This paper describes the implementation of the first successful fracture treatments in the Carboniferous formation of the Trent Field, in the Southern North Sea. To date, two wells have been successfully fractured with indications from IPR work that the total deliverability from the Lower Trent was increased by 300%. Today the wells are flowing over 45 mmscfd from the Upper and Lower Trent with minimal drawdown. In this paper we describe the reservoir challenges of fracturing the Carboniferous formation. These challenges included deviated wellbore effects, contrasting leakoff and spurt, natural fractures in the Upper Trent, low sand-shale stress contrast and uncertainty of the principal stress azimuth. The paper describes the pre treatment tests, challenges of analyzing the mini-frac and the logic used in the final design.

Because the Trent platform is not normally manned the need for no proppant flowback was critical to the success of the fracturing program. To prevent proppant flowback both wells used a 20/40 dual coated resin ISP proppant The first well took 7 days to cleanup to an acceptable flowback of <5 pounds per hour of proppant In an attempt to decrease the amount of time to cleanup the well, the second well utilized forced closure and the addition of fibers. Cleanup time was reduced to 2 days.


The Trent Field located within Block 43/24 was discovered in 1991. The field is located in the Southern North Sea Gas Basin 100 miles north of East Anglia. The field contains up to 15 distinct sand-bearing units, however, only three units are commercial at this time. Of these units, the Lower Trent, which accounted for over half of gas-in-place is made up of low permeable sands (0.1–10md). Initial appraisal of the Lower Trent was a disappointing 0.5–1 mmscfd.

The first fracture treatment on the Trent was performed in 1993 in Well 43/24–3. In an attempt to determine the deliverability of target zone the fracture treatment had to stay within this interval. The well was perforated with 12 spf over a 21-ft interval. This created a major challenge to control multiple fractures and height growth. In an attempt to control these factors the design called for a small pad and low pump rate. The treatment was also the first job in the North Sea to use a high temperature Borate. Unfortunately, the treatment screened out prematurely with placing only 9,000 lbs. of proppant Post evaluation indicated that the well screened out because of near wellbore tortuosity and height growth.

Because of the failure from the first job and the need to successfully treat deviated wellbores, core work was performed to determine the fracture azimuth and Dynamic elastic properties. From this work it was determined that the maximum horizontal stress was 193–267 from the North which was perpendicular to what was expected in this area. This was later confirmed with borehole breakout.

Additional challenges included little stress contrast, contrasting permeabilities and natural fractures in the Upper Trent. Laboratory work was performed to determine the dynamic leakoff and spurt loss in both the Upper and Lower Trent.

The treatment pumped used Intermediate Strength Ceramic Proppant with RCP that utilized a dual-coat curable phenolic resin. The entire treatment was pumped with resin coated proppant to ensure that there would be no proppant flowback The resin-coated proppant was successful in attaining minimal proppant flowback However, the second treatment included fibers, which enabled the second well to cleanup in two days versus 7 days.

Well and Reservoir Data

Reservoir Interval. The Carboniferous formation is a highly complex fluvial system and is made up of 15 distinct sand bearing units. Of these 15 sand-bearing units only three intervals are of commercial value at this stage.

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