Oil wells producing from carbonate formations generally experience chemical scaling (carbonates and/or sulfates) during some phase of their production history. In several Saudi Aramco vertical wells, production of formation water containing associated carbon dioxide gas has resulted in calcium carbonate scaling. Scaling potential studies have indicated the threshold level of an organic phosphonate scale inhibitor used to mitigate such scaling in these wells is less than one ppm. This low protection threshold allows considerable leeway in scale squeeze design for the problem wells. Phosphonate based scale inhibitor squeeze treatments provide the most common and effective means of preventing the scale formation in such fields. In vertical well applications, long squeeze lives of more than ten years have been observed in fields producing from carbonates. The residual inhibitor levels have fallen below 0.1 ppm in several of these wells without return of scale. The increased drilling of horizontal holes and inevitable increases in watercut in these wells have led to scale problems. The design of a viable and economic horizontal well scale squeeze treatment was called for. Considerable problems are, however, inherent in the development of such horizontal treatment strategies. Sorbie, et al., recently published a mathematical scale inhibitor squeeze model for use in horizontal well treatments. This model was used to evaluate several treatment options for horizontal wells having a low carbonate scaling potential. Simulated residual returns and squeeze life data were used for different stages and scenarios in Sorbie's model to arrive at the most optimistic squeeze strategy. Based on the information provided by the model and previous vertical well experience, a simple and inexpensive bullheaded squeeze resulted in a successful treatment. This resulted in a substantial economic savings over a coiled-tubing delivered treatment. The theory behind this simple strategy will be discussed. The results of two case studies will be presented.
An alternative scale inhibition method using encapsulated scale inhibitor has been successfully used to control calcium carbonate scaling in the Ghawar Field oil wells of Saudi Aramco, Saudi Arabia. Field tests indicate that the Ghawar Field requires a low threshold scale inhibitor concentration for scale mitigation. The encapsulated phosphonate scale inhibitor treatment procedure is thus ideally suitable for scale control in such fields. Since 1994, a total of 89 wells have been treated with this procedure. After more than five years of treatment, there has been no reappearance of scale deposit on the treated wells except for two instances of scaling. Low treatment cost and the resulting long treatment life have provided an excellent incentive to treat more wet producers using the encapsulated scale inhibitor treatment method instead of treatment by conventional scale inhibitor squeezes. An additional benefit is realized from this encapsulated inhibitor method when treating marginal high water cut wells and wells located in low pressure areas by ensuring that the wells sustain flow after the treatments without the need for extensive livening work. This paper presents the results of a field case study where calcium carbonate scaling was controlled using the encapsulated scale inhibitor treatment procedure. Treatment design, job procedure, inhibitor return monitoring, economic analysis and comparison with conventional squeeze treatments as well as future applications are presented. Introduction Calcium carbonate is the most commonly encountered scale in the Ghawar Field of Saudi Arabia. Due to the presence of high reservoir pressure (>2700 psi) with reservoir fluid containing 5–20% dissolved acidic gases (CO2 and H2S), there is no CaCO3 scaling problem in the reservoir and at the bottom-hole of the tubing. However, as the fluid moves up the production tubing, the dissolved gases flash out of the brine as pressure is reduced. The loss of CO2 results in an increase in fluid pH. This shifts the thermodynamic balance, and results in the brine being supersaturated with respect to CaCO3. By the time the nucleation and kinetics of crystal growth favor the scale formation, the brine has reached the top 1000 feet and higher of the production tubing. The CaCO3 scale formation is represented by the equation: Calcium carbonate scale formation has resulted in production loss and severe field operational problems in the Ghawar Field oil producers. Since 1987, conventional scale inhibitor squeeze treatments have been used to control this scaling problem. All wet producers in the Ghawar Field require scale inhibitor treatments to avoid production loss as well as expensive scale removal from the producing tubing string, wellhead, manifold and flow-lines. Initial squeeze treatment costs were very high due to high pumping cost, particularly since a large number of wells had to be treated. An alternative scale inhibition method was therefore sought to reduce the treatment costs. The first trial of an encapsulated scale inhibitor treatment was performed in 1994 with encouraging results. Consequently, more wells were treated using the encapsulated scale inhibitor method in 1997 and subsequent years. Low MIC After monitoring residual inhibitor levels of the squeezed wells, it was recognized that a low threshold scale inhibitor concentration or MIC (minimum inhibitory concentration) requirement existed for the Ghawar Field.
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