Previous Parts

Part 1 - Overview

Part 2 - Reservoir Simulation Model

Objective

– Evaluate the benefits of waterflooding vs. primary depletion in our cross-section simulation model.

Reservoir Simulation Model Overview

Here, we provide some relevant details of the simulation model that we use.

• Simulation model type: cross-section (X-Z)
• Simulation grid: 100 x 1 x 20 grid cells
• Grid cell dimensions: Constant DX, constant DY, DZ varies by layer and equal to height of cross-section layers
• Only two phases present in the simulation model - oil and water
• Reservoir rock and fluid properties (PERMX, PERMY, PERMZ, PORO, Swi, …) vary by layer but are otherwise constant in each layer
• PERMX is the layer permeability in the X-direction and PERMY = PERMX
• PERMZ is the layer permeability in the Z-direction and is equal to 10% of PERMX
• All cells are active and each cell has a net-to-gross (NTG) ratio of 1.0
• All wells are simple, fully-penetrating vertical wells with zero well skin
• All wells have fixed well controls throughout duration of production
• Total production time is 15 years.

See Part 2 - Reservoir Simulation Model for description of the simulation model.

Introduction

In the previous post, we described the simulation model that we will use for waterflood performance evaluation. In this post, we focus on applying the simulation model to demonstrate the benefits of waterflood compared to primary depletion. The simulation models for depletion scenarions are similar except for the different well configurations and locations (arrangement of producer and injectors), and well control specifications (production and injection rates).

In the primary depletion scenario, the simulation model contains a single oil production well (producer). For waterflooding, we will consider two different scenarios with different number of water injection wells (injectors). All three production cases are described:

• Primary depletion (Case 1): The simulation model contains one producer located (approximately) in the middle of the model.
• Waterflooding (Case 2): The simulation model has one producer located (approximately) in the middle of the model, and two, identical injectors located at leftmost and rightmost grid blocks of the simulation model respectively. This case is similar to Case 1 except that we have added two water injectors to the model.
• Waterflooding (Case 3): The simulation model has one injector and one producer located at the leftmost and rightmost grid blocks of the model.

For consistency across the simulation models, we use the same total production and total injection rate across all cases. In case 2, each water injector has the same injection rate while Case 3, the single water injector has twice the rate of one the water injectors in Case 2.

The two waterflood cases will illustrate the effect of producer-injector distance, and the importance of including economics as part of our evaluations to enable proper scenario analyses. The net present value (NPV) in the two cases will be different even though the production profiles are similar.

In the next section, we describe the different simulation model and well configuration and well control specifications.

Simulation Models

In this section, we will describe the simulation model for each production scenario. There are three different simulation models corresponding to the three production scenarios described earlier, one for primary depletion and two models for the two waterflooding cases.

The simulation models are similar in all aspects except for the number of wells, the well locations, and the values of the well controls for the water injectors.

In the simulation models, all wells are fully-penetrating vertical wells, i.e., completed in all layers of the simulation model. A well location is specified as (I, J, K1-K2) where I and J are the grid block indices in the X- and Y-directions respectively, and K1 and K2 represent the start and end layers where the wells are completed.

The total field reservoir production and injection rate is set at 8,000 STB/D. These values correspond to an annual production of about 5% of the oil in place (STOIIP) in the simulation model.

In the next sections, we will describe each production case and the corresponding well configurations.

See Part 2 - Reservoir Simulation Model for additional details about the reservoir simulation model.

Case 1: Primary Depletion - One Producer

The simulation model for this case contains only the producer located in grid block (50,1,1-20). The control type for the well is reservoir voidage rate and the value of the control is 8,000 STB/D.

The well configuration schematic for this case is shown in Figure 1. It is important to note that there is no water injection in this case and the simulation model does not contain any aquifer. The source of reservoir energy is from the expansion of the oil.

Figure 1: Case 1: Well configuration for primary depletion.

Case 2: Waterflood - One Producer + Two Injectors

The simulation model for this case contains the producer in the same location as in Case 1, but the two water injectors are completed at the leftmost (1,1,1-20) and rightmost (100,1,1-20) grid blocks respectively (see Figure 2). The producer has the same well control type and control value (8,000 STB/D) as in Case 1. The two injectors each have reservoir injection rate control and the control value is set at 4,000 STB/D. The simulation model for this case contains three wells.

Figure 2: Well configuration for waterflood (Case 2) - 1 producer + 2 water injectors.

Case 3: Waterflood - One Producer + One Injector

The simulation model contains one injector at the leftmost grid block (1,1,1-20) and one producer at the rightmost grid block (100,1,1-20). Both wells are operated under reservoir voidage control and the production rate and injection rate are set at 8,000 STB/D. The well configuration for this case is shown in Figure 3.

Figure 3: Well configuration for waterflood (Case 3) - 1 producer + 1 water injector.

The main difference in the above simulation models is the number of wells and the well locations. Also, since we are including economic model in our performance evaluation, the three different cases will have a different total well costs which would be reflected in the economic calculations.

For simplicity, we have assumed that the drilling and completion cost per well is the same in all cases. In addition, all wells are assumed to be pre-drilled and ready for production/injection at the start of production.

Simulation Runs and Results

Simulation Runs

We perform simulation runs for all three models. After each simulation run, the net present value (NPV) is computed using the production profiles and the economic parameters defined previously.

The full simulation workflow (build model, run simulation, post-processing) takes about 12 seconds.

Simulation Results

Table 1 shows a summary of important production parameters

Nomenclature

- WC           = Water cut, Fraction
- WOR          = Water-oil ratio, STB/STB
- COP          = Cumulative oil produced, STB
- CWP          = Cumulative water Produced, STB
- CWI          = Cumulative water Injected, STB
- RF           = Oil Recovery Factor, %
- NPV          = Net present value, $
- PORO         = Grid cell porosity, Fraction
- PERMX        = X-direction grid cell permeability, md
- PERMY        = Y-direction grid cell permeability, md
- PERMZ        = Z-direction grid cell permeability, md
- NTG          = Net-to-gross ratio, Fraction
- STB          = Stock Tank Barrels, volume unit
- STOIIP       = Stock Tank Oil Initially In Place, STB