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Production in offshore Mexico mature fields is mostly driven by gas injected from surface. With time, this injected gas flows directly through the natural fractures of the low-pressure carbonate reservoirs, leaving oil trapped in the low-permeability matrix. Over the past few years, the gas-oil contact (GOC) has rapidly moved across those fields—up to 6.5 ft per month in some wells—, making conventional gas shutoff techniques either unsuccessful or uneconomic. A new rigless intervention method using coiled tubing (CT) equipped with real-time telemetry has been used to revive oil production in gas-invaded wells. The objective was to achieve better results than the mixed success that had been obtained with gas shutoffs using chemicals and to reduce the cost and time typically involved with traditional workover operations. The approach consists of the modification of the downhole completion through CT. After perforating a new interval in the lower oil-bearing zone, a CT string is conveyed down the well and precisely hung by another CT at the end of the existing production tubing. Equipped with slotted bars, the string allows directly tapping into the newly opened zone while bypassing the former intervals that are mostly producing gas. From a CT standpoint, such interventions in an offshore environment present significant challenges, ranging from logistical to operational. During the first implementation of this new technique, the available section for anchoring the CT hanger was only 11.5 ft of 3 1/2-in. tubular inside a 5 1/2-in. completion. In addition, the projected tail of the CT hang-off was very close to the well total depth (only 10 ft from the bottom). The use of CT with real-time telemetry was thus critical to an accurate depth control that would allow not only determining the actual length of the CT string to be cut, but also for precisely hanging that string. In addition, the joint use of real-time telemetry and a downhole tension and compression module was key to ensuring proper actuation of the anchoring mechanism downhole while protecting the integrity of the new and former completion components. As a result of that intervention, the gas/oil ratio was reduced by 96%, while oil production increased more than twofold. In addition, the use of the CT measurement system and its flexibility saved a major workover intervention and the associated deferred production to the operator. This rigless methodology, leveraged by CT real-time telemetry, brings a new, viable, and economical alternative to gas-control treatments. Use of the technique can significantly extend the life of producers facing major gas-control issues in environments where the complexity of the reservoir and its dynamics tend to make shutoff treatments complicated and their outcome uncertain.
Production in offshore Mexico mature fields is mostly driven by gas injected from surface. With time, this injected gas flows directly through the natural fractures of the low-pressure carbonate reservoirs, leaving oil trapped in the low-permeability matrix. Over the past few years, the gas-oil contact (GOC) has rapidly moved across those fields—up to 6.5 ft per month in some wells—, making conventional gas shutoff techniques either unsuccessful or uneconomic. A new rigless intervention method using coiled tubing (CT) equipped with real-time telemetry has been used to revive oil production in gas-invaded wells. The objective was to achieve better results than the mixed success that had been obtained with gas shutoffs using chemicals and to reduce the cost and time typically involved with traditional workover operations. The approach consists of the modification of the downhole completion through CT. After perforating a new interval in the lower oil-bearing zone, a CT string is conveyed down the well and precisely hung by another CT at the end of the existing production tubing. Equipped with slotted bars, the string allows directly tapping into the newly opened zone while bypassing the former intervals that are mostly producing gas. From a CT standpoint, such interventions in an offshore environment present significant challenges, ranging from logistical to operational. During the first implementation of this new technique, the available section for anchoring the CT hanger was only 11.5 ft of 3 1/2-in. tubular inside a 5 1/2-in. completion. In addition, the projected tail of the CT hang-off was very close to the well total depth (only 10 ft from the bottom). The use of CT with real-time telemetry was thus critical to an accurate depth control that would allow not only determining the actual length of the CT string to be cut, but also for precisely hanging that string. In addition, the joint use of real-time telemetry and a downhole tension and compression module was key to ensuring proper actuation of the anchoring mechanism downhole while protecting the integrity of the new and former completion components. As a result of that intervention, the gas/oil ratio was reduced by 96%, while oil production increased more than twofold. In addition, the use of the CT measurement system and its flexibility saved a major workover intervention and the associated deferred production to the operator. This rigless methodology, leveraged by CT real-time telemetry, brings a new, viable, and economical alternative to gas-control treatments. Use of the technique can significantly extend the life of producers facing major gas-control issues in environments where the complexity of the reservoir and its dynamics tend to make shutoff treatments complicated and their outcome uncertain.
In the current brown field environment a lot of mature gas wells in the Southern North Sea (SNS) are liquid loading. Foamer can be injected in the wellbore as a gas well deliquification (GWD) measure to mitigate this liquid loading behavior. Foamer can be injected periodically in batch mode or continuously downhole by means of a small capillary string installed in the wellbore. To date ONEgas* is producing 12 offshore gas wells located on 3 manned SNS platforms by means of continuous foamer (CF) injection. The first offshore CF installation came online in 2011 and dozens more installations are scheduled in the near future. CF has gone through a steep learning curve where the next step is to install CF on an unmanned SNS platform. After 4 years of gas production with CF a lot has been learned about designing, installing and operating capillary string CF installations. This paper demonstrates the success of continuous foamer injection by showing increased production and recovery due to foamer but also presents the challenges that were experienced in terms of uptime i.e. poor reliability due to capillary blockages, sand erosion and surface facility upsets etc. The method of tackling these reliability issues to maximize uptime is presented, including an overview of the current and future subsurface and surface hardware components. *ONEgas is a combined business unit of NAM and Shell UK
Field Delta located 95 Km North West of the city of Mumbai is producing through 13 wellhead platforms through approximately 60 oil wells mostly operating on gas lift. The recent flowing gradient surveys recorded in the wells have indicated drop in liquid level thus resulting in de-optimized gas lift system. Many wells in the field have also ceased to flow due to liquid loading and gradual drop in liquid level below the last operating gas lift valves. Recompleting the wells with smaller tubing sizes and Gas Lift Valves upto the bottom of the well using workover rig in offshore is cost intensive and time taking and may not be economically viable for all the wells. Therefore various revival strategies which do not require workover and can be used for extending the operating life of mature wells have been discussed in the paper through various case studies. These technologies provide a sustainable & reliable means to retrofit gas lift to reach the deepest point. Methodology adopted to carry out the designing by matching the existing valve depths and possibility to go deeper considering the system limitation has been discussed in the paper with few examples. Simulation indicated that in 6 wells scope exists for enhancing production by replacing dummies at deeper depths with CVs with the available gas injection Pressure. 19 wells have been identified in which scope exists for deeper injection below current injection depth (last Gas Lift Mandrel) through rig-less applications like single point gas lift and rigless coiled tubing gas lift system below the packer. A comparative analysis of different technologies to revive production from liquid loaded wells have been brought out in the paper through various case studies.
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