WellFlo is the software used extensively for the production technology phase. This software employs the concept of nodal analysis. The objectives of this section are:
o To create a base case by modelling Gelama Merah -1 vertical exploration well o Modifying the base case for the Gelama Merah producers
o Selecting the optimum tubing size
o Running sensitivity analysis on the chosen tubing size to water cut and depletion of reservoir pressure
8.2.1 Base Case Model
The required input data for the base case is the reservoir fluid properties, the well test data and pressure transient analysis data which is presented in Table E.1-1 (in Appendix E.1), Table C.4-1 and Table C.4-2 (see Appendix C.4).
A production test (DST#1) has been carried out in Gelama Merah-1 well using 3 1/2”
OD production tubing. The tested reservoir is Unit-8 sand, perforated from 1521 m to 1530 m-MDRKB.
8.2.2 PVT Correlation Matching
The PVT data is matched by using a suitable black oil correlation. Closest match was given by the following correlations:
Table 8.1: The black oil correlation used to match the PVT data (Velarde, 1996)
Table E.1-4 shows the ranges of data used to develop the Vasquez-Beggs correlation
Fluid Parameters Correlation
Bubble point pressure (Pb), Solution GOR (Rs) and Oil Formation Volume Factor (Bo)
Vasquez
Oil Viscosity, µo Beggs
Gas Viscosity, µg Carr
The best flow correlation model for Gelama Merah-1 is Hagedorn and Brown (mod) because this is the empirical correlation generally used for two phase flow in a vertical well. It also gives the closest match to the well test results for flowing bottomhole pressure and oil rate (Economides et al., 1994; Production Technology notes, 2010). Gelama Merah reservoir is saturated meaning two phase inflow is taking place therefore the applicable Inflow Performance Relationship (IPR) model used is Vogel (Production Technology notes, 2010). The results for the simulations are presented in Figure E.1-1 and Figure E.1-2 (see Appendix E.1). Figure E.1-1 shows IPR of Gelama Merah-1 with initial pressure 2116 psia and an AOF 4492 stb/d. The calculated productivity index (J) is 3.8478 stb/d/psi.
Figure E.1-2 shows an intersection point between Inflow Performance Relationship (IPR) and Tubing Performance Relationship (TPR). The point represents the operating point pressure which is 1726 psia with the corresponding oil rate of 1376.5 stb/d at 0% water cut and GOR of 310.7 scf/stb.
Base case done! The base case is then modified to fit the purpose for the Gelama Merah Producers i.e. GMP-1 to GMP-8. The best flow correlation model for these horizontal completions is Beggs and Brill. This correlation is applicable to any pipe inclination and flow direction (Economides et al., 1994; Production Technology notes, 2010).
8.2.3 Tubing Size Optimisation
In the Production Technology notes (2010), it is stated that the correct way to design a well is to obtain an estimate of the expected production rates at various times in the field's life (Obtained from the Reservoir engineer). The required size of the production tubing is estimated to allow these volumes of fluid to be produced.
Production profile is analyzed and the wells are grouped together according to their plateau production rate. Table 8.2: Grouping of the wells according to their plateau production rate and identifying the target oil rate for simulation purposes.
Table 8.2: Grouping of the wells according to their plateau production rate and identifying the target oil rate for simulation purposes
Group Well preparation just in case for any enhancement activities.
The only parameter that is under operational control of the Production engineer is the wellhead pressure or the system ‘backpressure’. The remainder of the completion can only be influenced by the engineer at the design stage. Hence, it is a must to carry out sensitivity analysis on selecting the optimum tubing size to ensure that the selected option is robust and ‘fit-for-purpose’ during its lifetime (Production Technology notes, 2010). Sensitivity analysis on wellhead pressure and tubing size was carried out to find the optimum tubing size. Table 8.3 shows the optimum tubing size for the Gelama Merah Producers. For GMP-1, GMP-2, GMP-3 and GMP-7, the optimum tubing size is 3 ½”. The rest of the producers i.e. GMP-5, GMP-6, GMP-4a and GMP-8 require an optimum tubing size of 2 3/8”.
Table 8.3: The optimum tubing size for Gelama Merah Producers
Group Well
1 GMP - 1 3300 3 1/2" 2.992 330 producers i.e. GMP-5, GMP-6, GMP-4 and GMP-8 require an optimum tubing size of 2 3/8” which is sufficient to allow the required volume of fluid to be produced.
Figure E.1-3 and Figure E.1-4 (see Appendix E.1), shows the sensitivity analysis to tubing size (ID) and wellhead pressure for GMP-1 and GMP-2 respectively. From the figure, the 2 3/8” OD tubing has the lowest operating rate. This tubing diameter is too small for the required volume of oil. If tubing size is too small this may cause excessive pressure drop which can restrict production. While, the 4 ½” OD tubing can achieve production rate much higher than necessary. Large tubing cost extra and may cause inadequate reservoir inflow. The 2 7/8” and 3 ½” tubing is able to achieve the required production rate. However, 3 ½” tubing is chosen to be the best option over 2 7/8” because a relatively larger tubing diameter would be ideal for future preparation for any enhancement activities (Production Tecnhology notes, 2010).
Figure E.1-5 and Figure E.1-6 (see Appendix E.1) shows the sensitivity to tubing size (ID) and wellhead pressure for GMP-5 and GMP-5 respectively. From the figures, the operating point rate for the 3 ½” and 4 ½” tubing can achieve production rate much higher than necessary. The 2 7/8” and 2 3/8” tubing size is able to achieve the target production rate. But, the 2 3/8” tubing is chosen over 2 7/8” because larger tubing cost more than smaller tubing (Production Tecnhology notes, 2010).
8.2.4 Well Performance Sensitivity Analysis
In nodal analysis, the whole production system behaves as a single unit, finding a common value of the production rate for inflow and tubing performance relationships (IPR and TPR) at the same flowing bottomhole pressure. This allows us to estimate the well productivity under today’s actual or future expected producing conditions. The sensitivity of the well design to the many factors which effect well production as the well ages can be examined. So as to minimize the total well capital and operating costs over its complete lifetime (Production Technology notes, 2010).
Some of the more frequently encountered sensitivity analyses are described below.
Effect of Water Cut and Depletion
Figure E.1-7, Figure E.1-8, Figure E.1-9 and Figure E.1-10 shows the operating rate against water cut at different layer pressure for GMP-1, GMP-2, GMP-5 and GMP-4 respectively (see Appendix E.1.2).
Table 8.4: The result after running sensitivity analysis on water cut and layer pressure
Pressure, psia Water Cut, % Oil Rate, stb/d
Production causes the decrease in reservoir pressure, for GMP – 1, as the reservoir pressure depletes, water cut increases and oil rate decreases. Further reduction in reservoir pressure with an increase in water cut causes the well to stop flowing.
Running sensitivity analysis on water cut gives a good indication on when to start using artificial lift. The requirement for artificial lift will be discussed in detail in the following Section 8.3.