The South Magnus Satellite oil field was discovered in February 1995 with oil and gas reserves estimated to be 26 mmstboe in a Brent Group reservoir.
This development is distinctive in that the field was developed without any well test or production data. The resulting reservoir and production uncertainties were accommodated within the design.
The field was developed as a subsea horizontal production well and a subsea water injection well connected to the Magnus Platform via a 7-9 km subsea tieback.
A notable achievement for BP and the Magnus Partners is that production started (18,000 barrels of oil a day) in May 1996 only 472 days after discovery making this the fastest development of a BP operated oil field.
After 11 years of plateau oil production, the Magnus Main Field (Fig. 1) entered the decline phase at the end of 1994, with the onset of water breakthrough in several key producing wells. This resulted in a demand to find new production to fill the production facilities and make use of the available infrastructure. An extensive mainfield infill drilling campaign was in progress to replace production. One satellite, North West Magnus, had already been discovered and was under appraisal. The South Magnus satellite (Fig. 1), was discovered in February 1995. The field was developed in a rapid timescale with only limited reservoir data. First production was delivered in May 1996, 472 days after discovery. This paper describes how this was achieved.
The discovery well, 211/12a-19, encountered a 56 metre gross oil column of good quality Brent Sands, at a depth of 3215 mtvdss. The well was not tested on discovery, as the drilling rig was needed to continue the Magnus main field development programme. The reservoir had been fully cored and wireline logged, and several RFT oil samples were obtained. It was believed that this data, plus information from other Brent fields and discoveries, would be sufficient to allow characterisation of the reservoir for development purposes.
Lack of precise fluid data turned out to be a key uncertainty after analysis showed the RFT oil samples to be contaminated with drilling mud. Table 1 shows the range of estimated values for the key fluid property data required in the reservoir simulation model. The saturation pressure, or bubble point, of the oil was estimated to be nearly 5800 psia, only 1400 psia below the initial reservoir pressure of 7200 psia. The most likely gas-oil ratio (GOR) was estimated to be 1522 scf/stb, significantly higher than the Magnus Main Field GOR of approximately 800 scf/stb. The lack of a reliable production fluid sample also prevented accurate analysis of the propensity for hydrate, wax and scale formation.
With no production test data, future well performance had to be estimated from wireline log and core data. Figure 2 shows a summary of the log data and reservoir stratigraphy and Table 2 summarises the formation properties. An oil-water contact (OWC) at 3271 mTVDss was penetrated within the thinner, poorer quality sands of the upper Rannoch Formation. Core air permeabilities, arithmetically averaged, were good (Table 2) at least in the better quality Tarbert and Etive Formations, with values ranging from 270 to 480 mD. In the lower Etive Formation several high permeability plugs >1 Darcy) were encountered, raising concerns over the potential for early water breakthrough in this unit. Analysis of an extensive well test dataset from Magnus resulted in a core-to-test permeability correction factor of 0.5. This was applied to the core averages to estimate well productivity indices (PI's). The notional well PI for the discovery well was estimated to be about 25 bbl/d/psi.
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