Innovative Acid Fracturing Operations Used to Successfully Stimulate Central North Sea Reservoir (1996)

A.N. Martin, SPE, BJ Services (UK) Ltd. Abstract In the summer of 1995, a novel technique was used to stimulate a Central North Sea chalk reservoir. The technique involved the use of two large, dynamically positioned stimulation vessels pumping down the same well simultaneously. The use of this technique allowed the stimulation of long, highly deviated wells to be conducted in a single continuous operation. The need for the vessels to return to port in order to re-load was eliminated; a time saving of 36 hours, minimum, per trip. Additionally, high injection rates could be maintained at high wellhead pressures for extended periods of time (up to 16 hours). The difficulty of the operation, which involved positioning alongside of the jack-up two of the world's largest stimulation vessels, was exacerbated by the need to maintain an accurate inventory of the fluids on each vessel. It was critical that one vessel did not run out of acid before the other. To facilitate this, the operation was controlled from one vessel, with the supervisor being able to monitor what each vessel was doing individually, as well as the combined effect of the two vessels. Altogether, three highly deviated wells were treated in this reservoir. The use of a new stimulation technique meant that the treatments for the ten zones in each well could be completed without having to shut down the vessels' high pressure pumps. It is believed that the treatments carried out by the two well stimulation vessels represent three world firsts. First, the total volume of hydrochloric acid pumped in each well is believed to be a record for an offshore well, in a single treatment. Secondly, the total amount of hydraulic horsepower available for use on location is believed to be a record for an offshore well. Finally, this was the first time that two dynamically-positioned stimulation vessels had been rigged up on the same well simultaneously. Introduction The reservoir is located in the UK sector of the Central North Sea. It is part of a large tertiary basin, which contains several large, well known North Sea reservoirs. The formations consist of Danian and Paleocene sediments. The Paleocene section is primarily clastic, whilst the Danian is a micritic-biomicritic limestone consisting mostly of coccoliths and coccospheres cemented with calcite. These formations are known locally as the Ekofisk and Tor chalks, with the Ekofisk overlying the Tor. The formations tend to be soft, with reservoir pressures of around 7,000 psi, at depths between 9,000 and 11,000 ft. Reservoir temperature in this field is 240 F. The problem faced by the operator was that the field, in order to be economic, had to be completed with the minimum of cost. The field was relatively small and had low permeability. The number of producing wells would have to be kept to a minimum. All wells would have subsea wellheads and would be tied back to a nearby platform, which was operated by the same company. Only three wells would be drilled, and each of these would be highly deviated. The wells would be drilled to bisect the several different zones contained within the Ekofisk and Tor formations. Even after all these measures had been taken to reduce the development and production costs of this reservoir, the field would not be economic without successful stimulation. However, each well contained 10 separate producing intervals, each of which had to be stimulated separately for maximum effectiveness. The total costs of the offshore stimulation for each individual interval would be prohibitive. It was estimated that if conventional methods were used for these stimulations, each well would take between 30 to 40 days to stimulate. In order to minimise the time taken to stimulate each well, a novel approach was taken. A new completion was designed, so that each zone could be treated directly after the previous zone, without the need for shutting down the stimulation operation. A huge quantity of stimulation fluid would have to be available on location, ready to be pumped. P. 479