Pressure Transient Analysis of Naturally Fractured Reservoirs: A Case Study

Abstract

Abstract The characteristic pressure behavior of naturally fractured reservoir systems has been extensively researched in petroleum engineering literature. In a naturally fractured system, reservoir fluids exist in two interconnected systems, the matrix system which provides the bulk of the reservoir volume, and the fracture network which provides the conductive pathway for transmitting fluids to the producing wells. If the flow between adjacent matrix blocks and fluid transport from the matrix blocks to the wellbore is only through the fracture network, then the system is considered dual-porosity. When there is possibility of fluid flow directly between the neighboring matrix blocks and to the well through the matrix in the unfractured region, the system is considered to be dual-permeability. However, the pressure responses from actual field data display similar characteristics for both dual-porosity and dual-permeability reservoirs. Field data that display the classical dual permeability behavior are not very common in the petroleum literature. This paper presents some field pressure transient tests from a naturally fractured Saudi Arabian reservoir that display the classical dual-permeability characteristics and the analyses performed on them. Introduction The significance of natural fractures and fracture related production in the Hanifa reservoir has been reported by earlier investigators. They found that this reservoir has low matrix permeability between 0.01 and 5md and yet during production testing, anomalously high flow rates such that could not be produced from such low permeability matrix systems were recorded on the flowmeter log. It was also noticed that over half of the flow could be attributed to only one or two 10ft thick stratigraphic intervals. The large disparity between core derived permeabilities and well test permeabilities also indicated that there must be another enhanced permeability system in this reservoir. It was reported that on the average, permeability from well test was 40 times greater than the permeability determined from core plugs. This was attributed to the presence of fractures which have also been observed in several cores from Hanifa wells and were also seen on borehole imaging logs. Most of the fractures in the cores are open and less than 2 mm wide. In a recent detailed study by Luthy and Grover, they concluded that the fractures and stylolites form the essential fluid permeability system of the reservoir. From these previous efforts on the Hanifa reservoir, it was established that the Hanifa is a dual-permeability system consisting of a matrix permeability system and a fracture permeability system. The fracture permeability system accounts for the majority of the fluid flow in this reservoir. However the matrix could contribute some production, however small, in some unfractured intervals. The main objectives of this analytical pressure transient work were to seek for reservoir engineering evidence to confirm the dual-permeability characteristics of this naturally fractured reservoir from the behavior of the pressure transient and to estimate flow capacities. The resulting flow capacities would be used in generating permeability distribution for numerical flow simulation. Reservoir Concepts The term dual porosity, often used to describe naturally fractured reservoirs, stands for a reservoir with a primary and a secondary porosity. The primary porosity usually refers to a matrix system which was formed when the reservoir was originally deposited. This matrix system is made up of fine pores and a low permeability. The secondary porosity was formed later by geological processes which modified the primary porosity. In our case, the secondary porosity is a set of interconnecting fractures, fissures or vugs which have high permeabilities. The matrix system serves as the fluid storage medium for the entire system since more than 90 percent of the total fluid reserve is contained in the matrix pore spaces. P. 357^