Optimising Recovery in Gas Condensate Reservoirs (2014)

Abstract Gas condensate reservoirs exhibit complex flow behavior below the dewpoint pressure, caused by compositional changes and the creation and growth of a condensate bank around the wellbore, which effectively reduces the relative permeability to gas flow. As a result, gas production decreases and liquid condensate, a valuable resource, is left behind in the reservoir. Well deliverability impairment resulting from liquid dropout has been a main focus of gas condensate studies for over 60 years. We have used compositional reservoir simulation, with representative lean- and rich-condensate fluids and velocity-dependent relative permeability models, to predict condensate dropout under typical operating conditions. The effectiveness of different production methods and remediation solutions in minimizing condensate buildup below the dewpoint pressure was quantified, using first a single-well model and then full-field models of tight and low-permeability gas condensate reservoirs in which six vertical wells were compared with two horizontal wells. We found that, although both horizontal wells and vertical well stimulation do improve well productivity, productivity enhancement depends greatly on well and reservoir parameters such as horizontal well lengths, well placement, reservoir permeabilities, and gas condensate compositions. For gas condensate production below the dewpoint pressure, it is possible to achieve an optimum balance between gas production rate and pressure drawdown, thus minimizing condensate dropout effect while producing at a reasonable rate. In a low-permeability gas condensate reservoir, the six vertical wells perform slightly better than the two horizontal wells for the same amount of gas production. In a tight gas condensate reservoir, on the contrary, gas recovery with two horizontal wells is significantly greater than with six vertical wells. Although, in this model, well stimulation can increase the productivity of the vertical wells in tight gas condensate reservoir, it is not as effective as using horizontal wells. Introduction Continuous developments in drilling and logging technologies have enabled deeper, higher pressure, and higher temperature gas condensate reservoirs to be discovered and developed. In addition, most mature gas condensate fields worldwide are at the later stage of their field life, gradually approaching their dewpoint pressure below which liquid condensate drops out. Globally, the increasing demand for natural gas liquids on world markets has stimulated interest in optimizing gas condensate resources (BP 2014). Gas condensate reservoirs exhibit complex flow behavior as a result of retrograde condensation when the bottomhole flowing pressure drops below the dewpoint pressure. Gas condensate dropout near the wellbore must be considered, as changes in fluid saturations affect relative permeabilities. As a result, it affects the final decision made in the production planning of a gas condensate field. This has been the subject of many studies for over 60 years (Muskat 1949). It was discovered that three concentric regions with different liquid saturations emerge around a gas condensate well producing below the dewpoint pressure (Kniazeff and Naville 1965). Away from the well, an outer region contains the initial liquid saturation. Next, an intermediate region shows a rapid increase in liquid saturation and a corresponding reduction in gas relative permeability. Liquid in this region is still immobile because the critical saturation has not been reached yet. Nearer to the well, an inner region forms where liquid saturation exceeds the critical saturation and both the reservoir gas and liquid condensate flow into the well with constant composition.