Evaluation of oil field chemicals for secondary oil recovery systems in Kuwait

2001 ◽  
Vol 48 (4) ◽  
pp. 245-251 ◽  
Author(s):  
A. Al‐Sayegh ◽  
J. Carew ◽  
A. Al‐Hashem
Keyword(s):  
Oil Recovery ◽  
Oil Field ◽  
Secondary Oil Recovery

scholarly journals The use of laurylamine hydrocholoride CH3(CH2)11 NH3 –Cl for secondary oil recovery

2012 ◽  
Vol 9 (1) ◽  
pp. 120-123
Author(s):  
Baghdad Science Journal
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Cationic Surfactants ◽  
Water Injection ◽  
Solution Concentration ◽  
Oil Field ◽  
Residual Oil ◽  
Secondary Oil Recovery ◽  
Total Oil ◽  
The Relationship

Laurylamine hydrochloride CH3(CH2)11 NH3 – Cl has been chosen from cationic surfactants to produce secondary oil using lab. model shown in fig. (1). The relationship between interfacial tension and (temperature, salinity and solution concentration) have been studied as shown in fig. (2, 3, 4) respectively. The optimum values of these three variables are taken (those values that give the lowest interfacial tension). Saturation, permeability and porosity are measured in the lab. The primary oil recovery was displaced by water injection until no more oil can be obtained, then laurylamine chloride is injected as a secondary oil recovery. The total oil recovery is 96.6% or 88.8% of the residual oil has been recovered by this technique as shown in fig. (5). This method was applied in an oil field and it gave approximate values close to that obtained in the lab.

Experimental Investigation of a Viscous Surfactant and Surfactant Flooding to Enhance Oil Recovery

2009 ◽  
Author(s):  
Omid Arjmand ◽  
Jalal Foroozesh ◽  
Ali Reza Roostaee ◽  
Shahaboddin Ayatollahi
Keyword(s):  
Oil Recovery ◽  
Terephthalic Acid ◽  
Recovery Process ◽  
Oil Field ◽  
Recovery Factor ◽  
Water Flooding ◽  
Surfactant Flooding ◽  
Chemical Solutions ◽  
Secondary Oil Recovery ◽  
Enhance Oil Recovery

A chemical Enhanced Oil Recovery (EOR) process receives more attentions nowadays. Crude Terephthalic Acid (CTA) as a chemical compound is used for flooding here as an alternative to the traditional hydrolyzed polyacryl amide (HPAM). Crude Oil samples from an Iranian oil field were used during the flooding tests. Sand packed models using two different sizes of sand mainly 50 and 100 meshes were employed in this investigation. A comparison between water flooding and CTA flooding as a secondary oil recovery process revealed that the recovery was improved by 10% when CTA was used. The effect of various injection rates and different concentration of chemical solutions on the recovery factor have been checked. Besides, experimental results improved the surfactant behavior of the CTA solution in water. Moreover, at tertiary state, Sodium Dodocyl Sulfate (SDS) as an anionic surfactant was flooded. Experiments showed that recovery factor increased by 5% OOIP while using SDS.

scholarly journals Sulfidogenic Microbial Communities of the Uzen High-Temperature Oil Field in Kazakhstan

2021 ◽  
Vol 9 (9) ◽  
pp. 1818
Author(s):  
Diyana S. Sokolova ◽  
Ekaterina M. Semenova ◽  
Denis S. Grouzdev ◽  
Salimat K. Bidzhieva ◽  
Tamara L. Babich ◽  
...  
Keyword(s):  
High Temperature ◽  
Oil Recovery ◽  
Oil Field ◽  
Injection Wells ◽  
Sulfate Reducing ◽  
Microbially Influenced Corrosion ◽  
Dsrab Gene ◽  
Fermentative Bacteria ◽  
Secondary Oil Recovery ◽  
Bottom Zone

Application of seawater for secondary oil recovery stimulates the development of sulfidogenic bacteria in the oil field leading to microbially influenced corrosion of steel equipment, oil souring, and environmental issues. The aim of this work was to investigate potential sulfide producers in the high-temperature Uzen oil field (Republic of Kazakhstan) exploited with seawater flooding and the possibility of suppressing growth of sulfidogens in both planktonic and biofilm forms. Approaches used in the study included 16S rRNA and dsrAB gene sequencing, scanning electron microscopy, and culture-based techniques. Thermophilic hydrogenotrophic methanogens of the genus Methanothermococcus (phylum Euryarchaeota) predominated in water from the zone not affected by seawater flooding. Methanogens were accompanied by fermentative bacteria of the genera Thermovirga, Defliviitoga, Geotoga, and Thermosipho (phylum Thermotogae), which are potential thiosulfate- or/and sulfur-reducers. In the sulfate- and sulfide-rich formation water, the share of Desulfonauticus sulfate-reducing bacteria (SRB) increased. Thermodesulforhabdus, Thermodesulfobacterium, Desulfotomaculum, Desulfovibrio, and Desulfoglaeba were also detected. Mesophilic denitrifying bacteria of the genera Marinobacter, Halomonas, and Pelobacter inhabited the near-bottom zone of injection wells. Nitrate did not suppress sulfidogenesis in mesophilic enrichments because denitrifiers reduced nitrate to dinitrogen; however, thermophilic denitrifiers produced nitrite, an inhibitor of SRB. Enrichments and a pure culture Desulfovibrio alaskensis Kaz19 formed biofilms highly resistant to biocides. Our results suggest that seawater injection and temperature of the environment determine the composition and functional activity of prokaryotes in the Uzen oil field.

scholarly journals The experience of implementation of polymer flooding technology at Zaburunye oil filed as a method for developing mature fields

2021 ◽  
Vol 3 (1) ◽  
pp. 29-42
Author(s):  
M. Sh. Musayev ◽  
D. A. Musharova ◽  
B. Zh. Zhappasbayev ◽  
E. K. Orynbassar
Keyword(s):  
Oil Recovery ◽  
High Water ◽  
Volatile Oil ◽  
Polymer Flooding ◽  
Oil Field ◽  
Recovery Factor ◽  
Wide Range ◽  
Secondary Oil Recovery ◽  
High Water Cut Stage ◽  
High Water Cut

In conditions of high depletion of oil fields and volatile oil prices, methods of enhanced oil recovery are becoming especially relevant, the use of which contributes to an increase in the oil recovery factor in addition to the use of secondary oil recovery methods. One of the technologies allowing to increase the oil recovery factor is polymer flooding technology, the distinctive advantage of which in comparison with other chemical methods is a wide range of application conditions and design variability during implementation. This paper presents the results of the application of polymer flooding technology in the oil field of Kazakhstan Zaburunye, which is in the high water-cut stage. To determine the strategy for the further implementation of polymer flooding technology and in order to find the optimal predictive development options, calculations were carried out on the developed hydrodynamic model.

scholarly journals Polymer gels for controlling water thief zones in injection wells

2012 ◽  
Vol 5 (1) ◽  
pp. 37-44 ◽  
Author(s):  
Gustavo-Adolfo Maya-Toro ◽  
Rubén-Hernán Castro-García ◽  
Zarith del Pilar Pachón-Contreras. ◽  
Jose-Francisco Zapata-Arango
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Injection Wells ◽  
Recovery Processes ◽  
Injection Water ◽  
Secondary Oil Recovery ◽  
High Concentrations ◽  
Low Efficiency ◽  
Hydrolyzed Polyacrylamide ◽  
Positive Results

Oil recovery by water injection is the most extended technology in the world for additional recovery, however, formation heterogeneity can turn it into highly inefficient and expensive by channeling injected water. This work presents a chemical option that allows controlling the channeling of important amounts of injection water in specific layers, or portions of layers, which is the main explanation for low efficiency in many secondary oil recovery processes. The core of the stages presented here is using partially hydrolyzed polyacrylamide (HPAM) cross linked with a metallic ion (Cr+3), which, at high concentrations in the injection water (5000 – 20000 ppm), generates a rigid gel in the reservoir that forces the injected water to enter into the formation through upswept zones. The use of the stages presented here is a process that involves from experimental evaluation for the specific reservoir to the field monitoring, and going through a strict control during the well intervention, being this last step an innovation for this kind of treatments. This paper presents field cases that show positive results, besides the details of design, application and monitoring.

scholarly journals Development of an analytical model to predict oil reservoirs performance using mechanical waves propagation

2021 ◽  
Author(s):  
Hesham A. Abu Zaid ◽  
◽  
Sherif A. Akl ◽  
Mahmoud Abu El Ela ◽  
Ahmed El-Banbi ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Field Measurements ◽  
Field Trials ◽  
Oil Field ◽  
Reservoir Properties ◽  
Actual Performance ◽  
Reservoir Performance ◽  
Mechanical Waves ◽  
Incremental Oil Recovery ◽  
Wave Induced

The mechanical waves have been used as an unconventional enhanced oil recovery technique. It has been tested in many laboratory experiments as well as several field trials. This paper presents a robust forecasting model that can be used as an effective tool to predict the reservoir performance while applying seismic EOR technique. This model is developed by extending the wave induced fluid flow theory to account for the change in the reservoir characteristics as a result of wave application. A MATLAB program was developed based on the modified theory. The wave’s intensity, pressure, and energy dissipation spatial distributions are calculated. The portion of energy converted into thermal energy in the reservoir is assessed. The changes in reservoir properties due to temperature and pressure changes are considered. The incremental oil recovery and reduction in water production as a result of wave application are then calculated. The developed model was validated against actual performance of Liaohe oil field. The model results show that the wave application increases oil production from 33 to 47 ton/day and decreases water-oil ratio from 68 to 48%, which is close to the field measurements. A parametric analysis is performed to identify the important parameters that affect reservoir performance under seismic EOR. In addition, the study determines the optimum ranges of reservoir properties where this technique is most beneficial.

Laboratory studies of oil-washing characteristics of surfactants in the pore space of reservoir rocks

2021 ◽  
pp. 86-98
Author(s):  
V. Yu. Ogoreltsev ◽  
S. A. Leontiev ◽  
A. S. Drozdov
Keyword(s):  
Oil Recovery ◽  
Pore Space ◽  
Oil Field ◽  
Oil Fields ◽  
Molecular Surface ◽  
Laboratory Studies ◽  
Reservoir Rocks ◽  
Technological Efficiency ◽  
Chemical Eor ◽  
Physical And Chemical

When developing hard-to-recover reserves of oil fields, methods of enhanced oil recovery, used from chemical ones, are massively used. To establish the actual oil-washing characteristics of surfactant grades accepted for testing in the pore space of oil-containing reservoir rocks, a set of laboratory studies was carried out, including the study of molecular-surface properties upon contact of oil from the BS10 formation of the West Surgutskoye field and model water types with the addition of surfactants of various concentrations, as well as filtration tests of surfactant technology compositions on core models of the VK1 reservoir of the Rogozhnikovskoye oil field. On the basis of the performed laboratory studies of rocks, it has been established that conducting pilot operations with the use of Neonol RHP-20 will lead to higher technological efficiency than from the currently used at the company's fields in the compositions of the technologies of physical and chemical EOR Neonol BS-1 and proposed for application of Neftenol VKS, Aldinol-50 and Betanol.

Experimental Design and Evaluation of Surfactant Polymer for a Heavy Oil Field in South of Sultanate of Oman

2021 ◽  
Author(s):  
Ali Reham Al-Jabri ◽  
Rouhollah Farajzadeh ◽  
Abdullah Alkindi ◽  
Rifaat Al-Mjeni ◽  
David Rousseau ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
History Matching ◽  
Oil Field ◽  
Reservoir Rock ◽  
Sultanate Of Oman ◽  
Industrial Chemicals ◽  
Oil Viscosity ◽  
Injection Strategy ◽  
Operational Conditions

Abstract Heavy oil reservoirs remain challenging for surfactant-based EOR. In particular, selecting fine-tuned and cost effective chemical formulations requires extensive laboratory work and a solid methodology. This paper reports a laboratory feasibility study, aiming at designing a surfactant-polymer pilot for a heavy oil field with an oil viscosity of ~500cP in the South of Sultanate of Oman, where polymer flooding has already been successfully trialed. A major driver was to design a simple chemical EOR method, to minimize the risk of operational issues (e.g. scaling) and ensure smooth logistics on the field. To that end, a dedicated alkaline-free and solvent-free surfactant polymer (SP) formulation has been designed, with its sole three components, polymer, surfactant and co-surfactant, being readily available industrial chemicals. This part of the work has been reported in a previous paper. A comprehensive set of oil recovery coreflood tests has then been carried out with two objectives: validate the intrinsic performances of the SP formulation in terms of residual oil mobilization and establish an optimal injection strategy to maximize oil recovery with minimal surfactant dosage. The 10 coreflood tests performed involved: Bentheimer sandstone, for baseline assessments on large plugs with minimized experimental uncertainties; homogeneous artificial sand and clays granular packs built to have representative mineralogical composition, for tuning of the injection parameters; native reservoir rock plugs, unstacked in order to avoid any bias, to validate the injection strategy in fully representative conditions. All surfactant injections were performed after long polymer injections, to mimic the operational conditions in the field. Under injection of "infinite" slugs of the SP formulation, all tests have led to tertiary recoveries of more than 88% of the remaining oil after waterflood with final oil saturations of less than 5%. When short slugs of SP formulation were injected, tertiary recoveries were larger than 70% ROIP with final oil saturations less than 10%. The final optimized test on a reservoir rock plug, which was selected after an extensive review of the petrophysical and mineralogical properties of the available reservoir cores, led to a tertiary recovery of 90% ROIP with a final oil saturation of 2%, after injection of 0.35 PV of SP formulation at 6 g/L total surfactant concentration, with surfactant losses of 0.14 mg-surfactant/g(rock). Further optimization will allow accelerating oil bank arrival and reducing the large PV of chase polymer needed to mobilize the liberated oil. An additional part of the work consisted in generating the parameters needed for reservoir scale simulation. This required dedicated laboratory assays and history matching simulations of which the results are presented and discussed. These outcomes validate, at lab scale, the feasibility of a surfactant polymer process for the heavy oil field investigated. As there has been no published field test of SP injection in heavy oil, this work may also open the way to a new range of field applications.

Sign in / Sign up

Export Citation Format

Share Document