WATER FLOODING

Water flooding for EOR candidate reservoirs is important to be done. Some literature suggest that solution gas drive reservoir is the best candidate for water flooding. The water will sweep remaining oil which is left by primary recovery between wells due to lack of reservoir pressure. However, there is possibility that the reservoir pressure is still high but the oil is immobile due to low mobility and loss solution gas during depletion period. By doing water flooding, pay continuity will be concluded which will reduce risks during EOR operation.

The target reservoir contains 31.93 MMSTB of oil with 10% oil recovery after 27 years of production.  The gross pay of the reservoir which is mostly shaly limestone is 45 m average.  The primary drive mechanism in the reservoir is fluid expansion drive (solution gas drive) with very low water influx. Production from the reservoir is characterized by high initial rate with high rate decline. Currently, mostly wells producing from the reservoir suffer water blocking where water is encroaching the wells and is saturating around the wellbore.

The oil has 35 API gravity with 211 scf/stb cumulative GOR (black oil). Initially, the oil moved 2.1 times slower than water. At pressure around 900 psi, the oil moved more slower and  was left by water which saturated the vicinity of the wellbores.  The wellbores have then suffer high water cut production (more than 95%) until economic limit is reached. However, when a new well is drilled in new location (such as only 15 meters away, well C1 on Figure 5), the  well produces fluid with water cut much lower (60%) even the perforation is lower than the 95% water cut wells (well B and B1 on Figure 5). This indicates that much oil which cannot move to water-blocked wells is still left between wells .

Water flooding model

The model is based on frontal displacement theory which was developed by Buckley and Leverett in 1942. The fractional flow equation and frontal advance equation in the theory are applied for radial flow model. Both equations are presented here:

Fractional flow equation:

Frontal advance equation:

To solve fractional flow equation, data permeability vs water saturation is required from core analysis (Figure 1). For simplifying, capillary pressure effect is neglected.  Both graphs of fractional flow equation and frontal advance equation are plotted on the same scale (Figure 2). The effect of injection is evaluated in three phases:

1. Phase 1: Solving water blocking around wellbore of producers, no noticeable water cut change in the producers.

2. Phase 2: Stabilizing water cut, water cut in the producers gradually decrease.

3. Phase 3: Stabilized water cut, water cut in the producers relatively constant until water breakthrough.

Phase 1 will be last for 7.6 days without noticeable water cut change in the producers. Water cut will gradually decrease to 73%. This production profile will be stable until water breakthrough or 314 days. Figure 3 shows cross section front movement and Figure 4 shows radial front movement.

Figure 1: Permeability vs water saturation

Figure 2: Solving fractional flow equation and frontal advance equation

Figure 3: Cross section front movement

Figure 4: Radial front movement

Effect of well A (injector)

Refer to top structure map on Figure 5. The structure is relatively plate with around 250 m of distance between wells. Well A have been injected for quite long. Total 261 Mbbl of water have been injected since 2009 with average rate of 575 bwpd. The injection phases in well A1 and A3 is not distinguishable. However, based on the model above, phase 2 had been finished in 30.5 days or after 101 Mbbl (5.1% PV) of water injected and phase 3 have remained until water breakthrough reached or after injecting 1039 Mbbl (53.1 % PV) of water. Rate declines on Figure 6 and Figure 7 show clearly the effect of injection in well A where both rate declines are negative. Water cut of both wells tend to decrease to 73% and oil productions keep increasing. Noncontinuous injection to well A due to unreliable production facility results in low horizontal sweeping efficiency. “Stop and go” situation during injection with low injection rate (575 bwpd average) has allowed water to escape to aquifer naturally and leaves oil on top building water-oil layer in the reservoir.  Continuous injection with high rate (2000 bwpd) will solve the problem.

Figure 5: Top structure

Figure 6: Rate decline well A1

Figure 7: Rate decline well A3

Estimated production

Current field production is 270 bopd with only well A as injector. By converting well B, C and D into injection well, the field will loss 30 bopd. After 30.5 days, the production will climb up to 560 bopd where every injection cluster contribute between 50 and 125 bopd each.

Future development

After injecting water for 314 days or 53.1% PV, all producers will water-out. Continuing water injection will uneconomically visible. However, from the previous project, pay continuity had been concluded. Moreover, well A as injector connect to well A1 and well A3 as previously discussed. IOR or EOR is the next step for exploiting the reservoir. By adjusting the completion of wells to make the injector closer to producers by means of horizontal radial drilling will improve oil recovery (IOR). Adding chemical such as surfactant into injected water will enhance oil recovery (EOR). Injecting water+chemical immediately after 15% PV of water injected will decrease pumping cost and processing costs.

In current patent by BP Exploration Operating Company Ltd.,  water with certain ionic concentration will give better performance in case of horizontal and vertical sweep. It is concluded that 500 to 5000 ppm of certain ionic concentration will increase oil recovery. To achieve such concentration with certain ionic concentration, a reverse osmosis plant and high salinity source water are required. The plant will need at least 0.1 MPa of pressure higher than osmotic pressure of the membrane to get reverse osmosis effects. To fulfill 2000 bwpd injection rate, around 30 square meters of osmotic membrane are needed.

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