The scale control challenges for two North Sea carbonate reservoirs are reviewed in this paper. Whilst carbonate reservoir are not the largest source of hydrocarbon within the North Sea, they are very significant on a global bases.
The mechanism of scale inhibitor chemical retention observed for phosphonate, polymer, and vinyl sulphonate co-polymer inhibitors on carbonate reservoir substrates is outlined. Chemical placement represents the most significant technical challenge when performing scale squeeze treatments into fractured chalk reservoirs. Examples from over 50 field treatments applied in reservoirs E and V, where both phosphonate and vinyl sulphonate polymer chemicals have been deployed, are used to illustrate the difference in chemical retention observed in laboratory evaluations. The laboratory studies demonstrated clear potential for significant extension in treatment lifetime by changing from a phosphonate to a vinyl sulphonate co-polymer-based scale inhibitor. The selection and qualification of chemical placement systems for deployment of inhibitors in fractured carbonate reservoirs are also outlined. To this end, novel technologies to enhance conventional scale inhibitor chemical placement are vital to economic success during water flood projects.
The correct selection of scale inhibitor for the control of mineral scale within reservoirs and associated production tubing is vital if economic hydrocarbon production is to be maintained. The following section will outline the principle differences between carbonates and sandstone reservoirs, which makes scale inhibitor selection and application a technical challenge.
Carbonate reservoirs are principally composed of carbonate minerals, which include calcite (CaCO3), dolomite (Ca,MgCO3), ankerite (Ca,Mg,FeCO3), and siderite (FeCO3). Carbonate reservoirs can be sub-divided into chalk and limestone. Chalk reservoirs are composed of small spherical/plate-like particles (cocoliths) of calcium carbonate from the skeletons of marine organisms, which became compacted and cemented to form rock with a higher primary porosity - this shown in Figure 1. Limestone is generally formed by the deposition of fine carbonate mud with associated fragments of biogenetic material (shells, etc) which is compacted to form rock.1,2 Such a limestone reservoir would generally have a low primary porosity but a high secondary porosity owing to the dissolution of some of the rock caused by reaction of pore fluids during burial.
Flow within carbonate reservoirs generally occurs as a result of fluid flow within fractures (both natural and induced), which enhance production. The fluid flows first through interconnecting pores, and then, second, along the fracture paths to the well bore. The pores formed during sediment deposition are generally poorly connected within carbonate reservoirs resulting in a lower permeability/porosity ratio than for sandstone reservoirs. The deposition of scale, both carbonate and sulphate, within carbonate reservoirs results in a decline in total production rate, with the fractures becoming restricted owing to the deposition of scale as a film. In the smaller fractures, the deposition and restriction of flow could be associated with the migration of scale particles which block, or reduce, fluid paths. Mechanical or acid generated fractures can sustain a significant amount of damage (95% of the fracture face not contributing) before the fluid production from such a well is significantly rimpacted.3