A prolific Southeast Asia onshore oilfield has enjoyed scale free production for many years before recently experiencing a series of unexpected and harsh calcite scaling events. Well watercuts were barely measurable, yet mineral scale deposits accumulated quickly across topside wellhead chokes and within downstream flowlines. This paper describes the scale management experience, and the specific challenges presented by this extraordinarily low well water cut, low pH, calcium carbonate scaling environment. To the knowledge of the authors, no previous literature works have been published regarding such an unusual and aggressive mineral scale control scenario. A detailed analysis of the scaling experience is provided, including plant layout, scaling locations, scale surveillance and monitoring programs, laboratory testing, product selection and implementation, and scale inhibitor efficacy surveillance and monitoring programs. The surveillance and application techniques themselves are notable, and feature important lessons learned for addressing similar very low water cut and moderate pH calcium carbonate scaling scenarios. For example, under ultra-low watercut high temperature well production conditions, it was found that a heavily diluted scale inhibitor was necessary to achieve optimum scale control, and a detailed laboratory and field implementation process is described that led to this key learning lesson. The sudden and immediate nature of the occurrence demanded a fast-track laboratory testing approach to rapidly identify a suitable scale inhibitor for the high temperature topside calcium carbonate scaling scenario. The streamlined selection program is detailed, however what could not be readily tested for via conventional laboratory testing was the effect of <1% water cut, and how the product would perform in that environment. A risk-managed field surveillance program was initiated to determine field efficiency of the identified polymeric scale inhibitor and involved field-trialing on a single well using a temporary restriction orifice plate (ROP) to modify the residence time of the injected chemical. The technique proved very successful and identifed that product dispersibility was important, and that dilution of the active scale inhibitor had a positive effect on dispersibility for optimum inhibitor action. The lessons learned were rolled out to all at-risk field producers with positive results. The ongoing success of this program continues and will be detailed in the manuscript and presentation. This paper demonstrates a unique situation of calcium carbonate scale formation and control that utilized a previously unreported and analytical surveillance approach. The cumulative performance derived by improving not only chemical selection, but the way the wells were managed via surveillance and chemical management decision making processes is compelling and of value to other production chemists working in the scaling arena.

Calcium carbonate is a pH dependent inorganic mineral scale that is influenced by CO2 and H2S partitioning. CaCO3 prediction must therefore include accurate modelling of the aqueous phase and all hydrocarbon phases present. pH dependent scale prediction challenges and the development of a rigorous procedure for generation of more accurate results were previously published. This procedure has now been applied to an onshore oilfield in Southeast Asia for assessment and management of CaCO3 scaling. A rigorous scale prediction workflow was applied to ‘at-risk’ field producers that showed CaCO3 scaling at and/or downstream of the wellhead choke valve (WHCV). By inputting relevant field data into an integrated PVT/scale prediction code and using the correct procedure, it was possible to evaluate scaling potentials. A series of sensitivity studies allowed well ranking based on the predicted severity of their scaling potentials. The approach validated mechanistic hypotheses for scale development in prolific low watercut, ultra-high CO2, sour, high temperature producers. Close matching of predictions with actual wellhead scaling events provided the basis for improved full-field scale management, and strategic targeting of onsite scale mitigation resources. Target field producers exhibited 0.2% to 25% watercut and presented different degrees of scale precipitation at and/or downstream of the WHCVs. Following well scaling potential assessment, each producer was subject to a series of sensitivity studies to identify (i) how scaling changed with time and (ii) provide focus on the key inputs that most impacted predictions. The initial findings, considering measurement errors (normal field variability), were surprising as key input parameters such as gas phase CO2 and produced water calcium ion concentration appeared to show minimal influence on the final scale prediction results for these wells; even more remarkable considering typical production featured very low salinity produced brine and ultra-high CO2 sour field gas. Focus was therefore shifted to field temperatures, pressure profiles and volumetric flow rates. Of importance is that the selection of ‘critical parameters’ is field specific and that the example presented here shows the variability in scale precipitation at different stages of well production, and how the scaling potential (SR and mg/L) must be evaluated together with the predicted daily theoretical mass of scale (kg/d). This is important in the study of wells with such variable water cut. The following paper demonstrates the value of a rigorous and systematic approach to the prediction of CaCO3 scale, which is often investigated using inappropriate or incomplete methodologies. In this work the authors demonstrate how the technique can address and explain important operational issues and provide solid foundations for implementing and indeed improving the field scale management program.