Predicting the location of barium sulfate scale formation in production systems
- Ian Ralph Collins (BP Exploration)
- Document ID
- Society of Petroleum Engineers
- SPE International Symposium on Oilfield Scale, 11-12 May, Aberdeen, United Kingdom
- Publication Date
- Document Type
- Conference Paper
- 2005. Society of Petroleum Engineers
- 4.2.3 Materials and Corrosion, 5.2 Reservoir Fluid Dynamics, 1.8 Formation Damage, 4.3.1 Hydrates, 2.2.2 Perforating, 4.3.4 Scale, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.2 Pipelines, Flowlines and Risers
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Mineral scale formation and deposition on downhole and surface equipment is a major source of cost and reduced production to the oil industry.This paper describes a novel semi-quantitative kinetic approach to predicting the location of barium sulfate formation and deposition.The key conclusions of this work are:
There is probably negligible formation damage arising from barium sulfate deposition in the near well bore region.
There are three kinds of barium sulfate precipitation in the well depending upon the scaling tendency (saturation ratio) in the produced brine (it is assumed that the higher saturation ratio values for barite at the bottom of the well is a consequence of mixing of high sulfate brine from sea water breakthrough with high barium brine formation water). The location of the scale formation can be predicted from knowledge of the nucleation induction time coupled with mass transfer arguments. The equations describing these have been developed in this paper and applied to some general illustrative cases demonstrating the applicability of the approach. In particular, a method has been developed for predicting the location of scale formation and deposition at low saturation ratios such as developed when sulfate-removal is utilized as a barite scale control technology.
Mineral scale formation and deposition on downhole and surface equipment is a major source of cost and reduce production to the oil industry.Solid scale formation mainly results from changes in physical-chemical properties of fluids (i.e., pH, pCO, T and P) during production or from chemical incompatibility between injected water and formation water. However, prediction remains notoriously difficult, mainly owing to the complexity of modeling both thermodynamic and kinetic behaviour of carbonate and sulfate systems in high salinity solutions at high temperatures and pressure.
In simplistic terms, scaling in a well or in a flowline can be imagined as the following process:Brine enters the pipe in a supersaturated state, as it flows along the pipe nucleation and growth occurs creating both crystals in the bulk of the solution, which increase in size in the direction of flow, and crystals which have grown on the pipe walls.Previous studies have focused on investigating surface nucleation and growth on metal surfaces and understanding the relationship between heterogeneous nucleation and growth on pipeline surfaces (surface growth) rather than homogeneous nucleation and growth from the bulk solution. The trend towards understanding heterogeneous nucleation and growth has gained interest because surface growth and/or scale adhesion is recognised to be as serious an issue as homogeneous "bulk" precipitation, as conventionally e xamined in industry standard bulk "jar" type tests for the assessment of scale inhibitor performance [1-3]. The concept is to examine the amount of barium sulfate nucleation and growth occurring on the metal surfaces within the pipelines and reservoir equipment and investigate how it can be reduced either by chemical additives or process design. This is in contrast to focusing on the bulk (homogeneous) precipitation, which, on its own, may be expected to have a less significant impact on production. Numerous techniques and theories have been proposed to measure and predict rate of crystal growth and to a lesser extent, rate of nucleation. Knowledge of precipitation kinetics (nucleation and crystal growth) is required in order to predict scale formation and the correct use of inhibitors in scale control1. Crystal growth and nucleation rates can depend on a number of factors including supersaturation, hydrodynamic conditions and temperature. Temperatures can range from ~95ºC in the reservoir through to ~80ºc at the wellhead, to <40ºC at the platform.Furthermore, in deep water reservoirs, temperatures at the seabed can be as low as 3ºC that causes a cooling effect in the flow lines carrying the oil from the well and can result in hydrates.
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