3D dynamic fault sealing capacity modelling to improve history matching: a case study in Oligocene reservoir, Tay Ho Field, Blocks A, Cuu Long basin, Offshore
- Authors: Hung Viet Vu *, Dong Duc Nguyen, Gia Phuoc Phan, Vu Minh Le, Hai Hoang Ninh
PVEP Block 01/97&02/97, HCM City, Vietnam
- Keywords: 3D fault seal capacity, Fault clay, Fault permeability, Fault thickness, Fault transmissibility.
- Received: 19th-July-2022
- Revised: 23rd-Oct-2022
- Accepted: 21st-Nov-2022
- Online: 1st-Feb-2023
- Section: Oil and Gas
Fault transmissibility multipliers are a simple way of accounting for the effects of faults on fluid flow across fault plans in history matching of production simulation models. Fault transmissibility multipliers can be calculated using parameters such as fault clay, fault smear, thickness, and permeability. In this study, three emperical methods given by Manzocchi et al. (1999), Jolley et al. (2007), and Sperrevik et al. (2002) have been applied to the Oligocene sandstone reservoir, Tay Ho Field. The Oligocene reservoir is a complicated sandstone that was deposited in alluvial-fluvial and lacustrine environments, trapped by both stratigraphic and structural types, sandbody isolated by multi-activated faults. Fault sealing is one of the key factors controlling hydrocarbon accumulations and trap volume and can have a significant influence on reservoir performance during production. Furthermore, the prospective of structural or combination traps in stacked clastic reservoir settings that are typically found in many of the known hydrocarbon provinces in the Cuu Long basin, often critically hinges on the presence of a working fault side seal. Based on a thorough understanding of the key controls on fault seal risk and retention capacity, a consistent methodology to access these factors across a prospect portfolio is essential to achieve a balanced prospect ranking and an accurate assessment of prospect success volumes. In the process workflow built by PVEP Blocks 01/97 & 02/97, the assessment of fault seal capacity and compartmentalization in the Oligocene reservoir have been incorperated by using fault deformation, displacement, juxtaposition, fault zone thickness, shale gouge ratio (SGR), shale smear factor (SSF), clay smear potential (CSP), fault thickness and permeability. In our research, the Sperrevik et al. (2002) method provides the best historical match and most logical geological evidence; thus, it shall be used for dynamic models and further studies.
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