Scale Control within North Sea Chalk/Limestone Reservoirs. The Challenge of Understanding and Optimizing Chemical Placement Methods and Retention Mechanism: - Laboratory to Field.
- Myles Martin Jordan (Nalco Co.) | Fredrik Arthur Sjursaether (Schlumberger) | Ian Ralph Collins (BP Exploration)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Facilities
- Publication Date
- November 2005
- Document Type
- Journal Paper
- 262 - 273
- 2005. Society of Petroleum Engineers
- 5.1.1 Exploration, Development, Structural Geology, 5.3.4 Integration of geomechanics in models, 1.10 Drilling Equipment, 2.2.2 Perforating, 2.5.2 Fracturing Materials (Fluids, Proppant), 1.14 Casing and Cementing, 5.2 Reservoir Fluid Dynamics, 5.4.1 Waterflooding, 1.8 Formation Damage, 4.2.3 Materials and Corrosion, 1.6.9 Coring, Fishing, 2.4.3 Sand/Solids Control, 4.3.4 Scale, 1.2.3 Rock properties, 3.2.4 Acidising, 5.2.1 Phase Behavior and PVT Measurements, 4.1.5 Processing Equipment, 5.8.7 Carbonate Reservoir, 3 Production and Well Operations, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 4.1.2 Separation and Treating
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The scale-control challenges for two North Sea carbonate reservoirs are reviewed in this paper. While carbonate reservoirs are not the largest source of hydrocarbons within the North Sea, they are very significant on a global basis.
The mechanism of scale-inhibitor chemical retention observed for phosphonate, polymer, and vinyl sulfonate copolymer (VS-Co) inhibitors on carbonate-reservoir substrates is outlined. Chemical placement represents the most significant technical challenge when performing scale-inhibitor squeeze treatments into fractured chalk reservoirs. Examples from more than 50 field treatments applied in reservoirs E and V, in which both phosphonate and VS-Co 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 VS-Co-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 waterflood 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 outlines the principle differences between carbonate and sandstone reservoirs, which make scale-inhibitor selection and application a technical challenge.
What is Carbonate? 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 is shown in Fig. 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.
Fluid Flow in Carbonate Reservoirs 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, 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 impacted.3
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