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Water injection fields account for over half of Malaysia’s oil production, with most of these fields at matured waterflooding stage. Low sweep efficiency due to water conformance where reservoir with high heterogeneity might cause premature breakthrough is one of the issues that leads to low oil recovery. In this study, we described the comprehensive experimental analysis to substantiate waterflooding performance in heterogeneous reservoirs by evaluating the flow diversion chemical (FDC) as a water conformance agent at high temperature.Chemical characterization, rheology, particle size analysis, compatibility, and thermal stability were evaluated for FDC according to the prevailing mechanism. Afterward, an experiment to simulate the reservoir environment was conducted to estimate oil incremental and blocking mechanism, in terms of residual resistance factor (RRF) performance in the intended field condition.The test was innovatively set up using commercial outcrop and reservoir native cores in dual-core permeability systems to test high permeability and low permeability porous media at high temperature up to 115°C temperature to mimic the conformance process. Typical single core flooding test are only able to determine the potential of the blockage mechanism by determining the RRF, without the diversion effect to quantify the additional oil recovery from the flow diversion process. The setup uses cylindrical preserved core plug samples with permeability contrast ranges from 100mD to 2 Darcy and tested at 115°C. The customized coreflood design successfully mimicked the conformance process. In our study, the RRF of 186 and cumulative oil recovery of 52% with an incremental oil recovery of >5% was obtained by the FDC injection.The study provides an innovative way in the coreflooding experiment to evaluate the performance of a conformance control agent in a heterogeneous reservoir with high temperatures.

Fines migration is a recognized as one source of formation damage in oil and gas production wells. A newly fine stabilizers chemical was developed and applied to prolong oil well productivity by adhering the migrating fines to the pore surfaces and reducing the tendency for mobilization as observed in the laboratory. The paper presents the successful pilot application and monitoring process of newly developed fine stabilizer in an oil well with has a history of rapid decline after several times of stimulation.A screening process to identify pilot well was carried out into well "C". The well was natural flow for almost 2 decades but in last 8 years, it showed a sharp oil productivity decline after several times workover (re-perforation). A series of experiments were performed to identify the root cause of the rapid decline of the oil well and concluded due to migrating clays. The newly fines stabilization chemical was developed which has a purpose to prevent detachment of those fines and prolong the formation structure integrity by keeping the fines stuck on the rock surface. The workflow breakdown design structure for injection and monitoring were carried out to ensure the well achieve the agreed objective that was to increase back production by reperforation job and to reduce production decline rate by 90% for the first 6 months and 30% afterwards.As a first pilot, well "C" has the main target to delay the production decline after re-perforation due to fines migration as concluded based on root cause analysis of formation damage from comprehensive laboratory experiments. The novel inhouse fines stabilization chemical was introduced as damage remedial by neutralizing fines migration through microflocs and coagulated fines as solid. It was injected near the wellbore around 4-5 ft. and monitored for 6 months. The sampling was taken regularly to measure produced clay and sands and compared with the pre-treatment results. The particle size measurement showed if the produced particles decreased significantly. The post-treatment of fine stabilizer chemical shows that it can prolong oil well productivity by delaying the decline rate to 1.5%/month for 6 months monitoring period and even stable over 1 years, which means exceed the expectation.The successful result of well treatment using newly fine stabilizers chemical has unlocked additional oil production and prolong well life.

The slug flow regime typically forms during multiphase flow in subsurface and surface facilities, which can result in severe flow capacity losses. The foam injection is a proposed method to control and remove slugging in the wellbore and nowadays, the foam application has been extended to controlling the slugging in the pipeline transportation. Prior to a pilot deployment in an offshore Field "S", this study describes a technological assessment review of a newly designed internal foam chemical to control slugging. This application for controlling foam slugs aims to eliminate hydrodynamic slugs that constantly form at Field "S" due to wave instability at gas-liquid flow rates. Based on liquid level trending at surface facilities platform of Field "S", a slug flow regime was observed from severe fluctuation trending. Technology assessment was conducted using inhouse guidelines that aim to shorten overall pilot deployment to initiate testing as early as possible. The laboratory experiment was performed including compatibility tests. The foam stability and interfacial tension (IFT) were carried out using Teclis Foamscan and Grace spinning drop tensiometer, respectively. Meanwhile, the rheology characterization of foam was conducted using a Foam rheometer for the viscosity test. A slug flow regime was discovered based on severe fluctuation trending at surface facilities platform of Field "S" for liquid level trending. Utilizing internal guideline designed to hasten the entire pilot deployment and start testing as soon as possible, technology assessment was done. A pressurized foam Rheometer was used to measure the foam dynamic viscosity, and it measured about 5.2 cP at a shear rate of 1000 s-1. The IFT measured lower than with water and other commercial foamer. When the foam chemical, defoamer, and demulsifier were tested for compatibility with production chemicals such scale inhibitor, corrosion inhibitor, and biocide, neither precipitation nor separation was seen. The recently developed foam chemical may help to further reduce corrosion from 0.17 mm/y to 0.05 mm/y. The technical, operational, health and safety, and environmental major unknown elements of this newly designed technology have all been evaluated and identified. Foam created by foam injection is a main challenge with this method, but it has been overcome by finding the right demulsifier and defoamer. Based on this study, a newly developed foam chemical has been identified as a potential to be deployed in reducing liquid slugging in the pipeline. If slugging can be effectively controlled, value creation will result from an increase in gas and liquid production as well as the avoidance of pipeline maintenance and repair.

The scale problem is turning into a fluid-related flow assurance concern in oil and gas wells at various locations in the Malaysian basin. Flow assurance issues can have a severe influence on the total fluid production trip from subsurface to surface. Oilfield scale comes in different varieties, including organic, inorganic, gas, soap, and mixed scales. In the past, there was only one type of scale dissolver chemical that could be used, making it less efficient to dissolve multiple types of scales at once. The evaluation of a recently developed, so-called robust solid dissolver (RSD), from the lab to a pilot deployment, is presented in this work. The RSD technology was developed based on a stable micro-emulsion solution that comprises acid and solvent components. Near the wellbore and along the tubing string of an oil well, it can concurrently dissolve organic and inorganic scales. After extensive visual analysis and laboratory experimentation, it was determined that the mixed scales issue was the cause of the oil production's rapid decline. This conclusion was supported by laboratory analysis and observations made from the wellsite throughout the tubing string and near wellbore casing. Based on laboratory tests, RSD can dissolve mixed scales 100% in 24 hours at well temperature and no incompatibility issue with production chemicals and all the pumping/wireline components. The RSD was developed based on the total organic system that can prevent corrosion, is compatible with hydrocarbon. The RSD was piloted at oil well "1" at Field PN and executed successfully to remove mixed scales and the well was revived. Based on result from the first Pilot, it revived oil well, increased production at a certain level. By increasing oil production rate and having value creation as a single chemical treatment to address mixed scales concerns, the new RSD has unlocked its potential to revive the well due to mixed scale issues.

A novel developed fines stabilizer (FS) chemical was used to successfully treat an oil well by reducing the decline rate from 17% per month (pre-treatment) to 1.5%/month (post-treatment for a 6-month monitoring period). Following this success story, more qualified candidates are flocking to replicate it. As a result, the challenge now is to predict each candidate's post-treatment performance. The paper focuses on the development of numerical modelling of a fine stabilizer chemical using a chemical reaction approach to understand the mechanistic process and will serve as a benchmark for future technology replication performance prediction. The mechanisms of the novel developed FS chemical were observed in the laboratory through fine particle coagulation and flocculation. The methodology of this study is to translate the mechanisms and key features associated with observed laboratory data into a scripted chemical reaction program that was coupled with a numerical reservoir simulator. Prior to well modelling, laboratory coreflooding data were validated. To properly represent the mechanistic process with a chemical reaction approach and capture the near wellbore effect, a single well model with local grid refinement was developed. The chemical reaction feature provides a versatile toolbox for modeling complex processes involving chemical and physical interactions. The actual production data history matching process with was carried out to investigate key important parameters. The FS chemical reaction was divided into two stages: damage and treatment. The damage was defined as fines deposited in the pore throat plugging and reducing permeability near the wellbore. Fines migration frequently indicates a build-up of fines in the near-wellbore region over time. As a result, the damage caused by these deposited fines reduces permeability. The novel FS chemical will remove deposited fines through micro-flocs and coagulating fines as solid. The history matching process was completed for core data and the mechanistic model with production and pressure data, and acceptable matches were obtained using rate control. The mechanistic model was tested with constrain at bottomhole pressure for few months historical data. It can predict the production performance with good accuracy compared to actual welltest data. Key parameters of FS injection were observed because of this research and can be used as a benchmark in the future to demonstrate the concept of extending oil well productivity and predicting field replication to recurrence the success story.

The deployment at the field-scale of a novel technique to improve oil recovery using nanoparticles injection is challenging. It requires a comprehensive evaluation of a series of laboratory experiments, to translate and validate the mechanisms into a numerical model to predict accurately and reduce uncertainty parameters. This paper describes the application of novel advanced reservoir modeling for nanoparticles from pore-scale to field-scale, using an offshore Malaysian oilfield as a pilot field case. A series of laboratory experiments (fluid-fluid and fluid-rock) and numerical studies: nanofluid formulation, pore-scale studies, validation, and upscaling process into the field-scale model were carried out. The development of nanofluids was formulated to meet key criteria such as compatibility and thermal stability at the intended field condition. Prior to coreflooding tests with native core, a series of experiments to observe mechanisms were carried out. The results of the laboratory experiments were then validated in the 1D coreflooding model. The procedure was continued with observed critical parameters being scaled-up into 3D field-scale model before running the prediction scenarios. The newly developed nanofluids for the intended field performed well in compatibility and thermal stability tests at reservoir temperature. Precipitation and sedimentation were not observed in this solution. The wettability alteration to more water-wet was observed with consistent results through interfacial tension measurements, contact angle measurements, and relative permeability measurements. Coreflooding was performed using native core, and the reduction of residual oil saturation was approximately 25% between pre- and post-nanoflooding. The adsorption of nanofluids was measured to be around 1.12 mg/g of rock. All these results were input into the model and the history match quality index achieved an acceptable match of ~95%. Several critical parameters for the upscaling process were investigated such as reaction rate of particle aggregation, adsorption, and retention factor. During the scale-up process, the velocity of the fluids and pressure drop were conserved because the recovery is sensitive to flooding rate and the viscosity of the fluids are pressure dependent. The field-scale model was run for the intended field location. The potential of using nanoparticles was evaluated and compared to the no further activity scenario giving an additional recovery factor of approximately 1% per year. The developed method of novel robust advanced reservoir modeling for nanoparticles creates a new reference as the first application in the world of novel advanced numerical modeling at field-scale.

The nanoparticles are considered as an attractive emerging improved oil recovery technique in last decade due to its ability to propagate deeper into pore throat and displace unswept oil in the reservoir. Current understanding of its mechanisms in conventional oil has been observed so called disjoining pressure that involved wettability alteration, log-jamming, and viscosity effect. This paper presents recent investigation of new potential mechanism during development of nanofluids to improve oil recovery in Malaysian oilfield. The new inhouse nanofluids was developed using acrylamide monomers that were grafted on the surface of silica-based nanoparticles. A minor concentration of surfactant was introduced into the formulation to observe synergistic effect. The nanoparticles were characterized under electron microscope. Compatibility and thermal stability tests were conducted using reservoir fluids at reservoir temperature. The rheology of fluids was measured during monitoring of stability. In term of wettability alteration, sequence fluid-fluid and rock-fluid tests were conducted includes dynamic interfacial tension (IFT) and optical contact angle (OCA) measurement. The particle size was measured with size around 20 nm. Adding small concentration of additive showed good performance in term of compatibility, thermal stability, and wettability alteration through IFT reduction and OCA measurement. Nanofluids with additive provided excellent compatibility with reservoir fluids and stable at reservoir temperature over 60 days. Its viscosity was also more stable during observation period without creating micro-emulsion. The IFT reduced insignificantly from 2.6 to 1 mN/m and when introduced additive, the IFT reduction achieved 0.01 mN/m. This synergistic effect was observed during IFT measurement and called as fragmentation. Our recent finding leads to provide new reference for displacement mechanism using next generation of nanofluids and offers further potential of nanoparticles with multiple mechanisms and rapid synergistic effects prior its application in in Malaysian oilfield.

A naturally flowing well "C" was experiencing a sharp oil productivity decline (13%/month) and skin build-up was observed from well testing to ascertain quantitatively whether damage occurs. Meanwhile, asphaltenes and paraffins are well-known as the primary sources of organic deposition that can compromise the well's flow assurance, occurring not only in the wellbore but also in the reservoir pores, reducing flow efficiency and clogging the flow paths. This paper discusses an integrated workflow for determining the root cause of damage in the well. Thus, the remedial strategy can be better defined. Laboratory testing is crucial to identify the root cause of damage. The integrated laboratory experiments were designed to elucidate, diagnose, and mitigate the damage mechanism. In this study, it was divided into 3 integrated tests: rock solids (inorganic), fluids (organic), and mixtures (wax). The X-ray diffraction (XRD) technique was used to determine mineral compositions of rock. The particle size dispersed in reservoir fluid were measured through dynamic light scattering instrument. The properties and precipitations of organic and mixtures were measured. Water composition and crude oil were analysed and characterized through saturate, asphaltene, resin and aromatic (SARA) analysis. The colloidal stability index was determined from SARA analysis and considered stable. The composition of water was determined to contain only 20 ppm of calcium carbonate. The wax content, pour-point and wax apparent temperature were measured at 1.61%, 6°C, and 12°C respectively, which was significantly lower than the flowing tubing head temperature. Therefore, the potential damage caused by organic and mixtures deposition can be minimized. This well was being produced from sandstone rock, there was no obvious evidence of sand being produced into the surface, which was consistent with observations from a neighbouring well producing from a similar formation. Sand production was measured around 9-15pptb, which was classified as an obscurely produced sand problem. The mineralogy of the formation has been determined using XRD analysis both from the observed well and a neighbouring well. Both wells demonstrated consistency when the clay content was 20-30% with the major clay type observed as migrating clay (>50%) and minor as swelling clay ( The workflow can identify the root cause of formation damage in this well, which is a mechanical mechanism caused by fines migration. Treatment with a fine stabilizer may be chosen to prolong the productivity of the well. This workflow can be used as a practical guide for determining the source of formation damage via integrated laboratory experiments.

PVT analysis of reservoir fluid samples provides essential information for determining hydrocarbon in place, depletion strategy, and hydrocarbon flowability. Hence, quality checking (QC) is necessary to ensure the best representative sample for further analysis. Recently, a novel tool based on Equation of State (EOS) was introduced to tackle the limitation of the Hoffmann method for surface samples with high impurities and heavier components. This paper presents comprehensively evaluating a novel EOS-based method using various PVT data from Malaysian fields. Numerous PVT separator samples from 30 fields with various reservoir fluids (Black Oil, Volatile, and Gas Condensate) were carried out and evaluated. The impurities contain a wide range of up to 60%. The 2-phase P-T (pressure and temperature) diagram of each oil and gas phase before recombination was calculated using PVT software based on Equation of State (EOS). The 2-phase P-T diagram was created and observed the intersection point as calculated equilibrium at separator conditions. Once it is observed and compared with written separator condition in the laboratory report and observed its deviation. Eventually, the result will be compared with the Hoffmann method. The Hoffmann method is well-known as a traditional QC method that was initially developed using gas condensate PVT data to identify possible errors in measured separator samples. If the sample has high impurities and/or heavier components, the Hoffmann method will only show a straight line to the lighter components and those impurities and heavier components will be an outlier that engineers will misinterpret that it has errors and cannot be used for further analysis such PVT characterization. The QC using EOS-based were conducted using actual fields data. It shows potential as novel QC tools but observed only less than 10% of data with complete information that can meet intersection points located precisely similar with reported in the laboratory. There is some investigation and evaluation of the EOS-based QC method. First, most of the molecular weight of the heavier fluid composition of gas and oil phase was not reported or used assumptions especially when its mole fraction is not zero. Second, properties of heavier components of the oil phase (molecular weight and specific gravity) were not measured and assumed similar as wellstream. Third, pressure and temperature data are inconsistent between the oil and gas phase at the separator condition. This study can provide improvement in laboratory measurement quality and help engineers to have a better understanding of PVT Report, essential data requirements, and assumptions used in the laboratory. Nevertheless, the Hoffmann method can be used as an inexpensive QC tool because it can be generated in a spreadsheet without a PVT software license. Both combination techniques can provide a comprehensive evaluation for separator samples with high impurities before identifying representative fluid for further analysis.

As an emerging technology, nanoparticle offers advanced benefits to be used as a novel improved oil recovery method. The nanoparticle has a much smaller size than pores of rock that can penetrate deeper in the reservoir and it is easily functionalized to change the wettability of rocks. However, the synthesize and screening process of nanofluids will be a laborious task and need a long-term period and numerous cores at rock-fluid tests. It would be a big issue if the research period is short and native cores are limited or even unavailable. This paper presents a rapid test approach to evaluate nanofluids for a Malaysian oilfield with limited cores. Numerous nanofluids: nanopolymer and nanosurfactants, were evaluated using crude oil from a selected oilfield. Rapid measurement tests are proposed based on a parallel bottom-up approach from contact angle, thermal stability, and interfacial tension (IFT) measurement with at reservoir temperature conditions. Glass plate was initially used as the solid media for optimization of nanofluids concentration. Once this is ascertained then it can be used for further analysis on limited native core slab. Rock mineralogy, fluid rheology, and characterization were also determined. The fluid-fluid and rock-fluid measurements were repeated to ensure consistency of results and to estimate deviation in measurements. Based on a rapid test approach, it was observed that the screening process only took several days instead of months to select suitable nanofluids and glass plates that could be used in the screening process to reduce consuming cores for oilfields with a limited core. A series of glass plate experiment showed consistent results with the core slab. It was observed that dynamic optical contact angle using can achieve steady conditions for approximately half an hour. It was also observed that both the glass plate and replicate core slab show consistency of wettability alteration trend and benefits of multiple runs can observe how big the deviation of measurement. As predicted, all nanofluids can alter the rock wetting behavior. A decreasing contact angle showed that the solid media was rendered to be more water-wet, which implies better oil displacement due to residual oil saturation reduction. Surfactant grafted nanoparticles have given marginal effect on IFT reduction at a certain concentration and achieved steady in less than an hour. These results showed the most potential rapidly for further analysis on coreflooding experiments. The rapid test approach can evaluate and screen nanofluids for detailed coreflooding experiments. This approach readily applies for uncored or limited cores and limited research period.

Water alternating gas (WAG) is a well-known strategy to improve the mobility issues during gas injection. However, WAG was identified still having some challenges during implementation at oilfield with high reservoir heterogeneity and high permeable zones in the reservoir and will cause unfavorable mobility ratio. Enproperties of the selected core samplehancement of WAG (EWAG) using foam and surfactant has been research to solve its issue and has success stories. This paper will describe the work process of EWAG to be Pilot at Malaysian oilfield, focusing on numerical investigation during upscaling process. Foam treatment has role for gas mobility control, delaying gas breakthrough and diverting gas to unswept zones. Meanwhile, the surfactant was utilized to reduce the IFT between gas and liquid to enable gas dispersion into liquid phase. An in-house foaming surfactant has been developed and used for coreflooding experiment at harsh environment. It was used to generate stable foam in contact with gas and it caused a mobility reduction which was suitable for mobilizing trapped oil and hence improving oil recovery. Coreflood experiment was performed on native core and all experimental results were consolidated and checked for the quality prior model calibration in the reservoir simulator. Once coreflood model was constructed, base case was run using default foam parameters. It aimed initially to test whether the model run smoothly and to observe the matching quality using the default values. Once satisfactory matchings were achieved, the process continued with foam parameters upscaling. During scale-up process the velocity of the fluids and pressure drop were conserved as laboratory data. The important scale-up parameters and the corresponding scale-up ratio were investigated. Mobility Reduction Factor (MRF) was calculated by dividing average DP for each foam cycle with base differential pressure (DP) in the prior gas injection. MRF values for both lower and higher rate show increasing MRF values. Regardless, these values are lower in lower flowrates sequences compared to ones for higher flowrates. This corresponds to MRF values calculated in the laboratory analysis. Therefore, stronger and more stabilized foam were generated using higher injection rates. Lower and higher flowrates had distinctive set of foam parameters. The acceptable matches for differential pressure, oil, water, and gas were achieved. for lower flowrate. Based on this study, model was able to capture production trends depicted in the laboratory analysis. The foam parameter set from higher flowrates have more potential for further upscaling and modeling in full-field scale.

The potential of nanoparticles, which are classified as advanced fluid material, have been unlocked for improved oil recovery in recent years such as nanoparticles-assisted waterflood process. However, there is no existing commercial reservoir simulation software that could properly model phase behaviour and transport phenomena of nanoparticles. This paper focuses on the development of a novel robust advanced simulation algorithms for nanoparticles that incorporate all the main mechanisms that have been observed for interpreting and predicting performance. The general algorithms were developed by incorporating important physico-chemical interactions that exist across nanoparticles along with the porous media and fluid: phase behaviour and flow characteristic of nanoparticles that includes aggregation, splitting and solid phase deposition. A new reaction stoichiometry was introduced to capture the aggregation process. The new algorithm was also incorporated to describe disproportionate permeability alteration and adsorption of nanoparticles, aqueous phase viscosities effect, interfacial tension reduction, and rock wettability alteration. Then, the model was tested and duly validated using several previously published experimental datasets that involved various types of nanoparticles, different chemical additives, hardness of water, wide range of water salinity and rock permeability and oil viscosity from ambient to reservoir temperature. A novel advanced simulation tool has successfully been developed to model advanced fluid material, particularly nanoparticles for improved/enhanced oil recovery. The main scripting of physics and mechanisms of nanoparticle injection are accomplished in the model and have acceptable match with various type of nanoparticles, concentration, initial wettability, solvent, stabilizer, water hardness and temperature. Reasonable matching for all experimental published data were achieved for pressure and production data. Critical parameters have been observed and should be considered as important input for laboratory experimental design. Sensitivity studies have been conducted on critical parameters and reported in the paper as the most sensitive for obtaining the matches of both pressure and production data. Observed matching parameters could be used as benchmarks for training and data validation. Prior to using in a 3D field-scale prediction in Malaysian oilfields, upscaling workflows must be established with critical parameters. For instance, some reaction rates at field-scale can be assumed to be instantaneous since the time scale for field-scale models is much larger than these reaction rates in the laboratory.

Due to their large surface-area-to-volume ratio and enhanced chemical reactivity, nanoparticles have attracted increasing interest among researchers in the upstream petroleum industry for enhanced oil recovery (EOR) applications which target the recovery of oil left behind by primary and secondary recoveries, by pressure depletion and waterflooding, respectively. In EOR applications, fluids not originally present in the reservoir, such as polymer, surfactant, carbon dioxide or steam, are injected into the reservoir to either increase the sweep efficiency or to mobilize remaining oil so as to reduce the residual oil saturation. In these applications, EOR agents are used to either reduce the mobility of the injected fluid relative to that of oil or to increase the ratio of viscous to interfacial forces, that is, capillary number. In this chapter, we begin with a discussion of the potential use of nanoparticles in the upstream oil industry. This will be followed by a discussion of the unique physics and chemistry of nanoparticles. Then a detailed discussion on how nanoparticles can be used to improve the mobility control and capillary number will be given. It is shown that nanoparticles hold promise in either augmenting existing EOR agents (e.g., surfactant and polymer) or may even replace them to become EOR agents in their own right, although many technical challenges still exist and research is in its early stage. Next the HSE aspects of nanoparticles both in laboratory investigation and field applications will be discussed. We will then conclude with suggestions for future research. With ever increasing advances of nanoparticle technology in many fields of science and engineering, we believe translation of this knowledge to EOR will yield tangible fruits in the not too distant future. However, concerted multidisciplinary efforts will be needed to realize this goal.

Waterflood is well-known as the cost effective secondary recovery mechanism to improve oil recovery. With current challenging oil price environment, waterflood continues to be one of the main candidate of choice. Hence, it is very important to maximize by optimizing the process. The objective of this paper is to propose a rapid technique to evaluate and optimize current matured waterflooding project in an offshore brown field with complex stacked reservoirs and production system through dynamic data analyses. Interwell connectivity evaluation can assist in reservoir characterization, well placement, and evaluate waterflooding performance. Therefore, dynamic data analytics workflow applying interwell connectivity evaluation and Streamline as implicit approach are proposed. The importance of clustering each area become important to raise particular issues such as poor properties and connectivity. The production and injection points are evaluated and unswept area can be identified. Therefore, waterflood can be optimized. This study resulted if current waterflooding can be optimized and new potential well placement can be identified to increase oil recovery. Compared with no further action case, oil recovery can be potentially improved 3-4% based on numerical full-field modelling prediction. The technique will be very useful to have business decision rapidly in weeks. With current oil price situation, it can be as a cost-effective technique, especially for brown fields with mature waterflood projects and have complexity in geological and production system that commonly time consumption. The proposed workflow can be deployed to other neighbor mature fields.

This paper demonstrates that data-driven approach can address to resolve the big data complexity, enhance reservoir characterization and accelerate history matching process into an offshore mature field with many challenges such as complex reservoir geology with high properties variation, fair correlation between seismic amplitude and reservoir properties, multi-stacked completion of production/injection strings, commingled production system from multiple zones, mechanical leaking issue and sparse production allocation. By these complexities, classical technique of integrated full-field modelling cannot be done easily. In addition, it is difficult to acquire reservoir engineering insights for reservoir characterization. Data-driven reservoir modelling approach is applied to tackle the technical challenges. A workflow is proposed for rapid quality check of big data and integrated with systematic reservoir engineering analyses. In data-driven approach, current understanding of geology and physics is relieved with field measurements data as the foundation of constructing the model. The model is kept at high level and introduce further detail where needed within the bound of uncertainty to achieve history match. Data-driven approach has successfully improved reservoir characterization and provide cost-effective technique to accelerate history match process. The quality of big data (i.e. pressure, correct production allocation of each zone) plays key role in data-driven approach. Through early valuable insights from engineers, it significantly reduced the iterations number for history match purposes between engineers and geologist. In this study, it cuts from commonly in months to be weeks. Consequently, field-level and well-level history match can be satisfactorily achieved with deviation within 5%. The blind testing has been conducted to validate data-driven approach and improve confidence level with the model for further field development opportunities such as waterflood optimization, stimulation, new well placement, effective completion and enhanced oil recovery. The results can be reconciled with geological understanding, which will be very useful and suitable in current oil price situation as a cost-effective technique, especially for mature fields with large data and have complexity in geological and production system. The data-driven approach can be deployed to other neighbour mature fields and can improve the level of confidence to support fast business decisions.

Summary This paper presents rapid techniques of reservoir connectivity evaluation in a mature oilfield with multi-stacked sandstone reservoir and recovery process involving waterflooding, through production and injection data analyses. The issue in waterflooding here is to understand the influence of water injection to oil production in complex reservoir geology. Hence, accurate interpretation of reservoir connectivity is critical to have high flow efficiency. Prudent reservoir management often requires fast solution to evaluate and subsequently improve the efficiency of the on-going waterflooding performance and also for tertiary recovery purposes. Therefore, dynamic data analytics workflow applying Pearson’s Correlation Coefficient (PCC) interwell connectivity technique verified with Streamline is proposed. The PCC and Streamline techniques are able to provide rapid framing analysis of reservoir network incorporating production and injection data. Both techniques can identify areas with good or poor connectivity, injection efficiency and barrier/sealing fault in relatively short timeframe (weeks). Identification of these areas can provide important information for reservoir characterization, reservoir dynamic behaviour and reservoir management plans. It can be utilized as an efficient tool for management to decide strategic business decision to improve oil recovery through waterflood optimization and enhanced oil recovery processes.

Summary Government of the Republic of Indonesia urgently requires accelerating oil and gas production through EOR methods because oil and gas sector still plays an important role in Indonesian economy. This paper presented the observation of opportunities and challenges in developing first nanotechnology in enhanced oil recovery (Nano-EOR) in Indonesia. This study introduced a developed screening criterion and a methodology for evaluation Nano-EOR candidates in Indonesia. Prior to introducing Nano-EOR in Indonesia in the middle of 2017, the government have done with previous studies of top 34 EOR potential fields and concluded into: CO2 (18%), steam flooding (3%) and chemical flooding (79%). We presented the difficulties those techniques to be implemented currently in Indonesia. Hence, it is required a breakthrough solution of fast-tracking and cost-efficient method. As an emerging EOR technology, we investigated Nano-EOR as new fast-tracking and cost-efficient techniques. We observed several recognized benefits and challenges during developing Nano-EOR for fast-tracking implementation at low oil price situation. Based on our study, Nano-EOR is favourable for the most listed potential oilfield for EOR, proven technique and can tackle current constraints of traditional EOR techniques. The discussion about challenges from technical, fiscal, and regulation aspects are also included in this paper.

Chemical enhanced oil recovery is another strong growing technology with the potential of a step change innovation, which will help to secure future oil supply by turning resources into reserves. While Substantial amount of crude oil remains in the reservoir after primary and secondary production, conventional production methods give access to on average only one-third of original oil in place, the use of surfactants and polymers allows for recovery of up to another third of this oil. Chemical flooding is of increasing interest and importance due to high oil prices and the need to increase oil production. Research in nanotechnology in the petroleum industry is advancing rapidly and an enormous progress in the application of nanotechnology in this area is to be expected. Nanotechnology has the potential to profoundly change enhanced oil recovery and to improve mechanism of recovery. This paper, therefore, focuses on the reviews of the application of nano technology in chemical flooding process in oil recovery and reviews the application nano in the polymer and surfactant flooding on the interfacial tension process.

This study investigates the effect of a stabilizer on nanofluid stability and incremental oil during the enhanced oil recovery process. Untreated nanoparticles tend to form aggregates that are larger than the primary particle size when dispersed in liquid. This phenomenon affects the flooding process because the particles will be retained at the inlet injection point rather than be transported through a porous medium. A non-toxic (environmentally friendly) stabilizer, polyvinylpyrrolidone, is studied that successfully improves the stability of silica-based nanofluids at a particular time and temperature. In addition, it alters nanofluids properties such as the surface conductivity, pH, viscosity, and the particle size distribution that takes into account the nanofluids stability. During coreflooding as a tertiary process, improving the stability of nanofluids significantly affects the increase in oil recovery. These investigations will go beyond the nanofluids restriction at higher concentrations (e.g., 0.1 wt% or higher). Stability is observed as an important parameter in accomplishing successful nanofluids for enhanced oil recovery process.

This paper presents the investigation of using nanoscale polyacrylamide-based spheres (nanospheres) as a displacement fluid in enhanced oil recovery (EOR). Coreflood experiments were conducted to evaluate the impact of nanospheres and its concentration dispersed in model formation water on oil recovery during a tertiary oil recovery process. The coreflood results showed that nanospheres can enhance residual oil recovery in the sandstone rock samples and its concentration showed a significant impact into incremental oil. By evaluating the contact angle, it was observed that wettability alteration also might be involved in the possible oil displacement mechanism in this process together with fluid behavior and permeability to water that might divert injected fluid into unswept oil areas and enhance the residual oil recovery. These investigations promote nanospheres aqueous disperse solution as a potential displacement fluid in EOR.

Coreflood experiments were conducted to evaluate the impact of the initial rock wettability on oil recovery during a tertiary oil recovery process using hydrophilic silica-based nanofluids at reservoir temperatures. An adopted scale of reservoir wettabilities (water-, intermediate-, and oil-wet systems) is used for the core plugs, which were prepared by aging processes. The relationships among temperature, initial wettability, and an additional oil recovery nanofluid flooding process were investigated. The results showed that the initial wettability affects oil recovery performance and showed a greater effect at higher temperatures, as represented by the reservoir temperature. An extended postflush nanoflooding was performed to evaluate incremental oil recovery, and this cycle shows great potential for field applications. By evaluating the contact angle and interfacial tension, it was found that wettability alteration plays a more dominant role in the oil displacement mechanism via nano-EOR. These results...

Chemistry of the injected water has been investigated as an important parameter to improve/enhance oil recovery (IOR/EOR). Numerous extensive experiments have observed that water chemistry, such as ionic composition and salinity, can be modified for IOR/EOR purposes. However, the possible oil displacement mechanism remains debatable. Nanoparticle recently becomes more popular that have shown a great potential for IOR/EOR purposes in lab-scale, where in most experiments, water-based fluid were used as dispersed fluid. As yet, there has been no discussion in the literature on the study of water chemistry on enhanced oil recovery using silica-based nanoparticles. A broad range of laboratory studies involving rock, nanoparticles and fluid characterization; fluid–fluid and fluid-rock interactions; surface conductivity measurement; coreflood experiment; injection strategy formulation; filtration mechanism and contact angle measurement are conducted to investigate the impact of water chemistry, such as water salinity and ionic composition including hardness cations, on the performance of silica-based nanoparticles in IOR/EOR process and reveal possible displacement mechanism. The experimental results demonstrated that water salinity and ionic composition significantly impacted oil recovery using hydrophilic silica-based nanoparticles and that the oil recovery increased with the salinity. The primary findings from this study are that the water salinity, the ionic composition and the injection strategy are important parameters to be considered in Nano-EOR. © The Author(s) 2015 Open Access This article is distributed under the terms of the Creative Commons Attribution License which permits any use, distribution, and reproduction in any medium, provided the original author(s) and the source are credited.

Examining fluid behavior in the presence of nanoparticles is essential to understand the displacement mechanism when a nanoparticle is used as novel enhanced oil recovery (EOR) method. Recent investigations showed that nanoparticles have great potential for EOR in the lab-scale. Since its displacement mechanism is not yet clearly understood, studies about fluid-fluid and fluid-rock interactions will be essential as a way to unlock how its mechanism. Saline water is studied in the presence of hydrophilic silica nanoparticles at different conditions such as temperature, concentration, various salt ions and nanoparticle size and initial rock wettability. The fluid properties measurement involves density, viscosity, pH and surface conductivity. Crude oil from a field in the North Sea is employed to measure interfacial tension between oil-phase and aqueous phase (saline water and nanofluids) at different temperatures. Contact angle is also measured among quartz rock as solid phase and those fluid phases at different initial rock wettability. These compatibility tests is useful to have better understanding about displacement mechanism and boundary of using nanoparticles as EOR method (Nano EOR) before applying in the field-scale. The processes and observations are outlined and also further detailed in the paper as a part to unlock nanoparticles flooding as a future promising EOR method. Introduction Nanofluid is a new class of fluid engineered and a new interdisciplinary area of great importance where nanoscience, nanotechnology, and thermal engineering come across (Yu and Xie, 2011). It is defined as nanoparticle that has average size less than 100 nm, suspended in traditional heat transfer fluid such as water, oil or ethylene glycol (Das et al., 2008). Nanofluid consists of two-phase systems, solid and liquid (Yu and Xie, 2011) since nanoparticles (NPs), as solid phase, is commonly dispersed in liquid. Nanofluids have greatly attracted in wide range fields application in recent years. Yu and Xie (2011) highlighted the current application of nanofluids such as heat and mass transfer enhancement (Kim et al., 2006, 2007a, and 2007b; Ma et al., 2007, and 2009), friction reduction and magnetic sealing in mechanical application (Kim et al., 1999; Shen et al., 2008; Yu et al., 2008; Mitamura et al., 2008; Chen and Mao, 2010; Peng et al., 2010; and Vekas et al., 2010), and biomedical application (Zhang et al., 2007; Jalal et al., 2010; Jones et al., 2008; Liu et al., 2009; Mahapatra et al., 2008; Nakano, 2008; Singh and Liliard, 2009; and Gajjar et al., 2009). The potential of nanofluids for oil and gas industries application has been summarized by Kong and Ohadi (2010), as presented in Table 1. It can be also used for geochemical exploration (Wang et al., 1997). Another benefit of nanofluids in drilling and sand problem has been investigated by Chaaudhury (2003), Zitha (2005), and Evdokimov et al. (2006). In heavy oil application, it can upgrade the viscosity of heavy oil and bitumen as a catalyst (Ying and Sun, 1997; Scott et al., 2003; and Hendraningrat et al., 2014a). The NPs easily aggregated once they hydrated. It is because they have a large surface-to-volume ratio due to the small particle size. For instance, Fig. 1 shows hydrated silica when dispersed in base fluid such as water (has hydrogen element). The materials with high surface-to-volume ratios react at much faster rates because additional surfaces are available to react. Therefore they possess high surface energies. The NPs consequently create an aggregate form to minimize this surface energy.

Unconventional oil reservoirs such as heavy oil, extra heavy oil, oil shale and oil sand/bitumen are very interesting since these kinds of oil are currently proven to constitute a huge amount of total world oil reserves. However, it is difficult to handle these kinds of oil due to very high viscosity. Thermal application methods may have great possibilities for heavy oil and bitumen production. Prior to shipment to downstream markets, the bitumen needs to be upgraded to produce higher value of liquid hydrocarbon products. However, the issues in oil sands industry are environmental challenges such as green-house-gas (ghg) emission, huge amount of fuel and water consumption, liquid and solid wastes disposal. The objective of this study is to investigate an effective and efficient upgrading process by adding decalin as hydrogen donor, water and various type nanometal particles (40-500 nm) as catalysts into Athabasca bitumen. Athabasca bitumen has been successfully upgraded by reducing its viscosity about 80% (measured at 60 °C) by applying catalytic aquathermolysis at 240 °C during 12 hours. As hydrogen donor, decalin is very interesting. Besides cheap, it could dramatically accelerate viscosity reduction with concentration of 5 wt.%. The degree of viscosity reduction will increase with increased decalin concentration. However degree of bitumen upgrading will decrease with presence of water. It seems that synergetic effects to the upgrading process did not work effectively. Hence water consumption during aquathermolysis process might be reduced to minimize the cost. Since earlier studies have shown that nanoparticles may reduce heavy oil viscosity, four types of nanometal particles have been studied and some of them accelerated viscosity reduction during catalytic aquathermolysis process at particular concentration. Improper nanometal particle type and concentration are reversed effect. Temperature and heating time have vital role in the upgrading process.

The development of current technology has enabled manufacturer to create various types of nanoparticles for multi-purposes in various sectors including the oil and gas industry. The use of nanoparticles for enhanced oil recovery (EOR) has been studied in the past decade both in the lab- and pilot-scale projects. Most of the research observed that nanoparticles are very attractive for EOR purposes. However, most of those studies use ??of silica-based nanoparticles. The use of other types of nanoparticles should be investigated as alternative solution. In this study, two water-based metal-oxides nanoparticles: Al2O3 and TiO2, were employed. The primary size of both nanoparticles ranged of 40-60 nm. Nanofluids was prepared by dispersing 0.05 wt.% metal-oxides nanoparticles with synthetic saline water. Berea sandstones cores are used as porous media with average porosity and permeability of 15% and 60 mD respectively. Coreflood experiment was conducted by injecting metal-oxides nanofluids as tertiary process (Nano-EOR). Degassed crude oil with viscosity ranged 5–50 cP was also used. To investigate the effect of temperature and rock wettability to oil recovery, coreflood experiment has been performed on various temperature condition and initial cores wettability: water-wet, intermediate-wet and oil-wet. The detailed process and results are outlined in the paper to reveal the possible application of metal-oxides nanoparticles as alternative EOR method.

This paper presents the investigation of aluminium oxides (Al2O3) nanoparticles for enhanced oil recovery (EOR) purposes. As comparison, a silica dioxides (SiO2) nanoparticle is also included in this study. The single primary size of both nanoparticles is 16-17 nm. Untreated nanoparticles tend to aggregate from primary particle size and cause bigger size when dispersed such as in formation water. In this paper, a dispersant is used and studied to avoid early nanoparticle aggregation. It is observed that dispersant will alter fluid behavior and successfully provide better stability at particular concentration. Based on coreflood experiment, Al2O3 nanofluid was successfully increased oil recovery with higher displacement efficiency 13% than SiO2 (5%) as tertiary process. Contact angle measurement was conducted to understand the oil displacement mechanism nanoparticles. Once Al2O3 nanofluid with dispersant introduced to the brine, it reduces contact angle from 54o to 21o which means the quartz plate has altered to be more strongly water-wet. However, SiO2 nanofluid altered only to be 31o. This measurement is consistent with additional oil recovery result where Al2O3 nanofluid has higher additional oil recovery than SiO2 as tertiary recovery. These investigations are essential to unlock the possibility of using aluminium oxides for EOR process.

Current global demand for fossil fuel such as oil is still high. This encourages oil and gas industries to improve their effort of finding new discoveries, developing technique and maximizing recovery of their current resources including in low-permeability reservoir. Enhanced oil recovery (EOR) is a technique to enhanced ultimate recovery. Since technology has been continuously developed such as nanotechnology/nano-size material, EOR methods have improved. One of them is Nano-EOR that triggered great attention in last decade. Nanoparticles may alter the reservoir fluid composition and rock-fluid properties to assist in mobilizing trapped oil. Most of observation from lab-scale reported that it seems potentially interesting for EOR. Since reservoir management is very essential for the success of all improved/enhanced oil recovery (IOR/EOR) methods, optimizing nanofluids concentration is a proposed reservoir management to maximize oil recovery using Nano-EOR in this paper. Low-permeability water-wet Berea sandstones core-plugs with porosity ranged 13-15% and permeability ranged 5-20 mD were tested. A hydrophilic silica nanoparticles with primary particle size 7 nm was employed without surface treatment. Nanofluids with various concentration ranged 0.01 - 0.1 wt.% were synthesized with synthetic saline water for optimizing study. The wettability alteration due to nanofluids was observed; coreflood experiment was conducted and compared its displacement efficiency. The results observed a range of nanofluids concentration that could maximize oil recovery in low-permeability water-wet Berea sandstone. Although contact angle of aqueous phase decreases as nanofluids concentration increase which means easier of oil to be released but we observed that higher concentration (e.g. 0.1 wt.%) has a tendency to block pore network and will decrease or even without additional oil recovery. This study provides if concentration of nanofluids has an important parameter in Nano-EOR and could be optimized to maximize oil recovery of low-permeability water-wet Berea sandstone.

The paper presents compositional simulation studies of miscible water-alternating-gas (WAG) flooding in stratified reservoirs with respect to compositional variation with vertical depth and temperature. Two series of fluid system were selected from fifth and third SPE comparative study for Reservoir-A and Reservoir-B respectively. The Reservoir-A is an undersaturated black oil reservoir and has initial gas-oil ratio (GOR) of 557 scf/stb. Meanwhile Reservoir-B is near-critical oil reservoir with initial GOR of 3519 scf/stb. The minimum miscible pressure (MMP) variation with depth was calculated using equation of state in both reservoirs. In this study, temperature gradient sensitivity is ranging from 10 to 30°F per 1000 ft for both active and passive thermal gradient. The existence of thermal diffusion in WAG process is also discussed. It is investigated that active and passive thermal gradient will give opposite composition variation trend. In active temperature gradient, the amount of light components will increase and heavy components will opposite with respect to depth. Unlike active thermal gradient, the gravity isothermal and passive thermal gradients segregate the heavy components toward the bottom. The initial oil in place (IOIP) varies due to compositional variation which is again due to gravity and thermal gradients. These issues should be even more obvious when we have oil reservoir with higher GOR or near-critical reservoir. In these particular reservoirs, the presence of gravity and passive thermal gradients will decrease IOIP calculation whereas both reservoirs will have less C7+ components than in basecase. Otherwise, considering thermal diffusion effect by applying active thermal gradients will increase IOIP. Several parameters were also evaluated during WAG process in both reservoirs such as: various hydrocarbon injection gases, cyclic injection scheme, WAG cycle and ratio, and reservoir heterogeneities. Therefore the effect of compositional variation due to gravity and thermal gradients can be conclusively evaluated.

Nanoparticles have become an attractive agent for improved and enhanced oil recovery (IOR & EOR) at laboratory scale recently. Most researchers have observed promising result and increased ultimate oil recovery by injecting nanofluids in laboratory experiments. In previous study, we observed that interfacial tensions (IFT) decreased when hydrophilic nanoparticles were introduced to brine. The IFT decreases as nanofluids concentration increase and this indicates a potential for EOR. We have also investigated nanofluid flow in glass micromodel and high permeability Berea sandstone (ss) cores, and we observed that the higher concentration of nanofluids; the more impairment of porosity and permeability. Since low permeability oil reservoirs have still huge volume of oil reserves, this study aims to reveal nanofluids possibility for EOR in low-medium permeability reservoir rocks and investigate its suitable concentration. In this paper, laboratory coreflood experiments were performed in water-wet Berea ss core plugs with permeability in range 9- 35 mD using different concentrations of nanofluids. Three nanofluids concentrations were synthesized with synthetic brine; 0.01, 0.05 and 0.1 wt.%. To investigate disjoining pressure as displacement mechanism due to nanoparticles, contact angle between crude oil from a field in the North Sea and brine/nanofluids have been measured. Increasing hydrophilic nanoparticles will decrease contact angle of aqueous phase and increase water-wetness. Despite increasing nanofluid concentration shows decreasing IFT and altering wettability, our results indicate that additional recovery is not guaranteed. The processes and results are outlined and also further detailed in the paper to reveal the possible application of nanofluid EOR in lower-medium permeability oil reservoir.

Abstract In last decade, a number of papers about nanoparticles studies have been published related to its benefit for oil and gas industries. Some of them discussed about the potential of nanoparticles for enhanced oil recovery (EOR) in the laboratory scale. One of possible EOR mechanisms of nanofluids has been described as disjoining pressure gradient (Chengara, 2004, and Wasan, 2011). The benefit of using silica nanoparticles was explained by Miranda (2012). Hence, the present study objective is to investigate the potential of hydrophilic silica nanoparticles suspension as enhanced oil recovery agent and find out the main mechanisms of nanofluids for EOR. In this study, hydrophilic nanoparticles with average particle size of 7 nm were used in both visualization glass micromodel flooding experiments and core flooding experiments. A water-wet transparent glass micromodel and Berea sandstone cores with 300–400 mD permeability were used as porous medium. Synthetic brine was used as disperse fluid for nanoparticles. In order to investigate the recovery mechanisms of nanofluids, interfacial tension (IFT) and contact angle between different concentration nanofluids and crude oil have been measured by using spinning drop and pendent drop methods. The experimental results indicate that the nanofluids can reduce the IFT between water phase and oil phase and make the solid surface more water wet. In the visualization glass micromodel flooding experiments, it was observed that nanofluids can release oil drops trapped by capillary pressure, while the high concentration nanofluids stabilized oil-water emulsion. For the core flooding experiments, nanofluids can increase recovery about 4–5% compared to brine flooding. These results indicate that these nanoparticles are potential EOR agents. The future expectation is that nanoparticles could mobilize more oil in the pore network at field scale to improve oil recovery.

In a past decade, various nanoparticle experiments have been initiated for improved/enhanced oil recovery (IOR/EOR) project by worldwide petroleum researchers and it has been recognized as a promising agent for IOR/EOR at laboratory scale. A hydrophilic silica nanoparticle with average primary particle size of 7 nm was chosen for this study. Nanofluid was synthesized using synthetic reservoir brine. In this paper, experimental study has been performed to evaluate oil recovery using nanofluid injection onto several water-wet Berea sandstone core plugs. Three injection schemes associated with nanofluid were performed: 1) nanofluid flooding as secondary recovery process, 2) brine flooding as tertiary recovery processs (following after nanofluid flooding at residual oil saturation), and 3) nanofluid flooding as tertiary recovery process. Interfacial tension (IFT) has been measured using spinning drop method between synthetic oil and brine/nanofluid. It observed that IFT decreased when nanoparticles were introduced to brine. Compare with brine flooding as secondary recovery, nanofluid flooding almost reach 8% higher oil recovery (% of original oil in place/OOIP) onto Berea cores. The nanofluid also reduced residual oil saturation in the range of 2-13% of pore volume (PV) at core scale. In injection scheme 2, additional oil recovery from brine flooding only reached less than 1% of OOIP. As tertiary recovery, nanofluid flooding reached additional oil recovery of almost 2% of OOIP. The IFT reduction may become a part of recovery mechanism in our studies. The essential results from our experiments showed that nanofluid flooding have more potential in improving oil recovery as secondary recovery compared to tertiary recovery.

A proper analysis and fluid characterization is an essential key for successful modeling the behaviour of gas condensate reservoir. This paper demonstrates a robust multiple equation of state (EOS) modeling process for gas condensate reservoir at Senoro field. Senoro is a new major gas condensate field in East Indonesia with estimated IGIP greater than 2 Tcf and CGR range from 3-80 STB/MMscf. Senoro field is divided into two structures: the northern part is a carbonate reefal build-up, namely Mentawa, member of Minahaki formation, and the southern part is a platform carbonate Minahaki formation. The hydrodynamic condition in both formations poses a challenge to fluid characterization, where Mentawa member has both oil and gas with active aquifer, while Minahaki formation only has gas bearing rock with aquifer. Senoro field has collected 36 samples, measured from down-hole and surface. The samples also cover composition analysis for surface recombined fluid. The required laboratory experiment such as CCE, DL and CVD have also been measured. The mathematical recombination was performed as a quality check to measure well-stream composition. Two EOS models have been developed successfully to determine physical properties and to predict the fluid behaviour of Senoro. The heptanes-plus fraction is split into three pseudo-components to characterize fluid using Gamma distribution model. The fine-tuned fluid properties from all available data match both EOS models satisfactorily. These EOS models have also been matched with historical single radial welltest model. Compositional grading has also been developed to generate compositional map. These established EOS models are used for compositional simulation. The gas and condensate profiles now could be predicted for optimizing field development plan. The use of EOS models can lead not only to a further field development strategy, but also to optimize the surface processing facilities.

Chemical flooding is of increasing interest and importance due to high oil prices and the need to increase oil production. Research in nanotechnology in the petroleum industry is advancing rapidly, and an enormous progress in the application of nanotechnology in this area is to be expected. The nanotechnology has been widely used in several other industries, and the interest in the oil industry is increasing. Nanotechnology has the potential to profoundly change enhanced oil recovery and to improve mechanism of recovery, and it is chosen as an alternative method to unlock the remaining oil resources and applied as a new enhanced oil recovery method in last decade. This paper therefore focuses on the reviews of the application of nanotechnology in chemical flooding process in oil recovery and reviews the applications of nanomaterials for improving oil recovery that have been proposed to explain oil displacement by polymer flooding within oil reservoirs, and also this paper highlights the research advances of polymer in oil recovery. Nanochemical flooding is an immature method from an application point of view.

This paper presents systematic studies of hydrophilic metal oxide nanoparticles (NPs) dispersed in brine intended to reveal their potential to enhance oil recovery (EOR) in various rock wettability systems. The stability in suspension (nanofluid) of the NPs has been identified as a key factor related to their use as an EOR agent. Experimental techniques have been developed for nanofluid stability using three coupled methods: direct visual observation, surface conductivity and particle size measurements. The use of a dispersant has been investigated and has been shown to successfully improve metal oxide nanofluid stability as a function of its concentration. The dispersant alters the nanofluid properties, i.e. surface conductivity, pH and particle size distribution. A two-phase coreflood experiment was conducted by injecting the stable nanofluids as a tertiary process (nano-EOR) through core plugs with various wettabilities ranging from water-wet to oil-wet. The combination of metal oxide nanofluid and dispersant improved the oil recovery to a greater extent than either silica-based nanofluid or dispersant alone in all wettability systems. The contact angle, interfacial tension (IFT) and effluent were also measured. It was observed that metal oxide-based nanofluids altered the quartz plates to become more water-wet, and the results are consistent with those of the coreflood experiment. The particle adsorption during the transport process was identified from effluent analysis. The presence of NPs and dispersant reduced the IFT, but its reduction is sufficient to yield significant additional oil recovery. Hence, wettability alteration plays a dominant role in the oil displacement mechanism using nano-EOR. © The Author(s) 2014 Open Access This article is distributed under the terms of the Creative Commons Attribution License which permits any use, distribution, and reproduction in any medium, provided the original author(s) and the source are credited.

Align with current dynamic technology development, waterflooding techniques have been improved and optimized to have better oil recovery performance. In addition the latest worldwide industries innovation trends are miniaturization and nanotechnology materials such as nanoparticles. Hence one of the ideas is using nanoparticles to assist waterflood performance. However it is crucial to have a clear depiction of some parameters that may influences displacement process. The focus of this study is to investigate the effects of some parameters influencing oil recovery process due to nanoparticles such as particle size, rock permeability, initial rock wettability, injection rate and temperature. This study is part of our ongoing research in developing nanofluids for future or alternative enhanced oil recovery (Nano-EOR) method. Three different sizes of hydrophilic silica nanoparticles with single particle diameter range from 7 to 40 nm were employed and have been characterized under scanning electron microscope (SEM). Nanofluids were synthesized using 0.05 wt.% nanoparticles that dispersed into synthetic brine (NaCl 3 wt.% ~ 30,000 ppm). The contact angle variation due to nanoparticles size was also measured at room condition. Coreflood experiment has been conducted using 26 Berea sandstone cores to evaluate the effect of those parameters above on oil recovery due to Nano-EOR. The cores permeability was in range from 5 to 450 mD. To study the effect of initial rock wettability on oil recovery due to Nano-EOR, original core wettability has been changed with aging process from water-wet to intermediate and oil-wet respectively. Temperature was also studied in range 25-80 °C to fulfill the possibility of applying Nano-EOR at reservoir temperature. The coreflood testing was repeated for each case to have consistency result. The processes and results are outlined and also further detailed in the paper to bring knowledge about nanoparticles flooding as a future promising EOR method.

A number of researchers put on attention on nanoparticles suspension (nanofluids) as part of nanotechnology application in enhanced oil recovery (EOR) nowadays. This experimental study is preliminary stage of nanofluids for EOR project at NTNU. This paper presents the investigation of interfacial tension reduction, nanoparticles retention and permeability impairment in porous media by injecting nanoparticles suspension into glass micromodel. The deposition and pore-blockage of nanoparticles in glass micromodel were investigated and microscopically visualized by taking sequential images. A hydrophilic nanoparticles and synthetic seawater (brine, NaCl 3 wt. %) as base fluid were chosen in this study. The nanofluids were made with various concentration from 0.1 to 1.0 wt. %. The sonicator as liquid homogenization tool was used just before injecting the nanofluids into glass micromodel to avoid agglomeration. A dynamic interfacial tension (IFT) phenomenon has observed during this experiment. Introducing dispersed nanoparticles in brine has reduced dynamic IFT. It will decrease when increasing nanoparticles concentration. Theoretically, it makes oil easier to move out since the friction force between water-phase and oil-phase will also decrease (Afrapoli, 2010). Based on microscopic visualization from glass micromodel, it observed nanoparticle has deposited and adsorbed at surface pore network. In permeability measurement, it reduced 41–72% after injected with nanoparticles. Dynamic light scattering analysis is also performed for nanoparticles entrapment analysis. Another nanoparticles which has bigger average size and lower specific surface area, showed similar behavior with previous nanoparticles suspension. However the permeability reduction is less around 17–21% at similar nanofluids concentration. In conclusion, this phenomenon of nanoparticles transport process possibly occurs due to its deposition on pore surface and blockage in pore throat of glass micromodel. This study provides essential knowledge for us of nanoparticles behavior in pore media before going further experiment stage to as EOR method.