Determination of Perforation and Production Strategy for Single Well with Aquifer using CMG


Note: This is the third project for the reservoir simulation course. A radial model has been used to simulate a single well with bottom aquifer. The perforation and production strategy were determined through the reservoir simulation.

Description of the Reservoir

A target petroleum production unit is given in this project. To construct a radial model, assume the outer radius is 200 m, and the thicknesses of three layers are 8 m, 8 m, and 4 m, respectively. The water-oil contact is  -3140 m; and the bubble point pressure is 10000 kPa. There is an aquifer that is 50 m thick connecting to the bottom of the production unit. The aquifer has the same permeability, 200 md, and porosity, 0.20, with all layers. Rock properties, relative permeability, and PVT data are the same as previous project, Comparing the Performance of 5-Spot and Inverted 9-Spot Patterns by Reservoir Simulation using CMG Suite. The aquifer is 2.5 larger than the reservoir. Figure 1 shows the simple model for production unit and aquifer.

Figure 1. A simple model for production unit and aquifer.

Parameters to determine the size of radial grids include:

  • Number of divisions alone radius direction: 15
  • Number of divisions alone theta direction: 5
  • Grid block width in radius direction: 3, 5, 8, 10, 10*15, 24

There is a production well in the center of the production unit, meaning the well location in the grid system is (1,1). The production started from January 1, 1995; the liquid production rate is 50 m3/day; all layers are perforated for production. Production well constraints are: min bottom hole pressure 1500 kPa and max liquid production rate as 100 m3/day for operation, and max water cut is .95 for monitor and shut-in conditions.

Tasks:

  • Water Cut

Put the simulation stop time card at Jan. 1, 2020, determine the date/time that water breaks, and water cut reaches 50, 60, 70, 80, 90 and 95%.

Dates of Water breaks, and water cut reaches 50, 60, 70, 80, 90 and 95% could be determined through Figure 2. Water Cut vs. Time Curve, and listed in Table 1.

Table 1. Water Cut vs. Time

Water Cut Water Break 50 60 70 80 90 95
Date 01/01/95 05/01/00 09/01/00 04/01/01 01/01/02 12/01/03 11/01/05

Fig. 2 Water Cut vs. Time Curve for Base Case

  • Perforation Strategy

There are 7 perforation plans for base case, which are layer 1+2+3, layer 1+2, layer 1+3, layer 2+3, layer 1, layer 2, and layer 3, respectively. Figures 3-6 show the water cut curves, cumulative oil production, oil production rate, and average reservoir pressure with various perforation plans. The water cut curves could be separated in to three groups based on the time water cut reaches the peak and the shape of the curve:

  • Group 1, all the perforation plans including layer 1, such as layer 1+2+3, layer 1+2, layer 1+3, and layer 1;
  • Group 2, all the perforation plans including layer 2 but excluding layer 1, such as layer 2+3, and layer 2;
  • Group 3, layer 3 only.

Layer 1 dominates the water production in group 1, and layer 2 dominates the water production in group 2.

At early time, layer 1 only produced least water, while layer 3 only produced most. And Group 1 has shortest production history, and group 3 has longest production history. If only taking water cut account, perforating layer 3 only should be best. But, there are still something others we need to consider, such as recovery, oil production rate, and average reservoir pressure, etc.

From Fig. 4, the cumulative oil production curve, layer 1 only could produce the most oil (130.54 MS m3), while layer 3 only could produce the least (128. 36 MS m3). The, the choice should be layer 1 only. Figures 4 and 5 confirm this suggestion. Layer 1 has the longest stable oil production rate with 50 m3 per day.

Fig. 3 Water Cut with Various Perforation Plans

Fig. 4 Cumulative Oil Production vs. Time with Various Perforation Plans

Fig. 5 Oil Production Rate vs. Time with Various Perforation Plans

Fig. 6 Average Reservoir Pressure with Various Perforation Plans

  • Critical Production Rate

To find an optimum or critical production rate, 4 more production rates have been tried, such as 30, 40, 50, 60, 70 m3 per day. Figures 6-9 show the water cut curves, cumulative oil production, oil production rate, and average reservoir pressure with various production rates.

Figures 7, 9, and 10 show that the less production rate, the longer oil produced, and the slower average pressure dropped. Those three figures could not tell which production rate is the best one, while Fig. 8, the cumulative oil production could. The pink curve which represents the oil production rate at 60 m3 per day is higher than any other, which is 130.98 MS m3.

Fig. 7 Water Cut with Various Production Rates

Fig. 8 Average Reservoir Pressure with Various Production Rates

Fig. 9 Oil Production Rate vs. Time

Fig. 10 Average Reservoir Pressure with Various Production Rates

  • Effects of Permeability Anisotropic Ratios

To find out the effect of permeability anisotropic ratios (kv/kh) on the performance of the well, 3 more ratios have been tried, such as 0.01, 0.5, and 1.0. Figures 10-13 show the water cut curves, cumulative oil production, oil production rate, and average reservoir pressure with various permeability anisotropic ratios.

All the figures show that the performance of permeability anisotropic ratio being 0.01 is significantly from those other three. At early time of production, the higher permeability anisotropic ratio, the earlier water breaks and the higher water cut is (Fig. 11). Since for the case that permeability anisotropic ratio is 0.01, the water break very late and water cut is lower than others at early time, water cut increases very fast, and reached the limitation fastest. At late time of production, there is no difference between 0.1, 0.5, and 1.0. From Figs. 13 and 14, the case that permeability anisotropic ratio is 0.01 has the longest stable production time, and lowest average reservoir pressure, because no cross flow exists. The permeability anisotropic ratio of 0.01 means fluid can only flow in horizontal direction, and pressure can effectively drive the fluid flow through the reservoir rock. That could be confirmed by the cumulative oil production data showed on Fig. 12 and Table 3.

Fig. 11 Water Cut with Various Permeability Anisotropic Ratios

Fig. 12 Cumulative Oil Production with Various Permeability Anisotropic Ratios

Fig. 13 Oil Production Rate with Various Permeability Anisotropic Ratios

Fig. 14 Average Reservoir Pressure with Various Permeability Anisotropic Ratios

Table 3. Cumulative Oil Production and Recovery with Various Permeability Anisotropic Ratios

Parameters Permeability Anisotropic Ratio
0.01 0.1 0.5 1.0
Cumulative Oil Production (MS m3) 133.92 130.98 129.08 128.99
Recovery (%) 44.377 43.400 41.430 42.743

Summary

  1. Perforating Layer 1 only and the liquid production rate is set up at 60 m3 per day is the optimum production plan.
  2. Lower permeability anisotropic ratio has better performance due to less cross flow.
Advertisements

Leave a Reply

Fill in your details below or click an icon to log in:

WordPress.com Logo

You are commenting using your WordPress.com account. Log Out / Change )

Twitter picture

You are commenting using your Twitter account. Log Out / Change )

Facebook photo

You are commenting using your Facebook account. Log Out / Change )

Google+ photo

You are commenting using your Google+ account. Log Out / Change )

Connecting to %s

%d bloggers like this: