Scale Control in Chalk Reservoirs: The Challenge of Understanding the Impact of Reservoir Processes and Optimizing Scale Management by Chemical Placement and Retention—From the Laboratory to the Field

Abstract

The scale control challenges for a large North Sea carbonate reservoir are reviewed in this paper. Field data from a reservoir where the process of scale ion stripping between the seawater injection well and production wells is known to occur is studied in detail to identify if it is possible to predict the impact it has on scale management. Injection water sulphate ions are shown to break through eventually, but the seawater fraction at which this occurs varies between different wells. The impact of the various possible driving mechanisms, and the extent to which matrix and fracture flow contribute to the process, are described. The discussion is generalised to findings applicable to other carbonate systems. The mechanisms of scale inhibitor retention when phosphonate, polymer, and vinyl sulphonate co-polymer inhibitor squeeze treatments are applied in this carbonate reservoir are 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 the reservoir, 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 a 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. A key factor in the success of such treatments is an understanding of chemical placement and the effectiveness of the treatment chemicals. Evaluation of residual chemical concentration or scaling ion chemistry has long been used in monitoring programs, and more recently probes have been developed which increase the rate of evaluation/interpretation. All these methods prove that the chemical is present in the brine when sampled, or that scale formation is not occurring at the point of brine analysis. This paper outlines the experimental methods developed to evaluate the suspended solids collected from the produced brine by environmental scanning electron microscope (ESEM) and the associated brine chemistry to evaluate the scale risk within the produced fluids. The combination of these methods has improved the integrated scale management program in terms of evaluating scale squeeze placement effectiveness and squeeze lifetimes, and provide the confidence the extend the period between scale squeeze treatments, and in some cases stop treatment were brine analysis alone would have suggested further scale squeeze applications. Introduction 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. Firstly we outline the principle differences between carbonates 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 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.

Evaluation of Barium Sulfate Scale Inhibition Using Relative Permeability Modifier Polymers as Adsorption Enhancer for Mature Offshore Well Treatments in Campos Basin, Brazil

“…Test 1 inhibitor release curve presented the expected inhibitor release trend reported in literature. − Test 2, however, presented an atypical curve. Lithology of core sample for test 2 comprises less mineral variety than that of samples from test 1: In particular, no clay mineral was detected in core samples for test 2.…”

Simultaneous Well Stimulation and Scale Squeeze Treatments in Carbonate Reservoirs

“…16,17,20,21  Based on the carbonate coreflood results presented in this study for black oil and HT condensate reservoirs it is not advised to blend phosphonate scale inhibitor within HCL acid or organic chelant stimulation fluids for use in carbonate reservoir as there is a risk of formation damage potential under matrix flow conditions. This damage is believed to be due to excessive precipitation of the scale inhibitor with calcium released from the rock by the action of the acid or organic chelant and the increased pH at the rock/fluid interface associated with the carbonate dissolution process.…”

Simultaneous Well Stimulation and Scale Squeeze Treatments in Sandstone and Carbonate Reservoirs

“…The same has been observed in laboratory and field applications within the Middle East. 17,18,19 Test Code K mD values% change Oil perm 1 -Stage 6 into brine saturated core 1. …”