Impact of Brine Flow and Mixing in the Reservoir on Scale Control Risk Assessment and Subsurface Treatment Options: Case Histories

[+] Author and Article Information
Eric J. Mackay

Institute of Petroleum Engineering Riccarton,  Heriot-Watt University, Edinburgh, EH11 1QH, United Kingdomeric@pet.hw.ac.uk

Myles M. Jordan


J. Energy Resour. Technol 127(3), 201-213 (Apr 25, 2005) (13 pages) doi:10.1115/1.1944029 History: Received September 24, 2004; Revised April 25, 2005

As offshore production environments become ever more complex, particularly in deepwater regions, the risks associated with formation damage due to precipitation of inorganic scales may increase to the point that production by conventional waterflooding may cease to be viable. The ability to predict and control such formation damage can thus become critical to project success under such circumstances. The work described in this paper presents how the risk may be managed from early in the CAPEX phase of projects through to the OPEX phase by use of reservoir simulation tools to better understand the scaling potential in a reservoir and the possibilities for effective scale control. This process is illustrated by reference to a number of field examples where specific scaling problems have been identified, and the ability to implement effective scale management has been impacted by detailed fluid flow and brine-mixing calculations.

Copyright © 2005 by American Society of Mechanical Engineers
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Figure 5

Scale squeeze process

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Figure 6

Injection and production profiles used to identify whether adequate placement may be achieved at a variety of pump rates (here 1, 5, and 10barrelspermin (bpm)).

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Figure 7

Example of impact of changing sweep pattern. The model predicts that this mixing zone will remain static around well B4, potentially causing scale damage problems for a more extensive period than if well I3 had not begun injection.

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Figure 8

Streamline calculations for a mature water-flooded reservoir in the North Sea predict that one production well, in particular, in this field (circled) produces seawater injected by five separate injectors (I1–I5, with streamlines from each injector colored differently). This well has required some 200 scale-inhibitor squeeze treatments.

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Figure 9

Example of match between observed ion concentration data and model that accounts for brine mixing and scale precipitation deep within the reservoir

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Figure 10

Example of the changes in ion concentrations that can occur during processes, such as depressurization, where flow patterns established during water flooding are changed and other previously unmixed aquifer brines may start to be produced

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Figure 1

Examples of scale deposits

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Figure 2

Scale management strategy selection process

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Figure 3

Evidence of reservoir stripping of barium is a sandstone system, with sulphate concentrations affected principally by simple dilution

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Figure 4

Evidence of reservoir stripping of sulphate is a carbonate system, with barium concentrations affected principally by simple dilution, except at high seawater fractions when some sulphate breakthrough occurs

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Figure 19

In this well production is maintained during the five years for which inhibitor returns are displayed, and the barium concentrations rise in response to the treatments. Based on the analysis presented above, here the well exists within a local scaling environment.

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Figure 20

In this case, production is also maintained during the five years for which inhibitor returns are displayed, but the barium concentrations do not rise in response to the treatments. Here the mixing and precipitation must be taking place deeper within the reservoir away from the well.

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Figure 11

Calculations showed that an increase in overflush volume from 500to5000bbl would reduce the height of the initial inhibitor concentration spike during flow back. This spike had been causing process upsets in the facility due to stabilization of emulsions in the separator.

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Figure 12

When the increase in overflush volume from 500bbls (Squeeze No 1) to 5000bbls (Squeeze No 2) was carried out, the flowback spike was reduced and the squeeze life was also extended due to the improved placement

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Figure 13

Comparison of field return concentrations with previously calculated concentrations, and new ones based on reservoir simulation placement calculations show a marked improvement in accuracy

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Figure 14

Production and injection profiles along an 800m long horizontal well. Positive flow rates represent flow into the well bore, negative values represent flow from the well bore to the formation. Crossflow into the heel of the well may be overcome by increasing pump rate in this case to 5 or 10bpm.

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Figure 15

In the case of this well in the same field, even a 10bpm pump rate is not sufficient to overcome the crossflow effects that result from the well traversing the boundary between different fault blocks.

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Figure 16

Seawater distribution at end of production. Note seawater will displace through much of the aquifer before breaking through to the central production well.

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Figure 17

Barium concentration versus seawater fraction for all wells.

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Figure 18

Predicted inhibitor distribution using squeeze model and return concentrations for a vertical well. Protection is achieved up to 2 million barrels of water production. At this point, although well returns are considerable above MIC, one zone toward the heel of the well would be unprotected (red).




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