Abstract

Coiled tubing horizontal drilling technology is quickly moving into new frontiers in the Western Canadian Basin. To this point, most efforts have been focused towards sweet oil reservoirs in the 1000 – 2000 m true vertical depth range. There is an ever-increasing interest in deeper sour plays which impose some significant design challenges on both conventional and coiled tubing drilling. This paper reviews the underbalanced coiled tubing drilling operation of a 2300 m true vertical depth sour gas carbonate reservoir in Central Alberta. Issues faced during the drilling included hole cleaning, wellbore stability, motor performance at low liquid injection rates, and recirculation of sour liquids as a drilling medium.

Introduction

The subject well program was a horizontal extension of a new well drilled to the Crossfield formation in South Central Alberta. Coiled tubing was selected as the methodology due to its continuous underbalanced capabilities, as well as its suitability for sour well drilling and live well intervention without surface releases of reservoir gas.

Reservoir Description

The Crossfield Member of the Upper Devonian Period is a dolomite sequence exhibiting fenestral and intercrystalline microvuggy porosity ranging from 2 to 9.5% with an average of 4.4%. The Crossfield at this location has been dolomitized with some post dolomite porosity reduction by way of dolomite cements, bitumen, and anhydrite cements. The Crossfield is capped by hypersaline dolomites and massive anhydrites of the Upper Stettler.

Gas from the Crossfield Member is sour, with a H2S concentration of approximately 5% at the subject well. The formation is underpressured at approximately 12000 kPa (5.2 kPa/m) and therefore required significant N2 volumes to maintain underbalanced conditions.

Conventional Rig Preparations

The vertical and build sections were drilled with a conventional drilling rig and set at an inclination of 89.5 degrees and 2435 m Measured Depth (MD) or 2328 m True Vertical Depth (TVD). The well was cased to this depth with 139.7 mm casing run back to surface. The average rate of build of the build section was 10 degrees per 30 m.

Coiled Tubing Equipment

The coiled tubing drilling equipment consisted of a 73.0 mm coiled tubing reel and injector with coiled tubing hydraulic power unit with control cabin and accumulator. A coiled tubing hybrid mast unit and substructure complete with V-door, catwalk and pipe racks was used, with the mast suspending the injector and therefore alleviating the continuous need for a crane. Pumping equipment included a fluid pumper, nitrogen pumper and nitrogen bulk storage unit, and a chemical injection pump for corrosion inhibition.

The surface handling system included a 80 m3 test separator complete with choke manifold, sample catcher and flare stack, as well as 64 m upright tanks for oil and water storage.

The bottom hole assembly (BHA) as shown in Figure 1, consists of a drill bit, positive displacement mud motor with bent housing, non-magnetic dual float sub, non-magnetic collar complete with muleshoe and rubber inserts for vibrational resistance, downhole pressure sub, non-magnetic collars (as required for non-magnetic spacing), coiled tubing quick connect, bi-directional orienting tool and coiled tubing connector. The coil is fitted with an 11.9 mm multi conductor wireline for steering tool, gamma ray tool, and pressure sub operation, as well as two 9.5 mm capillary tubes for hydraulic operation of the orienting tool.

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