Pub Date : 2017-12-22DOI: 10.4172/2157-7463.1000350
A. Roy
Biosurfactants are those compounds which contains both hydrophilic and hydrophobic moieties i.e., amphiphilic in nature. They have advantages over the chemical surfactant such as low toxicity, eco-friendly, etc. They possess wide range of industrial applications such as bioremediation, food processing, oil industries and health care. Various microorganisms have the ability to produce the potential biosurfactant. In the present study, microbial culture which showed highest biosurfactant activity i.e., SA3 based on the oil displacement activity and emulsion layer was selected for various culture parameters optimization. Sodium nitrate as a nitrogen source and dextrose as a carbon gives the highest biomass and biosurfactant production. Further 2% of dextrose and 2% of inoculum size provides the highest biomass and biosurfactant production. Growth kinetics and biosurfactant kinetics study reveals that the maximum biomass was produced after 96 h and maximum production of biosurfactant was after 72 h of incubation period. Overall, the results indicated the potential use of SA3 isolate in bioremediation processes.
{"title":"Effect of Various Culture Parameters on the Bio-surfactant Production from Bacterial Isolates","authors":"A. Roy","doi":"10.4172/2157-7463.1000350","DOIUrl":"https://doi.org/10.4172/2157-7463.1000350","url":null,"abstract":"Biosurfactants are those compounds which contains both hydrophilic and hydrophobic moieties i.e., amphiphilic in nature. They have advantages over the chemical surfactant such as low toxicity, eco-friendly, etc. They possess wide range of industrial applications such as bioremediation, food processing, oil industries and health care. Various microorganisms have the ability to produce the potential biosurfactant. In the present study, microbial culture which showed highest biosurfactant activity i.e., SA3 based on the oil displacement activity and emulsion layer was selected for various culture parameters optimization. Sodium nitrate as a nitrogen source and dextrose as a carbon gives the highest biomass and biosurfactant production. Further 2% of dextrose and 2% of inoculum size provides the highest biomass and biosurfactant production. Growth kinetics and biosurfactant kinetics study reveals that the maximum biomass was produced after 96 h and maximum production of biosurfactant was after 72 h of incubation period. Overall, the results indicated the potential use of SA3 isolate in bioremediation processes.","PeriodicalId":16699,"journal":{"name":"Journal of Petroleum & Environmental Biotechnology","volume":"9 1","pages":"1-4"},"PeriodicalIF":0.0,"publicationDate":"2017-12-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78209068","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2017-11-27DOI: 10.4172/2157-7463.1000348
B. Nasser, Ramadan Ar, H. Ry, Mohamed Me, W. Ismail
Oilfield water samples from injection water treatment facility and soil/sludge samples from Gas Oil Separation Plant (GOSP) at Saudi Aramco were analyzed for the presence of SRB and PAH-degrading bacteria. SRB were detected by targeting a fragment of the apsA gene encoding adenosine-5-phosphosulfate reductase, which is characteristic of all SRB. The PAH-degrading bacteria were detected using a primer pair that amplifies a fragment of the gene encoding the large subunit of the naphthalene dioxygenase gene nahA. The nahA gene was detected in almost half of the soil/sludge samples with the highest copy number of 60540 copies/g soil/sludge. Most of the analyzed water samples contained high copy numbers of nahA gene with the highest copy number 3846 copies/ml. Most of the analyzed water samples revealed the presence of high copy numbers of the apsA gene with the highest copy number of 44 x 106/ml in sample number 2. Only 7 of the soil/sludge samples revealed the presence of the apsA gene with the highest copy number of 107920/g soil/sludge in sample number 11. In contrast to the nahA gene, the highest copy numbers of the apsA gene were detected in the water samples. SRB and PAH-degrading bacteria exist in some Saudi oilfields and appear to play a role in the H2S production and PAH degradation.
{"title":"Detection and Quantification of Sulfate-Reducing and Polycyclic Aromatic Hydrocarbon-Degrading Bacteria in Oilfield Using Functional Markers and Quantitative PCR","authors":"B. Nasser, Ramadan Ar, H. Ry, Mohamed Me, W. Ismail","doi":"10.4172/2157-7463.1000348","DOIUrl":"https://doi.org/10.4172/2157-7463.1000348","url":null,"abstract":"Oilfield water samples from injection water treatment facility and soil/sludge samples from Gas Oil Separation Plant (GOSP) at Saudi Aramco were analyzed for the presence of SRB and PAH-degrading bacteria. SRB were detected by targeting a fragment of the apsA gene encoding adenosine-5-phosphosulfate reductase, which is characteristic of all SRB. The PAH-degrading bacteria were detected using a primer pair that amplifies a fragment of the gene encoding the large subunit of the naphthalene dioxygenase gene nahA. The nahA gene was detected in almost half of the soil/sludge samples with the highest copy number of 60540 copies/g soil/sludge. Most of the analyzed water samples contained high copy numbers of nahA gene with the highest copy number 3846 copies/ml. Most of the analyzed water samples revealed the presence of high copy numbers of the apsA gene with the highest copy number of 44 x 106/ml in sample number 2. Only 7 of the soil/sludge samples revealed the presence of the apsA gene with the highest copy number of 107920/g soil/sludge in sample number 11. In contrast to the nahA gene, the highest copy numbers of the apsA gene were detected in the water samples. SRB and PAH-degrading bacteria exist in some Saudi oilfields and appear to play a role in the H2S production and PAH degradation.","PeriodicalId":16699,"journal":{"name":"Journal of Petroleum & Environmental Biotechnology","volume":"176 1","pages":"1-7"},"PeriodicalIF":0.0,"publicationDate":"2017-11-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79830410","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2017-10-16DOI: 10.4172/2157-7463.1000343
M. Abdelkhalek, Ahmed H. El-Banbi, M. Sayyouh
Production data analysis is a viable tool for reservoir characterization and estimation of initial gas in place (IGIP) and reserves. Several methods are available to analyse production data starting with Arps classical decline curve analysis (DCA) in 1945 all the way to more sophisticated analytical and advanced DCA techniques. Most of these methods are applicable only for single phase flow in porous media. In this paper, we present a simple analytical decline curve analysis (ADCA) model that takes into account the effect of water influx on gas reservoir performance. We introduced the water influx effect into the pseudo-steady state flow equation which enables us to estimate the reservoir pressure and the IGIP for water drive gas reservoirs. The model is based on coupling the material balance equation for gas reservoirs, aquifer models, and the gas flow equation to calculate the well’s production rate versus time. The model can also estimate reservoir pressure, gas saturation, water production rate, and gas production rate with time. When the model is run in history-match mode to match gas and water production, we can estimate the IGIP, well’s productivity index, and aquifer parameters. The model can also be run in prediction mode to predict gas and water production at any conditions of bottom-hole flowing pressure (BHFP) (or surface tubing pressure) and reserves can be calculated. The model was validated with several simulated cases at variable conditions of rate and pressure. The model was then used to perform decline curve analysis in several field cases. This technique is fast and requires minimum input data. The paper will also present the application of this technique to analyse production data and predict reserves for gas wells producing both gas and water.
{"title":"Analytical Decline Curve Analysis Model for Water Drive Gas Reservoirs","authors":"M. Abdelkhalek, Ahmed H. El-Banbi, M. Sayyouh","doi":"10.4172/2157-7463.1000343","DOIUrl":"https://doi.org/10.4172/2157-7463.1000343","url":null,"abstract":"Production data analysis is a viable tool for reservoir characterization and estimation of initial gas in place (IGIP) and reserves. Several methods are available to analyse production data starting with Arps classical decline curve analysis (DCA) in 1945 all the way to more sophisticated analytical and advanced DCA techniques. Most of these methods are applicable only for single phase flow in porous media. In this paper, we present a simple analytical decline curve analysis (ADCA) model that takes into account the effect of water influx on gas reservoir performance. We introduced the water influx effect into the pseudo-steady state flow equation which enables us to estimate the reservoir pressure and the IGIP for water drive gas reservoirs. The model is based on coupling the material balance equation for gas reservoirs, aquifer models, and the gas flow equation to calculate the well’s production rate versus time. The model can also estimate reservoir pressure, gas saturation, water production rate, and gas production rate with time. When the model is run in history-match mode to match gas and water production, we can estimate the IGIP, well’s productivity index, and aquifer parameters. The model can also be run in prediction mode to predict gas and water production at any conditions of bottom-hole flowing pressure (BHFP) (or surface tubing pressure) and reserves can be calculated. The model was validated with several simulated cases at variable conditions of rate and pressure. The model was then used to perform decline curve analysis in several field cases. This technique is fast and requires minimum input data. The paper will also present the application of this technique to analyse production data and predict reserves for gas wells producing both gas and water.","PeriodicalId":16699,"journal":{"name":"Journal of Petroleum & Environmental Biotechnology","volume":"63 1","pages":"1-9"},"PeriodicalIF":0.0,"publicationDate":"2017-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80124057","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2017-08-31DOI: 10.4172/2157-7463.1000339
N. El-Mehbad
Esters are excellent lubricants and high performance industrial fluids, but they are often costly. We prepared the ester sorbitol palmitate via an inexpensive phase-transfer catalysis method as an additive for the retardation of oil oxidation. The effects of the sorbitan palmitate content on the lubricant properties and oxidation stability of a base oil were determined. The addition of sorbitan palmitate to the oil retarded oxidation and enhanced the pour point depression. A novel method for inhibiting oxidation through the action of micellar cores was suggested. This micellar inhibition offers a new concept for the protection of lubricants against oxidative degradation.
{"title":"Preparation of Sorbitol Palmitate by Organic Catalysis and Its Application for Base Oil Stabilization","authors":"N. El-Mehbad","doi":"10.4172/2157-7463.1000339","DOIUrl":"https://doi.org/10.4172/2157-7463.1000339","url":null,"abstract":"Esters are excellent lubricants and high performance industrial fluids, but they are often costly. We prepared the \u0000 ester sorbitol palmitate via an inexpensive phase-transfer catalysis method as an additive for the retardation of oil oxidation. The effects of the sorbitan palmitate content on the lubricant properties and oxidation stability of a base \u0000 oil were determined. The addition of sorbitan palmitate to the oil retarded oxidation and enhanced the pour point \u0000 depression. A novel method for inhibiting oxidation through the action of micellar cores was suggested. This micellar \u0000inhibition offers a new concept for the protection of lubricants against oxidative degradation.","PeriodicalId":16699,"journal":{"name":"Journal of Petroleum & Environmental Biotechnology","volume":"109 1","pages":"1-4"},"PeriodicalIF":0.0,"publicationDate":"2017-08-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82488013","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2017-08-31DOI: 10.4172/2157-7463.1000340
Al-Sulaiman Fa, Fadaws Ah, A. Ta
Geologic evaluation of the Kirkuk underground was conducted by comparison of the geometric properties of the cavities derived from two surveys running during 1989 and 2015. The vertical cross sections of the cavities show that most cavities have shown that most cavities have irregular shape because of the presence of impurities in the salt bed that cause different leaching velocities in different directions. The relationship of the cavity roof with tilted salt bed was studied, that shows some of the cavities are not safe to store LPG.
{"title":"Geologic Evaluation of Kirkuk Underground Storage Project","authors":"Al-Sulaiman Fa, Fadaws Ah, A. Ta","doi":"10.4172/2157-7463.1000340","DOIUrl":"https://doi.org/10.4172/2157-7463.1000340","url":null,"abstract":"Geologic evaluation of the Kirkuk underground was conducted by comparison of the geometric properties of the cavities derived from two surveys running during 1989 and 2015. The vertical cross sections of the cavities show that most cavities have shown that most cavities have irregular shape because of the presence of impurities in the salt bed that cause different leaching velocities in different directions. The relationship of the cavity roof with tilted salt bed was studied, that shows some of the cavities are not safe to store LPG.","PeriodicalId":16699,"journal":{"name":"Journal of Petroleum & Environmental Biotechnology","volume":"83 1","pages":"1-4"},"PeriodicalIF":0.0,"publicationDate":"2017-08-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78744656","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2017-08-31DOI: 10.4172/2157-7463.1000338
V. Co, Osuji Lc, Onojake Mc
Bituminous sands obtained from six different locations in Ondo State, Nigeria were analysed. Physicochemical parameters were studied using American Standard Testing and Materials (ASTM) procedures and analysis of hydrocarbon and non-hydrocarbon fractions using Ultraviolet Visible Spectrophotometer were undertaken. Results obtained show: density (0.877-0.884 g/cm3); specific gravity (0.878-0.886); API gravity (28.133°API to 29.531°API); kinematic viscosity (0.440 cSt to 0.550 cSt); dynamic viscosity (0.290-0.360); cloud point (-15°C to -2°C); moisture content (775 ppm to 1761 ppm); gum content (605-1895 mg/100 ml) and pour point of <-34°C. Result of the Saturates, Aromatics, Resins and Asphaltene (SARA) analysis revealed; saturates; 44.139% to 69.436%, aromatics; 21.778% to 44.949%, resins; 11.067% to 28.369% and asphaltenes; 8.634% to 29.278%. They suggest that these bituminous sands have similar characteristics, can be classified as medium heavy oils on the API gravity scale, high in saturate hydrocarbons and low in asphaltene content which indicates their high hydrocarbon potential.
{"title":"Bulk Physiognomies and Sara Constituents of Bituminous Sands from Ondo State, Nigeria","authors":"V. Co, Osuji Lc, Onojake Mc","doi":"10.4172/2157-7463.1000338","DOIUrl":"https://doi.org/10.4172/2157-7463.1000338","url":null,"abstract":"Bituminous sands obtained from six different locations in Ondo State, Nigeria were analysed. Physicochemical parameters were studied using American Standard Testing and Materials (ASTM) procedures and analysis of hydrocarbon and non-hydrocarbon fractions using Ultraviolet Visible Spectrophotometer were undertaken. Results obtained show: density (0.877-0.884 g/cm3); specific gravity (0.878-0.886); API gravity (28.133°API to 29.531°API); kinematic viscosity (0.440 cSt to 0.550 cSt); dynamic viscosity (0.290-0.360); cloud point (-15°C to -2°C); moisture content (775 ppm to 1761 ppm); gum content (605-1895 mg/100 ml) and pour point of <-34°C. Result of the Saturates, Aromatics, Resins and Asphaltene (SARA) analysis revealed; saturates; 44.139% to 69.436%, aromatics; 21.778% to 44.949%, resins; 11.067% to 28.369% and asphaltenes; 8.634% to 29.278%. They suggest that these bituminous sands have similar characteristics, can be classified as medium heavy oils on the API gravity scale, high in saturate hydrocarbons and low in asphaltene content which indicates their high hydrocarbon potential.","PeriodicalId":16699,"journal":{"name":"Journal of Petroleum & Environmental Biotechnology","volume":"22 1","pages":"1-4"},"PeriodicalIF":0.0,"publicationDate":"2017-08-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84398968","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2017-08-17DOI: 10.4172/2157-7463.1000335
I. Khasanov
At new construction and reconstruction of petrochemical production facilities for replacement of bolted equipment covers and hatches are widely used quick opening closures of different design. In this paper are analyzed quick opening closures of covers and hatches as well as pipelines, chambers and apparatuses dead end sections. Their advantages and shortcomings are presented. It is shown that high reliability, fabricability and ease of use requirements are met by new generation quick opening closures–ZKSsh/Zatvor Kontsevoi Sektorny Sheryk=Sector End Closure by Sherik. The closure design makes it possible to fabricate and deliver it both as an equipment component and in the form of a separate finished product to be installed at various vertically or horizontally oriented branch pipes, including in replacement of the existing fixtures in all possible diameter and pressure ranges.
{"title":"Quick Opening Closures-A New Stage in Petrochemical Industry","authors":"I. Khasanov","doi":"10.4172/2157-7463.1000335","DOIUrl":"https://doi.org/10.4172/2157-7463.1000335","url":null,"abstract":"At new construction and reconstruction of petrochemical production facilities for replacement of bolted equipment covers and hatches are widely used quick opening closures of different design. In this paper are analyzed quick opening closures of covers and hatches as well as pipelines, chambers and apparatuses dead end sections. Their advantages and shortcomings are presented. It is shown that high reliability, fabricability and ease of use requirements are met by new generation quick opening closures–ZKSsh/Zatvor Kontsevoi Sektorny Sheryk=Sector End Closure by Sherik. The closure design makes it possible to fabricate and deliver it both as an equipment component and in the form of a separate finished product to be installed at various vertically or horizontally oriented branch pipes, including in replacement of the existing fixtures in all possible diameter and pressure ranges.","PeriodicalId":16699,"journal":{"name":"Journal of Petroleum & Environmental Biotechnology","volume":"1 1","pages":"1-5"},"PeriodicalIF":0.0,"publicationDate":"2017-08-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88397922","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2017-08-12DOI: 10.4172/2157-7463.1000336
Vaishali Sharma, A. Sircar, N. Mohammad, S. Patel
Non-Darcy Flow behavior is important for describing fluid flow in consolidated or unconsolidated porous media when abrupt changes in velocity dominates. A criterion or a generalized equation is required to understand this flow behavior in the isotropic/anisotropic carbonate and sandstone reservoirs, and naturally or hydraulically fractured reservoirs. Various correlations and equations have been reviewed in this paper to quantify this non-Darcy coefficient (i.e., beta coefficient) mathematically. It has been observed that this coefficient is highly dependent on rock properties (mainly porosity, permeability and tortuosity). An algorithm to determine the values of the beta coefficient by using the correlations have been presented and coded and converted in to a robust user-friendly simulator. This simulator can take a large amount of data set as input and will generate a large data set of beta values as output. The obtained or calculated beta value is very useful for predicting the change in pressure gradient with respect to velocity and hence can give the best estimate of hydrocarbon production under challenging or adverse pressure drop conditions.
{"title":"A Treatise on Non-Darcy Flow Correlations in Porous Media","authors":"Vaishali Sharma, A. Sircar, N. Mohammad, S. Patel","doi":"10.4172/2157-7463.1000336","DOIUrl":"https://doi.org/10.4172/2157-7463.1000336","url":null,"abstract":"Non-Darcy Flow behavior is important for describing fluid flow in consolidated or unconsolidated porous media when abrupt changes in velocity dominates. A criterion or a generalized equation is required to understand this flow behavior in the isotropic/anisotropic carbonate and sandstone reservoirs, and naturally or hydraulically fractured reservoirs. Various correlations and equations have been reviewed in this paper to quantify this non-Darcy coefficient (i.e., beta coefficient) mathematically. It has been observed that this coefficient is highly dependent on rock properties (mainly porosity, permeability and tortuosity). An algorithm to determine the values of the beta coefficient by using the correlations have been presented and coded and converted in to a robust user-friendly simulator. This simulator can take a large amount of data set as input and will generate a large data set of beta values as output. The obtained or calculated beta value is very useful for predicting the change in pressure gradient with respect to velocity and hence can give the best estimate of hydrocarbon production under challenging or adverse pressure drop conditions.","PeriodicalId":16699,"journal":{"name":"Journal of Petroleum & Environmental Biotechnology","volume":"51 1","pages":"1-12"},"PeriodicalIF":0.0,"publicationDate":"2017-08-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80895938","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2017-08-07DOI: 10.4172/2157-7463.1000337
Kuiqian Ma, Yanlai Li, Ting Sun
Literature survey shows that polymer flooding was generally conducted during high water-cut stage (WCT>80% to 90%). Even the first China Offshore polymer flooding project was carried out in SZ when water cut was 60%. By then, conduction of polymer flooding in early phase (WCT<10%) was just discussed in theory. For offshore oilfield, the treatment of water could be costly. Because polymer improves mobility ratio of replacement fluid over oil and sweep efficiency, less water is injected and less water is produced. So, we did enormous research about the polymer flooding on early stage by theoretical analysis, series of experiments and chemical flooding simulation. Based on these researches, we carried out the first field test of polymer flooding on early stage in LD. Single well polymer injection test was started in Mar 2006 when the water cut in the pattern was lower than 10%. After the trial, there were other 5 water injectors being converted to polymer injectors from 2007 to 2009. The polymer flooding controlled reserve was about 25,250,000 m3. For the early stage polymer flooding, the characteristics of the responses on producers were different from the case in which polymer flooding was conducted during high water cut stage. The water producing of the producers continued to rise up after polymer flooding, but the simulation research showed that the water cut increasing rate was lower than the rate during merely water flooding. In addition, we observed the drop-down on the water cut in some wells, such as A11, A12, A13, A15, etc. For the well A11, the highest water cut reduction reached 41% after the injectors (A5/A10) profiles controlled, and net incremental oil for A11 even reached 154,510 m3. By Dec 2014, the total incremental oil by polymer flooding was about 754,650 m3, and the stage oil recovery efficiency was enhanced by 3.0%. The polymer flooding is still effective, and we will get more oil from the polymer flooding.
{"title":"Research and Practice of the Early Stage Polymer Flooding on LD Offshore Oilfield","authors":"Kuiqian Ma, Yanlai Li, Ting Sun","doi":"10.4172/2157-7463.1000337","DOIUrl":"https://doi.org/10.4172/2157-7463.1000337","url":null,"abstract":"Literature survey shows that polymer flooding was generally conducted during high water-cut stage (WCT>80% to 90%). Even the first China Offshore polymer flooding project was carried out in SZ when water cut was 60%. By then, conduction of polymer flooding in early phase (WCT<10%) was just discussed in theory. For offshore oilfield, the treatment of water could be costly. Because polymer improves mobility ratio of replacement fluid over oil and sweep efficiency, less water is injected and less water is produced. So, we did enormous research about the polymer flooding on early stage by theoretical analysis, series of experiments and chemical flooding simulation. Based on these researches, we carried out the first field test of polymer flooding on early stage in LD. Single well polymer injection test was started in Mar 2006 when the water cut in the pattern was lower than 10%. After the trial, there were other 5 water injectors being converted to polymer injectors from 2007 to 2009. The polymer flooding controlled reserve was about 25,250,000 m3. For the early stage polymer flooding, the characteristics of the responses on producers were different from the case in which polymer flooding was conducted during high water cut stage. The water producing of the producers continued to rise up after polymer flooding, but the simulation research showed that the water cut increasing rate was lower than the rate during merely water flooding. In addition, we observed the drop-down on the water cut in some wells, such as A11, A12, A13, A15, etc. For the well A11, the highest water cut reduction reached 41% after the injectors (A5/A10) profiles controlled, and net incremental oil for A11 even reached 154,510 m3. By Dec 2014, the total incremental oil by polymer flooding was about 754,650 m3, and the stage oil recovery efficiency was enhanced by 3.0%. The polymer flooding is still effective, and we will get more oil from the polymer flooding.","PeriodicalId":16699,"journal":{"name":"Journal of Petroleum & Environmental Biotechnology","volume":"152 1","pages":"1-4"},"PeriodicalIF":0.0,"publicationDate":"2017-08-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78219403","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2017-07-27DOI: 10.4172/2157-7463-C1-034
Manal Hamad AlAmiri
P of CO2 and hydrocarbon (HC) gas injection into a heavy crude oil was investigated at high pressure/temperature condition, using high permeable well-sorted original reservoir sandstone. Complete series of PVT and slime tube tests were followed by vertical and horizontal gas floods to study the impact of injection rate, injectant type and reservoir pressure. Dimensional analysis was performed to study the involved mechanism and forces. Sometimes direct injection of CO2 may not be practically and economically possible. In addition, in plans for CO2 storage, CO2 as a free phase in a reservoir is coupled with a significant leakage risk that prevents the scenario of direct injection. Therefore, in the second part, the enhancement of heavy oil recovery was tested by the carbonated water injection. The results of the first part of core flooding experiments demonstrated that gravity and solubility are the most effective mechanisms in oil recovery. The reduction in oil recovery in horizontal flooding for HC gas injection is higher due to the smaller difference between the densities of CO2 and oil compared to HC gas/oil systems. Furthermore, a small increase of oil recovery after breakthrough (BT) during N2 injection proves the importance of the solubility mechanism. Therefore, In this case, more precise analysis could be performed by applying the dissolution number instead of capillary and/or bond number. For the second part of the experiments, the results obtained demonstrate that the capability of carbonated water to enhance oil recovery for both secondary and tertiary flooding is significantly greater than that for water flooding. The creation of a low resistance flow channel and low oil recovery in water flooding is compensated by CO2 diffusion and subsequent viscosity reduction and oil swelling in heavy oils.
{"title":"Health, safety and risk within the Kuwait Oil Company context","authors":"Manal Hamad AlAmiri","doi":"10.4172/2157-7463-C1-034","DOIUrl":"https://doi.org/10.4172/2157-7463-C1-034","url":null,"abstract":"P of CO2 and hydrocarbon (HC) gas injection into a heavy crude oil was investigated at high pressure/temperature condition, using high permeable well-sorted original reservoir sandstone. Complete series of PVT and slime tube tests were followed by vertical and horizontal gas floods to study the impact of injection rate, injectant type and reservoir pressure. Dimensional analysis was performed to study the involved mechanism and forces. Sometimes direct injection of CO2 may not be practically and economically possible. In addition, in plans for CO2 storage, CO2 as a free phase in a reservoir is coupled with a significant leakage risk that prevents the scenario of direct injection. Therefore, in the second part, the enhancement of heavy oil recovery was tested by the carbonated water injection. The results of the first part of core flooding experiments demonstrated that gravity and solubility are the most effective mechanisms in oil recovery. The reduction in oil recovery in horizontal flooding for HC gas injection is higher due to the smaller difference between the densities of CO2 and oil compared to HC gas/oil systems. Furthermore, a small increase of oil recovery after breakthrough (BT) during N2 injection proves the importance of the solubility mechanism. Therefore, In this case, more precise analysis could be performed by applying the dissolution number instead of capillary and/or bond number. For the second part of the experiments, the results obtained demonstrate that the capability of carbonated water to enhance oil recovery for both secondary and tertiary flooding is significantly greater than that for water flooding. The creation of a low resistance flow channel and low oil recovery in water flooding is compensated by CO2 diffusion and subsequent viscosity reduction and oil swelling in heavy oils.","PeriodicalId":16699,"journal":{"name":"Journal of Petroleum & Environmental Biotechnology","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2017-07-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87048608","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：