This paper discusses damage removal in naturally fractured carbonate, oil reservoirs of the central North Sea, located in the vicinity of salt domes. The reservoir rock is the well-known Tor chalk, the mechanical properties of which have been greatly modified by the proximity of diapirs. The matrix rock is much harder (similar to a limestone) and extensively fissured. Wells drilled through these reservoirs suffer from very severe damage as a result of the invasion of the natural fractures by large amounts of drilling mud. Productivity is restored by high-rate damage-removal treatments alternating stages of crosslinked gel, customized acid formulations, and ball sealers. Pre-and postjob well performances demonstrate huge productivity-index increases as a result of the cleanup of the natural fissures. This paper emphasizes mud-loss survey during drilling and perforation strategies; candidate selection, i.e., pre-and postjob productivity based on both rock (matrix and fissures) and damage properties; treatment execution (as per actual North Sea jobs); and treatment evaluation and diversion efficiency.
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.
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