Effective Gas-Shutoff Treatments in a Fractured Carbonate Field in Oman

Abstract

Summary A giant, fractured carbonate field in north Oman has both complex geology and complex reservoir-drive mechanisms. The upper, densely fractured layers are produced using the gas/oil gravity-drainage (GOGD) process, while the less-fractured lower set of layers is subjected to waterflooding. The production from the GOGD layers is through vertical and horizontal wells completed in a thin fracture oil rim. Gas conformance control is a challenge in many of these wells because the gas breakthrough occurs for a variety of reasons: downward movement of fracture gas/oil contact (fracture-oil-rim thinning), gas breakthrough via high-conductivity fractures (fracture gas breakthrough), zonal-isolation failure at the wellbore (mechanical gas breakthrough), and increasing gas saturation in the matrix (matrix gas breakthrough). An integrated multidisciplinary team studied well and reservoir performance and openhole (OH) and cased-hole logs to diagnose the source of higher-than-expected gas/oil ratio (GOR) in several GOGD wells. The most important logs in this work were memory-production-logging-tool (MPLT) surveys used to identify the sources of gas production and formation-microimager (FMI) logs used for fracture identification and characterization. This paper illustrates the work carried out in horizontal openhole and vertical cased-hole completions to shut off the undesirable gas flow successfully. The horizontal wells identified with poor zonal isolation behind the liner were treated with an innovative gel gas-shutoff procedure. The merits of this procedure outweighed those of other proposed solutions: targeted placement, a strong full-blocking gel to fill up channels behind the liner, inert particles to control fluid loss of the full-blocking gel to small fractures and the formation matrix, and displacement with an already-cured gel that could be washed out of the wellbore. Significant drops in the GORs of these wells resulted in sustained oil-production increases. This is a step change in the ability to manage detrimental gas production in this field and is expected to lead to further opportunities for improved gas management and well performance in this field and other fields where the GOGD recovery mechanism is used. Introduction The giant fractured carbonate field was discovered in 1964 and came on stream 3 years later. The field has seven reservoir layers—A through G—and multiple subunits within each layer. The upper layers A, C, D, and E1/E2 are more intensely fractured than lower layers, the E3/E4, F, and G reservoirs. Initial production from the reservoirs (1967 to 1970) was by natural depletion, supported by gas injection in the A reservoir unit from 1968 onward. After this initial period of gas injection, water injection was implemented in the A, C, D, and E reservoirs (1970 through 984). Previously unknown fracture networks in these layers resulted in rapid water breakthrough. This was followed by GOGD development (1983 through 1998), which was successful in arresting the decline in the oil production. Following a simulation study in 1996, it was decided to implement a line-drive waterflood with horizontal wells in layers that were considered sparsely-fractured. Because GOGD is not effective in sparsely fractured reservoirs, waterflooding these layers was expected to increase recovery substantially in those layers. Since 1997, field development and operation have used this combination of GOGD and localized waterflood. A recent review of production and petrophysical data showed that the fracture spacing varies significantly both horizontally and vertically. This impacts the GOGD efficiency and recovery factor, since GOGD is inefficient where fracture spacing is larger, because the oil has to travel longer distances through the matrix to the nearest fracture set to be recovered.