Coreflood Tests Research Articles

Comprehensive evaluation of a novel re-crosslinkable preformed particle gel for the water management of reservoir with concentrated divalent ions

As one of the most widely used technology to ameliorate the reservoir's heterogeneity, polymer gels have been applied for more than 60 years. However, how to plug fractured reservoirs with significant abnormal features, high temperature and high salinity, especially the divalent cations, is still a challenging target. This work systematically evaluated a novel salt-resistant re-crosslinkable preformed particle gel (SR-RPPG) designed for fractured reservoirs with excellent salt resistance (up to 5 % CaCl2). We evaluated the swelling kinetics, thermal stability and plugging efficiency of this SR-RPPG. We assessed the swelling kinetic and re-crosslinking behavior of the SR-RPPG through the bottle test method. High temperature-resistant glass tubes with thermally stable O-rings were employed to evaluate the long-term thermal stability of the SR-RPPG product, and the testing lasted for over 200 days. A fractured model was used to assess the plugging efficiency of the SR-RPPG product. Results showed that the SR-RPPG could swell more than 30 times its original volume in 5 % CaCl2 and a middle east formation water. Besides, the SR-RPPG gel slurry can re-crosslink to form a rubber-like elastic bulk gel at 80–100 °C, and the elastic modulus of the re-crosslinked bulk gel can reach up to 1350 Pa with a swelling ratio of 10. The SR-RPPG prepared in 1 % NaCl, 2 % KCl, middle east formation water and 5 % CaCl2 with a swelling ratio of 10 have been stable for over 200 days at 100 °C. The core flooding test demonstrated that the SR-RPPG could efficiently block the open fractures, and the water breakthrough pressure gradient reached 927.30 psi/ft (20.98 MPa/m).

Analyzing the Benefits of Designing a Multifunctional Surfactant Blend From Laboratory Scale to Field Scale in Hydraulic Fracturing under High-Salinity Conditions: A Case Study of the Mississippian Limestone Play

Summary Surfactants are typically used in hydraulic fracturing applications to perform a single function, which results in multiple surfactants being used during operations. In this study, flow loop and coreflood tests were conducted with slickwater fracturing fluid systems and analyzed in conjunction to observe the effectiveness of flowback surfactants and their ability to increase friction reducer performance. A multifunctional surfactant blend (MSB) is tested against surfactant formulations commonly used either as a flowback aid or as a performance enhancer for low-cost friction reducers in harsh conditions. A case study is conducted using wells in the Mississippian limestone play to correlate laboratory investigations to field observations. Each surfactant solution was tested with a friction-reducing polymer in synthetic brine containing a salt concentration of 200 000 mg/L representative of harsh field conditions in the laboratory evaluation. Coreflood tests were conducted under reservoir conditions to evaluate flowback efficiency quantified by regained permeability. To test the ability of the surfactants to improve friction reduction (FR) performance, a 0.4-in. inner diameter friction flow loop was used. In the field-scale application, four wells were hydraulically fractured with two wells acting as control cases and two wells including the addition of the MSB. Completions and production data are presented to compare the performances of the wells and the efficacy of the MSB at the field scale. Friction flow loop testing showed that slickwater fluids with commonly used flowback surfactant formulations, including the MSB, can greatly improve the performance of economical freshwater friction reducers, even in a high calcium (13 000 mg/L) synthetic brine. The same slickwater/surfactant fluids used in the flow loop tests were evaluated in coreflood tests. Depending on the degree of polymer-induced damage created in the core samples, fluids containing the MSB offered the most consistent regained permeability. The laboratory-scale study shows that the MSB is functional for both polymer damage mitigation and acts as a performance booster for the FR, allowing a more economical friction reducer to be selected for slickwater fracturing. In field applications, including the MSB in the fracturing fluid resulted in increased oil production volumes and/or a reduced need for remedial operations throughout the early life of the well. The results of this study show that by properly utilizing the friction flow loop and coreflood laboratory-scale experiments, an optimized MSB can be selected for hydraulic fracturing operations at the field scale. By selecting a flowback surfactant formulation that also increases friction reducer performance, a lower friction reducer dosage or a more economical friction reducer can potentially lead to operational savings at the field scale.

A comprehensive study on the application of a natural plant-based surfactant as a chemical enhanced oil recovery (CEOR) agent in the presence of different ions in carbonate reservoirs

Surfactant flooding is a promising CEOR approach in carbonate reservoirs and its efficiency has been verified. Commercial surfactants may impose various health and environmental issues. Therefore, utilizing a natural biodegradable surfactant at a low cost is a valuable option for the petroleum industry. In this research, a non-ionic surfactant derived from Acanthophyllum Plant Root Extract (APRE) was used as a bio-surfactant. The EOR potential of this surfactant was evaluated through various tests. Oil-water system interfacial tension (IFT) measurement, contact angle test for carbonate rock wettability alteration assessment, emulsion stability, compatibility, and surfactant flooding test were conducted. The effect of different ions of various salts on the IFT, carbonate rock wettability and the chemical interactions were also studied. The emulsion stability created by the surfactant was assessed through observational tests. The compatibility test (at 25 °C) showed that negligible sediment below the salinity of 50,000 ppm was formed. The IFT at CMC in formation water (optimum concentration of 12000 ppm) was reduced to 1.06 mN/m from an initial value of 2.16 mN/m. The optimum IFT value at different salinities was also determined. The wettability of the carbonate rock from a strongly oil-wet state (168°) was altered to water-wet (60.3°) in the presence of surfactant and FW with a concertation of 10,000 ppm. In the core flood test, the effect of different slug sizes and soaking time was also determined. It was observed that increasing slug size results in a lower mobility ratio and consequently higher oil recovery.

Influence of Sandstone Mineralogy on the Adsorption of Polar Crude Oil Components and Its Effect on Wettability

The crude oil–brine–rock (COBR) system is a combination of contacting phases where polar organic molecules in crude oil, inorganic ions from the brine phase, and charged mineral surfaces participate in complex interactions. One of the surface phenomena that occur in the COBR system is the adsorption of polar crude oil components, which can directly affect the capillary forces and wettability of the rock. The purpose of this research work was to determine polar organic component (POC) adsorption trends for sandstones of different origins and mineralogical compositions. Adsorption preferences for acidic and basic POCs were quantified by potentiometric titration during dynamic core flooding tests using modified crude oil. The influence of POC adsorption on wettability was investigated by evaluating capillary forces during the displacement of oil in a spontaneous imbibition (SI) process. The results of this work showed a clear relationship between the intensity of POC adsorption and sandstone mineralogy. Greater adsorption capacity and a predominant affinity for bases compared to that for acids were found in the sandstone material containing a sufficient amount of reactive illite clay minerals. On the other hand, the sandstone material consisting mainly of quartz with an insignificant content of kaolinite clay did not show a pronounced tendency to adsorb POCs. All the studied rock materials have also shown a significant impact of POC adsorption on capillary forces and wettability, confirmed during SI tests. As a result, a detailed mineralogical analysis along with crude oil chemistry is required to properly evaluate sandstone wettability and competently plan core flooding laboratory studies.

Improved Oil Recovery from Carbonate Reservoirs by Tuning Injection Seawater Composition

In order to improve the adaptability of low-salinity waterflooding technology in some areas where freshwater resources are scarce, we aimed at implementing the low-salinity effect (LSE) in carbonate reservoirs through tuning injection seawater composition. LSE of ion tuning water (ITW) was verified by the results of core flooding tests, obtaining a water-free recovery factor of 50.7% and cumulative oil recovery of 77.2%. The micro mechanisms behind it were revealed via direct force-measuring and Zeta parameter (Zetap) measuring. Our results are expected to provide a new LSW strategy via tuning injection seawater composition in the case of carbonate reservoirs.

Minimizing calcium lactate precipitation via the addition of gluconate ions for matrix acidizing with lactic acid

Organic acids are commonly used to replace hydrochloric acid (HCl) in high reservoir temperature applications, as they are less corrosive and weaker than HCl. However, organic acids have shown some problems due to acid reaction product solubility. One such organic acid, lactic acid, produces calcium lactate when it reacts with calcite, which has a low solubility in water. However, reaction product solubility can be improved by up to five times when gluconate ions coexist with lactate and calcium ions. The objective of this research is to evaluate lactic and gluconic acid mixtures in term of dissolving calcite, reaction product, corrosion, wettability and generating dominant wormhole.Lactic and gluconic acids were mixed together using deionized water and seawater to conduct calcite solubility tests. Corrosion tests, between 4 and 12 h, were also run under reservoir conditions. A formation response test (FRT) apparatus was used to run different coreflood tests using different combinations of injection rates, total acid concentration, and temperatures. These tests were accompanied with analytical analysis utilizing ICP and IC to measure calcium, iron and sulfate ions in solution.The results showed that mixing lactic and gluconic acids at a 1:1 M ratio provided the optimal results as no precipitation occurred at total acid strengths of 10 wt% and up to 27 wt%. Seawater usage caused calcium sulfate precipitation; therefore, three scale inhibitors were evaluated to determine mitigation rates. Acid-calcite dissolving results were satisfactory when limestone was exposed to a 1:1 and 2:1 M ratio of crushed core-to-acid ratios as at least 50% of the crushed core was dissolved. However, the two-acid mixture showed a corrosion rate that was higher than the acceptable rates and a trace of iron lactate precipitation occurred at 200 and 300 °F. Five gpt from a sulfur-based corrosion inhibitor was enough to mitigate the corrosion rate to allow for 8 h of testing. Coreflood tests showed that the mixture penetrated limestone core with minimal acid pore volume without any face dissolution or salt precipitation on the core faces.This research presents a set of diverse experimental data to confirm that lactic acid accompanied by gluconic acid can penetrate carbonate formation without any by-product precipitation. The two organic acids are less corrosive and less hazardous which can provide a safe operation environment and can decrease replacement and maintenance costs.

Foam-Assisted Capillary Trapping in Saline Aquifers—An Initial–Residual Saturation Analysis

Capillary trapping of gas in porous media is important for many processes such as oil recovery and gas geo-sequestration. Foam can mitigate gravity override and viscous fingering of gas by reducing its relative permeability through gas trapping. However, there are limited studies dedicated to understanding how foam assists in gas trapping, the best mode of foam injection for trapping, and its application in geo-sequestration. This paper uses an initial–residual saturation analysis to investigate foam-assisted capillary trapping during the surfactant alternating gas (SAG) injection process in saline aquifers. More specifically, we studied the effects of pore geometric properties, in situ generated foam, and surfactant concentration on gas trapping efficiency and final residual gas saturation, Sgr. First, NMR surface relaxometry measurements were carried out on the rock samples to indicate the mean pore sizes of the rocks. A series of core flooding tests, equipped with resistivity measurements, were then conducted using single-cycle gas injection followed by water injection, water alternating gas (WAG), and SAG injection methods to identify which mode of injection results in the most trapped gas. The results showed that the SAG method had a better sweep efficiency and trapped more gas than other methods. The initial–residual (IR) gas saturation relationships from SAG data measured from several rock samples were then analyzed using Land’s trapping model. Gas trapping efficiency (indicated by Land’s coefficient, C) and residual gas were also found to increase in rocks with large average pore sizes and with increasing surfactant concentration. However, increasing the surfactant concentration above a certain limit did not cause further improvement in the trapping coefficient but only increased the Sgr. The results also showed that high values of surfactant concentrations might cause a slight reduction in the foam’s apparent viscosity, which then reduces the initial gas saturation, and consequently, Sgr. Finally, a linear relationship between the Sgr and the measured log mean of surface relaxation times (T2LM) was obtained, and two correlations were proposed. Therefore, the NMR measurements can be considered a reliable prediction method for Sgr in porous media.

Formation damage reduction during CO2 flooding in low permeability carbonate reservoir with using a new synthesized nanocomposites

Oil reservoir production rates gradually decline as reservoir pressure lowers. There are many causes for this, including precipitation and asphaltene (ASP) deposition. This investigation seeks to assess the performance of Synthetic Zeolite-Zirconia-Cerium oxide (ZZC) nanocomposites (NCs) in the prevention of ASP damage using a coreflooding test under reservoir circumstances. In this research, used SEM, XRD, and EDX analyses to prevent ASP precipitation in the static phase and address ASP precipitation issues in the dynamic CO2 (CF) flooding test. Using Na-ZSM-5 zeolite nanoparticles (NPs), CO2-oil IFT experiments, isotherm models, and CO2 core flooding (CCF) tests at the static stage were carried out in the presence of ZZC. After that, CCF tests at the dynamic stage were created under the static conditions that had been established in order to examine permeability/porosity reduction in porous media. In comparison to Na-ZSM-5 zeolite NPs, ZZC absorbed more ASP. Additionally, ZZC and Na-ZSM-5 zeolite had decreased ASP precipitation when the pressure dropped from 2600 to 1700 Psi. The ASP depositions in the dynamic phase were reduced after adding ZZC, and the permeability/porosity reduction characteristics were enhanced. The results of this study may be used to address ASP precipitation during production phases.

A novel hybrid nano-smart water with soluble chlorides and sulphates and silica-montmorilant-xanthan nanocomposite for EOR: Insights from IFT and contact angle measurements and core flooding tests

Injection of smart water mixed with various oil-water interfacial tension (IFT) reduction agents such as nanoparticles (NPs) into oil reservoirs is a proven enhanced oil recovery (EOR) method. A novel silica-montmorilant-xanthan was used to formulate novel hybrid nano-smart water solutions for EOR. Performance of the hybrid nano-smart water solutions as dispersion media at optimum salinity and NC concentrations was assessed. Stability, IFT, zeta potential, and wettability alteration of the solutions were assessed to find the optimum concentrations. Two groups of single and binary salts were used in the smart waters. Smart waters with individual NaCl, KCl, MgCl2, CaCl2, Na2SO4, MgSO4, CaSO4, and K2SO4 salts at concentrations of 1000, 2000, 4000, and 10,000 ppm in one group. Smart waters with a combination of each of the chlorates with various sulphates with equal ratios (1000/1000, 2000/2000, 4000/4000, and 10,000/10,000 ppm) in distilled water in another group. Smart waters with a combination of each of chlorates with various sulphates with equal ratios in distilled water in another group. Then the effects of the solution of these salts on IFT and contact angle in water-oil-sandstone and water-oil-carbonate systems were investigated. The optimum concentration of K2SO4+MgCl2 for the sandstone sample was determined as 1000/1000 ppm with 1000 ppm of the NC. The optimum concentration of MgSO4 for the carbonate sample obtained was 10,000 ppm with 250 ppm of the NC. The lowest IFT (15.42 mN/m) was obtained for the nanofluid with an NC concentration of 250 ppm. The results suggest that the salt-in effect and nano-film formation are behind the IFT reduction. Contact angle at the same NP concentration decreased from 109° (preferentially oil wet) to 33° (strongly water-wet) in the carbonate sample. For sandstone, the contact angle at the same NC concentration increased from 77° (preferentially water-wet to 117° - preferentially oil wet). Finally, we used the optimum formulas for core flooding to examine the performance of the prepared hybrid nano-smart water solutions. Using these novel hybrid nano-smart waters yields oil recoveries of up to 54% and 60% of the Oil Originally in Place (OOIP) in carbonate and sandstone samples, respectively.

Performance evaluation and mechanism study of a functionalized silica nanofluid for enhanced oil recovery in carbonate reservoirs

In this investigation, a functionalized SiO2 nanofluid was developed by integrating sodium oleate to mercapto-terminated nano-SiO2 via the thiol-ene “click” reaction. The developed nanofluid in the presence of higher concentrations (> 40,000 ppm) of NaCl at 70 °C was confirmed to be more stable than the original SiO2 nanofluid based on the outcomes obtained from precipitate observation, particle dimension, and zeta potential measurements. Successful integration of sodium oleate on the target nanoparticles was corroborated by a series of characterization approaches. Furthermore, the viscosity, contact angle, and interfacial tension (IFT) determinations were conducted to investigate nanofluids' potential for enhanced oil recovery (EOR). The results indicated that the viscosity of the functionalized SiO2 nanofluid (labeled FF-4) accounted for 3.48 cp after adding 40,000 ppm NaCl, while that of the original SiO2 nanofluid (labeled OF-4) was 1.15 cp. From the contact angle values, the carbonate rock surface was transformed from oil-wet (135°) to water-wet (72° and 38°) after being treated with the OF-4 and FF-4. The wettability alteration was attributed to the formation of the wedge film in the contact line area between the rock and fluids (oil sample and nanofluid). The functionalized nano-SiO2 helped to reduce IFT because of the simultaneous presence of the alkane chain (oleophilic) and carboxylate group (oleophobic) on the particle surface, making the functionalized nano-SiO2 have an amphiphilic structure. However, the original nano-SiO2 hardly changed IFT. Micro-model experiments showed that the OF-4 had a prominent oil displacement effect by changing wettability to a water-wet state and reducing the viscous fingering phenomenon. Core flooding tests demonstrated that the oil recovery factor of the FF-4 was almost 2.5 times that of the OF-4. Viscosity improvement was considered as a new oil recovery mechanism after wettability alteration and IFT reduction. This paper revealed the important properties of the functionalized nano-SiO2 and provided a novel efficient nanofluid for EOR in carbonate reservoirs.

An Extended Unified Viscoelastic Model for Predicting Polymer Apparent Viscosity at Different Shear Rates

Summary Polymer flooding is one of the most commonly used chemical enhanced oil recovery (EOR) methods. Conventionally, this technique was believed to improve macroscopic sweep efficiency by sweeping only bypassed oil. Nevertheless, recently it has been found that polymers exhibiting viscoelastic behavior in the porous medium can also improve microscopic displacement efficiency resulting in higher additional oil recovery. Therefore, an accurate prediction of the complex rheological response of polymers in porous media is crucial to obtain a proper estimation of incremental oil to polymer flooding. In this paper, a novel viscoelastic model is proposed to comprehensively analyze the polymer rheological behavior in porous media. This proposed model was developed and validated using 30 coreflooding tests obtained from the literature and further verified against a few existing viscoelastic models. The proposed viscoelastic model is considered an extension of the unified apparent viscosity model provided in the literature and is termed as extended unified viscoelastic model (E-UVM). The main advantage of the proposed model is its ability to capture the polymer mechanical degradation at ultimate shear rates primarily observed near wellbores. Moreover, the fitting parameters used in the model were correlated to rock and polymer properties using machine learning technique, significantly reducing the need for time-consuming coreflooding tests for future polymer screening works. Furthermore, the E-UVM was implemented in MATLAB Reservoir Simulation Toolbox (MRST) and verified against the original shear model existing in the simulator. It is worth mentioning that the irreversible viscosity drop for mechanical degradation regime was captured during implementing our model in the simulator. It was found that implementing the E-UVM in MRST for polymer non-Newtonian behavior might be more practical than the original method. In addition, the comparison between various viscosity models proposed earlier and E-UVM in the reservoir simulator showed that the latter model could yield more reliable oil recovery predictions as the apparent viscosity is modeled properly in the mechanical degradation regime, unlike UVM or Carreau models. This study presents a novel viscoelastic model that is more comprehensive and representative as opposed to other models in the literature. Furthermore, the need to conduct an extensive coreflooding experiment can be reduced by virtue of developed correlations that may be used to estimate model fitting parameters accounting for shear-thickening and mechanical degradation.

Iron Sulfide Scale Inhibition in Carbonate Reservoirs.

Hydrocarbon production operations include water injection, varying stimulation approaches, and enhanced oil recovery techniques. These treatments often affect reservoir formation, production, and injection facilities. Such sorts of well operations cause the formation of organic and inorganic scales in the near-wellbore region and various production and injection structures. Downhole squeeze treatment is commonly used as a control measure to prevent scale precipitation. A scale inhibitor solution is introduced into a formation by applying a squeeze treatment. The method allows scale inhibitors to adsorb on the internal rock surface to avoid settling down the scale precipitates. Thus, the study of adsorption of different types of inhibitors to prevent scale formation on the reservoir rock through the execution of downhole squeeze treatment is becoming necessary. This study incorporated different experimental techniques, including dynamic adsorption experiments of chelating agents employing a coreflooding setup, inductively coupled plasma-optical emission spectrometry (ICP-OES) to inhibit the formation of iron-containing scales in limestone rocks, and ζ-potential measurements targeting determination of iron precipitation in varying pH environments on calcite minerals. The influence of the inhibitor soaking time and salt existence in the system on chelating agent adsorption was also evaluated in the coreflooding experiments. The findings based on the coreflooding tests reveal that the concentration of chelating agents plays a significant role in their adsorption on carbonate rocks. The treatments with 20 wt % ethylenediaminetetraacetic acid (EDTA) and 20 wt % diethylenetriaminepentaacetic acid produced the highest adsorption capacity in limestone rock samples by inhibiting 84 and 85% of iron(III) ions, respectively. Moreover, the presence of the salts (CaCl2 and MgCl2) considerably decreased the adsorption of 10 wt % EDTA to 56% (CaCl2) and 52% (MgCl2) and caused nearly 20% more permeability reduction, while more inhibitor soaking time resulted in comparably higher adsorption and lesser permeability diminution. The results of ζ-potential measurements showed that the pH environment controls iron(II) and (III) precipitation, and iron(III) starts to deposit from a low pH region, whereas iron(II) precipitates in increased pH environments in calcite minerals.

A High Effective Acid System to Stimulate Sandstone Reservoirs

Mud acid is regularly applied to recover or increase permeability of sandstone reservoir. However, due to its rapid reacting rate and heterogeneous displacement, the stimulation effect of conventional mud acid is relatively limited in sandstone formations. For mud acid, it is important to choose proper chemical additives to retard reaction rate and make it distributed homogenereously in formation. To overcome these shortcomings of mud acid, a new proprietary mud acid system has been developed for sandstone formations stimulation. The new system is composed of 2.0% multichemical solutions (MCS) +6.5%HCl+1.5% HF, and the combined solution contains nonionic surfactant, clay stabilizer, and dispersant which were specifically formulated. Core flooding experiments were conducted with the high effective mud acid; meanwhile, XRD and SEM analysis were performed before/after the core flooding tests. Retarded tests were also conducted for the new mud acid reacting with sandstone samples. Treatments with ten pores volume of the new high effective mud acid system were found to increase permeability of sandstone core approximately three times of its initial permeability. From the results of SEM and XRD analysis, most of clays were dissolved, and permeability was increased after core flooding by this new mud acid solution. On the basis of acidizing theory, the reaction retarded mechanism was explained about the new composite mud acid. Other properties of the new composite mud acid were also discussed. In comparison of conventional mud acid, the new composite mud acid can retard acidizing reaction rate and distribute evenly in formation; therefore, it can extend acidizing penetration and stimulate sandstone formation thoroughly. The new composite mud acid is more compatible and desirable than conventional mud acid, and it will be applied extensively for sandstone matrix stimulation.

Anaerobic activation of microorganisms indigenous to oil reservoirs to enhance oil recovery

Microbial enhanced oil recovery focuses on the activation, isolation, and screening of aerobic functional bacteria. Air injection is required to activate aerobic microorganisms for use in indigenous microbe oil displacement technology. In practice, however, oil reservoirs are oxygen-free, as the oxygen in the air is rapidly consumed by reducing substances and aerobic microorganisms attached to the water injection well at the front end of the reservoir. In the reservoir, most of the microorganisms metabolize anaerobically, and they are concentrated in the area where the residual oil collects in the rear of the facility. The aim of this study was to investigate the factors such as electron acceptors, activator components, and activator concentrations that influence anaerobic metabolism in indigenous microorganisms. Core flooding tests and field trials were conducted to evaluate the anaerobic microbial activation efficiency. The organic nitrogen source in the activator was crucial to anaerobic bacterial metabolism. Yeast powder was the preferred nitrogen source, and other optimal operating parameters included a C/N ratio of 20:1 and an activator concentration of 3 g·L−1. Under these conditions, the anaerobic emulsification index surpassed 90%. Core flooding tests demonstrated that microbial enhancement may provide up to 13.5% oil recovery. A total of 3471.15 BBLs of oil was recovered by injecting anaerobic activator into the Zhan3-15 well, and emulsified oil droplets were detected in the fluid. The results of this study could provide technical support for the practical anaerobic activation of reservoir microorganisms and the improvement of microbial enhanced oil recovery.

Environmental comparative study of biosurfactants production and optimization using bacterial strains isolated from Egyptian oil fields

Biosurfactants have recently gained popularity because they have numerous benefits over chemical synthetic surfactants, including higher biodegradability, lower toxicity, higher foaming, environmental compatibility, and effective properties under harsh conditions. This study aimed to produce effective biosurfactants by selected bacterial strains isolated from Egyptian oil fields to improve oil recovery and investigate their environmental aspects for microbial enhanced oil recovery. The selected strains were incubated in a new proposed nutrient medium H to produce biosurfactants with optimum surface and emulsification activities. Stability studies were conducted to examine the tolerance of produced biosurfactants in harsh reservoir conditions. Core flooding tests were performed to investigate the potential of produced biosurfactants in enhancing oil recovery. The environmental risk assessment was conducted to investigate if there are any possible threats of the selected bacterial strains. Results showed that selected bacterial strains Bacillus licheniformis and Bacillus subtilis could produce effective biosurfactants that reached their maximum surface activity after 24 h of incubation by reducing the surface tension from 71.8 mN/m to 27.13 mN/m and 25.74 mN/m, and the interfacial tension against kerosene from 48.4 mN/m to 1.27 mN/m and 0.38 mN/m at critical micelle concentration of 0.06 g/l and 0.04 g/l, respectively. The produced biosurfactants by Bacillus licheniformis and Bacillus subtilis showed significant emulsification activity against crude oil with emulsification indices of 50.2% and 63.7%, respectively. High stability was observed at high temperatures for a long-time period and more than 60% of their surface and emulsification activities were maintained over a wide range of pH and salinity. It was also found that 31.41–39.35% of additional oil could be recovered by the produced biosurfactants. Finally, Bacillus licheniformis and Bacillus subtilis are environmentally safe, have no potential for toxicity, and no risk could occur for MEOR.

Crude oil degradation in oilfield produced water by immobilized microbes and oil recovery improvement after its reinjection

Oilfield produced water (OPW) with crude oil is a huge threat to the natural environment. For the treatment of OPW, degradation of crude oil in OPW by microorganisms and OPW activation by microbial metabolites for oil recovery improvement after reinjection may be an effective and sustainable approach. In this study, the degradation of crude oil in OPW by immobilized isolated bacteria was designed and the enhancement of oil recovery by reinjecting treated OPW was examined. Aldehyde fiber was found to show the optimum immobilization effect for three isolated oil-degrading-bacteria (Pseudomonas sp. ZJI-1, Acinetobacter sp. YMJ-1, and Gordonia sp. G1). The crude oil degradation rate of the immobilized bacteria reached 82.6% within 7 days. The contents of some bioactive molecules helpful for oil recovery, including rhamnolipid and acetic acid, increased continuously in the designed system. Core flooding tests demonstrated that oil recovery increased by 8.61% after the treated-OPW reinjection. In summary, the immobilized bacteria could effectively remove crude oil from OPW, increase the contents of rhamnolipid and acetic acid, and in particular, improve the oil production efficiency after reinjection.

Accurate prediction of enhanced oil recovery from carbonate reservoir through smart injection of nanoparticle and biosurfactant

Selecting the most suitable enhanced oil recovery (EOR) method and subsequently an accurate prediction of EOR are essential in reservoir engineering. Generally, interfacial tension (IFT) and wettability alteration are effective agents on EOR. The aim of this work is to understand how contact angle can be changed additionally to the IFT changes. Different tests on IFT, wettability alteration, and core flooding of limestone slabs using rhamnolipid, N-doped graphene nanoparticle, and a mixture of aqueous solution of rhamnolipid with N-doped graphene were performed. Rhamnolipid at the CMC (250 mg/l) had just a significant effect on IFT reduction so that IFT decreased from 8.1(brine/oil system) to 0.4 mN/m. N-doped graphene at the CMC (500 mg/l), had only a significant effect on wettability so that it altered the slabs wettability from strongly oil wet (θ = 133.5°) toward strongly water-wet (θ = 51.5°). When both were used simultaneously at their CMC, the contact angle and IFT reached to 56° and 0.97 mN/m, respectively. Based on core flooding tests, 8.2%, 18.1%, and 24.2% of OOIP were obtained using N-doped graphene, rhamnolipid, and a mixture of them at their CMC, respectively. Our results showed that IFT has a more important role on Sor than the wettability change. The findings of this study can help for better understanding of the mechanism behind EOR using the combination of the biosurfactants and nanoparticles.

Experimental study of secondary and tertiary modes combined low salinity water and polymer flooding in sandstone porous media

AbstractCombined low salinity water (LSW) and polymer (LSP) flooding is the most attractive method of enhanced oil recovery (EOR). Considerable research has investigated effective mechanisms of LSP flooding. In this study, 10 laboratory core flood tests were carried out to evaluate the effects of LSW injection into samples without any clay particles, the timing of LSW injection, and the advantages of adding polymer to the injection water for EOR. Secondary and tertiary LSW injections were performed on sandpack samples with different wettability states and water salinity. Tertiary LSW injection after secondary synthetic seawater (SSW) injection in oil‐wet samples resulted in 13% more oil recovery, while the water‐wet sample showed no effect on the oil recovery. Secondary LSW injection in oil‐wet porous media improved oil recovery by 8% of the original oil in place (OOIP) more than secondary SSW injection. Tertiary LSP flooding after secondary SSW injection in the oil‐wet sample provided a recovery of 67.3% of OOIP, while secondary LSW injection followed by tertiary LSP flooding yielded the maximum ultimate oil recovery of about 77% of OOIP. The findings showed that the positive EOR effects of LSW and LSP flooding were the results of wettability alteration, pH increase, improved mobility ratio, better sweep efficiency, and oil redistribution. In addition, results showed that wettability alteration is possible without the presence of clay particles. The findings of this study can help for a better understanding of fluid propagation through the porous media and an investigation of delays in reaching ultimate oil recovery.

A Three‐Dimensional Study of Wormhole Formation in a Porous Medium: Wormhole Length Scaling and a Rankine Ovoid Model

AbstractUnderstanding how wormholes develop and how they change the permeability of the porous medium is important for many natural and industrial processes in subsurface solid‐fluid systems. We conduct core flood tests to study the wormhole formation in a porous medium under different flow rates and at different moments before breakthrough. We show that the wormholes created in core flood tests have lengths following a power‐law distribution, with more short ones than long ones. This statistical nature of the wormhole lengths allow one to experimentally study the wormhole competition in 3‐D: Many wormholes develop initially near the inlet, but only a few develop further. Our experimental results also show that the existing wormhole‐matrix models underestimate wormhole lengths because of the neglected additional pressure drop caused by the radial flow near the wormhole tip. We improve upon the existing models by approximating the radial flow near the wormhole tip with a Rankine ovoid model.

Matrix acidizing is a good stimulation process in which acid is introduced into the reservoir near the wellbore area via the wellbore or coil tubing. In the oil industry, formation damage is a prevalent problem. Bypassing wellbore damage by producing wormholes in carbonate reservoirs is the main purpose of acidizing the matrix of the formation. When doing lab tests, scientists

Matrix acidizing is a good stimulation process in which acid is introduced into the reservoir near the wellbore area via the wellbore or coil tubing. In the oil industry, formation damage is a prevalent problem. Bypassing wellbore damage by producing wormholes in carbonate reservoirs is the main purpose of acidizing the matrix of the formation. When doing lab tests, scientists are looking for a wormhole-inducing injection rate that can be used in the field. Meantime the ongoing works on the Ahdeb oil field's Mishrif reservoir, several reports have documented the difficulties encountered during stimulation operations, including high injection pressures that make it difficult to inject acid into the reservoir formation; and only a few acid jobs have been successful in Ahdeb oil wells, while the majority of the others have been failures; For this formation, there is a high incidence of oil well stimulation failed. This requires more study. Thus, in this work, we experimented to examine the effect of acid treatment on the petrophysical parameters of the Mishrif reservoir. The acid core-flood tests used seven core samples from a central Iraqi oil field.