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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 water flooding. 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 as 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) andincreasing gas saturation in the matrix (matrix gas breakthrough). An integrated multidisciplinary team studied well and reservoir performance and open-hole and cased-hole logs to diagnose the source of higher than expected GOR in several GOGD wells. The most important logs in this work were MPLT surveys used to identify the sources of gas production and FMI logs used for fracture identification and characterization. This paper illustrates the work carried out in horizontal openhole and vertical cased-hole completions in a giant fractured carbonate field to successfully shut-off the undesirable gas flow. The horizontal wells identified with poor zonal isolation behind the liner were treated with an innovative gel gas shut-off procedure. The merits of this procedure outweighed other 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 which could be washed out of the wellbore. Significant drops in the GORs of these wells resulted in sustained oil production gains. 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 three years later. The field has 7 reservoir layers A - G and multiple subunits within each layer. The upper layers A, C, D and E1/E2 are more intensely fractured than lower layers E3/E4, F and G reservoirs. Initial production from the reservoirs (1967–1970) was by natural depletion, supported by gas injection in the A reservoir unit from 1968 onwards. After this initial period of gas injection, water injection was implemented in the A, C, D and E reservoirs (1970–1984). Previously unknown fracture networks in these layers resulted in rapid water breakthrough. This was followed by GOGD (Gas-Oil-Gravity-Drainage) development (1983–1998), 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 those layers considered to be sparsely fractured. Because GOGD is not effective in sparsely fractured reservoirs, waterflooding these layers was expected to substantially increase recovery in those layers. Since 1997, field development and operation has utilized this combination of GOGD and localised waterflood. A recent review of production and petrophysical data showed that the fracture spacing varies significantly both hortizontally and vertically. This impacts the GOGD efficiency and recovery factor, since GOGD is inefficient where fracture spacing is larger, as the oil has to travel long distances through the matrix to the nearest fracture set in order to be recovered.

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.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractDrilling through weak formations with total losses, while concurrently controlling gas influx by pumping water down the annulus, is a situation often encountered in the main Northern Oman carbonate oilfields. Consequently cementing the intermediate liner and aiming to achieve total annular coverage for zonal isolation becomes a challenge.This paper describes a technique that has permitted the intermediate liner to be set and fully cemented while experiencing drilling fluid losses and formation flows. Using this technique, the liner packer is set before cementing, thus isolating the gas influx and removing the need to pump in the annulus during the cementation. Then by cementing using a foamed spacer and foamed cement in stages, the fluids can be effectively diverted up the annulus across the loss zones resulting in zonal isolation. For better control of the volumes, and to be able to react to a possible early increase in pressure, the inner-string liner method is used. This cement procedure has been employed on several wells and the cement bond log (CBL) results are very encouraging. Prior to employing this method, cement was only evident around the liner shoe joint. With this new method the total liner length has shown cement coverage from 80-100% with the top of cement (TOC) approaching the previous shoe. In addition this technique has resulted in economic gains by eliminating stage tools and annular packers.The drilling challenges of these fractured wells, the cementing requirements, the design notion of the foamed fluids, the operational execution, and the observed CBL results are all discussed. The value added by using this technique is also demonstrated.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractDrilling through weak formations with total losses, while concurrently controlling gas influx by pumping water down the annulus, is a situation often encountered in the main Northern Oman carbonate oilfields. Consequently cementing the intermediate liner and aiming to achieve total annular coverage for zonal isolation becomes a challenge.This paper describes a technique that has permitted the intermediate liner to be set and fully cemented while experiencing drilling fluid losses and formation flows. Using this technique, the liner packer is set before cementing, thus isolating the gas influx and removing the need to pump in the annulus during the cementation. Then by cementing using a foamed spacer and foamed cement in stages, the fluids can be effectively diverted up the annulus across the loss zones resulting in zonal isolation. For better control of the volumes, and to be able to react to a possible early increase in pressure, the inner-string liner method is used. This cement procedure has been employed on several wells and the cement bond log (CBL) results are very encouraging. Prior to employing this method, cement was only evident around the liner shoe joint. With this new method the total liner length has shown cement coverage from 80-100% with the top of cement (TOC) approaching the previous shoe. In addition this technique has resulted in economic gains by eliminating stage tools and annular packers.The drilling challenges of these fractured wells, the cementing requirements, the design notion of the foamed fluids, the operational execution, and the observed CBL results are all discussed. The value added by using this technique is also demonstrated.