The risks and uncertainties associated with scale control in new field developments can often have a significant impact on the field economics. This can be especially true for marginal subsea fields producing from areas with high barium concentrations in their formation waters. Other aspects such as completion design, reservoir formation and heterogeneity also have a significant impact both on the severity of the scaling potential and also the ability to effectively treat production wells via conventional bullhead squeeze treatments. In this paper we describe an analysis that was conducted during the Pre-Front End Engineering and Design (FEED) stage of a field in the Norwegian sector of the North Sea. The field was expected to produce hydrocarbons from two subsea templates located 1.6km and 6.3km from a floating production system over a field life of ~ 10 years. Seawater injection was preferred over gas injection for pressure support owing to the higher predicted hydrocarbon recoveries. Of particular concern was the high barium concentration of > 700 ppm recorded from an appraisal well water sample, indicating a very severe barium sulphate scaling potential with raw sea water injection. For this field, in addition to the very severe potential barium sulphate scaling regime, a number of factors combined to present an exceptionally severe risk to the fields net present value. This related to: subsea completions with multiple production wells co-mingling at the wellheads (although dual production lines were incorporated into the design plan partially to assist in scale management); and long (500 – 700m) horizontal production wells and completion designs involving open hole screens served to increase the risks associated with scale formation and effective chemical placement. A range of alternative options were examined together with the associated risks and uncertainties. In summary, the most significant risks and uncertainties associated with the economic viability for seawater injection in this field related to:
Uncertainties associated with the initial formation water composition.
The ability to squeeze treat wells without inducing fines mobilization and plugging sand control screens as observed in analogue fields.
The ability to effectively place scale inhibitor treatments along the length of the horizontal producers by bullhead treatments rather than coil tubing operations.
The potential for changes in the base case field production scenario
This work therefore allowed the design team to make informed decisions at the pre-FEED stage in a field where scale control had a significant impact on the fields economic viability.
The field under consideration is currently in its pre-development stage with oil production planned to commence in 2008. For this development, several aspects combine to make effective scale management a significant issue for consideration during the field development plan. This relates primarily to the high barium content recorded in the water sample (713 ppm, full composition given in Table 1 with the Miller water chemistry for comparison) and the current design case for pressure support in fault Blocks B and C being through sea water injection. This gives a considerable risk of very severe barium sulphate scaling occurring. Other aspects such as well design and placement issues serve to increase the risk to production for the base case production scenario.
The field in question is located in the Norwegian sector of the North Sea. It consists of 3 reservoir formations: Garn, Ile & Tilje. The reservoir sands are well consolidated and have a low clay content. All 3 reservoirs are present within each of the 3 fault blocks A, B & C but different fluid contacts have been found within the formations in each of the fault blocks (Figure 1). Hydrocarbons in place are currently estimated at 305mstb oil, 1.9TCf gas and 62mmstb condensate. The base-case for field development assumes a floating production system (FPSO).