, production can be divided into four stages: (1) water-cut decline, (2) low water cut, (3) rebound, and (4) water chase. Fit-for-purpose improved-oil-recovery measures were implemented for each stage to improve production performance. Key understandings and lessons learned include the following: (1) Polymer flood improves both sweeping and displacing efficiencies; (2) high interlayer permeability contrast leads to low incremental recovery; (3) variable well spacing should be adopted for different reservoir types; (4) adoption of large molecular weight (MW) and large slug size greatly enhances recovery; and (5) salt-resistant polymer is beneficial for produced water reinjection in Type II sand; (6) zonal injection increased swept reservoir zones by 9.8% and swept pay thickness by 10.3%; (7) profile modifications helped improve vertical conformance in injection wells and led to enhanced sweeping efficiency and extended low water-cut stage; and (8) optimization-recommended well spacing for Type I, Type II, and Type III sands is 10–15.5, 5.6–7.6, and 2.5–3.6 acres, respectively. In comparison with generally 6–8% incremental recovery by polymer flood in the industry, this project achieved an impressive incremental recovery of 12%, enhancing the oil recovery factor from 40% by primary recovery and waterflood to 52% stock tank oil initially in place (STOIIP). The progressive approach from laboratory experiments through pilots and finally to field application is a best practice for applying polymer flood fieldwide for a giant field such as the La-Sa-Xing Field.

Research of the impact of switching to low- salinity water during polymer water flooding

Background: Increasing the efficiency of a polymer flooding project, both technologically and economically, is always relevant.
 Aim: This paper aims to consider switching to less saline water as a fairly simple and effective way to increase the effectiveness of a polymer flooding project.
 Materials and methods: The work used data from a real polymer flooding project.
 Results: As a result, we have been able to significantly reduce polymer consumption and improve pumping efficiency.
 Conclusion: This work shows that, with the possibility of using less saline water, as a simple and effective way to reduce costs and increase efficiency, rolling polymer flooding.

Unified viscoelastic injectivity model: Analytical solutions predicting polymer excess pressure and fracture initiation

The most pressing question to embark on polymer flood projects is whether a polymer can be injected at economic rates while below reservoir parting pressure. There are several published examples of field polymer floods with unexpected injectivity and/or fracture initiation/propagation. Current commercial reservoir simulators lack the capability to model viscoelastic polymer rheology and fracture initiation and often lead to misleading expectations. The laboratory tests to select a polymer are performed without considering fracture or shear-thickening behavior near wellbores. This paper presents a physical-mathematical model to estimate excess pressure due to viscoelastic polymers and assist field operators in better polymer selection and injection design. One of the primary purposes of this paper is to develop predictive analytical tools based on the well-known Unified Viscoelastic Model (UVM), capable of estimating excess pressure and fracture initiation, independent of numerical solutions and reservoir simulators. Asymptotic techniques and special functions theory are utilized to construct a set of general closed-form analytical solutions. It is found that viscoelastic pressure drop can be determined by merely knowing the polymer rheology and slug radius from the wellbore. The derived viscoelastic pressure drop solutions can be easily implemented in MS Excel, which is convenient for engineers participating in the design and execution of polymer flooding projects. Analytical solutions are compared with numerical solutions, laboratory experiments, and field data, and excellent agreement is found.

Investigation of Brine pH Effect on the Rheological and Viscoelastic Properties of HPAM Polymer for an Optimized Enhanced Oil Recovery Design.

A novel approach to improve viscous and viscoelastic properties by exploiting the pH and salinity sensitivity of HPAM polymer is proposed in this paper. Polymer flooding is a well-developed and effective enhanced oil recovery technique. The design of the makeup brine is one of the most critical phases of a polymer flood project, since the brine composition, salinity, and pH directly influence the polymer viscosity and viscoelasticity. However, the viscoelastic properties of hydrolyzed polyacrylamide polymers have not been given much consideration during the design phase of polymer flood projects. Our experimental study focuses on the optimization of the makeup water design for polymer flooding by evaluating the optimum solution salinity and pH for better stability and improved viscoelastic behavior of the polymer. Initially, the brine salinity and ionic composition is adjusted and then hydrolyzed polyacrylamide (HPAM) polymer solutions of varying pH are prepared using the adjusted brine. Rheological experiments are conducted over a temperature range of 25–80 °C and at different aging times. Polymer thermal degradation as a function of pH is assessed by examining the solutions at 80 °C for 1 week. Amplitude sweep and frequency sweep tests are performed to determine the viscoelastic properties such as storage modulus, loss modulus, and relaxation time. A 15–40% increase in the polymer solution viscosity and a 20 times increase in relaxation time is observed in the pH range of 8–10 in comparison to the neutral solution. This can be attributed to the low-salinity ion-adjusted environment of the makeup brine and further hydrolysis and increased repulsion of polymer chains in an alkaline environment. These results indicate that the viscoelastic properties of a polymer are tunable and a basic pH is favorable for better synergy between the brine and the polymer. Alkaline low-salinity polymer solutions have exhibited 60% higher thermal stability in comparison to acidic solutions and thus can be successfully applied in high-temperature reservoirs. The results of this study show that polymer solutions with an optimum pH in the basic range exhibit a higher viscoelastic character and an increased resistance toward thermal degradation. Hence, the polymer solution salinity, ionic composition, and pH should be adjusted to obtain maximum oil recovery by the polymer flooding method. Finally, this study shows that more effective polymer solutions can be prepared by adjusting the pH and designing a low-salinity water/polymer recipe to get the additional benefit of polymer viscoelasticity. The optimized low-salinity alkaline conditions can reduce the residual oil saturation by stronger viscous and viscoelastic forces developed by more viscous polymers. The findings of this study can be employed to design an optimum polymer recipe by tuning the brine pH and salinity for maximum incremental oil recovery, particularly in high-temperature and high-salinity formations.

Current development of cellulose-based biopolymer as an agent for enhancing oil recovery

It is widely accepted that the chemical enhanced oil recovery (EOR) technique, especially polymer flooding, has been successfully implemented and improves oil production in oilfields worldwide. Polymers are injected into the well to increase the viscosity of the displacing fluid. Most of the polymer flooding projects employ synthetic polymer, and the rest uses biopolymer. Considering the environmental concern, it is encouraging to select biopolymer as an EOR agent. This study focuses on the current status of the development of the cellulose-based biopolymer for EOR since cellulose is abundant organic material in nature. Hydroxyethylcellulose (HEC) and Carboxymethylcellulose (CMC) have been utilized in the oil industry, while cellulose nanocrystal (CNC) and cellulose nanofibril (CNF) are recently being introduced as potential EOR agents. The evidence from the previously published data shows that cellulose-based biopolymers can improve oil recovery and have distinct characteristics. This study is a preliminary attempt for further application of cellulose-based biopolymer in EOR.

Analysis and Simulation of Polymer Injectivity Test in a High Temperature High Salinity Carbonate Reservoir.

Polymer flooding has gained much interest within the oil industry in the past few decades as one of the most successful chemical enhanced oil recovery (CEOR) methods. The injectivity of polymer solutions in porous media is a key factor in polymer flooding projects. The main challenge that faces prediction of polymer injectivity in field applications is the inherent non-Newtonian behavior of polymer solutions. Polymer in situ rheology in porous media may exhibit complex behavior that encompasses shear thickening at high flow rates in addition to the typical shear thinning at low rates. This shear-dependent behavior is usually measured in lab core flood experiments. However, data from field applications are usually limited to the well bottom-hole pressure (BHP) as the sole source of information. In this paper, we analyze BHP data from field polymer injectivity test conducted in a Middle Eastern heterogeneous carbonate reservoir characterized by high-temperature and high-salinity (HTHS) conditions. The analysis involved incorporating available data to build a single-well model to simulate the injectivity test. Several generic sensitivities were tested to investigate the impact of stepwise variation in injection flow rate and polymer concentration. Polymer injection was reflected in a non-linear increase in pressure with injection, and longer transient behavior toward steady state. The results differ from water injection which have linear pressure response to rate variation, and quick stabilization of pressure after rate change. The best match of the polymer injection was obtained with complex rheology, that means the combined shear thickening at high rate near the well and moving through apparent Newtonian and shear thinning at low rate.

An analytical tool to forecast horizontal well injectivity in viscous oil polymer floods

Injection rate is a key factor for successful polymer floods of viscous oil reservoirs. Injectivity during polymer flooding is lower compared to waterflooding due to the viscosity of polymer solution. Accurate estimation of injection rate/pressure build-up due to polymer injection is essential to evaluation and design of polymer flood projects. Typically, a short-term polymer injectivity test is performed on a single well, but it is hard to extrapolate future behavior of polymer injectivity because the tests are often too short. Reservoir simulation can be used to forecast injectivity, but the grid size and radial flow often affect the calculated injectivity. Analytical methods provide simple and quick ways to estimate injectivity using realistic reservoir conditions. The goal of this work is to develop an analytical tool and demonstrate its applicability by comparison with field data. An analytical solution is developed for the injectivity of horizontal wells in polymer floods in viscous oil reservoirs. The analytical solution is validated by comparing it to a numerical field-scale box model simulation. The pressure profiles are calculated using spreadsheets and compared against the data from several fields with increasing degrees of complexity. In each case, the analytical-spreadsheet method provides close matches of injection pressure data. This analytical tool can be used for preliminary design of polymer floods before getting into more complex and time-consuming reservoir simulations. • Developed an analytical solution for injectivity in viscous oil polymer floods. • Compared the analytical solution to numerical simulation with grid refinement. • Compared analytical solution to field data from 5 wells. • Novel tool to design and optimize polymer floods in viscous oil reservoirs.

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.

Polymer Injectivity Test Design Using Numerical Simulation

Polymer flooding is an enhanced oil recovery (EOR) process, which has received increasing interest in the industry. In this process, water-soluble polymers are used to increase injected water viscosity in order to improve mobility ratio and hence improve reservoir sweep. Polymer solutions are non-Newtonian fluids, i.e., their viscosities are shear dependent. Polymers may exhibit an increase in viscosity at high shear rates in porous media, which can cause injectivity loss. In contrast, at low shear rates they may observe viscosity loss and hence enhance the injectivity. Therefore, due to the complex non-Newtonian rheology of polymers, it is necessary to optimize the design of polymer injectivity tests in order to improve our understanding of the rheology behavior and enhance the design of polymer flood projects. This study has been addressing what information that can be gained from polymer injectivity tests, and how to design the test for maximizing information. The main source of information in the field is from the injection bottom-hole pressure (BHP). Simulation studies have analyzed the response of different non-Newtonian rheology on BHP with variations of rate and time. The results have shown that BHP from injectivity tests can be used to detect in-situ polymer rheology.

Experimental investigation and development of correlation for static and dynamic polymer adsorption in porous media

Part of the injected polymer during polymer flooding is lost in porous media by adsorption, mechanical entrapment, and hydrodynamic retention. Therefore, having a clear understanding of polymer losses/retention is very important for designing a technically and economically successful polymer flooding project. Polymer losses are traditionally modeled using Langmuir Isotherms, requiring costly and time-consuming dynamic corefloods to obtain fitting parameters. This research suggests a faster and low-cost method for first-order approximation of polymer adsorption in porous media without conducting corefloods. The proposed technique uses the results of polymer adsorption on the crushed core in the static test that can be used in a lookup table in the simulator instead of Langmuir Isotherms Equation. Mercury injection (MICP) was used to find a cut-off molecular size based on the hydrodynamic size of the polymer calculated using the Flory-Fox equation. Brunauer-Emmett-Teller (BET) tests are used to measure the specific surface area of the crushed core. These three tests determine the equivalent weight of crushed core to be used for static adsorption tests that would represent the specific surface area of the core. Seven high permeability Bentheimer core plugs from outcrops were used to perform polymer corefloods to determine polymer adsorption, followed by seven static adsorption tests performed at similar conditions to compare the results. Polymer adsorption tests showed that 1-h residence time, 0.5 solid-to-liquid ratio, and pre-saturating crushed core with brine before starting static adsorption were important to map static to dynamic polymer adsorption. Other important observations were the increase in polymer adsorption with increasing polymer molecular weight, polymer concentration, and NaCl salinity in order of descending significance of the effect. The proposed method gave a reasonable statistical correlation between static and dynamic polymer adsorption with a coefficient of determination (R2) of 0.97, and Pearson's correlation coefficient (r) of 0.98. The maximum deviation between static and dynamic result was 34% for cores of similar flow zones, and 48% for cores of dissimilar flow zones.

Screening and optimization of polymer flooding projects using artificial-neural-network (ANN) based proxies

Polymer flooding is one of the most broadly implemented chemical EOR processes due to its low injection cost and successes in oil production increments. This work develops artificial-neural-network based proxies by utilizing synthetic production histories generated from a high-fidelity numerical simulation model. Injection-pattern-based reservoir models are structured to establish the knowledgebase to train the proxies. A forward and an inverse-looking ANN models are structured in this study. The forward-looking expert system are employed as a forecasting and screening tool that is capable to predict time-based project responses. And the inverse-looking ANN predicts the project design schemes that fulfill the expected oil recoveries. The proxies are generalized considering reservoir rock and fluid properties and project design parameters. In this paper, we present results of extensive blind testing applications to confirm the validates of the proxy models. Afterwards, various applications of the expert systems are discussed. A project screening protocol that couples the expert system and particle swarm optimization (PSO) methodology is presented to maximize the polymer injection projects' net present value (NPV). Moreover, we propose a robust computational workflow that coupled utilize the inverse and forward-looking proxies to find various polymer injection schemes to fulfill the expected oil production profile, which effectively addresses the issue associated with the existence of non-unique solutions in the inverse design problems. The expert ANN systems and the associated project design workflows provide versatile approaches for the field engineers to obtain quick techno-economical assessments of polymer injection projects.

An Experimental Study on Hydrodynamic Retention of Low and High Molecular Weight Sulfonated Polyacrylamide Polymer.

Polymers are often added with water as a viscosifier to improve oil recovery from hydrocarbon reservoirs. Polymer might be lost wholly or partially from the injected polymer solution by adsorption on the grain surfaces, mechanical entrapment in pores, and hydrodynamic retention in stagnant zones. Therefore, having a clear picture of polymer losses (and retention) is very important for designing a technically and economically successful polymer flood project. The polymer adsorption and mechanical entrapment are discussed more in depth in the literature, though the effect of hydrodynamic retention can be just as significant. This research investigates the effect of the hydrodynamic retention for low and high molecular weight (AN 113 VLM and AN 113 VHM) sulfonated polyacrylamide polymer. Two high permeability Bentheimer core plugs from outcrops were used to perform polymer corefloods. Polymer retention was first determined by injecting 1 cm3/min, followed by polymer core floods at 3, 5, and 8 cm3/min to determine the hydrodynamic retention (incremental retention). A higher molecular weight polymer (AN 113 VHM) showed higher polymer retention. In contrast, hydrodynamic retention for lower molecular weight (AN 113 VLM) was significantly higher than that of the higher molecular weight polymer. Other important observations were the reversibility of the hydrodynamic retention, no permanent permeability reduction, the shear thinning behavior in a rheometer, and shear thickening behavior in core floods.

Geochemical performance evaluation of pre-flushing of weak and strong acids during pH-triggered polymer flooding

Implementing pH-triggered polymer is an efficient way to improve the conformance control of hydrocarbon formations. pH-triggered polymer solutions have high mobility in low pH conditions, while due to their high swelling capacity in higher pH values, their viscosity increases with pH increment. Therefore, they can fill high permeability zones/strata and consequently improve the efficiency of enhanced oil recovery. To achieve the desired viscosity of a pH-triggered polymer, the pH of porous media is regulated by implementing an appropriate acid pre-flushing. In this study, we develop a mathematical model to predict the acid pre-flush behavior before the main pH-triggered polymer flooding. Convection, diffusion, and homogeneous/heterogeneous geochemical reactions for a slightly compressible fluid flow in porous media is formulated. This model consists of three non-linear conservation equations (i.e., mass balance, species concentration balance, and Darcy law), which are solved simultaneously in a global implicit approach. We discretize the transport and geochemical reaction terms with a finite difference method by implementing the benefit of the Newton-Raphson method. Moreover, the code vectorization programming approach of the Python language is applied to decrease the computation time. The introduced model is validated against the experimental data available in the literature. This EOR method is mostly implemented on sandstones and there are very limited investigations on the applicability of this method on carbonate rocks. Hence, we simulate the injection of several acids (strong and weak acids) into a carbonate rock under different flow conditions (i.e., different Damkohler numbers). The obtained pH values reveal that weak acids can provide better results for acid pre-flushing in carbonate formations. Therefore, implementing these acids can be a more efficient way to increase the acid residence time as well as to improve the conformance control during a pH-triggered polymer flooding project.

An Overview on Polymer Retention in Porous Media

Polymer flooding is an important enhanced oil recovery technology introduced in field projects since the late 1960s. The key to a successful polymer flood project depends upon proper estimation of polymer retention. The aims of this paper are twofold. First, to show the mechanism of polymer flooding and how this mechanism is affected by polymer retention. Based on the literature, the mobility ratio significantly increases as a result of the interactions between the injected polymer molecules and the reservoir rock. Secondly, to provide a better understanding of the polymer retention, we discussed polymer retention types, mechanisms, factors promoting or inhibiting polymer retention, methods and modeling techniques used for estimating polymer retention.

A model-based decision analysis comparing water and polymer flooding in the development of a heavy oil field

Polymer flooding is an effective means to recover oil although the method creates conditions absent in traditional water flooding, mainly due to the physical phenomena related to this technique, such as adsorption of polymer molecules and non-Newtonian behavior. This work aims to guide the selection, through a decision analysis methodology, of the best strategy option using comparisons between water and polymer flooding projects in a heavy oil field development, under uncertainty, through a risk-return analysis.The methodology is based on a complete risk evaluation and decision analysis process presented by Schiozer et al. (2015), including the generation of uncertain scenarios, selection of representative models (RM), production strategy optimization for the RM, combination of the strategies in all scenarios, risk-return and risk curves analysis and the selection of the best strategy. The case study is representative of a heavy oil and high heterogeneous reservoir. We combined geological, economic and polymer uncertainties. We use Expected Monetary Value (EMV) as the objective function to measure economic return and Net Present Value (NPV) semi-deviation to measure risk.The results show that simplified comparisons between these two recovery methods, by only changing the injection fluid may lead to ill-informed decisions, and therefore, pre-planning is needed to realize the advantages from additional polymer costs to choose an optimal strategy. Furthermore, the results suggest that polymer flooding may be a viable alternative in the heavy oil field studied in this work.