Redevelopment of the Froy Field: Selection of the Injection Water
- Terje Ostvold (Norwegian U. of Science & Tech) | Eric James Mackay (Heriot Watt University) | Ross Andrew McCartney (Geoscience Ltd.) | Ian Richard Davis (Premier Oil Plc) | Egil Aune (Det norske oljeselskap ASA)
- 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
- 4.5 Offshore Facilities and Subsea Systems, 4.3 Flow Assurance, 2.2.2 Perforating, 4.1.2 Separation and Treating, 5.5 Reservoir Simulation, 4.2.3 Materials and Corrosion, 5.5.8 History Matching, 5.2 Reservoir Fluid Dynamics, 3.1.2 Electric Submersible Pumps, 1.6 Drilling Operations, 4.3.4 Scale, 5.1.2 Faults and Fracture Characterisation, 5.6.5 Tracers, 3.1.6 Gas Lift, 1.8 Formation Damage
- 4 in the last 30 days
- 349 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 9.50|
|SPE Non-Member Price:||USD 28.00|
The Frøy Field, Norwegian North Sea, was closed down in March 2001 but there are plans to re-develop it. Previously, seawater (SW) injection caused persistent BaSO4 scaling problems in the production wells, so this study was undertaken to determine whether there would be any benefit in using Utsira formation water (UW; low SO4) as opposed to seawater as the injection water.
Thermodynamic calculations indicated that whether SW or UW is injected, the principle scaling risks are from BaSO4 and CaCO3 deposition. Being more difficult to treat, the study focused on the BaSO4 risk. ECLIPSE modelling was used to estimate FW:SW:UW ratios over time for each new well assuming (a) SW injection and (b) UW injection. The results indicated that in each case, initial peaks in BaSO4 Saturation Ratio (SRBaSO4) would occur after ~1.5-2.5 years before declining. The peaks reflect co-production of seawater already present in the reservoir and formation water. The subsequent decline in SRBaSO4 reflects (a) decrease in the FW:SW ratio (SW injection case) and (b) dilution of produced Ba and SO4 as the produced UW fraction increases (UW injection case).
An evaluation of produced water analyses from Frøy and from analogue fields indicated that reservoir reactions will occur at Frøy whether SW or UW are injected but significant BaSO4 would only occur in the presence of seawater. Two methods were used to quantify SRBaSO4 in the new production wells over time after accounting for BaSO4 precipitation in the reservoir.
In the first, the amount of BaSO4 deposition in the reservoir was predicted from past produced water analyses and applied to the ECLIPSE results. The second involved the use of STARS to model the effect of reservoir reactions on the scaling potential. There were some differences in the results related to the amount of mixing predicted to be occurring in the reservoir, but contrary to initial expectations, both methods indicated that UW injection would not be beneficial.
Based on these results, seawater has been selected as the injection water resulting in significant OPEX and CAPEX cost savings.
The Frøy Field (Fig. 1) is a closed down and relinquished oil field located in the northern part of Block 25/5 and the southernmost part of Block 25/2. Frøy was discovered in 1987 with well 25/5-1 and was originally developed by Elf with a wellhead platform tied back to the Frigg field. Production started in 1995. However, due to a combination of low oil prices, low production and BaSO4 scale problems associated with seawater (SW) injection, Elf decided to cease production in March 2001. The wellhead platform was demobilized in the summer of 2002 (Fig. 2).
Since then, oil prices have risen and new and improved technologies have been developed for BaSO4 scale control, including desulphation of seawater, improved squeeze treatment implementation, and more efficient BaSO4 scale dissolvers. As a result, Det norske oljeselskap ASA (Det norske) and Premier Oil Norge AS plan to re-develop the field. As part of the re-development, there was an option to choose either SW or Utsira formation water (UW; low SO4 content, see Table 1) as the injection water for pressure support. Although intuitively, injection of UW as opposed to SW would be expected to reduce the BaSO4 scaling risk, the cost of this choice would be significant because it would require two wells to be drilled into the Utsira Formation and each to be fitted with an electric submersible pump (ESP) to provide the injection water for the field. Before deciding on the injection water to use on the re-development, it was first necessary to predict the future production wells scaling risks given (a) SW and (b) UW injection and then to determine whether the anticipated additional costs of mitigation
for SW injection would be more or less than the costs associated with UW injection (including Utsira Formation wells, pumps, additional OPEX, scale mitigation costs).
|File Size||2 MB||Number of Pages||23|