Controlling Water Inflows and Optimizing Production from an Oil Well Using Chemical Injection

For the past seven decades, oil has greatly been of use in homes, industries and for automobiles in most developed countries [1-6]. The existence of an adverse factor affecting oil production could have an impact on a country's economy and way of life [7, 8]. Several studies have shown that excessive water production is one of the main causes of a producing well's economic downfall, since the cost of separating, treating and disposing of produced water is a heavy burden on oil industry budgets [9, 10]. More than 40 billion dollars are spent annually on disposing of the excess water produced by the world's oil industry [11]. Excessive water inflow into an oil well has a negative impact on the well. Firstly, it leads to reservoir pressure decline which means the pressure available to drive oil towards the wellbore is lower than normal [12]. Secondly, water coning and channeling can take place whereby water from an underlying aquifer is drawn into the wellbore, leading to reduced oil recovery. Also, an increase in water production decreases the proportion of oil in the produced fluids. This high water cut means less oil is being produced [13]. In addition, treating, handling and disposing of produced water add to operational expenses since facilities must be designed or adapted to separate and manage the water, which can be costly. Moreover, in fields where waterflooding or other water-based enhanced oil recovery (EOR) techniques are used, managing excessive water production becomes even more critical. EOR refers to a set of techniques used to increase the amount of crude oil that can be extracted from an oil field. These techniques are employed after the primary and secondary recovery methods become ineffective. The primary method relies on natural reservoir pressure, and the secondary method typically involves water flooding to displace oil. EOR methods include thermal recovery, gas injection and chemical injection. Thermal recovery involves the introduction of heat, such as steam injection, to reduce the viscosity of the oil, making it easier to extract. Chemical injection involves injecting gases like carbon dioxide (CO₂), nitrogen, or natural gas to mix with the oil, reduce its viscosity, and push it towards production wells whereas chemical injection involves the injection of chemicals like polymers or surfactants to improve the mobility of the oil and increase its flow towards the production wells. Balancing the injected and produced fluids to optimize oil recovery can be challenging when there is excessive water inflow. High water production can mask the true performance of an oil reservoir, making it difficult to accurately assess reservoir properties and predict future production [14]. This complicates reservoir management and the design of production strategies. On the other hand, excessive water production during oil production can limit the life of oil and gas wells and can cause several problems including tubular corrosion due to high water salinity, fine migration and hydrostatic loading [15]. Therefore, a better understanding of water formation leads to a better perception of scientific progress and technological development in the oil and gas industry [16, 17]. Based on the hypothesis that the variation of the water cut (percentage of water production) would be an optimal parameter for justifying the phenomenon of water influx in a production well. This is the case for well X, and as soon as it came on stream in 2003, the oil production rate fell rapidly as a result of excessive water production. Several techniques can be used to improve production and the lifespan of well X. These include: the mechanical solution; the chemical solution and the completion solution [18-20].

Two researchers worked on water flow in the Jake field in south-east Sudan [21]. A few months after it came on stream, the water cut was up to 60%. This had an impact on oil production. A total of 14 MMBBL of water was produced up to the end of 2014. They injected nitrogen and lead into the reservoir to mitigate the inflow of water. This method reduced overall water production in the field from 60% to around 30%. But after a short period, water production started up again. So, to control the production rate from well X, would chemical injection be the best method of mitigating water inflow? The main aim of this paper is to test chemical injection as an effective method of mitigating water ingress. The specific objectives linked to achieving this aim are: to analyze the performance of the well prior to implementation of the method; to implement the method for controlling water inflow; to evaluate the performance of the well after implementation; and to evaluate the economics of the project. Two approaches are adopted for this study: nodal analysis and sensitivity analysis using Reveal and Prosper software. This paper is structured in 5 sections. Section 1 presents the introduction. Section 2 presents the methodology. Section 3 presents the data, the software used to achieve the objectives and the various results. Section 4 presents the results and discussion, and section 5 presents the conclusion.

Production, reservoir, pressure-volume-temperature (PVT) and well or completion data are presented in Tables 1 and 2.

Table 1. Production data of well X

Table 2. PVT, reservoir and completion data of well X

The production data shown in Table 1 illustrate the variations in water and oil production as a function of time. This will give a superficial idea of reservoir depletion and the monthly quantities of oil and water production. PVT, reservoir and completion data of well X are presented in Table 2.

The data in Tables 1 and 2 are analyzed using Reveal and Prosper software.

3.1 Nodal and sensitivity analyses

This subsection presents the results of the analysis of production, PVT, reservoir and completion data using nodal and sensitivity analysis methods. The study of initial well performance is presented in Figure 1.

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Figure 1. IPR and VLP of well X in the initial state

Figure 1 shows that 509.1 STB/day of liquid is initially produced, i.e., 71.3 STB/day of oil and 437.9 STB/day of water. It is clear that the water production rate is much higher than the oil production rate. Hence the problem of water coming in, which requires a chemical injection method to mitigate it. During the chemical injection method, 80,000 ppm of polymers and 2,000 ppm of gel are injected into well X over a period of 120 days. It is important to note that the injection operation is carried out at the same time as production. Figure 2 shows an illustrative model of the injection of polymers and gels into the reservoir.

Figure 2. Illustration of the injection of polymers/gels into the reservoir

The injection well is placed below the production well to make it easier to carry out the operation, as shown in Figure 2. This injection varies a number of parameters, in particular in: the well and the reservoir. This makes it possible to determine the impact of polymer and gel injection on the oil production rate. Figure 3 shows the variations in water and oil saturation as a function of time.

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Figure 3. Variations in water saturation and oil saturation

The increase in productivity as a function of time will lead to an increase in water saturation and a decrease in oil saturation as the reservoir is depleted, as shown in Figure 3. As in the reservoir, the injection of polymers and gels will also have a remarkable influence in the well. The impact of injecting polymers and gels into well X is characterized by the variation in 3 main parameters, namely: the flow rate of liquid produced, the flow rate of water produced and the flow rate of oil produced, the mass of gel produced and the viscosity of water produced. The variation in the quantity of water produced as a function of the quantity of polymer injected is illustrated in Figure 4.

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Figure 4. Variation in water production as a function of the quantity of polymers injected

When polymers are injected, the viscosity of the water increases due to the gelling of the water by the polymers. This increase will therefore have an impact on water production (see Figure 4). The increase in the quantity of polymers injected results in a decrease in the water production rate, as shown in Figure 4. This leads to an increase in the oil production rate. The variation in water viscosity as a function of time is illustrated in Figure 5.

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Figure 5. Variation in produced water viscosity

The viscosity of the water here reflects the ability of the water to move from the reservoir to the production well and then from the production well to the surface (see Figure 5). It is important to note that 29 days after chemical injection, the viscosity of the water varies between 373.44 Cp and 746.27 Cp. This makes it difficult to displace the water in favor of the oil, as shown in Figure 5. The variation in the flow rate of oil produced and the water cut (percentage of water production) as a function of time is illustrated in Figure 6.

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Figure 6. Variation in oil flow rate and water cut as a function of time

Figure 6 shows that on 31/03/2008, the water production flow rate is estimated at 3.6125 STB/day and the water cut at 72.25%, indicating high water production. However, after this date, it is important to note that oil production will increase considerably compared to the water cut due to water gelation. The variation in the flow rate of water produced and the mass flow rate of gel produced as a function of time is illustrated in Figure 7.

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Figure 7. Variation in the mass flow rate of gel produced and water produced as a function of time

It is important to note in Figure 7 that gel injection takes effect from 31/03/2008. This translates into gel production of 2,252.5 BM/d and 360 STB/d of water. These different production rates at the operating point can be quantified using the RPN and VLP curves. Figure 8 shows the IPR and VLP curves after injection of the polymers and gels.

Figure 8. IPR and VLP curve after injection of polymers and gels

Figure 8 shows that the oil production rate is much higher than the water production rate. For in 2,572.5 STB/day of liquid produced, there are 2,058 STB/day of oil and 514.5 STB/day of water with a water cut of 20%. This phenomenon is due to the lightening of the hydrostatic column as a result of the reduction in head losses and the increase in oil density.

3.2 Economic analysis

Table 3 shows total expenditures of the project.

Table 3. Total expenditures of the project

Total project expenditure is estimated at \$27,129,560 in Table 3. Table 4 shows the net present value (NPV) as a function of three selling prices per barrel of oil: \$50, \$78 and \$90.

Table 4. Variation in NPV as a function of three selling prices per barrel of oil

The results obtained in Table 4 are used to plot the variation in NPV as a function of time in Figure 9.

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Figure 9. Variation of NPV with time

Figure 9 shows that the project's return on investment will be 1 month after the well comes on stream. After the well is put into production, the project is profitable regardless of the selling price of a barrel of oil, as shown by the variations in profit: \$55,923,628 (selling price of a barrel of oil at \$50), \$93,557,825 (selling price of a barrel of oil at \$78) and \$131,192,022 (selling price of a barrel of oil at \$90).