This paper examines the impact on scale squeeze life of water/scale inhibitor re-distribution during extended shut in periods for bullhead scale treatment in a high permeability reservoir. The Eclipse 100 reservoir simulator was used to examine water re-distribution (gravity slumping) during extended shut in periods for horizontal wells in the Draugen reservoir. The work shows that in certain cases involving long horizontal wells (>1000 ft) in high permeability sands (3–5D) with low vertical/horizontal permeability contrasts, extensive water re-distribution can occur during extended shut-in periods owing to density differences between the injected (aqueous) fluids and the formation fluids. Full field reservoir modelling was then carried out to identify candidate wells within the Draugen field which offered greatest potential for improved chemical placement based on these findings. Near wellbore placement modelling was then conducted to optimize squeeze return lifetimes using gravity re-distribution to improve placement deeper (lower) in the reservoir vs. convention scale squeeze design methods such as larger overflush.

The work demonstrates that for selected cases, gravity re-distribution can be used to improve placement deeper (lower) in the near wellbore area. The modeling work also identifies limitations with the simple "radial" near wellbore models for such cases and identifies those wells in the Draugen field which would benefit from such treatments. An added benefit for low water cut wells was the potential to minimise post treatment lift issues associated with the injection of high volumes of water into the near wellbore for aqueous squeeze treatments, by allowing the injected aqueous treatment to sink away from the near wellbore area. New field treatments have therefore been designed based on the work described. The economic impact of the extended shut in times vs. improved squeeze treatments and deferred oil costs for this field case are also discussed following the field applications.


Scale control in horizontal wells is recognised as a particular technical and economic challenge, especially if effective chemical placement cannot be achieved through conventional bullhead squeeze treatments.1–6 In addition to the challenges associated with overcoming permeability contrasts in reservoir formations fluid re-distribution due to reservoir crossflow effects can often reduce the potential to effectively place chemical into certain zones of a production well such that pump rates and / or viscosified fluids may be required in order to effect placement along the length of the well during the chemical injection stage. Once injected however further fluid re-distribution can occur which in many cases may have a detrimental impact on inhibitor retention and inhibitor placement as the bulk of the chemical treatment is removed from certain (higher pressure) zones and re-distributed to other (lower pressure) zones7. Although such fluid re-distribution is normally associated with reservoir crossflow, gravity effects are also known to cause fluid distribution and will be examined further in this paper.

Gravity Slumping: For conventional aqueous chemical treatments in horizontal wells, gravity slumping due to density differences between the different fluids in the near wellbore area (lower density oil vs. higher density injected aqueous fluids) can lead to significant re-distribution during extended shut-in periods, especially when treatments are conducted at relatively low water cuts. Thus, fluid re-distribution may be expected to allow the inhibitor to contact more rock surface, be placed deeper (lower) in the formation and therefore result in improved squeeze lifetimes. This paper therefore describes a detailed evaluation of the impact of gravity slumping on the potential to re-distribute fluids in the near wellbore area and the impact this would have on scale inhibitor return concentrations.

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