Publications

Gas – Condensate reservoir system would be more complicated regarding fluid effects. To understand the fluid effects of Gas – Condensate reservoir system, several studies have been carried out, but there is no type curve matching method especially for Gas-Condensate reservoir system. In general, we use a composite model in Pressure Transient Analysis to analyze Gas-Condensate system, but we are still unable to map the condensate banking boundary in the reservoir. In this paper, we will use a numerical model approach to understand Gas-Condensate reservoir system based on Pressure Build Up analysis. We use a simulator for modelling the near well bore condition by using local grid refinement, then perform history matching with Pressure Build Up analysis result. This method will give us a clearer reservoir description and path of the condensate forming as a condensate banking. We will focus on the well MTD-02 to get a better understanding of our reservoir. The results of our method show that our Gas-Condensate reservoir system is a lean gas system, with several behaviors as we can see from PVT data, PBU Analysis result, and from the Simulation Model. This method gives us the path of condensate banking, so we can prepare strategy to overcome this situation. Gas fields have characteristics that are affected by the gas components itself, namely dry gas, wet gas and gas condensate. Sometime we call dry gas and wet gas as conventional gas reservoir. There are obvious physical environmental differences between gas condensate reservoirs and other conventional gas reservoirs (Qianhua et al, 2020). Ahbijit (2015) has stated that the term of wet gas is sometimes used as more or less equivalent to gas condensates.The methods and development of the operations of each gas field type has its own uniqueness, especially gas condensate type that has characteristic of liquid phase (condensate) which will form when the reservoir pressure reaches below its dew point pressure along with the depletion of reservoir pressure due to production. One of the effects of liquid phase (condensate) in the reservoir is that it will reduce gas mobility near wellbore area and there will be slightly change of relative gas permeability, so that gas production will not be optimal. The effect can reduce the well potential between 0% to 50% (Giamminonni et al, 2010)

Matindok Field is gas field producer located in Banggai Districts, Central Sulawesi, Indonesia. The production zone comes from Minahaki Formation, which is limestone. Since the beginning of production, condensate has been produced with average Condensate Gas Ratio (CGR) of around 13.5 STB/MMSCF and Gas Liquid Ratio (GLR) of around 73000 scf/STB with 48-50 API of condensate. Currently, Matindok Field’s average gas production is around 40 MMSCF/D. Moreover, with these parameters, Matindok Field is included as a gas condensate reservoir.

To keep gas production stable, we conducted well surveillance campaign each year to do pressure build-Up (PBU) test. We analyze the PBU data to obtain reservoir model data, reservoir parameters, reservoir boundary and so on. The PBU data states that reservoir model at Matindok Field is radial composite which shows that the permeability at near wellbore area is smaller than the outer zone that has more gas saturation. This is caused by reservoir pressure depletion at near wellbore area is greater than the outer zone. Thus, the pressure reaches below its dew point and condensate formed around wellbore area. In addition, from the PBU we can estimate the distance of condensate banking from the wellbore.

Beidokhti, et al, 2021 [1] suggest a three-region system in gas condensate reservoir:
• Region (1): this is the farthest region around the well with pressure over the dew point. The system contains a single gas-phase including the initial liquid saturation.

• Region (2): this region is near the first region toward the well. It is generated with pressure reduction below the dew point, and where the liquid saturation increases rapidly. It should be noted that, in this region, the liquid phase is immobile (SL < SLC).

• Region (3): this region is the nearest region around the well. The liquid saturation is higher than the critical saturation of condensate, so, gas and oil phases are mobile.

To simplify and to do reservoir monitoring, we did reservoir simulation case at MTD-02 well. This well is located at top structure of Minahaki Formation and has a fairly good production potential, which AOFP of 82 MMSCF/D and CGR of 13 STB/MMSCF. The MTD-02 well has complete data set to be analyzed such as PVT (CCE, CVD, Compositional analysis) and core data (RCAL, SCAL). To do an analysis that represents to the actual fluid behavior in the reservoir, the reservoir model used is a compositional analysis model. The result of the simulation model can describe the conditions of condensate in the reservoir and validate the result of condensate banking model from pressure transient analysis (PTA). So in the end, we can get the optimal gas rate with the influence of condensate in the reservoir.