Magnus Scale Inhibitor Squeeze Treatments - A Case History (1996)

Abstract The Magnus oilfield lies approximately 160 km NE of the Shetland Islands in the UK sector of North Sea. Areal sweep and pressure support is achieved via sea water injection into the reservoir. Due to the layered nature of the reservoir, formation water and sea water are often co-produced and are commingled in the production wellbore. This has often resulted in downhole deposition of barium sulphate scale and an appreciable reduction in well productivity. A combination of scale inhibitor chemistry and its deployment into the reservoir using novel diverting agents has significantly reduced the problems and are described in detail in this paper. Introduction The Magnus field was discovered by BP in 1974 and is located within blocks 211/12a and 211/7a of the UKCS, lying about 160 km north-east of the Shetland Islands in a water depth of 186m. The field contains three productive horizons with an estimated 1650 mmstb of oil initially in place. These are the Magnus Sandstone Member (MSM), the underlying Lower Kimmeridge Clay Formation (LKCF) and the overlying Turonian Reworked Sandstone (TRS). The MSM lies at a depth of approximately 3000m subsea and constitutes the major reservoir interval in the Magnus field, although the LKCF is also important. The oil in the Magnus field was sourced from shales of the Kimmeridge Clay Formation and has an a API gravity of 390 Magnus is the most northerly producing field in the UKCS. Oil production commenced in August 1983 and, to date, more than 593 million barrels have been produced. Reservoir Quality. The top and base of the MSM are well defined, and the reservoir itself can be broken down into a series of sandstone units. These sandstone units, or 'lobes', are separated by mudstone beds, ranging from 1-20 m in thickness, which act as vertical permeability barriers. Different amounts of pressure depletion has occurred in individual lobes, resulting in significant lobal pressure differences (typical spread in a single well is 400 psi). The maximum net pay is 108 m and the average porosity is 21%. Typical MSM permeability is in the range 200-500 mD, although higher permeabilities are observed in the crest of the field. High porosity MSM, and particularly LKCF, sands have low compressive strengths, and are prone to produce sand to the surface, especially in association with high water cuts. Petrographic Description. The MSM and LKCF reservoirs are composed of late Jurassic submarine fan sandstones. These sandstones are fine to medium grained, grading to very fine grained and coarse grained to conglomeratic. They are subrounded to angular, sub-arkosic grainstones with a low detrital clay content. Monocrystalline quartz is the major detrital constituent. Potassium feldspar may be present in significant quantities and polycrystalline quartz, rock fragments, mica and glauconite are also important detrital components. Reservoir Pressure. Reservoir pressure is supported by seawater injection, with an injection rate of about 250 mbd. To date, offtake from the field has significantly exceeded the volume of water injected, consequently reservoir pressure has fallen from the original 6650 psi at datum depth, to around 3000 psi at datum depth in the crest of the field. The current water injection rate has arrested the fall in reservoir pressure, but there is a substantial pressure gradient across the field, from 7500 psi at the base of certain injectors to 2750 psi at the base of certain crestal producers. Currently, post scale inhibitor squeeze treatment, most wells will not flow naturally if they have been displaced to a full column of seawater. Water Chemistry. Some variation in Magnus formation water chemistry has been observed in different wells and it is possible that this is due to different water compositions in individual lobes. Typically, the salinity of Magnus formation water is similar to sea water, and the barium concentration, prior to seawater breakthrough, is in the range 90–220 mg/l. The maximum mass of scale is predicted to be deposited at 2% v/v seawater, however the maximum scaling index is predicted to occur at about 50% v/v seawater. Typical water analyses from several wells are presented in Table 1. P. 403