This paper outlines the selection methods for the inhibitor chemical deployed and present the chemical returns profile from the 3 wells treated (some treatments lasting > 450 days) along with monitoring methods utilised to confirm scale control in the wells treated. The paper also explores in detail the issues associated with inhibitor squeeze vs. inhibitor stimulation deployment in deepwater, subsea fields, many of which are currently being developed in the Campos basin, Gulf of Mexico and West Africa, and is a good example of best-practice sharing from another oil basin.
The fields are located offshore in Angola in approximately 400 meters water depth. The fields are developed with both dry tree wells which are located on the Compliant Tower and subsea wells that are connected to the Compliant Tower via one of three subsea production manifolds. All of the fields are under waterflood. Gas-lift is available for artificial lift. A total of 10 dry tree and 13 subsea production wells have been completed thus far and the development program is still underway. All but two of the producers are completed with cased-hole frac packs. Some wells have multiple, or stacked, frac packs. The field was started up in January 2006. The Basis of design for managing barium sulfate scale was to scale squeeze the wells at seawater breakthrough. In the 4th quarter of 2007, some wells incurred seawater breakthrough much earlier than forecast which led to barium sulfate scale formation and significant production impairment. An ensuing proactive scale management program of both scale squeezes and incorporation of scale inhibitor in the initial completions has resulted in no further scaling events. Reservoir description: The reservoirs are composed of high quality turbidite sands deposited in a middle bathyal slope valley/incised canyon environment. Reservoir quality sands are found as vertically stacked and nested channel complexes that both erode and aggrade preexisting sediments. The turbidite complexes are typically 500-2000m wide, 10-60m thick, and composed of intercutting sand rich turbidite channels, shale-rich mudflows, debris flows and slumps.
Details of scale formation mechanisms are provided elsewhere1-5, as are the reasons why they pose problems in the production well, near-well areas and surface facilities6-8, much less commonly in injection wells9, and never deep within the reservoir10-13. The various techniques that may be adopted to meet the challenges of scale control may be divided into four principal categories, as follows: 1) Selection of injection fluid source 2) Chemical inhibition 3) Chemical/mechanical remediation 4) Flow conformance The range of formation water chemistry present within the four fields under study is presented in Table 1. The intention is to seawater flood all five fields to improve hydrocarbon recovery. It is clear that the range of barium ion concentrations is quite wide and this will result in differing mass of barium sulfate scale and different supersaturation values during seawater breakthrough. Figure 1 shows the mass of barium sulfate with rising seawater fraction in the produced waters for the four fields.
