Nanotechnology Helps Decrease Pressure, Increase Injection in Offshore China Oil Field

Abstract

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30407, “Case Study of Nanopolysilicon Materials’ Depressurization and Injection-Increasing Technology in Offshore Bohai Bay Oil Field KL21-1,” by Qing Feng, Nan Xiao Li, and Jun Zi Huang, China Oilfield Services, et al., prepared for the 2020 Offshore Technology Conference Asia, originally scheduled to be held in Kuala Lumpur, 2–6 November. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. Nanotechnology offers creative approaches to solve problems of oil and gas production that also provide potential for pressure-decreasing application in oil fields. However, at the time of writing, successful pressure-decreasing nanotechnology has rarely been reported. The complete paper reports nanopolysilicon as a new depressurization and injection-increasing agent. The stability of nanopolysilicon was studied in the presence of various ions, including sodium (Na+), calcium (Ca2+), and magnesium (Mg2+). The study found that the addition of nanomaterials can improve porosity and permeability of porous media. Introduction More than 600 water-injection wells exist in Bohai Bay, China. Offshore Field KL21-1, developed by water-flooding, is confronted with the following challenges: - Rapid increase and reduction of water-injection pressure - Weak water-injection capacity of reservoir - Decline of oil production - Poor reservoir properties - Serious hydration and expansion effects of clay minerals To overcome injection difficulties in offshore fields, conventional acidizing measures usually are taken. But, after multiple cycles of acidification, the amount of soluble substances in the rock gradually decreases and injection performance is shortened. Through injection-performance experiments, it can be determined that the biological nanopolysilicon colloid has positive effects on pressure reduction and injection increase. Fluid-seepage-resistance decreases, the injection rate increases by 40%, and injection pressure decreases by 10%. Features of Biological Nanopolysilicon Systems The biological nanopolysilicon-injection system was composed of a bioemulsifier (CDL32), a biological dispersant (DS2), and a nanopolysilicon hydrophobic system (NP12). The bacterial strain of CDL32 was used to obtain the culture colloid of biological emulsifier at 37°C for 5 days. DS2 was made from biological emulsifier CDL32 and some industrial raw materials described in Table 1 of the complete paper. Nanopolysilicon hydrophobic system NP12 was composed of silicon dioxide particles. The hydrophobic nanopolysilicons selected in this project featured particle sizes of less than 100 nm. In the original samples, a floc of nanopolysilicon was fluffy and uniform. But, when wet, nanopolysilicon will self-aggregate and its particle size increases greatly. At the same time, nanopolysilicon features significant agglomeration in water. Because of its high interface energy, nanopolysilicon is easily agglomerated, as shown in Fig. 1.

Minireview of Formation Damage Control through Nanotechnology Utilization at Fieldwork Conditions

“…To overcome the poor performance of water injection in the field, it was decided that the application of biological nano-polysilicon could be better than traditional materials (water). The experimental results from biological nano-polysilicon demonstrated increased stability of fluid, while permeability also increased by 30.4% of the initial value from the core sample obtained from the rock formation . It was concluded that biological nano-polysilicon has potential for use in field tests, and the KL21-1-B1 well was selected for its test application.…”

“…The field trial work for nanoparticles was done in June 2019 to improve productivity and lessen the risk of formation damage from poor water injection as in December 2015 200 m 3 /d of water was injected into the formation to recover oil. After a comprehensive study, it was found that the KL21-1-B1 well had suffered from the following problems: 77 1. The reservoir was associated with thin interlayers in the vicinity of the wellbore zone, and it contained poor reserve properties that are ineffective for water injection.…”

“…The experimental results from biological nano-polysilicon demonstrated increased stability of fluid, while permeability also increased by 30.4% of the initial value from the core sample obtained from the rock formation. 77 It was concluded that biological nano-polysilicon has potential for use in field tests, and the KL21-1-B1 well was selected for its test application. The stimulation technique was performed using biological nanopolysilicon injection to improve the performance of the well by overcoming the reservoir challenges encountered with the previous water flooding method.…”

“…This means that biological nanopolysilicon as nanoparticles was effective and satisfactory in the KL21-1-B1 well to overcome formation damage, providing the desired results. 77 However 1). The application of nanopolysilicon materials showed remarkable success, especially for its retention properties 78 to improve the injection capacity, resulting in increased permeability and production.…”

“…The field trial work for nanoparticles was done in June 2019 to improve productivity and lessen the risk of formation damage from poor water injection as in December 2015 200 m 3 /d of water was injected into the formation to recover oil. After a comprehensive study, it was found that the KL21-1-B1 well had suffered from the following problems: The reservoir was associated with thin interlayers in the vicinity of the wellbore zone, and it contained poor reserve properties that are ineffective for water injection. The formation contained clay minerals that caused formation damage by hydration expansion, which restricted fluid flow to the producing well. Pollution from the completion fluid was caused by fluid leakage of 80 m 3 . Formation of scales from water injection inhibited normal fluid flow into the producing well. …”