Scale Cause in the Smorbukk Field
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 94578, "Why Didn't All the Wells at Smorbukk Scale In?," by F. Vassenden, SPE, Statoil; O. Gustavsen, SINTEF Petroleum Research; and F.M. Nielsen, SPE, M. Rian, and A.J. Haldoupis, SPE, Statoil, prepared for the 2005 SPE International Symposium on Oilfield Scale, Aberdeen, 11–12 May.

Two of 19 wells were lost to carbonate scale in a high-pressure/high-temperature (HP/HT) gas/condensate field with commingled production. Tubing plugging by scale was identified as the problem. Plugging was caused by a 6 to 8°C increase in upper-zone water temperature when commingled with hydrocarbons from deeper formations.

Introduction

Smorbukk is a HP/HT Norwegian Sea gas/condensate field developed with commingled production from subsea wells. The operator expected severe calcite (CaCO3) scale problems. Five years' production experience in 19 wells has proved this expectation wrong. The dramatic exceptions were two wells that had to be shut in because of severe and sudden scale plugging after only 7 to 10 months of production.

Scale is a solid accumulation of inorganic substances that reduces flow capacity and can grow on tubing walls, in surface equipment, in perforation tunnels, or in the formation pore system. Carbonate scale can form if water becomes super-saturated with CaCO3. Sulfate and sulfide scales are insignificant in Smorbukk.

CaCO3-scale formation depends on the concentration of carbon and hydrogen compounds in the water and the CO2 pressure in the gas phase. For a tidal reservoir such as Smorbukk, marine fossils are a source of solid CaCO3 that equilibrates with water and gas over geological time. Because the formation water is saturated before production begins, only small changes in pressure and temperature are required to cause the solution to become supersaturated and cause CaCO3 precipitation.

A full understanding of CaCO3-scale formation in oil and gas reservoirs and wells requires focus not only on the carbonate ionic chemistry but also on the coupling between ionic chemistry and the flow process in the reservoir and tubing. This coupling is a result of water evaporation and CO2 loss that results from flow-induced pressure and temperature changes.

Commercial software tools for pressure/volume/temperature and scale-chemistry modeling were used together with simple radial-flow Darcy models to describe carbonate scaling in commingled gas/condensate Smorbukk wells. In the interplay of physical effects controlling scale precipitation, temperature-variation modeling has proved particularly important in understanding the observed behavior at Smorbukk.

Field Observations

Reservoir Description. The Smorbukk field is a part of the Asgard development, together with the Smorbukk Sor and Midgard fields. Asgard is developed with subsea wells only and began production in 1999. The Smorbukk field consists of five independent reservoirs (Garn, Ile, Tofte, Tilje, and Åre) containing gas/condensate and light oil. Most wells produce commingled from several of the reservoirs. Initial pressures were approximately 500 bar, and initial temperatures ranged from 145 to 165°C. Initial gas/oil ratios (GORs) ranged from 300 m3/m3 in the oil leg of Tilje to 1800 m3/m3 in the Ile layers. The combined effects of depressurization and gas breakthrough have caused the average producing GOR to increase from 700 to 1900 m3/m3. The formation waters differ significantly, with salinity and hardness increasing with depth, from 35,000 ppm total dissolved solids (TDS) [calcium (Ca)/sodium (Na)=0.03] in Garn to 165 000 ppm TDS (Ca/Na=0.24) in Åre.