Numerical Simulation of Hydraulic Fracturing in a Stacked Tight Gas Condensate Reservoir
Authors: Ataei Abdolrahim , Hui Wong Tiong , Chan Keng Seng , Lau Raymond K.Z. , Yeap Mei Ee 
Published: May 2016

Abstract
Hydraulic fracturing is a well known practice to improve the well productivity especially in tight gas reservoirs. For gas condensate reservoir, it can be applied to bypass the condensate bank that formed shortly after production start-up due to pressure drop below the saturation pressure. However, benefits of hydraulic fracturing in multiple stacked reservoirs with low initial gas saturations cannot be guaranteed. Unforeseen fracture propagation may result in premature water encroachment, thus adversely impacting well productivity. In order to avoid this, proper fracture modeling is critical to assess the benefits of hydraulic fracturing when dealing with relatively thin multiple stacked reservoirs.
This is the situations that exist in one of the gas condensate reservoirs located offshore Sarawak in Malaysia. This paper tries to address the challenges that exist in such a marginal gas condensate field. Reservoir simulation including a hydraulic fracture model was developed to simulate the condensate banking and fracture performance simultaneously. DST results were also modeled accurately to estimate the actual condensate bank effect and to reflect it back into the full field simulation model.
This paper shows how the lessons learnt from existing fractured wells, detailed modeling, and numerical simulation work can be used to optimize development of such a marginal field. It addresses the stimulation challenges in a marginal gas condensate green field.

Introduction
In this paper, we are addressing a tight gas condensate reservoir with 11 stacked sands separated by shale layers. The sand thicknesses are between 10- 110 feet and follows hydrostatic pressure regime at shallow zones and is over pressured by 2000 psi in deeper sands. Core data shows wide range of permeability between 0.01–10 md in different part of hydrocarbon zones.
DST results are also shows a tight formation with average permeability in the range of 3–7 md within the tested zones. Reservoir fluid analysis shows that the CGR is about 67–84 STB/MMSCF with CO2 content of 1% and H2S content of 1 ppm. Capillary pressure measurements show that a large part of the field is in transition zone. Figure 1(a) shows the measured and also the modeled Pc data from available core samples. It results high water saturation within the hydrocarbon sands as shown in Figure 1 (b).
As it can be seen there are several challenges exist in development of this field. These challenges are:- Stacked sands: The hydrocarbons are spreading in small to medium size compartments separated by shale layers. It will impact the completion strategy especially when it comes to producing from sands with different flow regimes.- Condensate banking: The richness of reservoir fluid and the low permeability matrix can impact the gas production forecast by condensate banking. This effect has studied using single well modeling.- Well stimulation: There is no doubt that without near wellbore productivity improvement, the low permeable sands will not have an optimum well productivity. Hydraulic fracturing has been suggested to improve the well deliverability in this field. However, it can be threaten seriously by early water break through due to the sand thickness, close proximity to aquifer and high water saturation in the formation.