Simulation model and history matching 95

This section will describe the simulation model which was used for the project. This simulation model was provided by the company. The number of cells is 237440 (128x53x35), the average individual cell size is 75x77x8 m. Mean porosity value is 0.27 and permeability is 911 mD; distributions of these parameters are presented in Figure 4.8.

Figure 4.8 Petrophysical properties including into UKCS field simulation model. Upper graph: porosity, lower graph:permeability. Reservoir properties are rather good.

According to Figure 4.8, the reservoir has a rather good properties which are very favorable for fluid flow. Net-to-gross distributions vary from 0.2 up to 1 in the model. Hence, the main controlling property for reservoir connectivity will be NTG; this is a good correlation with modeled depositional environment.

Figure 4.9 UKCS field kh grid in simulation model. Areas of improved properties are perfectly seen and correlated with the NTG grid.

The existing reservoir model for the UKCS field, provided by BP (Base Case model), simulates a black oil system. Pressure maintenance is presented by waterflooding. A rather weak aquifer is present on the western side (see Figure 4.10) of the field, providing the pressure support.

Matching the model

Initial geological interpretation is based on wireline logs and seismic attributes, but after each monitor survey we gather new data, which needs to be incorporated into the model. Hence, the seismic interpretation have been changed in order to satisfy the newly data after each monitor. The idea behind this is to make a cube of seismic differences, for each time slice pick seismic volumes with more or less the same attribute value, and then use them in geological and simulation modelling. These seismic volumes can be named – ‘geobodies’. This concept was presented at DEVEX 2010 (Martin & MacDonald, 2010). A special workflow was developed (see detailed description in Appendix). The final result was about 400 different geobodies (see Figure 4.11). According to this approach, a geobody has a dual- scaled definition:

In geophysics it is a 'small scale', seismically mapped discrete subdivision of the reservoir. In reservoir engineering it is a group of continuous cells in the model, characterised as being in the same transmissibility region (MULTNUM keyword in Eclipse; a description is presented in the Appendix).

Figure 4.11 Geobody distribution for the initial geological model (2009) (Martin and MacDonald 2010). Engineering domain geobodies.

Figure 4.12 Derived geobodies (for example, between green boundaries is one geobody). Geophysical domain geobodies. Lower figure: coloured inversion seismic data, zero phase, negative impedance is red (sand) (Martin and MacDonald 2010).

The reasons for using this method (according to Martin & MacDonald, 2010) are as follows:

1. The previous Full Field model was good but not adequate to capture the evolving understanding of field complexity shown by the sequential 4D seismic surveys and additional production data.

2. The field history predicts geobody connectivity as primary factor in understanding well performance and reservoir sweep.

The derived geobodies were then incorporated into the simulation grid (see Figure 4.13). Using this method is reasonable, as, for a highly compartmentalised reservoir, simulation is not realistic unless major flow units and communication between them have been quantified (Stewart, et al., 1988).

Figure 4.13 Geobodies in simulation model grid. Each colour reflects one separated geobody. Only the South- East simulation model is shown. Dark blue shows separate geobodies without any connections with others.

After incorporating the data, the next question is raised:

How is it possible to use this data in history matching? There are 3 ways to do this:

1. Vary transmissibility between bodies i.e. create an 'artificial' pathway for fluids (usually injected water). Actually, this is the most obvious way, from the geological point of view and results can be rather easily compared with production data: the velocity of the water goes from injector to producer, increasing water cut. Baffles on the boundaries of the geobodies can be explained by mud drapes or channel boundaries in the turbidite system. At the end of the day, this technique was the most applicable in this simulation model.

2. Vary transmissibilities within bodies. Here the same idea is used: it makes the water arrive at the right time to the producer, but for 100% validation of these changes it is necessary to have well test from well penetrating a particular geobody.

3. Vary pore volume within bodies. This procedure can also be implemented, but then there is a need to have additional control over STOIIP in the model, because porosity directly affects STOIIP.

of these is an isolated compartment without wells in it, just non-reservoir facies- shales. These have zero transmissibilities on each border, but pore volume within the body has not been changed. Although this seems reasonable, why is this the case? In the best case, these geobodies could be isolated compartments (parts of the reservoir) and contain hydrocarbons. But we cannot be sure about this until a well is drilled into this compartment.

Figure 4.14 Geobodies after excluding the 'dark blue' region. Now it is possible to see the regions which could be a fluid path, having permeability more than zero.

There is a clear example of the latter case. The most abundant body (in dark blue in Figure 4.12 and excluded from Figure 4.14) which is actually a border (conclude) all the pathways- should not be a compartment, although it can be according to the geology, but then, this should be shales, i.e. non-reservoir cells. So we cannot be sure about this and the engineers have decided not to make the pore volume of these cells equal to zero. Unfortunately, this approach has one weak side: using this manual approach, it is impossible to catch up all the small baffles and barriers within the geobody, but in fact, this should not have a significant

effect on fluid flow in the reservoir.

Figure 4.15 How the pathway was created. Red lines: barriers for flow. Red lines: pathway for injected water. Pointed geobodies (white lines) do not have connections to any other geobodies.

Figure 4.16 Well P2 water production rate history (blue dotted line) and base case simulation model results (red line). It is obvious that there is a lack of water in the well.

Figure 4.15 shows how a fluid pathway was created to solve the lack of water production in P2 (see Figure 4.16).

Let us see this example how one of these pathways shown in Figure 4.15 How the pathway was created. Red lines: barriers for flow. Red lines: pathway for injected water. Pointed geobodies (white lines) do not have connections to any other geobodies. The engineers have decided to make a pathway through the channel (which can be seen on NTG map: see Figure 4.17). There are two reasons for this choice: the NTG map and the 4D differences between M1 and BL highlight changes in this region. However, the interesting fact is that water breakthrough happened in P2, just after the time of M1, and I1 started injection about the same time; thus P2 was affected by water from I2, but this water went through the south part (this fact seen in the time-lapse data, as well). That means even though the matching is right (the simulation model reflects the history data), it cannot be geologically justified. Later, when I1 starts to inject, water was injected into this well, using the same channel to reach P2.

To sum up, the rationale of this method is the creation of an 'artificial' pathway for fluids between wells, with support from the geology.

Figure 4.17 Depositional environment and UKCS field main T31 sand reservoir. Higher NTG is highlighted in red. Seismic section A-A’ shows typical channel geometry of the NW-trending depositional system. The channels are cut by east-west trending faults (grey lines) (Gainsky, et al. 2010).

In other words, the reason, we should choose the channel as the pathway for injected water is obvious.

Figure 4.18 3D seismic cross-section along the P9 producer showing infill targets in T31U and T31L sands. The solid green lines are the completion intervals in P9. The blue curve shown along the well trajectory is the gamma ray log with vertical barriers indicated. The T31L sand is partially eroded by a younger channel (Gainsky, et al. 2010).

The 4D difference between M2 and M1 shows directly that changes occurred there. Nevertheless, the assumption, that this channel was the only pathway for water breakthrough to P2 can be argued. Let us examine the difference between BL and M1- along with the

from I2 (I1 was closed during that time period). It is possible to conclude that breakthrough occurred not through the channel, but in southern area, but that later, when I1 started injection, water flowed through the channel. So we need to be aware of isolating south region, thus avoiding oil sweeping from this area and water injection in it. At the least, the boundaries of the southern part geobodies need to be baffles, rather than barriers.

The final distribution of barriers and baffles used in matching is presented in Figure 4.19.

Figure 4.19 Sand barriers (black) and baffles (red) to flow used in matching (Gainsky, et al. 2010). Highlighted area- Segment 4- object of interest.