|STARLING 3RD WELL: AN INTEGRATED STUDY UTILISING THIN BED ANALYSIS AND MODELLING|
|Field Developments and Case Studies|
1Brunei Shell Petroleum Co Sdn Bhd, 2Shell UK Limited
The planned third well into the Starling field is an example of unlocking further recovery from a distal turbidite field with the aid of improved geological understanding of Forties turbidite reservoir, thin bed petrophysical analysis, geophysical understanding, static and dynamic scenario based modelling approach and dynamic data such as pressures and produced volumes.
The Starling Field is a gas condensate field and sits within blocks 29/3a on the south-western edge of the Palaeocene Forties Fan (Figure 1), discovered in 1978; the field is comprised of the distal Forties Sandstone Member turbidites trapped within a faulted 4-way dip closure above a non–piercing salt diapir. The structure is segmented by two large NW-SE trending normal faults that define a crestal graben area (Figure 2 and 3).
The Starling field was developed in 2007 by two deviated gas wells targeting the crest of the eastern and western fault blocks (Figure 4). The oil rim was deemed to be uneconomic given its thickness (less than 55ft tvd). The field came on stream with wells producing in excess of 150mMscf/d. Over the last few years the field’s production performance, combined with lack of water production has shown a need to elevate in-place gas volume in the field.
The key uncertainties post development include: aquifer strength, structural configuration within the graben and reservoir connectivity. A review of the petrophysical data and core supported the existence of thin bedded heterolithic sand facies which had previously been neglected and would contribute significantly to gas volumes and pressure support, and thereby unlock potential for incremental reserves targeted by a third well within the crestal graben area of the field.
A scenario based static and dynamic modelling approach was undertaken to evaluate the benefit of a third well. The approach utilised the revised concepts of lobes within distal turbidite to vary net to gross trends in the reservoir, use of thin bed petrophysical logs and different structural configurations to understand gross rock volume within the graben uncertainty. Interestingly the gross rock volume scenarios illustrated little variation in incremental gas volumes – but rather the aquifer strength, and fault extent and baffling nature and vertical connectivity impacted most on incremental volumes.
The third well was planned to intersect the crestal graben, between the two large structural faults, maintaining a standoff from the oil water contact and to gain maximum reservoir footage to increase productivity of the well. The well was drilled earlier this year.
Figure 3 Seismic cross section through the Starling Field showing the flank producers (29/3a-S1 and 29/3a-S2) and the third well drilled in 2010 (29/3a-S3) targeting the central graben of the field.
|FORTIES FAN SYSTEM|
The Palaeocene Forties Sandstone Member represents one of the most prolific hydrocarbon reservoirs in the UK Central North Sea, with large fields such as Nelson and Forties located in proximal part of the turbidite fan system characterised by channelized sequences and strong aquifer drive. There are a number of fields which have over the last 5 years come on production targeting the more distal part of the Forties fan system. Starling is such an example of a distally located field. The rock properties at Starling are consistently lower net to gross, porosity and permeability compared to the proximal channelized reservoirs. Key to successful development of the distal Forties reservoirs is understanding the depositional model, reservoir architecture and net to gross character – essential to optimise well placement and hydrocarbon volumes.
The original Field development plan for Starling allowed space for a contingent third well, after the initial drilling of the first two inclined gas producers. During 2009 upon monitoring of the 2 years of production performance, there was shown to be a volumetric gap between that produced to date and expected ultimate recovery versus the in-place gas volume. A project to update the static model (for all new available data including the initial interference well test) and to generate a dynamic model was fast-tracked to allow a business decision in 6 months to be taken upon drilling of the third well.
The modeling approach was to generate a number of static and dynamic scenarios to capture the key uncertainties in the field including aquifer drive, fault properties, facies distribution and rock properties within the crestal graben area of the field. The models were built primarily to understand the quality of the intra graben area of the field, linked to the tectono-stratigraphic history of the salt and Forties sandstone deposition. One end member model based on seismic uncertainty within the graben, captured potential thinning and reduced properties in the graben area, reflecting potential sea floor topography at the time of the Forties deposition. The other end member captured no sea floor bathymetry at the time of deposition and therefore reservoir thickness and properties would be similar to the flanks of the field. Alternative models also captured the possibility of rock properties diminishing across the field to the south west reflecting the distilling nature of the fan system as the fan reaches the margins.
A novel approach in the Forties Sandstone Member was the application of thin bed analysis. Thin bed analysis works well in formations which are comprised of finely laminated shale and sand sequences, that typified by distal Forties turbidites, as seen in the heterolithic facies within Starling (Figure 5 and Figure 6). This approach allow laminations of sand or shale which are below log resolution to be captured and therefore distinguish net and non-net intervals in packages which traditional methods would suggest is all net or all non-net. This affect showed that hydrocarbon saturations predicted had previously been too low, suppressed by low resistivity of the shale laminae and the erroneously low porosities which also impacted on permeability. These logs were utilized within the static model to generate models which accurately represented the net to gross and captured the permeability streaks and saturation.
The third well was drilled in 2010, and came in on the base case prognosis, the well did not TD within the Lista Formation and therefore a true thickness could not be determined, however average properties were similar to the flank producers, albeit with a larger proportion of calcite cemented zones. The results support the depositional model of no sea floor bathymetry at the time of deposition.
The third well was matured based on a variety of integrated data from a variety of disciplines. The well was matured within 9 months and within a year was drilled, with hook up planned for end 2010. Understanding the distal Forties reservoir is essential to allow for future exploration, appraisal, field development and infill well planning. The results of the third well show that the effects of including heterogeneous facies, which had previous been ignored in both volumetrics and pressure support, can add significant value.
We thank the Shell Exploration and Production UK Ltd and Esso Exploration and Production UK Ltd management for the permission to publish the Starling S3 well results and this paper.