Experimental Investigation of Light Oil Recovery from Fractured Shale Reservoirs by Cyclic Water Injection

2016 ◽  
Author(s):  
Yang Yu ◽  
James J. Sheng
Keyword(s):  
Experimental Investigation ◽  
Oil Recovery ◽  
Water Injection ◽  
Light Oil ◽  
Shale Reservoirs

scholarly journals Experimental investigation on continuous N 2 injection to improve light oil recovery in multi-wells fractured-cavity unit

Petroleum ◽  
2017 ◽  
Vol 3 (3) ◽  
pp. 367-376 ◽  
Author(s):  
Wei Su ◽  
Jirui Hou ◽  
Teng Zhao ◽  
Yuanyuan Xi ◽  
Can Cui
Keyword(s):  
Experimental Investigation ◽  
Oil Recovery ◽  
Light Oil

Challenges, Opportunities and Threats of Deep Bottoms-Up Water Injection in Heavy Oil Reservoir: Lessons Learnt from the G Field, South Oman

2021 ◽  
Author(s):  
Chaitanya Behera ◽  
Sandip Mahajan ◽  
Carlos Annia ◽  
Mahmood Harthi ◽  
Jane-Frances Obilaja ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Water Injection ◽  
Field Performance ◽  
Oil Field ◽  
Oil Fields ◽  
Reservoir Pressure ◽  
Light Oil ◽  
Alternative Water ◽  
Variable Water

Abstract This paper presents the results of a comprehensive study carried out to improve the understanding of deep bottom-up water injection, which enabled optimizing the recovery of a heavy oil field in South Oman. Understanding the variable water injection response and the scale of impact on oil recovery due to reservoir heterogeneity, operating reservoir pressure and liquid offtake management are the main challenges of deep bottoms-up water injection in heavy oil fields. The offtake and throughput management philosophy for heavy oil waterflood is not same as classical light oil. Due to unclear understanding of water injection response, sometimes the operators are tempted to implement alternative water injection trials leading to increase in the risk of losing reserves and unwarranted CAPEX sink. There are several examples of waterflood in heavy oil fields; however, very few examples of deep bottom water injection cases are available globally. The field G is one of the large heavy oil fields in South Oman; the oil viscosity varies between 250cp to 1500cp. The field came on-stream in 1989, but bottoms-up water-injection started in 2015, mainly to supplement the aquifer influx after 40% decline of reservoir pressure. After three years of water injection, the field liquid production was substantially lower than predicted, which implied risk on the incremental reserves. Alternative water injection concepts were tested by implementing multiple water injection trials apprehending the effectiveness of the bottoms-up water injection concept. A comprehensive integrated study including update of geocellular model, full field dynamic simulation, produced water re-injection (PWRI) model and conventional field performance analysis was undertaken for optimizing the field recovery. The Root Cause Analysis (RCA) revealed many reasons for suboptimal field performance including water injection management, productivity impairment due to near wellbore damage, well completion issues, and more importantly the variable water injection response in the field. The dynamic simulation study indicated negligible oil bank development due to frontal displacement and no water cut reversal as initial response to the water injection. Nevertheless, the significance of operating reservoir pressure, liquid offtake and throughput management impact on oil recovery cann't be precluded. The work concludes that the well reservoir management (WRM) strategy for heavy oil field is not same as the classical light oil waterflood. Nevertheless, the reservoir heterogeneity, oil column thickness and saturation history are also important influencing factors for variable water injection response in heavy oil field.

A Comprehensive Project of Thermal, Gas and Chemical EOR Method Application for Bazhenov Shale Formation

2021 ◽  
Author(s):  
Alexandra Ushakova ◽  
Elena Mukhina ◽  
Alexandra Scerbacova ◽  
Aman Turakhanov ◽  
Denis Bakulin ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Experimental Studies ◽  
Thermal Exposure ◽  
Chemical Eor ◽  
Light Oil ◽  
Shale Formation ◽  
Oil Injection ◽  
Oil Formation ◽  
Selection Of

Abstract The article describes the development aimed at a comprehensive study for enhanced oil recovery methods (EOR) of the Bazhenov shale oil formation. Potentially effective technologies for low-permeable reservoirs are under consideration: injection of associated petroleum gas in the mode of miscible displacement to recover light oil; injection of the surfactants water solutions, to separate sorbed hydrocarbons from the rock and change core wettability; and heating technologies to convert solid hydrocarbons into liquid and gaseous, and recover. The project explore potentially effective EOR technologies and their influence on the various types of hydrocarbons of the shale Bazhenov formation: mobile oil in closed pores, sorbed and solid (kerogen) hydrocarbons. Experimental studies were carried out: the selection of the gases composition, the selection of surfactant compositions, the study of the possibility of thermal exposure by over-heated water injection. The project is currently at the stage of determining the effectiveness of each method, selecting a technology for specific field conditions and identifying which hydrocarbon resources each method is aimed at extracting.

The Effect of Water-Induced Stress To Enhance Hydrocarbon Recovery in Shale Reservoirs

SPE Journal ◽  
2013 ◽  
Vol 18 (05) ◽  
pp. 897-909 ◽  
Author(s):  
Perapon Fakcharoenphol ◽  
Sarinya Charoenwongsa ◽  
Hossein Kazemi ◽  
Yu-Shu Wu
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Reservoir Pressure ◽  
Reservoir Temperature ◽  
Hydrocarbon Recovery ◽  
Induced Stress ◽  
Stress Changes ◽  
Matrix Blocks ◽  
The Matrix ◽  
Shale Reservoirs

Summary Waterflooding has been an effective improved-oil-recovery (IOR) process for several decades. However, stress induced by waterflooding has not been well studied or documented. Water injection typically increases reservoir pressure and decreases reservoir temperature. The increase in reservoir pressure and decrease in reservoir temperature synergistically reduce the effective stress. Because of such decrease in stress, existing healed natural fractures can be reactivated and/or new fractures can be created. Similar effects can enhance hydrocarbon recovery in shale reservoirs. In this paper, we calculated the magnitude of water-injection-induced stress with a coupled flow/geomechanics model. To evaluate the effect of water injection in the Bakken, a numerical-simulation study for a sector model was carried out. Stress changes caused by the volume created by the hydraulic fracture, water injection, and oil production were calculated. The Hoek-Brown failure criterion was used to compute rock-failure potential. Our numerical results for a waterflooding example show that during water injection, the synergistic effects of reservoir cooling and pore-pressure increase significantly promote rock failure, potentially reactivating healed natural macrofractures and/or creating new macrofractures, especially near an injector. The rock cooling can create small microfractures on the surface of the matrix blocks. In shale oil reservoirs, the numerical experiments indicate that stress changes during water injection can improve oil recovery by opening some of the old macrofractures and creating new small microfractures on the surface of the matrix blocks to promote shallow water invasion into the rock matrix. Furthermore, the new microfractures provide additional interface area between macrofractures and matrix to improve oil drainage when using surfactant and CO2 enhanced-oil-recovery techniques. These positive effects are particularly important farther away from the immediate vicinity of the hydraulic fracture, which is where much of the undrained oil resides.

The Douglas Field, Block 110/13b, UK East Irish Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 307-319 ◽  
Author(s):  
J. Bunce
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Column Height ◽  
Irish Sea ◽  
Artificial Lift ◽  
Water Alternating Gas ◽  
Stock Tank ◽  
Light Oil ◽  
Sandstone Formation ◽  
Water Cut

AbstractThe Douglas Field is located in Block 110/13b in the East Irish Sea. It was the first oilfield to be discovered and produced in the region, having been found in 1990 and brought on stream in January 1996. The field structure comprises a series of north–south-trending, tilted, extensional fault blocks. The reservoir interval is the Triassic Ormskirk Sandstone Formation comprising good quality aeolian and fluvial sandstones. The field is relatively shallow, with the top reservoir at c. 2120 ft true vertical depth subsea. The hydrocarbon is a light oil of 44°API gravity with a maximum column height of c. 400 ft. The Douglas Field contains an estimated stock tank oil in place of 248 MMbbl and was developed with 22 wells: 15 producers, six water injectors and a single sour gas and condensate disposal well. Electric submersible pumps are installed in oil producers for artificial lift and water injection was utilized from field start-up for pressure maintenance. A water-alternating-gas pilot was implemented on the field in 2017 as an enhanced oil recovery scheme. The field currently produces at a rate of c. 4000 bopd, with approximately 90% water cut. The field has produced 103 MMbbl to date, giving a current oil recovery of c. 41%.

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