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In drilling operations, drilling mud plays a very important role because it is irreplaceable functions. Drilling activities relate to problems caused by complex conditions in formation due to changes in temperature, pressure, and contamination from formation fluids. Using Oil Base Mud (OBM) mud systems in the form of Saraline and Smooth Fluid 05 is tested for drilling fluid performance and the results can be a reference for drilling operation. This research consist of two parts, the first: determining the drilling mud rheology value in the form of (Plastic Viscosity, Yield Point and Gel Strength) in each drilling mud of Saraline and Smooth fluid 05 mud using various high temperature parameters of 350oF, 300oF, and 270oF. The results of the mud rheology tests show at the higher the temperature, the values of rheology decreases. The second experiment is to determine the level of electrical stability in the mud which functions of oil-wet content in oil sludge (Saraline and Smooth fluid 05). The electrical stability value has a minimum limit value in OBM, which is 500 volts. In this experiment showed that the higher the temperature value, the electrical stability value in the mud will decrease, but in this study the value of electrical stability in Saraline mud and Smooth fluid 05 has a value above 500 volts, the composition OBM of Saraline and Smooth Fluid 05 sludge has very good oilwet content.

T field is a producting gas field in North Bali PSC, which currently producing 210 mmscfd from paciran sand stone formation. Paciran formation extends more than 20 km across the PSC area, which consists of 3 developed gas fields and one potential development field. The flowing material balance analysis conducted on T field suggests possibility of reservoir connectivty between this field and its neighboring fields. Even though each field is already have a well defined Gas Water Contact, a thorough investigation was done using hyrdodynamic potential analysis to see if theres any hydrodynamic potential that allowed connectivity between these fields, and enable tilted contact occurred between these field. Using pressure data taken from each fields exploration wells the analysis can be conducted that conclude that there is an existing hydrodynamic potential between gas fields in paciran formation. A review on the tilted contact analysis concludes that the existing hydrodynamic potential is not enough to tilt the contact as per actually observed contact.

Mawar Field is located in North Kalimantan Province. The field has an unconsolidated sandstone layer which is located in Tarakan formation. Porosity of the layer is more than 20%, while permeability of that is between 100 mD and 1000 mD. The zone which is poorly cemented is a source of sand problem. This sand production has an effect on the stability of oil and gas production. Sand production results in the formation of channeling around cement bonding. Sand production problem can be reduced. To overcome the acidity of the shallow formation, it can be done in two ways, that is Gravel pack using propan and stimulation using resin where the sand will be retained behind the formation. In research that has been done using core data and produced sand samples where the results obtained information about the characteristics of sand in shallow zones so that the appropriate treatment method can be recommended that is stimulation with resin. In the use of this resin there will be a permeability reduction of 15% -27% and a maximum fow rate reduction of 20%.

Modeling works of alkali surfactant injection are presented in this paper, in order to analysis the effect of salinity on surfactant adsorption and retention. Simulation model was built using UTCHEM simulator. The simulation model was validated using laboratory experiment. From the laboratory experiment and modeling, it was found that surfactant retention, as well as surfactant adsorption, increased with the salinity. However they were not linearly related. The application of microemulsion Type III (salinity of 1.4% wt.) gave the optimum flooding. Although more surfactant was adsorbed and retained compared to microemulsion Type I (salinity of 1.4% wt.), but it yielded the highest recovery factor. The formation of microemulsion Type II (salinity of 2.0% wt.) should be avoided since it effectively caused surfactant loss due to surfactant adsorption and retention.

The decline in production from of a field is the common problem in the oil and gas industry. One of the causes of the decrease in production is the decline of reservoir pressure. Based on the analisis result, it was found that SNP field had a weak water drive. The most dominant drive of the field was fluid expansion. In order to reduce the problem, a reservoir pressure maintenance effort was required by injecting water. In this research, the effect of water injection to reservoir pressure and cumulative production was analyzed. From the evaluation result, it was found that the existing inejection performance using one injection well to Zones A and B was not optimum. Because, the recovery factor was predicted to 29.11% only.By activating the four injection wells, the recoverty factor could be increase to 31.43%.

The use of the pipeline is the safest method in sending oil and gas from one area to another in oil and gas transportation system. The only challenge is to keep the pressure drop in the pipeline as small as possible to avoid high pressure differences. This pressure difference can result in reduced production flow rate and affect the flow pattern in the pipeline. The condition can lead to high possibility of a slug on pipelines that drain multiphase flow. Slug becomes one of the main concerns transport processes multiphase flow in pipelines. The emergence of slug in the pipeline could cause an unstable hydrodynamic conditions will continue to affect the liquid level in the inlet separator and cause flooding in the separator. Some of the conclusions mainly on the diameter of the pipeline, the size of the slug catcher and the size of the separator obtained from the calculation based on the study of literature and simulations with software HYSIS and OLGA. Design slug catcher to accommodate the number of processes that occur in the production transportation of X oil and gas field through a pipeline 10 inches along the 12 km with 20.68 m3 volume of slug using 3 (three) finger with diameter 28 inches and length of 10 meters each. For the separation process of oil and gas in the first five (5) years of X oil and gas field which has a high production of oil and condensate will require separator with 30 inches diameter, seam to seam height of 8.1 ft or 2.5 meters, with retention time for 2 minutes and the 3.2 slenderness ratio of the vertical separator.

Rate of penetration is one of the most significant drilling parameters for optimizing the cost of drilling geothermal wells. Many drilling variables affect the rate of penetration. Several correlations have been introduced to predict rate of penetration by involving some of the variables. In this study, a new empirical correlation based on an optimized nonlinear regression model was developed to predict ROP. Several drilling variables i.e. weight on bit, rotation-per minute, compressed air flowrate, true vertical depth, hole diameter, and foam flowrate were included into the correlation. SPSS (Statistical Product and Service Solutions) Software was applied to generate eight equations. The most appropriate equation was selected by comparing the calculated and measured ROP. The selected equation has average percentage difference of 14.6%. In addition, the procedure can be applied to estimate the effect of drilling variables on the accuracy of the model.

A pressure builds up test was performed in a dry gas exploration well. According to geological data indicated that there are two intersecting faults near the well. The analysis result provided not only information of the reservoir characteristics such as average reservoir pressure, permeability, and formation damage, but also confirmation of the presence of those two intersecting faults. In this study, a reservoir simulator was used to model pressure build up test of a well located near two intersecting faults. The effect of several parameters namely the distance between well to the faults, flow rate, and reservoir pressure, on bottom hole pressure behaviour was observed. The simulation results showed that the effect of variation of the distance between well and faults as well as that of reservoir pressure on estimation of permeability and skin factor is not significant. While, the variation of flow rate may result in a significant deviation. If a constant flow rate cannot be maintained during flowing period of the pressure build up test.

Background: Bronchiectasis is a chronic disease characterized by permanent dilatation of the conducting airways accompanied by sustained inflammation. Aims: To assess whether chronic inflammation of lungs in bronchiectasis is associated with alterations in the numbers of infiltrating antigen presenting cell (APC). Setting and Design: Lobectomy specimens from 12 nonsmoker, nonasthmatic patients with acquired (noncongenital) bronchiectasis and six control patients were included in the study. Histopathology slides were reviewed, and immunohistochemical markers for dendritic cells (DCs) macrophages and Langerhans cells have been applied and analyzed. Materials and Methods: Tissue specimens were stained by immunohistochemistry using markers for DCs (CD83 and CD23), macrophages (CD68 and CD163), and Langerhans cells (CD1A and S-100 protein). The mean cell counts of stained cells in five high power microscopic fields were recorded. Statistical Analysis Used: Descriptive statistics, mean, standard deviation, median, and interquartile range were used. A nonparametric Mann-Whitney U-test was used to compare cell counts between bronchiectasis and control patients. P

Patient: Female, 26-year-old Final Diagnosis: Adult-onset Still’s disease Symptoms: Fever • urticaria Medication: — Clinical Procedure: — Specialty: Dermatology • Rheumatology Objective: Rare disease Background: Adult-onset Still’s disease (AOSD) is a rare systemic autoinflammatory disease with a myriad of clinical presentations. The diagnosis is often challenging because there is no specific confirmatory test. Uncommon presentations can delay the proper diagnosis and management. Case Report: A 26-year-old woman presented with a history of urticaria for 2 years that had failed to respond to many types of treatment. Cutaneous biopsy showed neutrophilic urticaria. A diagnosis of AOSD was made after infectious, drug-related, neoplastic, and rheumatic etiologies had been excluded and based on the triad of fever, evanes-cent rash, and joint pain. Besides leukocytosis and increased levels of inflammatory markers, the patient’s laboratory results showed an extremely high D-dimer concentration and an increased antistreptolysin O (ASO) titer. Treatment with prednisolone and methotrexate resulted in resolution of the woman’s symptoms. Once clinical remission had been achieved, all laboratory markers returned to normal, yet the patient’s ASO titer remained elevated during 18 months of follow-up. Conclusions: Urticaria is a rare cutaneous manifestation of AOSD. Histopathology typically shows predominant neutrophilic infiltrates, which is a unique entity called neutrophilic urticarial dermatosis (NUD). Identifying diseases associated with NUD will facilitate prompt diagnosis and treatment of AOSD, as therapies for it largely differ depending on the underlying cause. Known etiologies of AOS include systemic lupus erythematosus (SLE), Schnitzler syndrome, hereditary autoinflammatory periodic syndromes, and serum sickness-like drug eruption. An elevated ASO titer is unusual, and in our case, it did not seem to follow the patient’s clinical course. An elevated D-dimer concentration can be an indicator of disease activity and testing might be beneficial in a subset of patients with normal ferritin levels.

Lapangan RMM adalah lapangan minyak dan gas dengan reservoir pada Formasi Santul dan Tabul pada sistem deltaik yang dikarakterisasi oleh perangkap struktural, stratigrafi, dan kombinasi keduanya.Maksud dari penelitian ini adalah sebagaisalah satu bagian perencanaan pengembangan lapangan tahap lanjut untukdapatmeningkatkan perolehan minyak yang ada saat ini, yaitu dengan melakukan simulasireservoir dengan peniginjeksian pada Lapangan RMM. Adapun tujuan dari penelitian ini adalah menganalisa keselarasan sifat fisik reservoir dan pola penginjeksian terhadap efisiensi pendesakan dan pengangkatan sisa cadangan hidrokarbon secara optimal.Penelitian ini dilakukan pada lapisan M31 diproduksikan dari 12 sumur yang terbagi dalam 2 blok 1 dan 4 memiliki sejarah produksi mulai bulan Januari 1956, blok 4 sampai sekarang belum diproduksikan. Dari 12 sumur yang berproduksi di lapisan M31 telah menguras minyak sebesar sebesar 6073.7 Mstb dengan Recovery Factor sekitar 30.61 % di blok 1 dengan OOIP 19.84 MMSTB.Case yang digunakan dalam penelitian ini adalah dengan pola injeksi Peripheral, Normal Five Spot dan Inverted Five Spot dan dengan beberapa sensitivity rate injeksi . Prediksi dilakukan dari tahun 2014 sampai tahun 2025. Dari case yang dilakukan, yang paling optimal menghasilkan minyak adalah dengan Case 1 yaitu dengan pola peripheral. Dengan laju injeksi air sebesar 2000 bwpd dengan menghasilkan minyak sebanyak 7042.5 MSTB

RM field is one of the fields located in Java Island. RM Field has great potential to be developed, In RM field water injection has been done to increase the value of oil production. The purpose of this paper are to find out the effect of heterogeneity on the RM field with dykstra parson and mobility ratio methods. The layers will be analyzed in the RM field were layers 22, 23 and 24. The results of the analysis for the Vdp value at layer 22 is 0.828, the Vdp value at layer 23 is 0.814, and the Vdp value in layer 24 is 0.812. In addition, a mobility ratio analysis was carried out using rock type 1 on the RM field and the M value on rock type 1 was 0.3429. The conclusion is with the dykstra parson analysis, it can be seen that RM field reservoirs tend to be heterogeneous, this is seen from the Vdp value which approaches the number 1, which is equal to 0.812 to 0.828, and with a value of M

The needs of petroleum as energy, have increasing while the oil production has depleting. Due to that needs, the method of Enhanced Oil Recovery (EOR) or in other hands as tertiary recovery (after primary recovery and secondary recovery) is being developed. EOR has many methods; one of the methods is chemical injection that consists of surfactant, alkaline and polymer. In this experiment, the author is using surfactant injection. The using of surfactant is to decrease the interfacial tension between oil and water, with the result is surfactant can displace oil through rock pores. This study will be discussing about the effect of salinity, surfactant types and surfactant concentrations on surfactant injection for carbonate rock. The surfactant types are Alpha Olefin Sulfonate (AOS) and Tween 20. The surfactant concentration varieties are 0,1%; 0,25%; 0,5%; 0,75% and 1%. Salinity varieties are 10.000 ppm; 15.000 ppm; 20.000 ppm and 25.000 ppm. From this study, it had determined that surfactant can displace the oil from rock pores based on the influence of salinity, surfactant concentrations and surfactant types to recovery factor. The determination of recovery factor will be using these methods; Amott apparatus (imbibition process) and injection using core holder and syringe pump. From experiments that have been done, the effect of surfactant injection on carbonate rocks is more optimal in core flooding process compared with imbibition process, with the recovery factor percentage is 57%. Core flooding process uses the external thrust, therefore the oil displacement with surfactant is more evenly and optimally.

Pressure Build Up analyses on a heavy oil well would give an inconclusive result on pressure derivative curves. Some kind of thermal injection should be performed prior to implementing the operation of Pressure Build Up test, where the heat will lower the viscosity of the reservoir fluid. The study was aimed to design a proper well test for N-7 Well using a simulator. Since the Pressure Build Up test was intended to reach radial flow period within shut in time of 100 hours, the viscosity of fluid should be reduced to 24.8 cp or less. Sensitivity of several parameters namely viscosity, permeability, porosity, and shut-in time was conducted in designing Pressure Build Up test. This sensitivity would give various radius of investigation. Furthermore, the study was continued to correlate radius of investigation as a function of the parameters mentioned above.

In this study, CO2 Flooding simulation models were used to predict oil recovery. The models were previously validated by laboratory experiments of continuous injection and water Alternating Gas (CO2) injection for miscible condition. Sensitivity test was performed to attain the effect of injection rate parameters. The simulation experiments indicated that the optimal performance for both methods obtained at injection rate of 0.09 cuft/day. The scenarios of continuous CO2 injection showed that the maximum recovery factor was 21.1%. While the maximum recovery factor of the scenarios of water alternating gas was 37.9%. Based on the results of the whole scenarios used, Walter Alternating Gas flooding resulted in more effective recovery factor than Continuous CO2 Flooding, within the range of injection rate studied.

Carbon dioxide (CO2) miscible flooding is one of the Enhanced Oil Recovery (EOR) methods that has been recognized as a promising method to improve of oil recovery before abandonment. In addition, many issues related to global warming or greenhouse effect due to CO2. By using CO2 as either miscible or immiscible flooding to enhance oil recovery injected into reservoir, it may help reduce environmental problems. Carbon dioxide (CO2) is able to improve of oil recovery effectively by important key parameter: minimum miscibility pressure (MMP), viscosity, and density. This paper aims to determine the effect of CO2 volume injection to reservoir fluid characteristic in order to CO2 miscible flooding for displacing the oil production. This research was carried out by some series of laboratory experiment that involve PVT test, slim tube test, and swelling test. The result from laboratory experiments were used to observe the use of CO2 and its effect on reservoir fluid characteristics such as viscosity, solubility, and swelling factor. MMP obtained from slim tube test is 2805 Psi. Based on the results, all trend of parameters: viscosity, solubility, and swelling factor showed the positive impact of CO2 have on liquid recovery.

Oil recovery may be increased by lowering interfacial tension between oil and water due to surfactant injection. Bagasse is one of the organic materials which has a fairly high lignin content, where lignin is the basic substance of making Natrium Lignosulfonate (NaLS) Surfactants. The research was divided into three sections. The first was experiment to produce lignin from bagasse. In this experiment 100 gram of bagasse with size of 60 mesh or 80 mesh extracted by benzene + ethanol (2:1) and then 20%, 50%, or 75% NaOH was added to activate lignin. The maximum amount of lignin produced was 24.88%. The second experiment was to produce NaLS surfactant from obtained lignin. FTIR equipment was used to verify the NaLS surfactant yielded using the method. The maximum amount of NaLS surfactant produced was 20.264% of bagasse mass. After that NaLS surfactant obtained from the previous process was used in chemical flooding experiment. In the experiments, the surfactant concentration in the solution was varied at 0.05%, 0.10%, 0.15%, and 1.00%. While temperature was set at 30°C, 40°C, 60°C, 70°C, or 80°C. The optimum condition happened when a solution with surfactant concentration of 1% was injected at 60°C. The recovery factor of oil using the condition was 0.47.

Well test analysis was conducted to determine the characteristics of reservoir rocks. From the well test analysis it is obtained information such as permeability and skin factor. The skin factor is a quantity indicating the presence of disturbance in the formation as a result of drilling operations, production operations, perforating casing, gravel pack installation, remedial well work, acidizing operation, and hydraulic fracture operation. The objective of this research is to determine the relationship of multi rate test method of Jones, Blount, and Glaze and the comparison result among pressure buildup test and pressure drawdown test analyses, using Kappa software or manually calculation. Therefore, in this paper will study the method of Jones, Blount, and Glaze and the well test analyses to determine further work of the wells on block X. The data used in this paper is secondary data, namely the results of well test from three wells.Applying drawdown test analysis of A, Y, and Z wells yield skin factor values of 3.37; 27.10; and -1.39. Where in buildup pressure Horner method analysis of A, Y, and Z wells yield skin factor values of 16.10; 11.18; and -2.07. In the method of type curve derivatives the drawdown analysis of A, Y, and Z wells yield skin factor values of 7.04; 11.18; and 4.20. The analysis of pressure buildup, of A, Y, and Z wells yield skin factor value of 25.11; 14.47; and 1.93. In the analysis using Kappa software of A, Y, and Z wells yield skin factor values of 5.56; 10.2; and 2.00. The skin results of these wells indicate the formation damages. The Short Term Multiple Rate Flow Tests analysis using Jones, Blount, and Glaze method from the plots of Δp/q versus oil flow rate (q) are b’ high and b’/b low. These indicate that the three wells are encountering formation damages. The Jones, Blount, and Glaze method as well as the pressure buildup and pressure drawdown test analyses in block X indicate that these wells require to be stimulated.

Wells X-1 is a gas condensate well which located in lapangan X, Sulawesi Island. At well X-1 well test was conducted using pressure build up, where the analysis was conducted with objective to determine the reservoir characteristic of X-1 wells such as permeability, skin, flow efficiency and investigation radius. In the pressure build up test, the horner plot and derivation analysis using pseudo pressure and P2 approaches were applied with the gas well X-1 has a reservoir pressure of 2555 psia. The analysis is done using saphir 3.20 and Ms.Excel software where the results of the counsel to see if there is any possibility of formation damage. X-1 is also known as homogeneous with a fault boundary present in the fault located at a certain distance from the well X-1 in which the fault is only one direction from the reservoir. The pressure derivative plot analysis was conducted with two methods such as two-point method and three-point method, where the result of the overlay of the derivative curve corresponds to the deviation of the calculation result method which is less than 10%. The horner plot analysis is also done with the ψ(P) pseudo pressure and P2 approach which is the result of horner plot analysis using pseudo pressure ψ(P) pseudo pressure in saphir 3.20 obtained the slope (m), permeability, and skin values respectively were 3.22432E + 5 psi2/cp, 132 mD, and 21.6, whereas Ms.Excel results obtained the price of slope (m), permeability, and skin respectively were 320890.61 psi2/cp, 134.83 mD, and 21.1. To analyze the horner plot using the P2 approach at saphir 3.20 the value of slope (m), permeability, and skins values respectively were 5495.07 psi2/cp, 125 mD, and 21.3 and for the results of Ms. Excel the price of slope (m), permeability, and skin respectively were 5451.66 psi2/cp, 147,29 mD, and 20,1. Positive skin results in both methods of horner plot and derivative plot indicate the well is damaged and need to be stimulated.

Hydraulic fracturing is one of the stimulation method that aimed to increase productivity of well by creating a high conductive conduit in reservoir connecting it to the wellbore. This high conductivity zone is created by injecting fluid into matrix formation with enough rate and pressure. After crack initiate and propagate, the process continue with pumping slurry consist of fracturing fluid and sand. This slurry continues to extend the fracture and concurrently carries sand deeply into formation. After the materials pumped, carrier fluid will leak off to the formation and leave the sand holds the fracture created. TLS Formation in X and Y Field is widely known as a formation that have low productivity since it has low permeability around 5 md and low resistivity 3 Ohm-m. Oil from TLS formation could not be produced without fracturing. This formation also have high clay content, 20 – 40 % clay. Mineralogy analysis also shown that this formation contains water sensitive clay such as smectite and kaolinite. Hydraulic fracturing has been done in this field since 2002 on around 130 wells. At the beginning of hydraulic fracturing campaign, the success parameter is only to make the wells produce hydrocarbon in economical rate. As the fractured wells become larger in number, several optimization is also been done to increase oil gain. Later on, the needs of conclusive analysis to evaluate well performance after hydraulic fracturing rise up due to sharp decrement of crude oil price. Accurate analysis and recommendation need to be conducted to assess the best candidate for hydraulic fracturing to maximize success ratio. Even though a common practice, candidate-well selection is not a straightforward process and up to now, there has not been a well-defined approach to address this process. Conventional methods are not easy to use for nonlinear process, such as candidate-well selection that goes through a group of parameters having different attributes and features such as geological aspect, reservoir and fluid characteristics, production details, etc. and that’s because it is difficult to describe properly all their nonlinearities. In that matter, Artificial Intelligence approach is expected to be an alternative solution for this condition.

Angiolipoma is characteristically described as an encapsulated mass of mature adipose tissue containing clusters of small blood vessels. The authors have described an extremely rare case of angiolipoma of the orbit. This rare case is only the third reported in the orbit and should be readily recognized from other differential diagnoses. The patient had an excellent prognosis after full surgical excision.

Medulloblastoma is an embryonal neuroepithelial tumor of the cerebellum and is the most common malignant central nervous system tumor in children. Different histological variants and patterns have been described. The classic variant represents the majority of cases. This report describes a rare case of large cell/anaplastic medulloblastoma with myogenic, melanotic and neuronal differentiation arising in the cerebellum of a 3-year-old boy who presented with headache and vomiting. Magnetic resonance imaging demonstrated a heterogeneously enhanced lesion in the fourth ventricle. Surgical resection of the tumor was accomplished, but a residual tumor was left behind because of the involvement of the brainstem. Postoperatively, the patient received chemotherapy and radiotherapy. Currently, 20 months after treatment, the patient has survived without further progression. Pathological examination revealed a high grade primitive neuronal tumor with foci of myogenic features, melanin containing epithelial elements and ganglion-like cells, which were confirmed by immunohistochemistry.

Accessory scrotum and congenital perineal lipoma are unusual congenital anomalies. Congenital pulmonary airway malformation (CPAM) is a rare congenital disorder of the lung. There are five types of CPAM, each with a different clinical presentation and prognosis. The present report involves a case of type 2 CPAM associated with accessory scrotum and congenital perianal lipoma.

This paper describes a method to rank potential infill well locations using Artificial Neural Networks (ANN) from existing well data. Sensitivity test was conducted for training and testing data used with comparison 2:8, 4:6, 5:5, 6:4 and 8:2 for each data. Root Mean Square Error difference between training and test data show that the best results obtained from the ratio of training data and testing data 8: 2. Two ANN models were built. The first model predicted top sand depth, resistivity, gamma-ray and density-neutron from infill well location (chosen from structural position and good oil rates from offset wells). The second model predicted initial oil rate from outputs from the first model. Predicted initial oil rates from the ANN model were compared with those from the 3D reservoir simulation model. They shows similar prediction of oil rates which gave high confidence in the predicted oil rate. Very different oil rate prediction between the two models can be used as consideration to improve the simulation model.

Eccrine angiomatous hamartoma (EAH) is a rare, benign cutaneous tumor. It is characterized by the proliferation of the eccrine gland elements that are closely associated with capillary proliferation. Patients usually present with a solitary nodule on the extremities that appeared at birth or during the prepubertal years. We report a rare case of EAH in a 13-year-old boy, with clinical features suggesting melanoma. Histologically, an EAH with changes resembling a verrucous hemangioma was noted.

This work presents a new alkaline–surfactant (AS) flooding formulation that replaces and improves the traditional alkaline–surfactant–polymer (ASP) flooding slug. With the design of a cost-effective AS slug, a new series of polymeric surfactants was produced based on agriculture material. In this article, the polymeric surfactant was produced by a graft polymerization process using several surfactant-to-acrylamide ratios. This surfactant was designed to graft the sulfonated group to the polymer backbone as one component system for interfacial tension (IFT) reduction and viscosity control. The performance of the resultant surfactants was studied in the presence and absence of sodium carbonate as an alkaline agent at reservoir temperature of 90°C. The feasibility of applying the AS formula was based on IFT measurement between crude oil and AS solution and viscosity tests. As a result, the ratio of 1:0.5 (S:A) was selected as the optimum ratio for IFT reduction and viscosity control. A combination o...

In this paper, simulation study was conducted to investigate the effect of spatial heterogeneity of multiple porosity fields on oil recovery, residual oil and microemulsion saturation. The generated porosity fields were fed into UTCHEM for simulating surfactant flooding in heterogeneous two-layered porous media. From the analysis, surfactant flooding was more sensitive than water flooding to the spatial distribution of multiple porosity fields. Residual oil saturation in upper and lower layers after water flooding was about the same with the reservoir heterogeneity. On the other hand, both residual oil and microemulsion saturation in the two layers after surfactant flooding became more equal as porosity distribution standard increased. Spatial heterogeneity of multiple porosity fields had only a small effect on residual oil saturation and recovery factor. The variation of recovery factor due to the reservoir heterogeneity was under 4.2%.