Changing the Injection Water on the Blane Field, North Sea: A Novel Approach to Predicting the Effect on the Produced Water BaSO4 Scaling Risk
- Ross Andrew McCartney (Geoscience Ltd.) | Andreas Burgos (Talisman Energy Norway) | Eyvind Sorhaug (Talisman Energy Norway)
- Document ID
- Society of Petroleum Engineers
- SPE International Conference on Oilfield Scale, 26-27 May, Aberdeen, UK
- Publication Date
- Document Type
- Conference Paper
- 2010. Society of Petroleum Engineers
- 4.1.5 Processing Equipment, 5.1.3 Sedimentology, 2.4.3 Sand/Solids Control, 5.6.5 Tracers, 1.14 Casing and Cementing, 7.2.1 Risk, Uncertainty and Risk Assessment, 5.2 Reservoir Fluid Dynamics, 4.2 Pipelines, Flowlines and Risers, 6.5.2 Water use, produced water discharge and disposal, 3.1.6 Gas Lift, 5.5.8 History Matching, 4.3.4 Scale, 5.5 Reservoir Simulation, 2.2.2 Perforating
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The Blane Field, North Sea, has one injection well and two production wells and is tied back to the Ula Field platform. The original scaling risk assessment was based on injection of platform produced water (PW) with minor seawater (SW) (~90:10 PW:SW). However, after injection of 25:75 PW:SW for only 6 weeks, a change in operational circumstances on the Ula Field meant that only 10:90 PW:SW injection water could be supplied for the next 18 months. There was a risk that this might result in unmanageable BaSO4 scaling conditions in the production wells but the alternative would be to cease injection, leading to reservoir pressure decline and loss of oil revenues.
The need for a rapid decision negated the use of reactive transport reservoir simulations to predict the future BaSO4 scaling risk under the new injection scenario so a novel, alternative approach was adopted. A history matched ECLIPSE model served as the basis for predicting the types of water entering the production wells over time and their rates. A 1-D reactive transport model was then used to predict the Cl, Ba and SO4 composition of these waters after accounting for the effects of reservoir reactions. These results were integrated in a spreadsheet to provide predictions of Cl, Ba and SO4 concentrations in the produced water from each well over time.
The results for future injection water scenarios indicated that the scaling risk would increase over time in the wells but, due to deposition of BaSO4 and CaSO4 in the reservoir, the BaSO4 scaling risk would be manageable even allowing for uncertainties associated with this approach.
Based on these results, and those of associated studies, a decision was made to continue water injection resulting in avoidance of loss in oil revenues. This novel scaling prediction approach may be useful on other fields where reactive transport reservoir simulations may not be possible.
The Blane Field is a subsea field located on the UK/Norway median line in Blocks UKCS 30/3a and NOCS N1/2. It has two cased, horizontal production wells (wells A and B) and one sub-vertical injection well (well C), each tied-back 34km to the Ula Field platform (Fig. 1). The reservoir is located in the Palaeocene Forties Sandstone Member which was deposited within in an unconfined, relatively distal, dominantly sheet-like turbidite fan system. The mineralogy of the reservoir sandstone is shown in Table 1. Calcite is occasionally present in cemented zones in the reservoir where it can represent up to 22% by volume of the zone, often accompanied by elevated (but subordinate) amounts of siderite (up to 9% by volume). The sedimentological sequence is ‘layer cake' where high density turbidites in the form of thick bedded submarine sand lobes represent the more permeable productive reservoir layers (porosity 18-20%) and these are interbedded with mudstones and shales. Whilst lateral communication in the reservoir appears to be good, vertical communication is poor with reservoir permeability varying between 0.05 and 300mD. The production wells have ~1220m perforated sections designed to intersect multiple layers and are completed with gas lift facilities to aid production at high water cuts. The injection well was perforated to allow injection into the oil-leg and top of the water-leg. Although an aquifer is present, the restricted vertical communication means that aquifer encroachment during production is expected to occur from the flanks rather than from below the reservoir.
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