B41oa oil and Gas Processing Section a flow Assurance Heriot-Watt University

2.4.2 Influence of Well Type on Scale Problems and Prevention 
A comparison between the types of production well in terms of scaling severity 
and methods of treatment is best presented by comparing and contrasting 
scale formation scenarios in vertical and horizontal wells for the same brine 
type as discussed below.
The type of producer well used has implications for the type of scale which 
might occur (due to draw down, injection/formation brine mixing etc.) and the 
ease of application of the squeeze treatment. 
Conventional Vertical or Deviated wells and Horizontal and High 
Angle Wells 
A vertical well would have a larger draw down in the near wellbore region and 
might result in more downhole carbonate formation whereas, in a horizontal 
well, the drawdown is much lower which has the effect of moving the 
carbonate scaling problem further uphole. 
For vertical wells, the application of squeeze treatments is a well-established 
technology. In a horizontal well, the draw down will be less marked and the 
pressure of the fluids may be high enough to prevent scale formation (until 
closer to the wellhead) – as a result, simple acid washing or continuous 
injection of scale inhibitor may be applied above the packer. 
If pressure in the horizontal section of the well fell significantly below the CO
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bubble point, then scale would form and a squeeze treatment would have to 
be implemented, possibly using coiled tubing. 
Subsea wells 
Subsea wells, whether they are completed as vertical or low-angle (horizontal) 
type wells, have certain operation problems associated with scale control and 
removal. For squeezing subsea developments, the principal problem is not 
with the well types but with the natures of the wellheads themselves. These 
wellheads may be quite remote on the sea floor and may be located at 
distances from 1 to 35 km from the mother platform. 

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TOPIC 2: Oilfield Scale 
 
 
 
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If there is a dedicated service line, then scale inhibitor may be applied from the 
installation to which the wells are tied back. Bullhead treatments can also be 
performed down the production lines and this may be achieved at higher pump 
rates (5 to 7 bbls per min.) than may be achieved through typical service lines 
(1 to 3 bbls per min.). However, this is conditional on the fact that each well 
has its own production lines and that there is not commingled flow from 
separate wells unless these wells can be shut-in individually. 
Scale removal for subsea wells using scale dissolver chemicals will encounter 
the same problems as the application of squeeze treatments. If scale removal 
is to be carried out by physical means, using coiled tubing and milling 
equipment, this would normally involves the use of a DSV with the higher costs 
and longer down time that this type of operation would involve. Clearly careful 
analysis is required and the following should be addressed: 
a) Assess and risk the scaling problem very carefully in advance. 
b) Plan to have sufficient service lines along the umbilical; this provides 
some flexibility for intervention with scale inhibitors or dissolvers. 
c) Carefully evaluate the downside of having to intervene with 
remediation; for example, by bringing in a DSV if disaster strikes.