Energy lost study for the steam and solvent assisted gravity drainage process, using reservoirs with Brazilian northeast characteristics

In Brazil, especially in the Northeast, there are still reservoirs containing heavy oils that are being operated by smaller companies that need to produce the fields, reducing production costs. There are different processes to recover heavy oil, one of which is steam and solvent assisted gravity drainage process, which uses two parallel horizontal wells, where the injector is placed above the producer. In this process, a solvent can be used with the steam, to try to reduce the steam rate injected. Process is carried out by injecting a hydrocarbon additive in low concentration together with steam. Steam contributes with the heat to reduce oil viscosity and solvent helps with miscibility, reducing the interfacial tension. The main force acting in this process is gravitational. The mobility of the displaced fluid is then improved, which may imply at an increase of oil recovery. In this study, a semi-synthetic model was analyzed, with average characteristics of the Brazilian northeast, where there is heavy oil in onshore reservoirs. Several simulations were carried out using a commercial oil reservoir thermal simulation software, where the influence of some operational parameters on oil recovery and energy in the reservoir were verified. The main objective of this study was to find a distance between producer and injector wells that allows reducing heat losses to the overburden and underburden when solvent and steam are injected into the process. It was found an optimal vertical distance to improve oil recovery.


Introduction
Oil is still part of the planet's energy sources, forming part of the Brazilian energy matrix.Therefore, technologies that involve the development and application of techniques capable of increasing the profitability of oil fields are important and require further study.Hence, through numerical simulation of reservoirs, different studies can be carried out at low cost and still provide convincing results (Silva et al., 2023;Silva et al., 2022).At a regional level, Rio Grande do Norte has large reserves of heavy oil.Although a significant part of these reserves has already been produced (mature fields), there is always a search for new technologies and supplementary recovery methods being studied, tested, and implemented with the aim of maximizing the amount of oil recovered from the reservoir (Silva, 2016;Barillas, 2008;Barillas et al., 2006).
Among the thermal methods used to recover these resources, continuous steam injection has become one of the main economically viable alternatives for heavy oils fields (Chai, et. al, 2023).The latent heat carried by the steam heats the oil in the reservoir, reducing its viscosity and facilitating its production (Dong et. al 2019, Li & Mamora, 2010;Galvão, 2012).
An alternative used to increase efficiency in thermal methods has been the addition of solvents to the injected steam (Jha et al., 2013).Solvents are light hydrocarbons that have the property of reducing interfacial tensions and facilitating oil production (Chai, et. al, 2023).Experimental results, numerical studies and field tests suggest that great benefits can be achieved with the addition of solvents to injected steam (Chang, et. al, 2013, Zargar, & Farouq Ali 2020), such as increasing oil flow rates and oil-steam ratios, reducing water and energy consumption for generating steam, reducing the emission of greenhouse gases (Nasr et. al 2002;Nasr et. al 2003;Praxedes & Barillas 2023).
Steam and solvent injection assisted gravity drainage (ES-SAGD) is a combination of a thermal method with a miscible method (Lyu et. al 2023), where the addition of solvent is a resource used to increase thermal efficiency in relation to steam assisted gravity drainage (SAGD), (Wu et. al 2020).
For a better understanding of the process, and to verify the expansion of the steam-solvent chamber, a two-dimensional model was chosen in the reservoir to perform an energy analysis of the steam and solvent injection for different vertical configurations between wells, with the purpose of verifying the influence of steam and solvent injection on oil recovery with the aim of reducing energy losses (Silva 2016;Praxedes & Barillas 2023).The main objective of this study was to find a distance between producer and injector wells that allows reducing heat losses to the overburden and underburden when solvent and steam are injected into the process.

Methodology
In this study, a semi-synthetic model was analyzed, with characteristics from the Brazilian northeast.The fractions of the pseudo-components used in the fluid model can be seen in Table 1.This hydrocarbon mixture has an average viscosity of 819 cP for the initial conditions of reservoir temperature and pressure.The solvent studied was C7 and its characteristics can be found in Table 2.The values shown in Tables 1 and 2 were used within the fluid model used in the 2D reservoir modeling, the composition of the oil corresponds to reservoirs in northeastern Brazil.The modeling of the homogeneous reservoir containing heavy oil has an area of 150m x 20m (2D model) and an oil pay net thickness of 28m (28m oil zone and 2m water zone).Figure 1 shows the reservoir (2,250 blocks), and the dimensions considered, and Figure 2 shows a frontal view of the reservoir, where the location of the producer well and the injector well (IK-view) in the reservoir can be seen, (You et al, 2012).Table 3 Shows rock reservoir properties.This information is necessary to be inserted into the reservoir model that will be simulated in a commercial software that allows analyzing the influence of some operational parameters on oil production, among others.

DV = 23m
Injector well producer well Operational conditions of the wells, used in the base model, are in Table 4.This information is necessary to be inserted into the reservoir model that will be simulated in a commercial simulator that allows analyzing the influence of some operational parameters on oil production, among others.
Energy lost (joules) to the overburden and underburden layers of the reservoir was calculated by Equation 1: An analysis of cumulative oil was carried out for different operational conditions was analyzed, and in founded which system has a higher heat loss.To carry out this study, a 2D reservoir was modeling, then some operational parameters were analyzed.Objective function of this study were oil recovery and heat loss primarily.This is the used methodology (Barillas et al., 2006;Praxedes & Barillas 2023): 1. To model a 2D reservoir.

2.
To analyze some operational parameters to see influence on oil recovery, oil rate and heat loss.
o With solvent (25% of solvent over steam rate).
3. To calculate NPl and heat loss.
4. To find a mathematical model.

5.
To analyze oil recovery and heat loss.

Results and Discussion
This section presents the results of the simulations carried out for two steam injection flows with and without solvent (they have already been optimized in the process).The solvent is injected at reservoir temperature.The study was carried out by analyzing the vertical distance (DV) between the wells (injector and producer) -Dv: 7m, 9m, 12m, 15m and 23m, for two steam injection flows with and without solvent.
Figure 3 shows oil rate production versus time for different vertical distances studied, cases without and with addition of 25% solvent (25% above steam injection).The beginning of production (first 365 days) was analyzed, as it was in the first year that there was a breakthrough from the oil bank to the producing well with the addition of the solvent.The case studied corresponds to a steam injection rate of 25 m³/day.
For steam injection rate of 25 m³/day, it was observed that the anticipation of the oil bank happened first, for cases without solvent (0% solvent), at all vertical distances (DV), however, with the increase vertical distance, when solvent is injected, the maximum oil rate of is greater.This is a result of the miscibility between solvent and oil, when injecting solvent with steam it delays the oil displacement to producer well but achieves a better sweep of it.Same analysis was carried out using an injection rate of 12.5 m 3 /day and with the same 25% of solvent injected (over this mass of steam), in this case due to the lower steam injection flow, there was an anticipation of the bank of oil when solvent was injected, unlike the previous case, for different vertical distances between wells.This can be seen in Figure 4.In this case there was a smaller amount of steam injected, this influences the heat injected into the reservoir, which in this case is smaller (half for the same reservoir), and the process is then more influenced by the miscibility of the oil solvent, so solvent injection benefits the anticipation of the oil bank in the producer.
Maximum oil rate peaks are higher in the case of higher injection flow rates, this is expected due to the greater energy injected into the system.Knowing the oil anticipation in a process is important to have an idea of the project's economics.Source: Authors.
Figure 5 (A) compares a view of the steam chamber, where the oil viscosities can be seen, (steam injection rate of 25 m³/day) without addition of solvent, and Figure 6 (B) with the addition of solvent .It is possible to observe that the oil arrives more quickly when no solvent is added (Figure 6 -A), there was greater heating due to the mass of steam that was injected, and it can be seen that there was a faster arrival of the oil bank or anticipation thereof in this case.
In the case of Figure 6 (A), which shows a smaller steam injection (12.5 m³/day) without solvent, it can be seen that the oil bank arrives faster when solvent is added to the system (Figure 6 -B).In this case the solvent/steam mixture is colder, oil viscosity in the system is greater than in the case of Figure 6 (A and B), but the solvent helps in mixing with the oil, due to its miscibility with it, the which allows it to reduce its viscosity, and in this case reaching the producer well more quickly when is using solvent.The study shows that a smaller amount of steam can be used, but solvent must be injected to reduce oil viscosity inside the reservoir by the same amount.
After this study, an energy analysis was carried out to find out which vertical distances lost the most energy to the overburden and underburden layers of the reservoir, using Equation 2shown in the methodology.The injection rate analyzed was 12.5 m³/day of steam and 25% solvent.
Figure 7 shows the energy lost to the overburden and underburden layers of the reservoir over time, for the different distances between wells studied (DV), with and without solvent addition.It can be observed that the addition of solvent causes heat losses to be lower when compared to cases without solvents (for all cases studied), showing that the injection of solvent helps to reduce energy losses to the overburden layers and underburden reservoir.Source: Authors.
It was observed in Figure 7 that the increase in the vertical distance between wells (DV) increases heat losses to the overburden and underburden layers, which was to be expected since they are closer to the upper layer.
Figure 8 shows the energy lost in the reservoir and the recovery factor, in 10 years for the cases studied previously.In Figure 8, it can be observed the increase in heat losses with the increase in vertical distance (DV), seen previously, but it can also be seen that the oil recovery factor is greater when steam and solvent are injected.Source: Authors.
Two mathematical models were carried out for the recovery factor with and without solvent, both over 10 years, one linear model (Equation 4) when is used solvent and other quadratic model (Equation 5), when is not used solvent in the process.
Figure 9 shows the energy lost in the reservoir and the recovery factor, in 20 years for the cases studied previously.In this figure, heat losses increase with increasing vertical distance (Dv), and the oil recovery factor is greater when steam and solvent are injected.Source: Authors.
Two mathematical models were carried out for the recovery factor with and without solvent, both over 20 years (Equation 6 and Equation 7).

Figure 1
Figure1shows that the dimensions of the reservoir used in the study are compared to reservoirs in the Potiguar basin, in terms of oil netpay and area exposed to gravitational drainage.The idea of using the 2D model to observe the formation of the vapor chamber, important in the steam-assisted gravity drainage process.

Figure 5 and
Figure5and Figure6show a steam chamber in a 2D-view for oil viscosity at vertical distance between wells (DV) of 15m on the same date for the four cases, with and without solvent.With steam injections rates of 25 m³ std/day (Figure5) and 12.5 m³ std/day (Figure6), respectively.

Figure 5 -
Figure 5 -Steam chamber, a comparison of oil viscosity for a vertical distance -Dv= 15 m, at a steam injection rate of 25 m³/day.Without solvent (A) / With solvent (B).

Figure 6 -
Figure 6 -Steam chamber, a Comparison of oil viscosity at a vertical distance -Dv of 15 m, at a steam injection flow of 12.5 m³/day.Without solvent (A) / With solvent (B).

Figure 7 -
Figure 7 -Energy lost analysis for different vertical distances between wells (DV) with steam rate of 12.5 m³/day and 25% solvent.

Table 2 -
Properties of C7 solvent used.

Table 3 -
Rock-reservoir properties and other values.

Table 4 -
Operational conditions of case base.