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Enhanced Hydrocarbon Recovery/Recuperación Mejorada de Hidrocarburos/ Recuperação Aprimorada de Hidrocarbonetos
Use of fiber optic sensors to evaluate the performance of injection wells in a polymer injection pilot project, Orinoco Basin, Venezuela
Use of fiber optic sensors to evaluate the performance of injection wells in a polymer injection pilot project, Orinoco Basin, Venezuela
Uso de sensores de fibra óptica para evaluación del desempeño de pozos inyectores en proyecto piloto de inyección de polímeros, Cuenca del Orinoco, Venezuela
Uso de sensores de fibra óptica para evaluación del desempeño de pozos inyectores en proyecto piloto de inyección de polímeros, Cuenca del Orinoco, Venezuela
Uso de sensores de fibra óptica para avaliar o desempenho de poços de injeção em um projeto piloto de injeção de polímero, Bacia do Orinoco, Venezuela
Uso de sensores de fibra óptica para avaliar o desempenho de poços de injeção em um projeto piloto de injeção de polímero, Bacia do Orinoco, Venezuela
Ivón Ulacio
IngºPetº, MSc, Dr. e-mail: ivonulacio@gmail.com
Andrés Ramírez
IngºPetº, MSc. e-mail: ramirezandr@gmail.com
Gonzalo Rojas
IngºPetº, PhD. e-mail: garojas45@gmail.com
Edgar Vásquez
IngºPetº. e-mail: emvb26@hotmail.com
Recibido: 5-10-24; Aprobado: 15-11-24
Abstract
Evaluating injection well performance is critical in polymer flooding projects for enhanced oil recovery. This paper presents a case study in an extra-heavy oil reservoir with an average viscosity of 4,150 cP, where a 1,600-ppm polymer solution was injected from 2017 to 2020. A distributed temperature sensor (DTS) was employed to evaluate the effective injection length, identify bypassed zones, and diagnose well behavior. The estimated effective length was compared with the static model and DTS data, and injection rate distribution was analyzed through pressure tests. Results indicate that approximately 30% of the well's horizontal section received the polymer solution, allowing the identification of potentially unswept areas. This information contributes to a better understanding of the well-reservoir interaction, improving the accuracy of simulation models, decision-making processes, and well-performance evaluation. Identifying bypassed zones and estimating volumetric sweep efficiency are crucial to optimize oil recovery in polymer flooding projects.
Resumen
Resumen
La evaluación del rendimiento de los pozos inyectores es crucial en proyectos de inyección de polímeros para la recuperación mejorada de petróleo. Este trabajo presenta un caso de estudio en un yacimiento de petróleo extrapesado con una viscosidad promedio de 4.150 cP, donde se inyectó una solución de polímero de 1.600 ppm desde 2017 hasta 2020. Se empleó un sensor de temperatura distribuida (DTS) para evaluar la longitud efectiva de inyección, identificar zonas by-passed y diagnosticar el comportamiento del pozo. Se comparó la longitud efectiva estimada con el modelo estático y los datos del DTS, y se analizó la distribución de la tasa de inyección mediante pruebas de presión. Los resultados indican que aproximadamente el 30 % de la sección horizontal del pozo recibió la solución polimérica, lo que permitió identificar áreas potencialmente no barridas. Esta información contribuye a una mejor comprensión de la interacción pozo-yacimiento, mejorando la precisión de los modelos de simulación, la toma de decisiones y la evaluación del rendimiento del pozo. La identificación de zonas by-passed y la estimación de la eficiencia de barrido volumétrico resultan claves para optimizar la recuperación de petróleo en proyectos de inyección de polímeros.
Resumo
Resumo
A avaliação do desempenho de poços injetores é crucial em projetos de injeção de polímeros para recuperação avançada de petróleo. Este artigo apresenta um estudo de caso em um reservatório de petróleo extrapesado com viscosidade média de 4.150 cP, onde uma solução polimérica de 1.600 ppm foi injetada de 2017 a 2020. Um sensor de temperatura distribuída (DTS) foi empregado para avaliar o comprimento efetivo de injeção, identificar zonas by-passed e diagnosticar o comportamento do poço. O comprimento efetivo estimado foi comparado com o modelo estático e os dados do DTS, e a distribuição da taxa de injeção foi analisada por meio de testes de pressão. Os resultados indicam que aproximadamente 30% da seção horizontal do poço recebeu a solução polimérica, permitindo a identificação de áreas potencialmente não varridas. Esta informação contribui para uma melhor compreensão da interação poço-reservatório, aprimorando a precisão dos modelos de simulação, os processos de tomada de decisão e a avaliação do desempenho do poço. Identificar zonas by-passed e estimar a eficiência de varrimento volumétrico são cruciais para otimizar a recuperação de petróleo em projetos de injeção de polímeros.
Palabras clave/Keywords/Palabras-chave:
Bom, desempenho, desempeño, fibra óptica, flood, injeção, inyección, mobilidade, mobility, optical fiber, performance, pilot, piloto, polímeros, polymer, pozo, reservoir, reservatórios, temperature, temperature, well, yacimiento.
Citar así/Cite like this/Citação assim: Ulacio et al. (2024) o (Ulacio et al, 2024).
Referenciar así/Reference like this/Referência como esta:
Ulacio, I., Ramirez, A., Rojas, G., Vásquez, E. (2024). Use of fiber optic sensors to evaluate the performance of injection wells in a polymer injection pilot project, Orinoco Basin, Venezuela. Geominas 52(93). 47-54.
Introduction
The field where the polymer injection pilot project was carried out belongs to the Orinoco Oil Belt. The reservoir is mainly unconsolidated sandstone of the Miocene age, from which oil of 8.5 °API is produced. After reaching the production plateau, efforts have been made to apply enhanced oil recovery technologies, which could be an efficient solution to increase the recovery factor and revitalize the field. One of these possibilities is polymer injection technology.
After carrying out the preliminary set of pre-project evaluations and obtaining promising results from laboratory analyzes similar to other publications [1], it was decided to carry out a pilot test in a field area, where the conditions did not show interest in applying any thermal recovery technique. The reservoir pressure at project initiation was 315 psia, reservoir temperature 115.5 °F (46.39 °C); average porosity of 0.32; the absolute permeability of the reservoir is estimated between 25 and 15 Darcy, and the thickness of the reservoir is 25'. Oil mobility is very low due to very high viscosity, estimated at 4,150 cP based on PVT data (reservoir conditions: 115.5 °F (46.39 °C) and 315 psia). The reservoir is a hydraulic unit, given the salinity results of produced water samples [2] and petrophysical correlation.
The polymer injection was carried out through three injection wells (Well AA06, AA07, AA08), each affecting two production wells (AA01, AA02, AA03, AA04). See figure 1, location of the wells.
Figure 1. Location of the injectors well regarding the producing wells.
The objectives of the control plan in this phase are the following:
– Establish which part of the horizontal section contributes to the injectivity of the well.
– Estimate the distribution of the injection profile.
– Evaluate if there are important changes during the injection.
The objective of the pilot project is to provide quick answers to questions about injection performance, polymer stability, and the effect of heterogeneities, among others. The results will determine whether the technology represents a feasible opportunity for future development of the field.
Well Completion
The horizontal wells drilled for the project have a maximum measured depth (MD) of 4,650 feet (1.42 km); vertical depth (TVD) averages 1,550 feet (0.47 km). The average thickness of the reservoir is 25 feet (7.62 m) and the average absolute permeability is between 15 and 20 Darcy. A diagram of the injection wells is presented in figure 2.
Figure 2. Well schematic.
Figure 3. Temperature measured in each of the injector wells.
The wells are equipped with fiber optic sensors and four pressure and temperature sensors (Fig. 2). The optical fiber has two ends because it was necessary to have a good temperature measurement along the horizontal section. The sampling period of the fiber optic sensors is every 5 min, at that time, the temperature is measured every 1.5 feet (45.72 cm) from the wellhead to the bottom of the horizontal section.
The pressure and temperature sensors are connected to the injection line and, as far as possible, placed at the same distance apart.
Baseline of the studied area
Before starting the injection, temperature, and pressure were recorded. The temperature measured by the fiber optic sensor was 115.5 °F (46.39 °C) (horizontal section, see figure 3), and the measured pressure was different in each sector, as shown in figure 1.
The injected fluid has an average temperature of 102.2 °F (39 °C); the difference between the injected and the reservoir fluid is 13.3 °F (-10.39 °C), which is enough to determine the sections in the horizontal well where the fluid is entering the reservoir.
Reservoir simulation established an optimal injection rate of 2,000 bbls/d, with a viscosity at reservoir conditions of 80 cP. The studies also showed that a high restriction at the beginning of the injection was possible, so the local pressure was expected to reach 550 psi after 1 month of injection. To avoid entering an injection regimen where dilation of the reservoir rock was possible, the injection rate was controlled and maintained below 2,000 bbls/d.
The simulation studies using water as the base fluid showed that only a short section of the horizontal well was necessary to receive the entire planned injection rate. In the case of well A06, a short section of 120 ft (36.58 m) was enough to inject all the fluid, given the high permeability of the reservoir. Figure 4 shows the results of one of these simulations, where the blue line represents the temperature profile of the horizontal section of the well during injection, as you can appreciate the temperature after 3,200’ is equal to 116 °F (46.67 °C), which is the same as the reservoir temperature, this indicates that no fluid is entering beyond this point.
Figure 4. Simulation results for well A06.
Figure 5. Apparent viscosity at a given shear rate.
It was expected that the viscosity of the injected fluid would affect the injection profile in the reservoir. At downhole conditions, the expected velocity was in the order of 0.279 ft/s (shear rate below of 1 sec-1), and a viscosity of 623.54 cP was expected [3], considering a polymer solution with a concentration of 1,500 ppm. This may have caused a positive conformation effect in the near-wellbore area. Figure 5 shows the relation between the shear rate and the apparent viscosity of the polymer solution employed in the project.
Control and Surveillance Plant of the Project
The operating parameters that were established as variables to be recorded during the project evaluation cycle were selected according to the risk assessment carried out at the beginning of the project, as described in other publications [4]. Every 3 months, a falloff was scheduled in the injection wells to evaluate the mobility of the polymer solution in situ and injection profile.
The principle of temperature logging is simple: a disturbance is created to detect changes that could be interpreted and related to reservoir features [5, 6, 7, 8]. For example, the disturbance could be a change in the injection rate or a shut-in followed by a restart of the injection or the reverse. The changes in the temperature are related to:
– Zones where most of the injected fluid is entering in the formation.
– Velocity of the fluid in the horizontal section.
– Leaks behind the casing or migrations.
Temperature log interpretation
Five falloff tests were carried out in 2017. Here we show the results in the case of well A06.
In well A06, we have a horizontal section of 1,440 ft (0.44 km) with a volume of shale (Vsh) of 0.148 fraction. The well was completed with a slotted liner of 500 μm (0.02 in). All the horizontal section was expected to receive the injected fluid, so after 3 months of injection, a falloff was performed; the event lasted 3 days.
Well A06
A 3D graph of the falloff results is shown in figure 6. The temperature profile before and after the shut-in is presented in figure 7. The blue line represents injection, and the magenta represents the shut-in. During shut-in, the average temperature is 105.6 °F (40.89 °C). Almost no change in the temperature profile is observed during injection (103 °F (39.44 °C) average); which could lead to the interpretation that all the horizontal sections in receiving polymer solution. At the end of the horizontal section, the temperature profile is similar to that of the shut-in period, meaning that it is warmer than the rest of the section. However, taking a more detailed approach to analyzing the temperature profiles during shut-in, it is observed that the section towards the end of the well tends to warm up more quickly with time. This indicated that the heel of the horizontal well is the part where most of the injected fluid enters the reservoir. Figure 8 shows the temperature profile changes during the first 2 h after the injection was restarted; every trace represents a different temperature profile at a different time. After observing the temperature profile for at least 10 h, it was evident that the last part of the well showed almost no change with time, so this zone was not receiving any fluid.
Figure 6. Event sequence in injector well A06.
Figure 7. Temperature profiles: Injection (magenta) and shut-in (blue) cases.
Figure 8. Changes in the temperature profile after injection restart.
Every curve represents a different temperature profile at a different time.
Figure 9. Hot fluid bank location, well A06.
Two zones appear to be contributing to the injection; the first is from 3,133 ft (0.95 km) to 3,405 ft (334 ft long), and the second is from 3,656 ft (1.11 kilometers) to 4,089 ft (285 ft long). Considering a geothermal temperature at the current depth of 116.6 °F (47 °C), the first section was taking approximately 35.7% of the injected fluid, and the second was receiving 64.3%. The effective length is estimated to be around 619 ft (0.19 kilometers).
During shut-in, some part of the polymer solution which is located in the vertical section gets heated by its surroundings, when injection is restarted the location of the hot fluid as it moves in the well can be obtained by tracking the change in the temperature profile. Figure 9 presents the results. The fluid velocity decreases as the depth increases; this means that there is less fluid moving inside the casing. In the end, the fluid velocity is reduced almost to zero. This supports the conclusion that the last part of the horizontal section is not taking fluid, and its decrease in temperature is due to the thermal conductivity of the completion and the reservoir. The most important reduction in velocity occurs after 3,700 ft (1.13 km), which is consistent with the estimation of the amount of fluid entering in the second section.
There is no significant change observed in the reservoir properties between 3,400 ft (1.04 km) and 3,600 ft (1.1 km). Therefore, the decrease in the injectivity profile must be related to unintentional skin caused during the drilling of the well (formation damage). These findings were considered in the calculation of the effective mobility, where the effective length and skin presence are included in the validation of the results. Also, for the future of the project, these data will influence drilling activities and well design and support decisions that will increase the productivity of the project.
Conclusions
· The fiber optics technology proved useful to avoid misinterpretation during fall-off and injectivity tests.
· The low velocities observed in the horizontal section favor an increase in the apparent viscosity of the injected fluid.
· The injection profile in the case presented shows a preferential fluid entry in the first half of the horizontal section, 619'.
· The well A06 appears to be damaged to some extent; therefore, care must be taken when drilling new wells. Increasing the effective length should be a priority for the extension of the project.
References
[1] Fabbri, C., Cottin, C., Jimenez, J., Nguyen, M., Hourcq, S., Bourgeois, M., & Hamon, G. (2014, January 19). Secondary and Tertiary Polymer Flooding in Extra-Heavy Oil: Reservoir Conditions Measurements - Performance Comparison. International Petroleum Technology Conference. doi:10.2523/IPTC-17703-MS
[2] Castro Yefrenck, Izarra Numan. "Presentación ATE 2016 Petrocedeño". Pdvsa Intevep.
[3] Carrasquero Migdalia, Castro Yefrenck. "Estudio de estabilidad química y térmica de soluciones poliméricas para el proyecto piloto de inyección de polímeros en Petrocedeño". Pdvsa Intevep año 2018.
[4] Manichand, R. N., Mogollon, J. L., Bergwijn, S. S. et al. (2010). Preliminary Assessment of Tambaredjo Heavy Oilfield Polymer Flooding Pilot Test. Presented at the SPE Latin American and Caribbean Petroleum Engineering Conference, Lima, Peru, 1-3 December. SPE-138728 MS. https://doi.org/10.2118/138728-MS.
[5] Aslanyan, A., Wilson, M., Al Shammakhy, A. et al. (2013). “Evaluating Injection Performance with High-Precision Temperature Logging and Numerical Temperature Modelling. Presented at the SPE Reservoir Characterization and Simulation Conference and Exhibition, Abu Dhabi”, UAE, 16–18 September. SPE-166007-MS. https://doi.org/10.2118/166007-MS.
[6] Carnahan, B. D., Clanton, R. W., Koehler, K. D.et al. (1999). “Fiber Optic Temperature Monitoring Technology. Presented at the SPE Western Regional Meeting, Anchorage, Alaska”, 26–27 May. SPE-54599-MS https://doi.org/10.2118/54599-MS.
[7] Haoua, T. B., Abubakr, S., Pazzi, J. et al. (2015). “Combining Horizontal Production Logging and Distributed Temperature Interpretations to Diagnose Annular Flow in Slotted-Liner. Completions”. Presented at the SPE Middle East Oil & Gas Show and Conference, Manama, Bahrain, 8–11 March. SPE-172593-MS. https://doi.org/10.2118/172593-MS.
[8] Irvine-Fortescue, J., Battashi, F., and Rubalcava, D. (2016). “Application of Fiber Optics in EOR Trials. Presented at the SPE EOR Conference at Oil and Gas West Asia, Muscat, Oman”, 21-23 March. https://doi.org/10.2118/179777-MS.
The author(s) declare(s) that she/he/they has/have no conflict of interest related to hers/his/their publication(s), furthermore, the research reported in the article was carried out following ethical standards, likewise, the data used in the studies can be requested from the author(s), in the same way, all authors have contributed equally to this work, finally, we have read and understood the Declaration of Ethics and Malpractices.
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