PTE 517 Group I Project

GAS CONDENSATE WELL TESTING

Team Members:

Avraham Hollander

Jye Collins

Alexis Iwasiw

Saihil Heble

Chenguang Xue

Georges Beyrouti

Nan Zhou

Ashish Mudegowdra Basavaraj

Introduction:

Gas condensate is a low-density mixture of hydrocarbon liquids that are present as gaseous components in the raw natural gas. It contains more heavy components comparing to the dry gas. Because it condenses out of the raw gas when the bottom-hole pressure falls below the dew point pressure in the reservoir, which is common during the gas well production, it is important to do the well testing analysis of gas-condensate to see its effect on the gas well.

At original reservoir conditions the gas condensate is a single phase fluid. Decline of reservoir pressure below the saturation pressure (Dew Point) causes the condensate to become a two phase fluid known as retrograde condensate. At this stage the liquid starts to get separated from the gas and causes the vapor percentage to decrease. But a continued pressure decrease can cause it to go back up again. The amount of liquid phase present depends not only on the pressure and temperature, but also on the composition of the fluid. Lean gas condensate generates a small volume of the liquid phase as compared to rich gas condensate which generates a larger volume of liquid. As a result it is important to determine the fluid composition.

In order to determine the fluid composition of a reservoir fluid, it is necessary to capture a representative sample of the reservoir fluid. Surface samples can be collected easily from test or production reservoirs. However, these results can sometimes be unrepresentative due to incorrect gas/liquid ratio, commingling zones, and changing production conditions prior or during sampling. Samples can also be collected down hole which is desirable if wellbore flowing pressure is above the dew-point pressure. If it is below, then two-phase flow is present in the wellbore and liquid forming prior to or during sampling will potentially result in unrepresentative sample.

Dew-points in the Reservoir:

Condensate begins to form out of the gas as the reservoir pressure drops below the dew-point pressure. Initially, this condensate is immobile due to the capillary forces within the porous area. This continues until enough condensate has formed that condensate saturation has exceeded critical liquid saturation, at which point the gas-condensate, multi-phase flow is determined by relative permeability effects.

At points far from the wellbore, there is ordinarily not enough condensate saturation to trigger mobility. However, near the wellbore, a pressure sink is formed where considerable amounts of condensate drops out of the gas and becomes mobile. As the condensate mobility increases, the gas mobility decreases and production is affected negatively. This is called condensate blockage. Additionally, the gas has lost its desirable heavy components in the form of condensate, further decreasing the profitability of the operation.

The challenging problem of Gas Condensate Reservoir -- Condensate Blockage:

Four regions can be defined within the gas-condensate reservoir which can help demonstrate the near-wellbore condensate blockage effect. Region 4 covers distances far from the wellbore where the reservoir temperature is still above the dew-point temperature of the original gas. In this region, single phase flow in the form of gas takes place. Region 3 begins at the distance point in the reservoir where the reservoir pressure is equal to dew-point pressure. Here liquid begins to drop out from the gas but is immobilized inside the pore space as explained above. The condensate blockage occurs in Regions 1 and 2 which start at the distance from the wellbore where condensate saturation exceeds critical saturation. These four regions can be seen on oil saturation versus pressure plot and on a derivative plot during well testing. Region 2 is strictly Darcy flow, and as explained above, the two-phase flow is limited by the relative permeability relationship of the gas and the condensate. Region 1 is an area within the condensate storage area that is sometimes distinguished from the rest because of two possible flow phenomena that may occur. The first is the effect caused by a flow of a high capillary number, where - due to the high velocity of the gas as it flows into the wellbore - the viscous forces dominate the interfacial tension forces. This will increase the relative permeability of the gas, reducing the effect of the condensate blockage. The other is the Forchheimer effect, where relative permeability of the gas is lowered by inertial drag as the gas goes from a velocity to a low velocity as it enters and exits pores. This is called non-Darcy flow. While the high capillary flow effect is positive, the Forchheimer effect is negative. The net impact of this region is usually positive.

Modeling Condensate Blockage and Modeling Behavior around a Fracture:

Modeling the blockage caused by the condensate build up near the wellbore is a practice used to predict the productivity of gas condensate reservoirs. The laboratory data is applied to different types of relative permeability models, such as pseudo pressure spreadsheets, fine-grade single well compositional, and grid block full field. The pseudo pressure method is best when first deciding whether the condensate blockage will affect the well deliverability. It employs the simplest assumptions of homogeneity and single flow, which allows for quick predictions and ease of

decision-making when it comes to run more tests or pick more complex models. If this model indicates the well productivity can be affected, the single well model is applied to quantify the blockage because it allows for more variability in rock heterogeneity, fluid composition, boundary conditions, and depletion. For the single well model, the assumed radial symmetry creates a two dimensional, fine grid. The grid consists of the dimensions of the formation height and radial distance, which are very small when near the wellbore and increase to a maximum size towards the boundaries. If this model indicates that the condensate blockage will significantly affect the well deliverability, the full field model (FFM) is considered the most accurate way to determine the behavior of the gas condensate through the use of PI multipliers, local grid refinement (LGR) around the wells, and generalized pseudo pressure (GPP) model. The PI multiplier is a fudge factor because it can be inaccurate from uncertainty in the input parameters and if used, then needs to be constant for each layer in the well model. The LGR utilizes high resolution of very small grid blocks around the wellbore to determine the condensate blockage, which can take a very long computing time. The GPP incorporates the varying saturations and relative permeabilities around the wellbore grid blocks that constitute the condensate blockage.

When the models reveal the well deliverability is declining due to the condensate blockage, hydraulic fracturing is used to improve the productivity. However it is not well understood as is it in dry gas wells, which typically results in the condensate building up around the fracture reshaping the blockage. As of now, the best way to understand the performance of condensate blockages around hydraulic fractures is to input both laboratory and field data into a fine grid model.

Case Study:

In this summary we introduce two case studies of the gas condensate reservoir, including the lean gas condensate reservoir and rich gas condensate reservoir.

The first case study part is the case study of a well from North Sea (UK) Reservoir. In this case, a numerical model was developed consisting of 6 layers. Multiple simulation runs were made varying the completion skin, pressure and fluid properties within the expected ranges. Results were history matched against the well test data. This lead to the conclusion that the ‘?’ was related to layering rather than condensate banking. This field example goes to show the complexity of assessment in condensate gas reservoirs as the introduction of variables associated with volatile fluid components and saturation hysteresis can typically make analytical solutions difficult. Numerical models are often the best source of quantification with analytical models for use as qualitative review.

The second case study part is about the well testing conducted over three years in the MTGC (North Africa) Reservoir. In this reservoir the fluid is a rich gas condensate overlying a thin oil rim. The section focuses primarily on well test analysis from the W-7 test well (Fig. 34). The pressure and rate histories from Well W-7 and the initial extended well test (IEWT) are shown in Fig. 35 and 36. Then Fig. 37 is a rate-normalised log-log plot of IEWT pressure changes and derivatives. From this figure we can know the information such as the phase redistribution, where the liquid drop-out as the condensate bank develops, where nearby faults presents and the mobility change of the whole reservoir etc.

References:

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