No abstract

Sabriyah and Raudhatain are the main fields producing from the Middle Marrat Jurassic formation in North Kuwait with approximately 5 km distance between the two fields. Raudhatain fluid is considered as Volatile Oil, while Sabriyah is described as Gas-condensate. 16 PVT samples from Raudhatain were analyzed and described as Volatile oil. 12 PVT samples taken from Sabriyah field where 7 samples show gas condensate behavior and rest shows volatile oil. A key challenge in understanding the Sabriyah fluid characterization is the fact that 5 well samples that showed Volatile oil behavior are not separated from the Gas condensate wells by any apparent barrier. In addition, the initial reservoir pressure is much higher than the saturation pressure, preventing the equilibrium of those fluids. The objectives for this study are to analyze the physical explanation of coexistent of oil and gas-Condensate in one communicated reservoir with reservoir pressure higher than saturation pressure, apply different modeling approaches to accurately describe the fluid behavior in Sabriyah field and finally capture the influence of uncertainty in the type of fluid on the production forecast. The physical explanation for this phenomenon was investigated from different points of view: the variation of temperature, compositional variation with depth, existence of geological barriers, and facies changes. It was found that the compositional variation with depth and the change of fluids with changes of facies can provide reasonable explanation for this phenomenon. The first explanation related to compositional variations with depth is supported by the observed data that shows a strong relationship between depth and fluid type, while the temperature did not influence significantly the gas-oil phase change. The second explanation related to the concept of gas and oil charge depending on facies is supported by mercury injection capillary pressure data taken from different depth in the reservoirs, this concept improves the understanding of fluid distribution which could not be explained in previous approaches. This paper shows the way of modeling this phenomena based on these two explanations, which honor both static and dynamic data with special reference to the effect of these different modeling approaches on the production forecast of Sabriyah field. The near critical fluids which are the type of fluids in Sabriyah field are usually problematic to handle with Equation of State; therefore solving this particular case is expected to add technical value to reservoirs of the same type of fluids. The facies dependence of gas and oil distribution and the way of modeling this phenomenon is an innovative view that can contribute to the description of similar fields.

Progress in multi-parallel computers opened up new possibilities in reservoir modelling providing opportunities in compositional simulation to study in detail highly complex physical process that are extremely computational demanding. This is particularly true for probabilistic methods such as the uncertainty quantification and analysis. Experimental design, ED, concept supersedes the conventional deterministic uncertainty analysis and offers new efficient and system approaches to identify and assess the impact of the key geology and engineering risks in strategic reservoir engineering decisions. Use of response surfaces, Monte Carlo stochastic modelling is an alternative to numerous full-scale reservoir simulation and is employed in petroleum industry since long ago [Amudo et al. 2008]. However, although ED has been introduced to reduce computation, it is computational expensive especially in compositional simulation with many degrees of freedom in the uncertainty parameters. This paper shows implementation of ED and the use of multi-parameter sensitivity analysis based on multidimensional Response Surfaces Models (RSM). The method was validated when key risks associated with development of a unique gas-condensate field in Yamal peninsular, Russia, were assessed. This reservoir is characterized by poor permeabilities in the range around 1.0 mD, abnormally high reservoir pressure and temperature (600 atm, up to 115 °C), high potential condensate content (potential C5+ content 280-380 g/m3) and the risk of a heavily compartmentalized some blocks of the field through faulting. The numerous identified uncertainties impacting the development of the gas-condensate reservoir are difficult to address in a traditional reservoir study using deterministic methods and only a probabilistic approach would guarantee to assess the production and recovery potential in all aspects and, moreover, allows informed decisions to be made on the data acquisition – or in general the appraisal strategy – and the development.

An unexpected raise of hydrogen sulfide levels during development of several gas condensate fields in Southwestern Gissar, producing from naturally fractured carbonate reservoirs, observed within a year, lead to necessity of full scale comprehensive investigation. For planning of effective mitigation strategy important questions related to the reasons of hydrogen sulfide level growth and prediction of its further behavior have been addressed in the present study. The entire investigation process encompassed both theoretical and practical parts. Theoretical part covered evaluation of sour gas sources that was crucial in respect to selection of conceptual methodology for predictions. All possible contributing sources including primary and secondary have been investigated to discern the causes and consequences of hydrogen sulfide occurrence. Practical component of the study employed cut to edge technologies tested and implemented in reservoir simulation. Based on conceptual constraints with the use of existing field data, interpretation results and regional knowledge basin and 3D static models with fracture network have been developed. Obtained modeling results have been integrated into compositional model, allowing to predict with applied uncertainty analyses further H2S content change during field development.