scholarly journals Development of fly ash reinforced nanocomposite preformed particle gel for the control of excessive water production in the mature oil fields

2019 ◽  
Vol 74 ◽  
pp. 8 ◽  
Author(s):  
Abhinav Kumar ◽  
Vikas Mahto ◽  
Virender Parkash Sharma
Keyword(s):  
Fly Ash ◽  
Critical Shear Stress ◽  
Oil Fields ◽  
Water Production ◽  
Sweep Efficiency ◽  
Improvement Rate ◽  
Preformed Particle Gel ◽  
Flow Experiment ◽  
Thermal Stability Of ◽  
Excessive Water

One of the appropriate methods to minimize water production and increase sweep efficiency is the utilization of Preformed Particle Gel (PPG) in the mature oil fields. In this paper, a new fly ash reinforced nanocomposite PPG was developed by the reaction of acrylamide as monomer, N,N′-Methylenebis (acrylamide) as crosslinker and nano fly ash in presence of Potassium Persulfate as initiator and it was compared with a conventional PPG which was designed without nano fly ash. On the incorporation of nano fly ash, swelling performance and thermal stability of PPG had increased significantly. Rheological data revealed that dynamic moduli (G′ and G″) of fly ash reinforced nanocomposite PPG has improved viscoelastic properties with a higher value of critical shear stress as compared to conventional PPG. The single sandpack flow experiment has shown the injectivity of nanocomposite PPG into the sandpack with a maximum resistance factor of 60.57. However, parallel-sandpack flow experiment showed that the newly developed nano fly ash reinforced nanocomposite PPG has a profile improvement rate of 92.98% and 97.83% for the permeability contrast of 2.16 and 4.14 respectively and hence it may be a promising agent in reducing excessive water production in mature oil fields.

Field Performances, Effective Times, and Economic Assessments of Polymer Gel Treatments in Controlling Excessive Water Production From Mature Oil Fields

2020 ◽  
Vol 143 (8) ◽  
Author(s):  
Munqith Aldhaheri ◽  
Mingzhen Wei ◽  
Ali Alhuraishawy ◽  
Baojun Bai
Keyword(s):  
Fractured Reservoirs ◽  
Descriptive Analysis ◽  
Naturally Fractured Reservoirs ◽  
Oil Fields ◽  
Water Production ◽  
Polymer Gel ◽  
Rock Formations ◽  
Water Cut ◽  
Matrix Rock ◽  
Excessive Water

Abstract Polymer bulk gels have been widely applied to mitigate excessive water production from mature oil fields by correcting the reservoir permeability heterogeneity. This paper reviews water responses, effective times, and economic assessments of injection-well gel treatments based on 61 field projects. Eight parameters were evaluated per the reservoir type using the descriptive analysis, stacked histograms, and scatterplots. Results show that water production generally continues to increase after the treatment for undeveloped conformance problems. Contrarily, it typically decreases after the reactive gel treatments target developed conformance issues. For the developed problems, gel treatments do not always mitigate the water production where the water cut may stabilize or increase by 17% in 22% of instances. In addition, they often do reduce water production but not dramatically to really low levels where the water cut stays above 70% and reduces by only 10% in most cases. Gel treatments are economically appraised based only on the oil production response, and both water responses (injection and production) are not considered in the evaluation. They have a typical payout time of 9.2 months, cost of incremental oil barrel of 2 $/barrel, and effective time of 1.9 years. In addition, they have better water responses and economics in carbonates than in sandstones and in unconsolidated and naturally fractured reservoirs than in matrix-rock formations. The current review strongly warns reservoir engineers that gel treatments are not superior in alleviating the water production and candidates should be nominated based on this fact to achieve favorable economics and avoid treatment failures.

New Gel Aggregates To Improve Sweep Efficiency During Waterflooding

2011 ◽  
Vol 14 (01) ◽  
pp. 120-128 ◽  
Author(s):  
Guanglun Lei ◽  
Lingling Li ◽  
Hisham A. Nasr-El-Din
Keyword(s):  
Low Cost ◽  
Oil Production ◽  
High Water ◽  
Resistance Factor ◽  
Water Production ◽  
Sweep Efficiency ◽  
Low Viscosity ◽  
Productivity Decline ◽  
High Water Cut ◽  
Water Cut

Summary A common problem for oil production is excessive water production, which can lead to rapid productivity decline and significant increases in operating costs. The result is often a premature shut-in of wells because production has become uneconomical. In water injectors, the injection profiles are uneven and, as a result, large amounts of oil are left behind the water front. Many chemical systems have been used to control water production and improve recovery from reservoirs with high water cut. Inorganic gels have low viscosity and can be pumped using typical field mixing and injection equipment. Polymer or crosslinked gels, especially polyacrylamide-based systems, are mainly used because of their relatively low cost and their supposed selectivity. In this paper, microspheres (5–30 μm) were synthesized using acrylamide monomers crosslinked with an organic crosslinker. They can be suspended in water and can be pumped in sandstone formations. They can plug some of the pore throats and, thus, force injected water to change its direction and increase the sweep efficiency. A high-pressure/high-temperature (HP/HT) rheometer was used to measure G (elastic modulus) and G" (viscous modulus) of these aggregates. Experimental results indicate that these microspheres are stable in solutions with 20,000 ppm NaCl at 175°F. They can expand up to five times their original size in deionized water and show good elasticity. The results of sandpack tests show that the microspheres can flow through cores with permeability greater than 500 md and can increase the resistance factor by eight to 25 times and the residual resistance factor by nine times. The addition of microspheres to polymer solutions increased the resistance factor beyond that obtained with the polymer solution alone. Field data using microspheres showed significant improvements in the injection profile and enhancements in oil production.

Elimination of Tight Emulsions

2021 ◽  
Author(s):  
Haakon Ellingsen ◽  
Hikmat Jaouhar ◽  
Andreas Hannisdal
Keyword(s):  
Crude Oil ◽  
Separation Efficiency ◽  
Operating Temperature ◽  
Oil Fields ◽  
Water Removal ◽  
Water Production ◽  
Test Results ◽  
Electrical Field ◽  
High Electrical Field ◽  
Performance Specifications

Abstract Maturing oil fields can pose a severe challenge for separation of oil and water. Increasing water production and tie in of new fields into existing infrastructure may result in separators struggling to meet performance specifications. Operational challenges are particularly experienced when the facilities are processing cold feedstock and tight emulsions. Typical solutions for overcoming separation challenges would be increasing operating temperature, injecting an increased quantity of demulsifier chemicals, or installing new larger separators. These alternatives may not be economically attractive or feasible for other reasons. The ability to successfully operate existing plants with tight and water-rich emulsions without incurring significant added operating expenditure is perceived as a major advantage. This paper will share the results from testing on a separator operating with Flotta Gold crude oil. The oil is known to produce particularly tight emulsions at low temperatures. The ePack technology has been tested to study its capability of separating water and crude oil from tight emulsions by means of electrical forces. The force generated by the high electrical field can break even tight emulsions, and the test results shown have proven the ability to go from very low separation efficiency without the ePack, to more than 90% water removal with the ePack turned on. Testing with residence times of up to 19 minutes without the ePack was not able to surpass the performance of a three minutes residence time with the ePack energized.

Investigation on Thermal Stability of Geopolymer Based Zeolite in Fire Case Study

2020 ◽  
Vol 1009 ◽  
pp. 31-36
Author(s):  
Kanokwan Kanyalert ◽  
Prinya Chindaprasirt ◽  
Duangkanok Tanangteerapong
Keyword(s):  
Weight Loss ◽  
Compressive Strength ◽  
High Temperature ◽  
Fly Ash ◽  
Alkali Activation ◽  
Different Types ◽  
Temperature Exposure ◽  
In Fire ◽  
Thermal Stability Of

This work aims to reveal the effects of zeolite on properties of fly ash based geopolymer under high temperature at 300 °C, 600 °C and 900 °C. The specimens were prepared by alkali activation of fly ash, which was partially replaced by two different types of zeolite at 10%, 20% and 30% by weight. The specimens were analyzed for the maximum compressive strength, weight loss percentage, XRD and SEM. The results highlighted that the percentage of weight loss increased with the ratio of zeolite replacement. The compressive strength of geopolymer with synthetic zeolite and natural zeolite at 7, 28, 60 days were similar. The high-temperature exposure resulted in the reduction in compressive strength in all proportions. At the same temperature, compressive strength of all specimens were not significantly different.

scholarly journals MONITORING AND CONTROL OF NEW TECHNOLOGIES FOR ENHANCED OIL RECOVERY AT THE PRODUCTION FIELDS IN WESTERN KAZAKHSTAN

2021 ◽  
pp. 1-9
Author(s):  
Gulnaz Zh. Moldabayeva ◽  
Raikhan T. Suleimenova ◽  
Sairanbek M. Akhmetov ◽  
Zhanar B. Shayakhmetova ◽  
Gabit E. Suyungariyev
Keyword(s):  
Factor Analysis ◽  
Oil Recovery ◽  
Statistical Models ◽  
New Technologies ◽  
Oil Field ◽  
Oil Fields ◽  
Water Production ◽  
Western Kazakhstan ◽  
Wide Range ◽  
Technical Measures

This paper discusses topical problems of further effective development of depleted oil fields (DOF) to increase their final oil recovery on the example of the oil field in Western Kazakhstan. Further exploitation of fields using waterflooding becomes unprofitable. At the same time, on average at these facilities, at least 50% of the reserves will remain unrecovered. Most of the oil fields in the Republic of Kazakhstan are at the late and final stages of development, which is characterised by an increase in the share of hard-to-recover oil reserves, a decrease in annual oil withdrawals, and a high water cut of the produced oil. Therefore, the problems of improving the technology aimed at reducing the volume of associated water production and increasing oil recovery from partially flooded deposits is very urgent. With an increase in the well density, the degree of field drilling and aging of the well stock, the work with the current declining well stock remains a very topical issue. Improving the efficiency of diagnostics and the systematic selection of wells for repair and isolation works is an important element for rationalising field development in the current conditions of profit variance in the oil and gas industry. The methods of bottomhole zone treatment also implement a deflecting effect on filtration flows. Therefore, this method includes a wide range of geological and technical measures: down-spacing; water production restraining; conformance control of injectivity profiles; forced production; all types of mechanical, thermochemical and thermal technologies. Consider a number of geological and technical measures that perform the tasks of occupational safety rules. Geological and statistical models are proposed for diagnosing wells for a premature increase of water production using factor analysis calculations for base production and Hall plots. Results. The degree of temperature influence of the primary components of the compounds on the rheology, filtration characteristics, and stability of inverted emulsions was determined. The classification of oil loss factors was carried out based on the results of downhole analysis and oil production losses were determined. Geological and statistical models for well diagnostics for premature increase in water production were built using factor analysis calculations for base production and Hall plots.

scholarly journals SINTESIS DAN KARAKTERISASI FAUJASIT DARI ABU LAYANG : Kajian Pengaruh Waktu Sintesis Terhadap Stabilitas Termal Struktur Faujasit (Kinetics of Faujasite Formation from Fly Ash)

2019 ◽  
Vol 2 (2) ◽  
pp. 10
Author(s):  
Sutarno Sutarno ◽  
Arief Budyantoro
Keyword(s):  
Thermal Stability ◽  
Fly Ash ◽  
Amorphous Phase ◽  
Zeolite Y ◽  
Weight Ratio ◽  
Hydrothermal Time ◽  
X Ray Diffraction ◽  
X Ray ◽  
Kinetics Of ◽  
Thermal Stability Of

Faujasite was hydrothermally synthesized from fly ash at 100oC in alkaline solution by reflux with 5M HCl and fusion with NaOH (weight ratio of NaOH/fly ash = 1.2) pretreatments. Kinetics of faujasite formation was performed by variation of hydrothermal time (0-120 hours). Thermal stability of faujasite from fly ash was tested at 400-900oC and was compared with commercial zeolite Y. The solid products were characterized by X-ray diffraction method. Results showed that faujasite was formed through dissolution of fly ash components such as quartz, mullite and amorphous aluminosilicates (0-3 hours) followed by crystallization to form faujasite (6-48 hours). In longer hydrothermal time (48-72 hours), faujasite transformed into zeolite P and completely formed hydroxysodalite after 120 hours. X-ray diffraction pattern showed that thermal stability of faujasite from fly ash was relatively lower than that of commercial zeolite Y. Faujasite from fly ash transformed into amorphous phase at 800oC whereas commercial zeolite Y transformed into amorphous phase at 900oC.

scholarly journals Enhanced oil recovery ability of branched preformed particle gel in heterogeneous reservoirs

2018 ◽  
Vol 73 ◽  
pp. 65 ◽  
Author(s):  
Long Yu ◽  
Qian Sang ◽  
Mingzhe Dong
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Water Flooding ◽  
Low Permeability ◽  
High Permeability ◽  
Sweep Efficiency ◽  
Reservoir Heterogeneity ◽  
Heterogeneous Reservoirs ◽  
Preformed Particle Gel ◽  
Profile Control

Reservoir heterogeneity is the main cause of high water production and low oil recovery in oilfields. Extreme heterogeneity results in a serious fingering phenomenon of the displacing fluid in high permeability channels. To enhance total oil recovery, the selective plugging of high permeability zones and the resulting improvement of sweep efficiency of the displacing fluids in low permeability areas are important. Recently, a Branched Preformed Particle Gel (B-PPG) was developed to improve reservoir heterogeneity and enhance oil recovery. In this work, conformance control performance and Enhanced Oil Recovery (EOR) ability of B-PPG in heterogeneous reservoirs were systematically investigated, using heterogeneous dual sandpack flooding experiments. The results show that B-PPG can effectively plug the high permeability sandpacks and cause displacing fluid to divert to the low permeability sandpacks. The water injection profile could be significantly improved by B-PPG treatment. B-PPG exhibits good performance in profile control when the high/low permeability ratio of the heterogeneous dual sandpacks is less than 7 and the injected B-PPG slug size is between 0.25 and 1.0 PV. The oil recovery increment enhanced by B-PPG after initial water flooding increases with the increase in temperature, sandpack heterogeneity and injected B-PPG slug size, and it decreases slightly with the increase of simulated formation brine salinity. Choosing an appropriate B-PPG concentration is important for B-PPG treatments in oilfield applications. B-PPG is an efficient flow diversion agent, it can significantly increase sweep efficiency of displacing fluid in low permeability areas, which is beneficial to enhanced oil recovery in heterogeneous reservoirs.

New method of controlling excessive water production in wells using induced formation damage

2015 ◽  
Vol 55 (2) ◽  
pp. 485
Author(s):  
Abbas Zeinijahromi ◽  
Pavel Bedrikovetski
Keyword(s):  
Fresh Water ◽  
Large Scale ◽  
Produced Water ◽  
Water Injection ◽  
Cost Effective ◽  
Formation Damage ◽  
Water Production ◽  
Permeable Barrier ◽  
Water Influx ◽  
Excessive Water

Excessive water production is a major factor in reduced well productivity. This can result from water channelling from the water table to the well through natural fractures or faults, water breakthrough in high permeability zones, or water coning. The use of foams or gels for controlling water production through high-permeable layers has been tested successfully in several field cases. A large treatment volume, however, is required to block the water influx that generally involves high operational and material costs. This extended abstract proposes a new cost-effective method of creating a low-permeable barrier against the produced water with induced formation damage. The method includes applying induced formation damage to block the water influx without hindering the oil production. This can be achieved by injection of a small slug of fresh water into the water-producing layer. This results in release of in situ fines from the matrix, which can decrease permeability and create a local low-permeable barrier to the producing water. In large-scale approximation, water injection with induced fines migration is analogous to polymer flooding. This analogy is used to model the fresh water with induced formation damage. Sensitivity studies showed that the injection of 0.01 PVI of fresh water resulted in the blockage of the water-producing layer and an incremental recovery by 8% in field case A, with respect to the standard production scenario. The authors found that the incremental gas recovery with induced formation damage was sensitive to reservoir heterogeneity, permeability reduction and slug volume.

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