Higher Recovery Factor Research Articles

Study of production enhancement through wettability alteration in a super-giant gas-condensate reservoir

Near wellbore condensate blockage phenomena commonly reduce gas production significantly. One efficient method for overcoming such problem is wettability alteration. Such issues as wettability state, treatment radius and time to reach the maximum level of production need be optimized prior to field application. In this paper, impact of these parameters are studied on gas and condensate production enhancement through wettability alteration. To do this, behavior of a well located in supergiant offshore Iranian gas condensate field is simulated and analyzed using a compositional model, single well and radial grid. The real fluid and reservoir properties of the studied well are utilized to construct the model. Different wettability states were defined using various relative permeability curves at various distances from the wellbore along with different treatment times are tested to find the best condition. Results indicate that near-wellbore wettability alteration leads to lower critical condensate saturation which has a significant impact on improving production parameters and reservoir recovery factors. Also, the highest recovery factor is achieved at optimal conditions where wettability is altered from strong liquid-wet to intermediate-wet at the small radius around the production well in early times. Furthermore, the inflow performance relationship curve (IPR) moves upward considerably which represents the magnificent production improvement.

Studies on the Stability of the Foamy Oil in Developing Heavy Oil Reservoirs

In the process of natural energy depletion, foamy oil is characterized of low production Gas Oil Ratio, high oil viscosity, high daily production rate and high primary recovery factor. The stability of the foam turns out to be the prevailing factor that governs the life of the ‘foamy oil’. To enumerate the main factors affecting the stability of the foam, a high-temperature–high-pressure visualized experiment model for foamy oil stability test was developed. A serial of experiments was conducted to evaluate the performance of the foam stability. The effects of oil viscosity, height of the oil column, dissolved gas content and dispersed gas were investigated and recorded. These experiments were conducted using a Hele-Shaw, a high pressure cell. The volume of foamy oil produced, either by a step reduction in pressure or by a gradual (linear) reduction in pressure, and its subsequent decay was observed, visually. The experimental results show that foamy oil stability increases with higher oil viscosity, higher oil column, higher dissolved gas content and higher pressure decline rate. Asphaltene content was not observed to increase the foamy oil stability significantly. The results also show that the foam quality of foamy oils is much lower than aqueous foams.

High-Performance Method for Determination of Pu Isotopes in Soil and Sediment Samples by Sector Field-Inductively Coupled Plasma Mass Spectrometry.

Plutonium is extensively studied in radioecology (e.g., soil to plant transfer and radiological assessment) and geochemistry (e.g., sediment dating). Here, we reported a new chemical separation method for rapid determination of Pu in soil and sediment samples, based on the following investigations: extraction behaviors of interfering elements (IEs, for inductively coupled plasma mass spectrometry (ICPMS) measurement) on TEVA resin; decontamination of U using TEVA, UTEVA, and DGA resins; and the impact of coprecipitation on Pu determination. The developed method consists of four steps: HNO3 leaching for Pu release; CaF2/LaF3 coprecipitation for the removal of major metals and U; the proposed TEVA + UTEVA + DGA procedure for the removal of U, Pb, Bi, Tl, Hg, Hf, Pt, and Dy; and ICPMS measurement. The accuracy of this method in determining 239+240Pu activity and 240Pu/239Pu and 241Pu/239Pu isotopic ratios was validated by analyzing five standard reference materials (soil, fresh water sediment, and ocean sediment). This method is characterized by its stable and high Pu recovery (90-97% for soil; 92-98% for sediment) and high decontamination factor of U (1.6 × 107), which is the highest reported for soil and sediment samples. In addition, the short analytical time of 12 h and the method detection limits, which are the lowest yet reported in literature, of 0.56 μBq g-1 (0.24 fg g-1) for 239Pu, 1.2 μBq g-1 (0.14 fg g-1) for 240Pu, and 0.34 mBq g-1 (0.09 fg g-1) for 241Pu (calculated on the basis of a 1 g soil sample) allow the rapid determination of ultratrace level Pu in soil and sediment samples.

A comparative experimental study of IOR potential in fractured shale reservoirs by cyclic water and nitrogen gas injection

Oil production from tight and shale formations accounted for more than half of total U.S. oil production in 2015 (EIA, 2016). Such amount is expected to grow significantly as the active development of low permeability reservoirs continues. Since the primary recovery is becoming less effective and large amounts of oil are locked in matrix, IOR techniques should be considered to face such challenge. Many recent studies have evaluated the potential of gas injection in shale plays. However, few studies discussed the feasibility of water huff-n-puff process. This study evaluated the potential of cyclic water injection (CWI) in shale plugs and compared it with the performance of cyclic gas injection (CGI).Eagle Ford core samples were used in this study and saturated with dead shale oil. X-ray diffraction (XRD) technique was employed to analyze the mineral composition of the sample. To reduce clay swelling, 5wt% of potassium chloride (KCl) solution was used as the injection fluid in CWI tests. Two groups of experiments were performed to examine the effects of soaking time and injection pressure (Pin) on the recovery performance. For one cycle of huff-n-puff, after reaching the Pin, the core plug was soaked with water for a certain time, then the surrounding pressure was released to enter the production period. Under the same operating conditions, CGI tests were conducted to compare the two IOR performances.The CWI experimental results show that soaking time affects the recovery factor (RF) of a single cycle within a certain range, which was similarly concluded from the CGI tests. Injection pressure can affect the recovery performance of CWI significantly. For example, after performing 12 cycles of water huff-n-puff, the RF for tests with Pin of 1000psi and 5000psi were 14% and 21%, respectively. When applying 5000psi, fractures were created on the plug and the size enlarged with further cycles operated. Comparing the two processes of CWI and CGI, different recovery characters can be observed. CWI showed the recovery potential at the first four cycles, and then the incremental oil recovery decreased dramatically in the subsequent cycles. By contrast, CGI presented a more continuous and steady recovery performance with high incremental RF, and then gradually diminished after seven cycles of huff-n-puff processes.

Floc proprieties and ultrafiltration characteristics by chitosan compound aluminum species coagulant under different pH conditions

In this study, the tendency of coagulation performances, floc characteristics and membrane resistances under different pH conditions in coagulation–ultrafiltration hybrid process was investigated by different Al species and chitosan (CS). Results indicated that CS as coagulation aid was independent of aluminum species. Coagulation efficiencies of three Al species (Ala, Alb and Alc) combined with CS were enhanced comparing with Al species used alone and shown similar variation tendencies during the pH range. The values of floc size and strength/recovery factor were relatively high at pH 6, and the maximum fractal dimension was achieved under alkaline conditions generally due to adsorption sweeping. Ala/Alb/Alc combined with CS contributed to larger flocs, higher recovery factors and smaller fractal dimension values than those without CS. The results of ultrafiltration experiments shown that membrane resistances during alkaline ranges were higher than those of acidic conditions, which indicated membrane fouling was more serious in alkaline range. In addition, the total membrane resistance was decreased significantly by CS addition.

Investigating the characteristic strength of flocs formed from crude and purified Hibiscus extracts in water treatment

The growth, breakage and re-growth of flocs formed using crude and purified seed extracts of Okra (OK), Sabdariffa (SB) and Kenaf (KE) as coagulants and coagulant aids was assessed. The results showed floc size increased from 300 μm when aluminium sulphate (AS) was used as a coagulant to between 696 μm and 722 μm with the addition of 50 mg/l of OK, KE and SB crude samples as coagulant aids. Similarly, an increase in floc size was observed when each of the purified proteins was used as coagulant aid at doses of between 0.123 and 0.74 mg/l. The largest floc sizes of 741 μm, 460 μm and 571 μm were obtained with a 0.123 mg/l dose of purified Okra protein (POP), purified Sabdariffa (PSP) and purified Kenaf (PKP) respectively. Further coagulant aid addition from 0.123 to 0.74 mg/l resulted in a decrease in floc size and strength in POP and PSP. However, an increase in floc strength and reduced d50 size was observed in PKP at a dose of 0.74 mg/l. Flocs produced when using purified and crude extract samples as coagulant aids exhibited high recovery factors and strength. However, flocs exhibited greater recovery post-breakage when the extracts were used as a primary coagulant. It was observed that the combination of purified proteins and AS improved floc size, strength and recovery factors. Therefore, the applications of Hibiscus seeds in either crude or purified form increases floc growth, strength, recoverability and can also reduce the cost associated with the import of AS in developing countries.

Mechanistic Modeling of the Alkaline/Surfactant/Polymer Flooding Process under Sub-optimum Salinity Conditions for Enhanced Oil Recovery

Alkaline–surfactant–polymer (ASP) flooding is potentially the most efficient chemical EOR method. It yields extremely high incremental recovery factors in excess of 95% of the residual oil for water flooding on the laboratory scale. However, current opinion is that such extremely high recoveries can be achieved under optimum salinity conditions, i.e., for the Winsor Type III microemulsion phase characterized by ultralow interfacial tension (IFT). This represents a serious limitation since several factors, including alkali-rock interaction, the initial state of the reservoir water, and the salinity of injected water, may shift the ASP flooding design to either sub-optimum or over-optimum conditions. A recent experimental study of ASP floods, based on a single internal olefin sulfonate (IOS) in natural sandstone cores with varying salinity from sub-optimum to optimum conditions, indicated that high recovery factors can also be obtained under sub-optimum salinity conditions. In this paper, a mechanistic model was developed to explore the causes behind the observed phenomena. The numerical simulations were carried out using the UTCHEM research simulator (at The University of Texas at Austin), together with the geochemical module EQBATCH. UTCHEM combines multiphase multicomponent simulation with robust phase behavior modeling. An excellent match of the numerical simulations with the experiments was obtained for oil cut, cumulative oil recovery, pH profile, surfactant, and carbonate concentration in the effluents. The simulations gave additional insight into the propagation of alkali consumption, salinity, surfactant profiles within the core. The study showed that the initial condition of the core is important in designing an ASP flooding. Because of uncertainties in the various chemical reactions taking place in the formation, an accurate geochemical model is essential for operating an ASP flooding in a particular salinity region. The simulation results demonstrate also that, for crude oil with a very low total acid number (TAN), the ultralow IFT and low surfactant adsorption can be achieved over a wide range of salinities that are less than optimal. The results provide a basis to perform better modeling of the sub-optimum salinity series of experiments and optimizing the design of ASP flooding methods for the field scale with more-complicated geochemical conditions.

Experimental and modeling studies on adsorption of a nonionic surfactant on sandstone minerals in enhanced oil recovery process with surfactant flooding

Surfactants have ability to reduce the interfacial tension between residual oil and water and give high recovery factor. Adsorption of surfactant onto the solid surface makes it less effective in reduction of interfacial tension in enhanced oil recovery (EOR) applications. Adsorption of Trigoonella foenum-graceum (TFG) as a nonionic surfactant on crushed sandstone rock was investigated in this work. Conductivity technique was used to measure amount of surfactant adsorbed on crushed rock. Batch experiments were used to investigate the adsorption of surfactant on solid rock surface. In addition, different adsorption equilibrium and kinetic models were fitted to experimental data and parameters for each model were determined. Among the two and three equilibrium models, the Jovanovic and Brouers-Sotolongo models exhibited better predictions and were most suitable for prediction of surfactant adsorption. The kinetic adsorption of surfactant was best suited to pseudo-second order model. Furthermore, the experimental adsorption data were modeled using a method named GA-RBF. It was concluded that the proposed GA-RBF model is accurate in prediction of kinetic adsorption behavior of surfactant. The results of this study can be useful in surfactant selection in EOR processes especially for chemical flooding schemes.

Solvent-Selection Criteria Based on Diffusion Rate and Mixing Quality for Steam/Solvent Applications in Heavy-Oil and Bitumen Recovery

Summary Heavy-oil and bitumen recovery requires high recovery factors to offset the extreme high cost of investments and operations. Attention has been given to solvent injection for this purpose, and it has been observed that high recoveries are achievable when it is combined with steam injection. Heavier (“liquid”) solvents (liquid at ambient conditions) are especially becoming more popular because of availability and transportation. High oil prices will allow the application of this kind of technique if a proper design is made to retrieve the injected solvent efficiently. “Liquid” solvents are advantageous because they yield a better-quality mixing (especially with very heavy oils and bitumen) but a lower diffusion rate than lighter solvents such as propane or butane. Despite this understanding, there still is not a clear screening criterion for solvent selection to mitigate both diffusion rate and the quality of the mixture. In this study, two main solvent-selection-criteria parameters—diffusion rate and mixing quality—were considered to evaluate solvent-injection efficiency at different temperatures. An optical method under static conditions and image-processing techniques were proposed to determine 1D diffusivity of liquid solvent into a wide range of oil samples in a capillary tube. This sampling range varies from 40-cp oil to 250-cp oil, for which digital-image treatment was developed. X-ray computerized tomography (CT) was applied for heavier (and darker) oils (viscosity range of 20,000 cp to 400,000 cp). The diffusion coefficients were then computed through nonlinear curve fitting on the basis of an optimization algorithm to ensure that the obtained values were in agreement with available analytical solutions. Next, viscosity measurements and asphaltene precipitation for the same heavy-oil/solvent mixtures were performed to determine the mixing quality. The ideal solvent types for different oil types were determined by using the results from the diffusion-rate and mixing-quality experiments. The experimental and semianalytical outcome of this research would be useful in the determination of the best solvent type for a given oil and in understanding the key factors that influence the quality of mixtures including viscosity reduction and probable asphaltene precipitation.

Separation of nickel(II) and cadmium(II) ions with ion-exchange and membrane processes

ABSTRACTSeparation of nickel(II) and cadmium(II) ions with use of ion-exchange resins—Amberlyst 15 and Lewatit OC 1026—supported liquid membranes (SLM), polymer inclusion membranes (PIM) and ion-exchange membranes (IM) from sulphate solution has been studied. Di(2-ethylhexyl) phosphoric acid (D2EHPA) was used as the ion-carrier in PIM and SLM separation. It was shown that use of SLM or PIM membranes enables separation of Ni(II)/Cd(II) ions. Experimental results data show that the highest recovery factor values were obtained for supported liquid membranes. The SEM surface and cross-sectional images of SLM support, polymer inclusion membrane and ion-exchange membrane have been also prepared.

Fluidized Bed Membrane Reactors for Ultra Pure H₂ Production--A Step forward towards Commercialization.

In this research the performance of a fluidized bed membrane reactor for high temperature water gas shift and its long term stability was investigated to provide a proof-of-concept of the new system at lab scale. A demonstration unit with a capacity of 1 Nm3/h of ultra-pure H2 was designed, built and operated over 900 h of continuous work. Firstly, the performance of the membranes were investigated at different inlet gas compositions and at different temperatures and H2 partial pressure differences. The membranes showed very high H2 fluxes (3.89 × 10−6 mol·m−2·Pa−1·s−1 at 400 °C and 1 atm pressure difference) with a H2/N2 ideal perm-selectivity (up to 21,000 when integrating five membranes in the module) beyond the DOE 2015 targets. Monitoring the performance of the membranes and the reactor confirmed a very stable performance of the unit for continuous high temperature water gas shift under bubbling fluidization conditions. Several experiments were carried out at different temperatures, pressures and various inlet compositions to determine the optimum operating window for the reactor. The obtained results showed high hydrogen recovery factors, and very low CO concentrations at the permeate side (in average <10 ppm), so that the produced hydrogen can be directly fed to a low temperature PEM fuel cell.

Investigation of immiscible CO2 and C1 injection and comparison with water injection for enhanced oil recovery in naturally fractured reservoirs

ABSTRACTReservoir oil and gas content tends to rise up to the surface as long as their potential energy levels are sufficient. In order to amplify this energy, either during the time when oil is uprising on its inherent energy or since after, so as to facilitate the traveling of oil to the surface, enhanced oil recovery (EOR) methods come into play. Furthermore, the increasing demand for oil from one hand, and the shrinkage of producible reserves on the other hand, have made it unavoidable to undertake EOR techniques. Built in this research was a 10-element model of reservoir fluid to simulate its behavior. Furthermore, slim tube simulation was undertaken to determine minimum miscibility pressure for various gases. Then, different scenarios of natural depletion, CO2 injection, methane injection, and water injection were simulated by ECLIPSE 300 software package with the results of different scenarios compared. The results indicated water injection to be associated with higher recovery factor.

Q&amp;A with Mikhail Chertenkov, Deputy CEO of Field Development Technology, Lukoil-Engineering

Q&amp;A The Yarega heavy oil field is an example of Russia’s technical advancements in heavy oil and bitumen production. Describe the technologies deployed in the field and their effects on production. Due to the requirements for high oil production rates and final oil recovery factors, we applied a counterflow steam-assisted gravity drainage (SAGD) technology in Yarega, which resulted in even reservoir coverage by thermal exposure, higher oil production rates, and lower steam/oil ratio values. Modeling results also had shown higher expected final oil recovery factors. A surface/underground thermal oil mining field development method is in common use in the Yarega field. The oil production performance indices of the oil mining method were significantly improved by the following measures: The lengths of horizontal wells drilled from underground mines were tripled due to new directional drilling systems, thus oil rates from new wells were increased. An upgrade of a surface steam generation unit raised the steam pumping pressure. By implementing counterflow SAGD technology, we increased horizontal well length, reduced operational expenses, eliminated adverse working conditions from the processes, and significantly improved workplace health and safety protection. The counterflow SAGD also allowed us to develop new areas in the Yarega field that were not prepared by functioning mines. What are the benefits of using thermal production technologies? In the Yarega field, there is no alternative to thermal methods for oil production. The majority of the nonthermal development technologies for heavy oil fields are known to be economically inefficient. Lukoil is working on improving thermal methods for production in its heavy oil fields. We have set a goal to increase oil production rates by 40% and final recovery factors by 10% by developing the currently employed methods and applying new approaches and technologies in pilot project programs.

Coagulation performance and floc characteristics of polytitanium tetrachloride and titanium tetrachloride compared with ferric chloride for coal mining wastewater treatment

The production and discharge of large volumes of wastewater during coal mining activities are one of the major environmental issues in Australia. Therefore, it is crucial to develop and optimise effective treatment processes for the safe disposal of coal mining wastewater (CMWW). In this study, we investigated the performance of a recently developed polytitanium tetrachloride (PTC) coagulant and compared with the performance of titanium tetrachloride (TiCl4) and the commonly used ferric chloride (FeCl3) coagulant for the treatment of CMWW from one of the coal mining sites in Australia. The use of Ti-based coagulants is particularly attractive for the CMWW treatment due to the advantage of being able to recycle the sludge to produce functional titanium dioxide (TiO2) photocatalyst; unlike the flocs formed using conventional coagulants, which need to be disposed in landfill sites. The results showed that both PTC and TiCl4 performed better than FeCl3 in terms of turbidity, UV254 and inorganic compounds (e.g. aluminium, copper or zinc) removal, however, PTC performed poorly in terms of dissolved organic carbon removal (i.e. less than 10%). While charge neutralisation and bridging adsorption were the main coagulation mechanisms identified for TiCl4 treatment; sweep coagulation and bridging adsorption seemed to play a more important role for both PTC and FeCl3 treatments. The flocs formed by PTC coagulation achieved the largest floc size of around 900μm with the highest floc growth rate. Both Ti-based coagulants (i.e., PTC and TiCl4) showed higher strength factor than FeCl3, while TiCl4 coagulant yielded the flocs with the highest recovery factor. This study indicates that Ti-based coagulants are effective and promising coagulants for the treatment of CMWW.

Computer-aided search and analysis of intervals with high current oil recovery factor in Kynovskian and Pashiyskain formations of romashkinskoe oil field

Computer-aided search and analysis of intervals with high current oil recovery factor in Kynovskian and Pashiyskain formations of romashkinskoe oil field

Energy 360: Invited Perspective: Another World’s First From The NCS: Subsea Gas Compression Is Here

President's column Steve Thurston, Chevron’s vice president of deepwater exploration and projects compares developing US Gulf of Mexico oil fields like Jack and St. Malo in 7,000 ft to the 1969 moon landing: “Except we are going to the moon every day!” It really is impressive to see how offshore and subsea technology have evolved over the years. Of the world’s current oil demand of approximately 93 million BOPD, some 27 million BOPD or 30% comes from offshore fields and the offshore contribution is expected to continue to grow according to Douglas-Westwood World Drilling &amp; Production Market Forecast 2005-2021. The Norwegian Continental Shelf (NCS) is among the front-runners in subsea technology developments and applications. It is like a giant “subsea and offshore 2.0 laboratory” for the rest of the offshore world. According to Statoil, it has more than 500 subsea wells and is the world’s largest operator in water depths greater than 100 m. The Troll-Oseberg Gas Injection subsea template installed in 1991 supplies gas subsea from Troll to Oseberg, 48 km away, making a gravity drainage recovery mechanism on Oseberg possible, resulting in a very high oil recovery factor. Through more than 150 multibranched subsea wells (two to six branches per well), individual Troll oil province development wells can connect with nearly 45,000 ft of productive reservoir. Subsea water separation and subsea reinjection units have been successfully used on the Troll oil and Tordis field developments. At the Tyrihans 10% additional recovery is achieved with injection of raw seawater from pumps on the seafloor. Snøhvit and Ormen Lange are all-subsea offshore gas developments and send unprocessed wellstreams to shore 90 and 75 miles from shore, respectively. Efficient subsea gas compression is the next challenge that the industry must face to continue subsea development. When an offshore gas field is developed 100% by a subsea development and the pressure falls because of production, compression will be needed at some point to maintain the production rate. But, there is no platform to put it on—unless you build one. What about installing subsea compression and skipping the platform altogether? Is this even possible? I posed questions to Statoil’s chief engineer in subsea technology, Rune Mode Ramberg, regarding the latest subsea compression developments on the NCS.

Low-Temperature Air/Solvent Injection for Heavy-Oil Recovery in Naturally Fractured Reservoirs

Summary Limited studies on oil recovery from naturally fractured reservoirs using low-temperature air injection show that the process is strongly dependent on oxygen (O2)-diffusion coefficient and matrix permeability, both of which are typically low. A new approach (i.e., the addition of hydrocarbon solvent gases into air) is expected to improve the diffusivity of the gas mixture and to accelerate the oxidation. To study this new idea, called low temperature air/solvent injection, laboratory tests were performed by soaking heavy-oil-saturated cores in air/solvent filled reactors to determine the critical parameters on recovery. Laboratory tests were complemented by conducting experiments using air at different O2 concentrations: zero (i.e., nitrogen), 21.0 mol% (air), and 37.3 mol% (O2-enriched air). For safety reasons, it is imperative that enough time be given for air diffusion before the injected air breaks through a highly permeable fracture network. This implies that the huff ‘n’ puff type of injection is a plausible option as opposed to the continuous injection of air. A high recovery factor was obtained by soaking a single matrix in an air/solvent chamber at static conditions rather than with air only. The period of pressure stabilization was faster for the air/solvent mixture than in 100% solvent. The asphaltene content was lower in the air/solvent case than in the 100%-air injection case. Instead of pure-hydrocarbon solvent, injection of an air/solvent mixture yields a better recovery with less asphaltene. This is expected to reduce the cost of the process compared with pure-solvent injection. At low temperatures (75C), O2 consumption in the matrix oil was low, while at high temperatures, the O2 was partially (150C) or totally (200C in the presence of propane) diffused and consumed in the matrix.

Combination of solid phase extraction based on nano alumina and liquid-liquid extraction for selective determination of palladium in food samples

A new simple and reliable method for rapid and selective extraction and determination of trace Pd(II) was developed. Combination of solid phase extraction (SPE) and liquid-liquid extraction (LLE) of trace amounts of palladium in food and water samples has been done successfully. By coupling of SPE with LLE, advantages of both can be combined including high extraction recovery and preconcentration factor (PF), environmental friendliness, low cost and appropriate time of analysis. All conditions for SPE and LLE were optimized in order to reach high PF and extraction recovery. The metal ion was eluted completely with 1.5 mL 2 M HClO4 in acetylacetone and measured by flame atomic absorption spectrometry (FAAS). The optimum experimental conditions such as pH, sample volume, amount of sorbent and concentration of eluent on the sorption of Pd(II) were evaluated. Under the optimized conditions, the sorption capacity of the modified nano-γ-alumina for Pd(II) was 13.5 mg/g. Preconcentration from 200 mL sample solution permitted a preconcentration factor of 266. The limit of detection of this method for Pd(II) was 0.2 μg/L and the relative standard deviation (RSD) of 100 ng/mL of Pd(II) was 2.3% (n = 10).

Micro-Emulsion Phase Behavior of a Cationic Surfactant at Intermediate Interfacial Tension in Sandstone and Carbonate Rocks

Based on the conventional approach, the trapped oil in rock pores can be easily displaced when a Winsor type (III) micro-emulsion is formed in the reservoir during surfactant flooding. On the other hand, the Winsor type (III) involves three phase flow of water, oil, and micro-emulsion that causes considerable oil phase trapping and surfactant retention. This work presents an experimental study on the effect of micro-emulsion phase behavior during surfactant flooding in sandstone and carbonate core samples. In this study, after accomplishing salinity scan of a cationic surfactant (C16–N(CH3)3Br), the effects of Winsor (I), Winsor (III) and Winsor (II) on oil recovery factor, differential pressure drop, relative permeability, and relative permeability ratio were investigated extensively. To carry out a comparative study, homogeneous and similar sandstone and carbonate rocks were selected and the effects of wettability alteration and dynamic surfactant adsorption were studied on them. The results of oil recovery factor in both rock types showed that Winsor (I) and Winsor (III) are preferred compared to Winsor (II) phase behavior. In addition, comparison of normalized relative permeability ratio at high water saturations revealed that Winsor (I) has more appropriate oil and water relative permeability than Winsor (II). The results presented in this paper demonstrate that optimum salinity which results in higher recovery factor and better oil displacement may occur at salinities out of Winsor (III) range. Therefore, the best way to specify optimum salinity is to perform core flood experiments at several salinities, which cover all phase behaviors of Winsor (I), Winsor (III), and Winsor (II).

Pengembangan Lapangan K Blok 2 Menggunakan Studi Simulasi Reservoir dengan Black Oil Simulator

The objective of this thesis is to discover the development of a field using the reservoir simulation study based on black oil simulator. The best scenario is one with the highest recovery factor according to the field condition.