Annulus pressure build-up (APB) remains an important design consideration for many wells, not just deepwater or subsea wells. This paper outlines a step-by-step methodology for analysing APB issues applicable to any type of well. Analyses of APB scenarios for a tight chalk oil reservoir and an HPHT gas-condensate reservoir in the Danish Sector of the North Sea are used to demonstrate the methodology. APB is a potentially serious issue with HPHT wells created by annuli that heat up during production. The increased temperatures cause fluid expansion that can potentially over-stress the casing and tubing if not mitigated. Specific issues for HPHT wells are presented. The significant increase in the use of multi-stage horizontal fracturing systems with open or cased hole packers and ball or intervention operated sliding sleeves creates a fluid contraction threat. Overpressure through annulus fluid contraction caused by cooling has been rarely analysed. A case is shown to disprove a common belief that the fluid external to the sleeves equalizes with the reservoir over the time frame of the stimulation operation which prevents over-pressurization. Failure cases are presented along with the design calculations required to assess the combination of tubing ballooning, fluid contraction / expansion and transient reservoir flow. It is demonstrated that with cases of toe-to-heel stimulation combined with low reservoir permeabilities, significant transient drops in pressure external to the sleeves can occur. This can lead to tubing, sleeve or packer failures.
Optimizing production and understanding inflow from long horizontal wells in tight chalk reservoirs has traditionally been difficult. The horizontal sections of these wells have been typically segmented into four to eighteen zones, driven by completion, stimulation and reservoir management requirements. Surface controlled sliding side doors have been used in a number of wells to control the zones for production optimisation, but permanent down hole monitoring of each zone had not been undertaken in the Danish sector so far. The subject of this paper is the installation and application of zonal pressure gauges and distributed temperature sensing in a recently drilled long horizontal oil producer in the Danish sector of the North Sea. Despite a very challenging trajectory and reservoir pressure variations along the horizontal section the well was drilled to 24,000 ft measured depth and equipped with permanent downhole monitoring and control capabilities. The horizontal reservoir section was segmented into five zones. In each zone a surface-controlled sliding side-door and a pressure and temperature gauge were installed. A fibre-optic cable for distributed temperature sensing (DTS) along the upper four zones to a depth of around 15,500 ft was installed as well. The upper four zones also contained an extra coiled-tubing operated sliding side door for restimulation purposes. After completing the well each zone was matrix acid stimulated. Stimulation monitoring with DTS allowed quantification of zonal acid coverage and identification of the scope for re-stimulation. During initial production of the well the pressure and temperature gauges in each of the zones proved valuable for start-up operations. Cross-flow between zones was identified and this knowledge was used for improved management of commingled zonal production. This paper describes how temperature and pressure data from each zone has been used for well production optimisation, in sometimes unexpected ways. The combination of being able to react without intervention using the real-time data has proven to be critically important and supported more efficient operations.
Appraisal and development of thin chalk reservoirs in the Danish Sector of the North Sea requires wells providing maximum reservoir contact and completions designs so that wells can be stimulated to maximize well productivity. Completion liners for pin-point matrix acid stimulations of long horizontal wellbore sections have been designed, manufactured and tested. The objective of the work was to identify a liner design with maximum inflow area but sufficient strength to withstand installation loads as is required if rotating the liner to target depth. This paper describes the results from finite element analyses of different slotted and some pre-drilled liner designs. Staggered patterns were selected following recommendation from manufacturers. Based on the results from the finite element analysis designs was chosen. Liner joints were manufactured and tested to verify the designs. Both slotted and pre-drill liner designs were verified.
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