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 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 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.

The use of data on capillary pressures in the development of deposits in the Middle Ob region

2021 ◽  
pp. 61-72
Author(s):  
I. G. Sabanina ◽  
T. V. Semenova ◽  
Yu. Ya. Bolshakov ◽  
S. V. Vorobjeva
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Oil Field ◽  
Oil Fields ◽  
The West ◽  
Injection Wells ◽  
Stage Of Development ◽  
Urgent Task ◽  
Capillary Pressures ◽  
Water Cut

Currently, most of the oil fields in the West Siberian oil and gas province are in the final stage of development. There is water-cut in production, a decrease in oil production, and the structure of residual reserves deteriorates. The search and application of the most successful scientific methods and technologies for improving oil recovery in the development of fields is quite an urgent task.It should be taken into account that hydrophobic reservoirs are common in the oil fields of Western Siberia, and when applying the method of reservoir flooding, this fact should be taken into account and a more detailed approach should be taken to the study of capillary forces to prevent flooding of productive objects. Despite the good knowledge of the West Siberian megabasin, some fundamental issues of its structure and oil and gas potential remain debatable.The article proposes methods for improving oil recovery of the BS10 formation of the Ust-Balykskoye oil field based on the study of capillary pressures in productive reservoir formations, and provides recommendations for the placement of injection wells. The study of the capillary properties of reservoir rocks will significantly improve the efficiency of exploration and field operations in oil fields.

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 Polymers for EOR Application in High Temperature and High Viscosity Oils: Rock–Fluid Behavior

Energies ◽  
2020 ◽  
Vol 13 (22) ◽  
pp. 5944
Author(s):  
Rubén H. Castro ◽  
Sebastián Llanos ◽  
Jenny Rodríguez ◽  
Henderson I. Quintero ◽  
Eduardo Manrique
Keyword(s):  
High Temperature ◽  
Oil Recovery ◽  
High Viscosity ◽  
Oil Field ◽  
Heavy Oils ◽  
Displacement Efficiency ◽  
Reservoir Conditions ◽  
Oil Displacement Efficiency ◽  
Sulfonated Polyacrylamide ◽  
Total Dissolved Solid

Viscosity losses and high degradation factors have a drastic impact over hydrolyzed polyacrylamides (HPAM) currently injected, impacting the oil recovery negatively. Previous studies have demonstrated that biopolymers are promising candidates in EOR applications due to high thermochemical stability in harsh environments. However, the dynamic behavior of a biopolymer as scleroglucan through sandstone under specific conditions for a heavy oil field with low salinity and high temperature has not yet been reported. This work presents the rock–fluid evaluation of the scleroglucan (SG at 935 mgL−1) and sulfonated polyacrylamide (ATBS at 2500 mgL−1) to enhance oil recovery in high-temperature for heavy oils (212 °F and total dissolved solid of 3800 mgL−1) in synthetic (0.5 Darcy) and representative rock samples (from 2 to 5 Darcy) for a study case of a Colombian heavy oilfield. Dynamic evaluation at reservoir conditions presents a scenario with stable injectivity after 53.6 PV with a minimal pressure differential (less than 20 psi), inaccessible porous volume (IPV) of 18%, dynamic adsorption of 49 µg/g, and resistance and residual resistance factors of 6.17 and 2.84, respectively. In addition, higher oil displacement efficiency (up to 10%) was obtained with lower concentration (2.7 times) compared to a sulfonated polyacrylamide polymer.

AN ANALYSIS OF THE PRODUCTION PERFORMANCE OF THE WINDALIA SAND RESERVOIR OF THE BARROW ISLAND OIL FIELD

1977 ◽  
Vol 17 (1) ◽  
pp. 105 ◽  
Author(s):  
C. T. Williams
Keyword(s):  
Oil Recovery ◽  
History Matching ◽  
Water Injection ◽  
Feasibility Studies ◽  
Oil Field ◽  
Production Performance ◽  
High Porosity ◽  
Injection Wells ◽  
Well Completion ◽  
East West

The Windalia Sand is a high porosity, low permeability oil reservoir. Currently 454 wells penetrate the unit for production or water injection operations, and are drilled on a north-south, east-west 16 ha (40 ac.) spacing. Early production performance data indicated a trend of water break-through into wells located east and west of water injection wells in an inverted nine-spot pattern. This early trend has continued and the east- west break-through has become more widespread with time. It was recognised that it could be possible to improve the performance of the waterflood if the factors causing the phenomenon were able to be identified. A detailed geological review of well data was initiated to investigate causes and possible controls of the phenomenon and to determine if oil recovery could be improved. This work was augmented by an engineering study of production data. Subsequently, a computer model was developed to investigate the simulated effects of changes to well patterns on the field's production performance.The geological review determined that the reservoir contains significant local and transitional irregularities (or inhomogeneities). The mapping of a number of reservoir parameters has shown there are genetic patterns or trends and these are postulated as being at least partial controls of preferential direction of fluid movement.Previously the reservoir had been regarded as being a more uniform "layer-cake" sand. Well completion practices and timing together with production and injection methods are thought to have accentuated the latent genetic controls. Imposed pressure parting has been postulated, on engineering premises, as a control of fluid movement. The modelling study used the notion of anisotropic permeability in attempting to history-match production performances.Because of the reservoir size and anisotropy it was impractical to model the entire field. Selected type areas within the reservoir were studied. Good history-matching of various well types (based on location within a pattern) was possible. Predictions of production performance can be made for various simulated pattern changes allowing feasibility studies to be made of possible conversion programs.East-west producing wells are being converted to injectors as they water out. This program has converted part of the reservoir to a line-drive injection configuration and improved performance in these areas is evident.

Selecting a Technology to Increase well Capacity and Enhance Oil Recovery of the YUS11 Formation of the Fainsk Oil Field

2018 ◽  
Vol 785 ◽  
pp. 146-152
Author(s):  
Vadim Aleksandrov ◽  
Marsel Kadyrov ◽  
Alexander Markov ◽  
Vadim Golozubenko ◽  
Sergey Aleksandrov
Keyword(s):  
Oil Recovery ◽  
Quantitative Assessment ◽  
Field Experience ◽  
Oil Field ◽  
Field Analysis ◽  
Injection Wells ◽  
Important Solution ◽  
Enhance Oil Recovery

To increase the development efficiency of reservoirs, methods to intensify inflows and enhance oil recovery are applied. The geological and field experience of applying these methods shows that a high technological effect can be reached in specific geological and geophysical conditions while in other conditions efficiency will be insignificant. In this relation, an important solution for this problem is the justification of selecting the most efficient technologies of stimulating pay zones. The research objective is to select the most optimal technologies of stimulating pay zones to increase the development scope and enhance oil recovery. Using geological and field analysis, a complex quantitative assessment was done for the efficiency of using methods to enhance oil recovery and stimulate pay zones in both production and injection wells.

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.

Calcium Sulfate Scaling Risk and Inhibition for a Steamflood Project

SPE Journal ◽  
2016 ◽  
Vol 22 (03) ◽  
pp. 881-891 ◽  
Author(s):  
Fangfu Zhang ◽  
Charles J. Hinrichsen ◽  
Amy T. Kan ◽  
Wei Wang ◽  
Wei Wei ◽  
...  
Keyword(s):  
High Temperature ◽  
Oil Recovery ◽  
Calcium Sulfate ◽  
Risk Model ◽  
Treatment Plan ◽  
Saturation Index ◽  
Middle Eastern ◽  
Oil Field ◽  
Water Composition ◽  
System Temperature

Summary Steamflooding is a widely used technique for heavy-oil recovery. Scale control during steamflooding, however, can be challenging because the high temperature of the steamflood can decompose thermally unstable inhibitors and/or lead to the precipitation of metal-inhibitor pseudoscale. In this paper, we present the analysis of the scaling risk and scale inhibition for a pilot steamflood project in a Middle Eastern oil field. The formation of this field is a dolomite formation interbedded with anhydrite (CaSO4) streaks. Anhydrite has been observed to be the predominant scale form. Anhydrite scale was presumably formed by the increased production-system temperature resulting from steamflooding and/or the mixing of steam condensate with connate water at equilibrium with calcium sulfate minerals at lower temperature and higher solubility. Anhydrite is inherently difficult to control because of its high solubility and the high-temperature (HT) conditions under which it forms. Compared with barite and calcite, only limited knowledge has been acquired for anhydrite control. To predict the scaling tendency and inhibitor need in different wells of this field with different supersaturation levels and temperatures, a scaling-risk model has been developed. To build such a model, detailed and revised laboratory procedures have been developed to study nucleation and precipitation kinetics of anhydrite at 125–175°C, different supersaturation, different water composition, and long reaction time. Predictions of this scaling-risk model suggest a saturation index (SI) of 0.8 as a critical SI for anhydrite control at >125°C. For example, when the SI is above 0.8, anhydrite will be difficult to control in the presence of threshold inhibitor. Model predictions were benchmarked with the water-chemistry data from a total of more than 20 wells from this field, and were found to be consistent with field observations of scale occurrence in different wells. With the recommended inhibitor concentrations, anhydrite scale has been controlled in this field, which provides validation that the proposed scaling-risk model is a powerful tool to optimize the scale-treatment plan for anhydrite.

Slowing Production Decline and Extending the Economic Life of an Oil Field: New MEOR Technology

2002 ◽  
Vol 5 (01) ◽  
pp. 33-41 ◽  
Author(s):  
L.R. Brown ◽  
A.A. Vadie ◽  
J.O. Stephens
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Enhanced Recovery ◽  
Water Injection ◽  
Oil Production ◽  
Oil Field ◽  
Economic Life ◽  
Oil Reservoir ◽  
Injection Wells ◽  
Black Warrior Basin

Summary This project demonstrated the effectiveness of a microbial permeability profile modification (MPPM) technology for enhancing oil recovery by adding nitrogenous and phosphorus-containing nutrients to the injection water of a conventional waterflooding operation. The MPPM technology extended the economic life of the field by 60 to 137 months, with an expected recovery of 63 600 to 95 400 m3 (400,000 to 600,000 bbl) of additional oil. Chemical changes in the composition of the produced fluids proved the presence of oil from unswept areas of the reservoir. Proof of microbial involvement was shown by increased numbers of microbes in cores of wells drilled within the field 22 months after nutrient injection began. Introduction The target for enhanced oil recovery processes is the tremendous quantity of unrecoverable oil in known deposits. Roughly two thirds [approximately 55.6×109 m3 (350 billion bbl)] of all of the oil discovered in the U.S. is economically unrecoverable with current technology. Because the microbial enhanced oil recovery (MEOR) technology in this report differs in several ways from other MEOR technologies, it is important that these differences be delineated clearly. In the first place, the present project is designed to enhance oil recovery from an entire oil reservoir, rather than treat single wells. Even more important is the fact that this technology relies on the action of the in-situ microflora, not microorganisms injected into the reservoir. It is important to note that MPPM technology does not interfere with the normal waterflood operation and is environmentally friendly in that neither microorganisms nor hazardous chemicals are introduced into the environment. Description of the Oil Reservoir. The North Blowhorn Creek Oil Unit (NBCU) is located in Lamar County, Alabama, approximately 75 miles west of Birmingham. This field is in what is known geologically as the Black Warrior basin. The producing formation is the Carter sandstone of Mississippian Age at a depth of approximately 700 m (2,300 ft). The Carter reservoir is a northwest/ southeast trending deltaic sand body, approximately 5 km (3 miles) long and 1 to 1.7 km (1/2 to 1 mile) wide. Sand thickness varies from only 1 m up to approximately 12 m (40 ft). The sand is relatively clean (greater than 90% quartz), with no swelling clays. The field was discovered in 1979 and initially developed on 80-acre spacing. Waterflooding of the reservoir began in 1983. The initial oil in place in the reservoir was approximately 2.54×106 m3 (16 million bbl), of which 874 430 m3 (5.5 million bbl) had been recovered by the end of 1995. To date, North Blowhorn Creek is the largest oil field discovered in the Black Warrior basin. Oil production peaked at almost 475 m3/d (3,000 BOPD) in 1985 and has since declined steadily. Currently, there are 20 injection wells and 32 producing wells. Oil production at the outset of the field demonstration was approximately 46 m3/d oil (290 BOPD), 1700 m3/d gas (60 MCFD), and 493 m3/d water (3,100 BWPD), with a water-injection rate of approximately 660 m3/d (4,150 BWPD). Projections at the beginning of the project were that approximately 1.59×106 m3 oil (10 million bbl of oil) would be left unrecovered if some new method of enhanced recovery were not effective. Prefield Trial Studies The concepts of the technology described in this paper had been proven to be effective in laboratory coreflood experiments.1,2 However, it seemed advisable to conduct coreflood experiments with cores from the reservoir being used in the field demonstration. Toward this end, two wells were drilled, and cores were obtained from one for the laboratory coreflood experiments to determine the schedule and amounts of nutrients to be employed in the field trial.3

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