The Cement Packer completion has found great use and applicability in Chevron Nigeria assets by creating a cost-effective way of accessing ‘behind-pipe’ production opportunities. These isolated hydrocarbon pools could not have been otherwise developed due to the un-favourable cost of a Major Rig Workover. This has helped to maximize value from oil and gas assets by returning previously inactive wellbores to production. The typical through-tubing technique of deploying cement packers in candidate wells has been to set a plug in the tubing to isolate the deeper reservoir, punch a hole in the tubing, displace cement through the hole in the tubing and place it across the new target sand so that the displaced cement would serve as an artificial packer in the tubing-casing annulus. The tubing would then be perforated across the cement packer and into the target reservoir. Much success has been recorded with the use of this technique and though it has provided proper tubing-casing annulus isolation, there have also been a few challenges. Some of the challenges include significant skin (caused by the extra pressure drop during fluid flow through the cement tunnel), limited perforation efficiency in dual-string wells (caused by gun-size limitations due to the tubing size) and lack of radial flow since the perforations are oriented at zero-degree phasing to avoid perforating into the second string in dual-string wells. Eliminating these challenges would significantly improve the well production rate and project economics. This paper presents three case studies where these challenges have been effectively addressed and the attendant results. In the first case study, we show how over-displacing the cement ensured that the column of cement was placed above (rather than across) the proposed completion perforations while still retaining annular isolation. This significantly improved the expected initial production rate of the well by a factor of more than three since there was no extra skin due to fluid flow through the cement tunnel. In the second case study, we show how we improved the perforation efficiency in a dual-string well despite being constrained by the gun size by perforating twice at zero-degree phasing. In the third case study, we show how we overcame the challenge of always perforating at zero-degree phasing in dual-string wells by performing dummy simulations (at the surface) using pipe-in-pipe configurations to better understand the perforating gun orientation downhole relative to the tubings and casing. Based on the results of the surface simulations, we achieved additional phasing in two perforation runs and this significantly increased the productivity of the well. A major lesson learnt was the importance of performing dummy simulations at the surface using pipe-in-pipe configurations to mimic the tubings-casing configuration. This was crucial to the success of the job where additional phased perforations were added.
Gas lift is one of the most common and economical methods of artificial lift deployed in mature oil fields in the Niger Delta. Availability of lift gas on the oil production jacket or platform is a critical enabler for gas lift initiation. Most mature fields do not have the luxury of gas lift supply on its jackets either because gas flowlines were not laid at inception or the gas flowlines are out-of-service due to integrity issues. Jacket X had four active oil well streams producing on natural flow at inception. In early 2017, these wells stopped production one after the other due to low tubing head pressure (LTHP) because of increasing watercut and declining reservoir pressure. The wells were producing at a combined rate of over 1,000 barrels of oil per day (BOPD) prior to stopping production. Well diagnostic and preliminary Nodal Analysis revealed the need to place the wells on gas lift to improve the vertical lift performance. However, this could not be executed as jacket X was not on the field gas lift flowline network. Without conventional lift gas on Jacket X, it was imperative to source for the most economic means of getting gas on the jacket. This paper highlights the processes and methodology of sourcing lift gas through an existing idle wellbore. During the bi-anual field review, the team of Operations personnel, Facilities Engineering and Asset Management reviewed and mapped out low cost strategy to restore production of the shut-in wells. Since most of these wells stopped production due to LTHP, improving vertical lift performance became the critical success factor. To address this issue economically, the asset team developed an ingenious method of sourcing the required lift gas on the same Jacket X through rigless well intervention on one of the existing idle wellbores. The innovative approach deployed involved identification of gas bearing reservoir in one of the idle wellbores, cement squeeze operations to provide zonal isolation, oriented perforation of identified gas reservoir, topside modification of existing wellhead configuration and eventual supply of lift gas to the casing of the shut-in wells. Utilizing the lift gas, the wells were placed on gas lift with 1,100 barrels of oil and 3.5 MMScfd of gas restored to production. Significant cost savings were realized during the execution of this project through the application of rigless interventions which eliminated the requirement of laying new flowlines to deliver required lift gas to Jacket X. Finally, this paper will share some of the challenges, lesson learned, and best practices adopted while executing this project.
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