The Grane field came on stream in 2003 with a planned production period of 25 years.
Presently, Grane is governed by 16 out of 31 planned oil producers. All the producers are horizontal and individually controlled. A total of 11 multilateral producers are planned in the ongoing drilling program.
This paper highlights the challenges related to developing a field with high density/high viscosity oil and an alternating sand/shale formation.
Historically, recovery factors have been low in heavy oil fields. The fluid properties promote an early breakthrough of gas and water. The drainage strategy at Grane has the primary objective to produce the field by stable displacement of the oil towards the horizontal producers with minimal water and gas coning. The primary drive mechanism is gas injection at the crest of the reservoir. At a later stage water injection will commence to complete the drainage. Well placement and well length are important factors to increase recovery.
Most of the wells at Grane penetrate an alternating sand/shale formation with low strength. The low formation integrity has resulted in serious challenges with respect to drilling and completion as a result of formation instability and loss of drilling fluid. This in turn has led to difficulties displacing to completion fluid, and reduced productivity due to incomplete cleanup of the wells and subsequent plugging of screens. This paper will describe the experienced challenges to drill, complete and produce the platform-drilled wells, and the lessons learned so far.
Several of the oil producers at Grane have experienced sand control failure due to erosion and sand screen damage during installation. The paper will highlight the sand management strategy, which aims to optimise oil production without jeopardizing safety.
Grane is located in the North Sea, 180 kilometers west of Norway's western coastline, Figure 1.
Figure 1. Planned and existing wells at Grane on base Heimdal Formation map. (available in fullpaper)
The Grane platform incorporates processing, drilling and quartering (PDQ) facilities. The total area of the reservoir covers 27 km2 and the average reservoir thickness is approx. 50 meters. The expected reserves are estimated to 120 MSm3 (755 million bbl). The oil bearing Heimdal sandstone is a Turbidite of Paleocene age with a permeability of 5-10 Darcy, a kv/kh close to unity and a porosity of approx. 33%. The shale formation partly surrounding the reservoir is brittle and chemically reactive (Smectite rich). The Grane oil is biodegraded, with an oil density of 940 kg/Sm3 (19° API), oil viscosity of 12 cP, and a Rs of 15 Sm3/Sm3. The Grane fluid is undersaturated, with no initial gas cap in the reservoir (bubble point 50-60 bar).
The high mobility of gas and water compared to the viscous Grane oil dictates measures to prevent coning. The choice of recovery mechanism between water and gas injection is thereby determined by the difference in viscosity and gravity of water and gas with respect to the oil, and the kv/kh ratio.
