Next Article in Journal
Investments in Electricity Distribution Grids: Strategic versus Incremental Planning
Previous Article in Journal
Influence of Coherent Vortex Rolls on Particle Dynamics in Unstably Stratified Turbulent Channel Flows
Previous Article in Special Issue
Experimental Study on Improving Oil Recovery Mechanism of Injection–Production Coupling in Complex Fault-Block Reservoirs
 
 
Search for Articles:
Title / Keyword
Author / Affiliation / Email
Journal
Article Type
 
 
Advanced Search
 
Section
Special Issue
Volume
Issue
Number
Page
 
Journals
Energies
Volume 17
Issue 11
10.3390/en17112726
energies-logo
Submit to this Journal Review for this Journal Propose a Special Issue
► Article Menu

Article Menu

share Share announcement Help format_quote Cite question_answer Discuss in SciProfiles thumb_up
...
Endorse textsms
...
Comment
first_page
settings
Order Article Reprints
Font Type:
Arial Georgia Verdana
Font Size:
Aa Aa Aa
Line Spacing:
Column Width:
Background:
Article

Enhancing Injectivity in Lithuanian Hydrocarbon Reservoirs through Wettability-Altering Surfactant Injection

by
Shankar Lal Dangi
1 and
Mayur Pal
2,*
1
Department of Earth Sciences, IIT Roorkee, Roorkee 247667, India
2
Department of Mathematical Modelling, Kaunas University of Technology-KTU, LT-51368 Kaunas, Lithuania
*
Author to whom correspondence should be addressed.
Energies 2024, 17(11), 2726; https://doi.org/10.3390/en17112726
Submission received: 18 April 2024 / Revised: 20 May 2024 / Accepted: 31 May 2024 / Published: 3 June 2024
(This article belongs to the Special Issue Fundamentals of Enhanced Oil Recovery II)
Browse Figures
Versions Notes

Abstract

:
Improved and efficient recovery methods are investigated as possible candidates to arrest the production decline and to improve the injection capacity in hydrocarbon fields in Lithuania. The data show that the Cambrian reservoirs in Lithuania are mixed to oil-wet in nature, which results in poor water-flooding efficiency. Wettability alteration could help in improved water injection and, at the same time, it could help recover additional oil from the residual oil saturation zone of the reservoir. In this paper, a screening exercise is conducted to help alter reservoir wettability, improve water injection efficiency, and to improve oil recovery. Analytical and machine-learning supported methods are used for screening. Based on the screening results, dilute surfactant-based injection techniques are suggested as a potential method to improve injectivity and, thereby, recovery from the field. An initial experimental analysis targets the wettability of the rock from the field, followed by testing for wettability-altering surfactants. Based on the findings of the screening study and experimental analysis, it is recommended that we initiate a core flooding experimental program to investigate wettability changes and enhance injection and recovery from the field.

1. Introduction

The Baltic basin comprising Lithuania, Latvia, and Estonia has several hydrocarbon reservoirs in offshore and onshore settings, most of which are located in the territory of Lithuania and Latvia [1]. The Baltic basin in Estonia is too shallow to have any significant reservoirs [2]. These reservoirs are made up of both sandstone and carbonate rocks (see Figure 1, which shows the hydrocarbon accumulation sites in the Baltic region). It is estimated that there are over 50 oil and gas fields in the region, both in onshore and offshore settings. Several of these fields are currently in decline (see Figure 2). Some of these hydrocarbon reservoirs are within the Gargzdai high area, covering over ~200 sq. km. area. These reservoirs are perfect candidates for improved and enhanced oil recovery. This study is focused on one of the reservoirs within the south-western part of Lithuania in the Gargzdai area.
Energies 17 02726 g001
Figure 1. Figure showing the spread of regional oil fields in Baltic basin [3].
Figure 1. Figure showing the spread of regional oil fields in Baltic basin [3].
Energies 17 02726 g001
Earlier work conducted by other authors [4] estimates that the Gargzdai high structure has a very high residual oil saturation ranging between 40–60%, which makes it a large target for enhanced oil recovery. The CO2 EOR method has already been evaluated in several fields with pilot trials showing very promising results [5,6,7,8]. The CO2 field injection trial was conducted in the Gargzdai residual oil zone [4,9] where a total of 1000 tons of CO2 was injected in one of the wells for a total period of 52 days. A differential pressure of 80–90 bars was used to inject the CO2 into the reservoir. Although promising results were obtained from the initial CO2 trial, the scale-up of CO2 injection is currently held up due to some legal barriers related to CO2 injection [10,11,12,13]. Therefore, it is natural to investigate other EOR methods for incremental oil recovery. To carry out the EOR evaluation and its applicability for Gargzdai oil reservoirs, we have first carried out EOR screening at two levels, first, using the EOR screening tool developed by Dicelytics Pvt. Ltd. [14], where machine-learning-based methods are used for EOR screening; and, second, using the analytical method, which is based on reservoir properties and SPE guidelines; the EOR method is selected [15,16,17]. Both screening exercises suggest the potential for Chemical EOR as a promising candidate for the Gargzdai reservoirs.
Energies 17 02726 g002
Figure 2. Figure showing production history for some of the reservoirs in Lithuania (production in thousand tons) [18].
Figure 2. Figure showing production history for some of the reservoirs in Lithuania (production in thousand tons) [18].
Energies 17 02726 g002
A review of existing data from the Gargzdai oil zone suggests that some of the reservoirs are in oil-wet to mixed-wet conditions [19]. Wettability plays a crucial role in oil recovery, where oil-wet formations impede water imbibition, leading to a diminished sweep efficiency and early water breakthrough. In such scenarios, oil tends to strongly adhere to the rock surface, retained within the matrix by capillarity [20,21,22]. During water flooding, successful oil displacement relies on water imbibition into the rock matrix, but, in oil-wet conditions, this process is hindered, preventing the efficient displacement of oil from tight pores [22,23]. Consequently, injected water primarily flows through larger pores or fractured networks, bypassing the oil in the matrix. This phenomenon exacerbates issues like poor sweep efficiency and premature water breakthrough.
Over 60% of global oil reserves are located in oil-wet reservoirs [24]. Despite this abundance, the oil recovery factor from such reservoirs remains notably low, with primary and secondary recovery methods typically retrieving only about one-third of the original oil in place (OOIP), leaving approximately two-thirds trapped as residual oil [24]. This inefficiency stems from various factors inherent to oil-wet reservoirs, including heterogeneous rock properties such as porosity and permeability, as well as variable wettability across the reservoir, collectively posing significant challenges to secondary oil recovery methods like water flooding [24,25,26].
Numerous laboratory studies have demonstrated that altering the rock surface wettability towards a more water-wet state can substantially improve oil recovery during water flooding. This phenomenon is attributed to the creation of positive capillary pressure under water-wet conditions, facilitating water imbibition into tight rock pores [22,23,27,28,29]. The inclusion of wettability-altering surfactants further enhances water imbibition into low-permeability matrices and promotes water spreading on carbonate rock surfaces, effectively releasing trapped oil and, thereby, augmenting cumulative oil recovery.
Cationic surfactants are proposed to form ion pairs with adsorbed organic carboxylates from crude oil, inducing the release of the adsorbed organic material from the surface and, thereby, altering wettability towards a more water-wet state [30,31,32,33,34]. Consequently, water gradually infiltrates the matrix structure, driven by capillary forces, while oil is expelled from the core. Anionic surfactants, particularly ethoxylated sulfonates with a high number of EO groups, have been investigated for their ability to displace oil through non-uniform brine imbibition [31]. The suggested mechanism involves the formation of a surfactant bilayer through a hydrophobic interaction with the surface, with the hydrophilic head groups creating a small water zone between the oil and the hydrophobic surface, generating a weak capillary force driving brine imbibition. Anionic surfactants tend to adsorb onto rock surfaces, especially carbonate reservoirs, due to the positive zeta potential from carbonate mineral ionization to Ca2+ ions [22]. To mitigate surfactant adsorption, the combination of anionic surfactants with sodium carbonate has been proposed [22]. This combination alters wettability and reduces the oil–brine interfacial tension to ultralow values (<10−2 mN/m), primarily facilitating buoyancy or gravity drainage for oil recovery. However, the reduced reliance on capillary forces for oil displacement may necessitate the inclusion of mobility control agents to mobilize oil through the reservoir [27,35].
Nonionic surfactants are extensively studied for their role as wettability-altering agents, contributing to enhanced oil recovery efforts [27,36,37,38,39]. Field trials have also been conducted using nonionic surfactants, for wettability altering surfactants, showing promising results [40,41,42]. Nonionic surfactants induce wettability alteration by solubilizing adsorbed hydrophobic material on carbonate surfaces into the aqueous solution via micellar action. In this hypothesis, the hydrophobic material is oil which would be dislodged due to the surfactant into the flowing brine and would be suspended due to the surfactant lowering the IFT. A favorable surfactant formulation and lower surfactant adsorption are critical to the economic success of any surfactant injection project [25]. Nonionic surfactants offer advantages over anionic ones, including brine compatibility, improved phase behavior, low adsorption on carbonate rock, and enhancing oil recovery via capillary-pressure-driven expulsion from tight matrix pores, eliminating the need for mobility control agents [27,39]. This paper discusses selecting the appropriate surfactant and conducting various laboratory experiments to assess its efficacy. Based on the findings of EOR screening and given the data suggesting the oil-wet nature of the rock, wettability-altering surfactants are used for carrying out experiments on the reservoir rock.
This paper is organized as follows: The introduction to EOR is presented first, followed by the field data description which is used in this study. The EOR screening results are presented in Section 3. The initial surfactant screening experiments are presented in Section 4. Section 5 discusses the impact of wettability alteration on water injection improvement. The conclusions are presented in Section 6.

2. Field Data

The field data used for the analytical screening are shown in Table 1. The data correspond to one of the depleted hydrocarbon fields, which is a Cambrian reservoir located in the Baltic basin at a depth of around 2 km. The field has been in production since early 1990 and has been water-flooded for pressure maintenance since 2000s [43]. The production forecast shows a declining production as shown in Figure 3. The water flood has provided initial production support, and, now, production is declining year after year. The reservoir makes a perfect candidate for improved and enhanced oil recovery.

3. Enhanced Oil Recovery Screening

Enhanced oil recovery (EOR) is a crucial method implemented subsequent to primary hydrocarbon extraction, designed to maximize the retrieval of the remaining hydrocarbons through secondary (e.g., water or gas flooding) and tertiary recovery mechanisms. Various EOR techniques encompass solvent-based, chemical, and thermal methods, each possessing distinct advantages and limitations. Figure 4 illustrates the classification of enhanced oil recovery screening methods based on SPE guidelines [17]. In the methodology flowchart, Figure 4 illustrates our approach and methodology, detailing the sequential steps and processes we undertake throughout our research. Typically, EOR strategies are deployed towards the latter stages of field development, as depicted in Figure 5. The initial phase of assessing EOR potential in a field entails EOR screening, traditionally relying on analytical methodologies outlined by the Society of Petroleum Engineers (SPE) [6,15,17]. However, there is a burgeoning interest in leveraging machine-learning techniques for EOR screening [44,45,46,47,48,49]. This section elucidates the outcomes derived from both traditional analytical screening methods and machine-learning approaches applied to field data.

3.1. Analytical Screening Using SPE Guidelines

Analytical EOR screening for a depleted oil field is conducted using an in-house Excel-based tool developed from the SPE guidelines [15,16,17]. Additionally, several SPE publications provide comprehensive screening criteria and guidelines for evaluating the feasibility of EOR projects under various technical and economic considerations, including factors like oil prices and technological advancements [50]. These guidelines offer valuable insights and methodologies for assessing EOR projects across different scenarios.
According to the SPE guidelines [16], the temperature requirement for in situ flooding is above 37 °C, with an API gravity of 10 to 27, while the field under study has a temperature of around 85 °C and an API gravity of 43.4, making in situ flooding unsuitable and prohibitively expensive. Similarly, steam flooding is recommended for reservoirs with depths of less than 5000 ft. However, our field’s depth is 6480 ft, rendering steam flooding inappropriate for our reservoir. Our reservoir exhibits specific characteristics, including being oil-wet, highly heterogeneous, and low viscosity. Although alkaline flooding is commonly employed for wettability alteration, it is typically effective for reservoirs with API gravities ranging from 13 to 35. Given that our field has an API gravity of 43.4, alkaline flooding alone is not a viable choice due to the incompatible API range. Regarding nitrogen and flue gas injection, these methods are optimal for reservoirs with viscosities lower than 0.4. Unfortunately, our field’s viscosity exceeds 0.63, making nitrogen and flue gas injection less suitable for our circumstances.

3.2. Machine-Learning-Based Screening

Dicelytics Ltd. offers an end-to-end solution for reservoir management, which includes an EOR screening tool, that uses machine-learning algorithms for EOR screening purposes [14]. Dicelytics software (https://prod.dicelytics.com/dicelytics/login, accessed on 17 April 2024) provides a production enhancement evaluation using AI and ML, laboratory evaluation, consultation, and data visualization. Dicelytics Ltd.’s physics- and machine-based software is a cloud-based software suite that allows physics-assisted artificial intelligence and machine-learning reinforced models to simulate, analyze, and support the field implementation of reservoir recovery management technologies. Table 2 shows the input data used in the Dicelytics EOR screening software tool.
Table 3, Table 4 and Table 5 displays the results of screening tests conducted using the Dicelytics software on the input data from Table 2. The screening tests are performed for various flooding methods used in oil recovery operations. The “Result” column indicates the percentage effectiveness of each flooding method in recovering oil under the specified conditions, listed in decreasing order of effectiveness. The methods tested include hot water, chemical flooding, in situ hydrocarbon (I-HC) injection, in situ CO2 (I-CO2) injection, microbial flooding, and polymer flooding.
Based on the analytical screening method, we can suggest that there are the following possible EOR methods, that can be applied to the field:
Low Salinity Water (LSW) Flooding: This method modifies the wettability of the reservoir rock, making it more water-wet and facilitating the displacement of oil. The alteration in ionic composition affects the interactions between the oil, water, and rock surfaces, leading to improved oil recovery. It typically involves modifying the water composition and injection strategy, which can be implemented with a relatively low capital and operational costs. This may be the cheapest option for the current scenario.
Surfactant–Polymer (SP) Flooding: Surfactants help to reduce the interfacial tension between the oil and water, improving oil mobilization, while polymers enhance the sweep efficiency by increasing the viscosity of the injected water, thus reducing channeling and improving displacement.
Alkaline–Surfactant–Polymer (ASP) Flooding: Alkalis are added to raise the pH of the injected water, which helps in reducing the reservoir’s rock wettability and enhancing oil recovery. Surfactants aid in reducing interfacial tension, while polymers improve the sweep efficiency. The cost depends on the dosage, the frequency of injection, and the specific chemicals used. Alkaline flooding is commonly applied in oil-wet or mixed-wet reservoirs. Alkaline flooding tends to be more effective for heavier oils, with API in the range of 13–35. Therefore, we can use ASP to obtain more effective results.
Chemical Flooding with CO2 or N2: Chemical flooding methods, such as CO2 or N2 foam or miscible flooding, can be combined with the existing water flooding. These methods enhance oil recovery by reducing oil viscosity, improving displacement efficiency, and altering the reservoir wettability. The current reservoir pressure is 3190 psi, which is sufficient for the miscibility of CO2. The viscosity is 0.63 to 1.44 cp, which favors CO2 flooding (for miscible flooding, the viscosity range is 0.1 cp to 100 cp, and, for immiscible flooding, it is perhaps more than 100 cp). Normally, N2 flooding is used in viscosity of less than 0.3 cp. Based on all these data, CO2 flooding can be used compared to N2 flooding. CO2 or N2 flooding methods can have higher costs compared to LSW or chemical flooding. The expenses are associated with capturing, compressing, and injecting the gas into the reservoir. The availability and proximity of CO2 or N2 sources, as well as the infrastructure required for their transportation and injection, also influence the cost-effectiveness.
Here, we have a very high heterogeneity in our field, so we may refer to chemical flooding. CO2 or hydrocarbon gas injection is also recommended because the injected gas can better reach and displace oil in different reservoir zones, including areas with varying permeability. In this paper, we further investigate chemical EOR, in particular, surfactant EOR, as it has been shown to give promising results in sandstone reservoirs and, particularly, for oil-wet rock [40,41,42].

4. Rock Wettability Assessment

Oil-wet reservoirs typically exhibit an inferior water-flooding efficiency compared to water-wet reservoirs due to the stronger adhesion of oil to rock surfaces. Consequently, water struggles to displace the oil effectively from the reservoir rock pores, resulting in a diminished oil recovery efficiency. To address this challenge, various techniques such as surfactant injection or chemical treatments are often employed to modify the reservoir’s wettability and enhance the water-flooding efficiency.
A special core analysis conducted in the laboratory on reservoir rocks sourced from Lithuanian reservoirs has confirmed their oil-wet nature [19]. The determination of rock wettability is established through contact angle measurements, detailed in Table 6 and Figure 6. The wettability index gauges the preference of the reservoir rock for oil or water. A positive wettability index signifies a water-wet condition, indicating a higher affinity for water, whereas a negative wettability index denotes an oil-wet condition, suggesting a greater affinity for oil.
Three tests were conducted on small rock plugs extracted from a Lithuanian reservoir, revealing that two of the tests (plug 1 and plug 2) yielded negative values for the Amott wettability index (IAH = −0.723 and IAH = −0.741, respectively), indicating an oil-wet wettability. This implies that the rock samples from these plugs have a stronger affinity for oil than water. However, an anomaly was observed with plug 3, which exhibited a positive wettability index (IAH = 0.073), contradicting the oil-wet wettability observed in plugs 1 and 2. Consequently, a reassessment of the rock’s wettability was warranted using a simple water droplet method. This re-evaluation is crucial as the contact angle plays a pivotal role in determining rock wettability, which, in turn, informs the selection of the appropriate enhanced oil recovery (EOR) methods.

4.1. Water Droplet Method and Quantification of Wettability

To verify the oil-wet nature of the rock, an experiment was conducted using the water droplet method, where the rock is saturated in oil, and then the wettability is tested by placing a water droplet on the rock and the contact angle is evaluated. To conduct the experimental investigation, reservoir rock, oil, and brine samples have been collected and saturated first in reservoir brine (200,000 ppm) for a period of 4 weeks, followed by oil saturation for 4 weeks.

4.2. Calcite Plate Test for Wettability Alteration

Since the rock is oil-wet in nature, we conduct an experiment using a known oil-wet rock, reservoir brine, and reservoir oil using surfactant solution. A calcite plate is used, as it is known to be oil-wet in nature. The plate is first dipped in reservoir brine, followed by reservoir oil. The saturated plate is then dipped in brine and surfactant solution, which results in changing the calcite plate to change its wettability from oil-wet to water-wet. When this happens, oil droplets start to form on the calcite plate and oil is released from the surface.
The water droplet experiment showed that water does not spread on the surface of the rock but, rather, forms a droplet, indicating the oil-wet nature of the rock. The calcite plate test confirms this result (Figure 7). It is seen that oil droplets start to form and are released from the surface.

4.3. Wettability Alteration Using Surfactant

For this experiment, we first prepared reservoir rock, cleaned it, and then placed it in reservoir brine solution for a period of 4 weeks. After aging in reservoir brine for 4 weeks, the rock sample is taken out and pictures are taken. Then, the rock is immersed in an oil bath for a period of 4 weeks. After the ageing in oil is completed, the rock sample is taken out, and then subsequently dipped in a surfactant solution for a few hours.
Similar to the calcite plate experiments, the surfactant solution alters the rock’s wettability from oil-wet to water-wet, allowing water to imbibe into the rock and displace oil molecules, as illustrated in Figure 8. The success of these experiments demonstrates the potential of surfactants to enhance oil recovery from the field. Although the exact mechanism and kinetics of wettability alteration are not fully understood yet and require further investigation, it is likely that the surfactant’s ability to adsorb onto the rock surface and/or remove polar components is responsible for this change in wettability.

5. Injection Improvement via Wettability Alteration

The oil-wet nature of the rock results in a poor water-flooding efficiency. The impact of wettability on water-flood efficiency in sandstone and carbonate reservoirs has been investigated by several authors [51,52,53]. If the wettability of the rock could be changed, then the water-flooding efficiency can be improved; this is achieved through the alteration of the water-relative permeability curve due to the adsorption of wettability-altering surfactants on the rock surface. Such changes in relative permeability curves have been demonstrated in [39,40,41,42]. The effect of a wettability-altering surfactant on injectivity improvement has been discussed in detail in [40,41].
A review of the field’s injection and production data [4,9] suggest that, for every 6 bbls. of water injected, 1 extra bbl. of oil can be produced. Therefore, if we can obtain a ~15% injectivity increase with surfactant injection, this would amount to having approximately five new water injectors. Similarly, a ~10% increase with surfactant injection would amount to having approximately four new water injectors. Figure 9 shows the number of water injection wells that can be replaced with the respective injectivity increase obtained from surfactant injection. There is also a direct implication of the injection improvement on electricity consumption and the running of water injection pumps. Figure 9 below shows that, even if a small injectivity increase is made through wettability alteration, the energy savings are equivalent to running additional injection wells with the same electrical consumption. Therefore, the wettability changes through a surfactant should also be seen as a cost-effective way of improving the field water-flooding efficiency.

6. Conclusions

In conclusion, the study focuses on a highly heterogeneous, oil-wet hydrocarbon field with permeability ranging from 0.01 to 100 md and porosity from 1% to 12%. Preliminary experimental testing using reservoir fluids and rocks shows that the use of a wettability-altering surfactant can help in improving oil recovery through wettability changes.
Due to the oil-wet nature and heterogeneity of the reservoir, traditional water flooding faces challenges like early water breakthrough and channeling through fractures. Therefore, it is recommended to use Surfactant–Polymer (SP) or Alkali–Surfactant–Polymer (ASP) flooding for enhanced oil recovery (EOR). The initial analysis and experiments indicate that surfactant flooding is effective for incremental oil recovery. It is suggested that we conduct extensive core flooding tests using reservoir fluids and rocks to further investigate this method. Surfactant treatment can improve the water-flooding efficiency by altering rock wettability, enhancing injectivity, and potentially reducing the need for additional injection wells, thus lowering operational costs
The work also suggests that the use of diluted surfactant injection will improve the water injection efficiency due to changes in the wettability of the rock, making it more water-wet. This will eventually result in changes in the relative permeability of the rock through surfactant adsorption, which will result in cost savings through injection efficiency improvements.

7. Recommendation

Based on the preliminary screening and experimental investigations demonstrating promising results with surfactant-based EOR methods in oil-wet reservoirs, it is recommended that we proceed with further investigation through core flooding experiments. These experiments will allow for a comprehensive quantification of expected recoveries and pave the way for future field trials. Following short-term injectivity trials, longer-term assessments should be conducted to evaluate the impact of surfactant injection on residual oil saturation and injectivity improvement. For field trials, we suggest implementing single-well tracer test (SWCTT), and log-inject-log with an observation well. These trials will provide valuable insights for optimizing surfactant-based EOR methods in oil-wet reservoirs and enhancing the hydrocarbon recovery efficiency.

Author Contributions

For research articles, both authors contributed equally, in the writing, reviewing, and conceptualization of the study. All authors have read and agreed to the published version of the manuscript.

Funding

This research received no external funding.

Data Availability Statement

Data are contained within the article.

Acknowledgments

The authors are thankful to Thomas M. Haselton from UAB Minijos Nafta for the fruitful discussion carried out during the course of the work presented in this paper.

Conflicts of Interest

The authors declare no conflicts of interest.

References

  1. Shogenova, A.; Sliaupa, S.; Vaher, R.; Shogenov, K.; Pomeranceva, R. Balti bassein: Ehitus, reservuaarikivimite omadused ja CO2 geoloogilise ladustamise võimalused. Est. J. Earth Sci. 2009, 58, 259–267. [Google Scholar] [CrossRef]
  2. Terasmaa, J. Estonia, the land of lakes. J. Int. Géosciences Environ. 2018, 358–366. [Google Scholar] [CrossRef]
  3. Rashid, A.; Malik, S.; Karaliute, V.; Makauskas, P.; Kaminskaite, I.; Pal, M. Lithuania’s geo-energy landscape: A brief overview of CCUS, hydrogen, and geothermal. Adv. Carbon Capture Util. Storage 2023, 1, 33–43. [Google Scholar] [CrossRef]
  4. Haselton, T.M.; Nafta, M. Exploiting the ROZ in Lithuania. In Proceedings of the 19th Annual CO2 Flooding Conference, Midland, TX, USA, 14 December 2013; Volume 14. [Google Scholar]
  5. Brock, W.; Bryan, L. Exxon Co USA, “SPE”. 1989. Available online: http://onepetro.org/SPERMPTC/proceedings-pdf/89LPR/All-89LPR/SPE-18977-MS/3214040/spe-18977-ms.pdf/1 (accessed on 23 February 2024).
  6. Manrique, E.; Thomas, C.; Ravikiran, R.; Izadi, M.; Lantz, M.; Romero, J.; Alvarado, V. SPE 130113 EOR: Current Status and Opportunities. 2010. Available online: http://onepetro.org/SPEIOR/proceedings-pdf/10IOR/All-10IOR/SPE-130113-MS/1771110/spe-130113-ms.pdf/1 (accessed on 23 February 2024).
  7. Hill, L.B.; Li, X.C.; Wei, N. CO2-EOR in China: A comparative, review. Int. J. Greenh. Gas Control 2020, 103, 103173. [Google Scholar] [CrossRef]
  8. Ghedan, S. SPE/EAGE Reservoir Characterization and Simulation Conference. 2009. Available online: http://onepetro.org/SPERCSC/proceedings-pdf/09RCSC/All-09RCSC/SPE-125581-MS/2720391/spe-125581-ms.pdf/1 (accessed on 23 February 2024).
  9. Haselton, T.M.; Nafta, M. Minijos Nafta Clean Energy Project; Baltic Carbon Forum: Tallinn, Estonia, 2019. [Google Scholar]
  10. Mathisen, A.; Skagestad, R. Utilization of CO2 from Emitters in Poland for CO2-EOR. Energy Procedia 2017, 114, 6721–6729. [Google Scholar] [CrossRef]
  11. Dangi, S.L.; Malik, S.; Makauskas, P.; Karliute, V.; Sharma, R.; Pal, M. An approach for assessment of CO2 leakage using mechanistic modelling: CO2 injection in deep saline aquifer of Lithuanian basin in presence of fault and fractures. Adv. Carbon Capture Util. Storage 2024. [Google Scholar] [CrossRef]
  12. Dangi, S.L.; Malik, S.; Makauskas, P.; Karliute, V.; Sharma, R.; Pal, M. Assessment of CO2 leakage using mechanistic modelling approach for CO2 injection in deep saline aquifer of Lithuanian basin in presence of fault and fractures. Balt. Carbon Forum 2023, 2, 15–16. [Google Scholar] [CrossRef]
  13. Dangi, S.L.; Malik, S.; Sharma, R.; Pal, M. Geomechanical Implications of CO2 Sequestration in Saline Aquifers. In Proceedings of the 14th Biennial International Conference SPG 2023, Kochi, India, 3–5 November 2023; Available online: https://spgindia.org/Kochi2023-expanded-abstracts/14th-conference-kochi23-top-177.pdf (accessed on 23 February 2024).
  14. Dicelytics Pvt. Ltd. Available online: https://www.linkedin.com/company/dicelytics/ (accessed on 23 February 2024).
  15. Taber, J.J.; Martin, F.D.; Seright, R.S. EOR Screening Criteria Revisited Part 1: Introduction to Screening Criteria and Enhanced Recovery Field Projects. 1997. Available online: http://onepetro.org/RE/article-pdf/12/03/189/2532146/spe-35385-pa.pdf/1 (accessed on 23 February 2024).
  16. Taber, J.J.; Martin, F.D.; Seright, R.S. EOR Screening Criteria Revisited-Part 2: Applications and Impact of Oil Prices. SPE Reserv. Eng. 1997, 12, 199–206. [Google Scholar] [CrossRef]
  17. Aladasani, A.; Bai, B. SPE 130726 Recent Developments and Updated Screening Criteria of Enhanced Oil Recovery Techniques. Available online: http://onepetro.org/SPEIOGCEC/proceedings-pdf/10IOGCEC/All-10IOGCEC/SPE-130726-MS/2342995/spe-130726-ms.pdf/1 (accessed on 23 February 2024).
  18. Šliaupa, S.; Šliaupienė, R. Prospects of Geological Storage of CO2 in Lithuania BALTIC CARBON FORUM 2021. In Baltic Carbon Forum; Gamtos Tyrimu Centras: Vilnius, Lithuania, 2021; Available online: https://bcforum.net/presentations2021/0303_Saulius%20Sliaupa.pdf (accessed on 23 February 2024).
  19. “Pal V15 Kerno Drėkinimo Testai”. Minijos Nafta Internal Report 1997—SCAL Analysis. Available online: www.minijosnafta.com/en (accessed on 23 February 2024).
  20. Morrow, “Wettability and Its Effect on Oil Recovery”. 1990. Available online: http://onepetro.org/JPT/article-pdf/42/12/1476/2222566/spe-21621-pa.pdf/1 (accessed on 27 March 2024).
  21. Abdallah, W.; Buckley, J.S.; Carnegie, A.; Edwards, J.; Herold, B.; Fordham, E.; Graue, A.; Habashy, T.; Seleznev, N.; Signer, C.; et al. Fundamentals of Wettability. Technology 1986, 38, 268. [Google Scholar]
  22. Hirasaki, G.; Zhang, D.L. Surface Chemistry of Oil Recovery from Fractured, Oil-Wet, Carbonate Formations. 2004. Available online: http://onepetro.org/SJ/article-pdf/9/02/151/2572183/spe-88365-pa.pdf/1 (accessed on 23 February 2024).
  23. Jadhunandan, P.P.; Morrow, N.R. Spontaneous Imbibition of Water by Crude Oil/Brine/Rock Systems. In Situ 1991, 15. Available online: https://www.osti.gov/biblio/5847471 (accessed on 23 February 2024).
  24. Sheng, J.J. Chapter 12. Surfactant Enhanced Oil Recovery in Carbonate Reservoirs Review of Surfactant Enhanced Oil Recovery in Carbonate Reservoirs. Adv. Pet. Explor. Dev. 2013, 6, 281–299. [Google Scholar]
  25. Rohilla, N.; Hirasaki, G.J. Pore Structure of Vuggy Carbonates and Rate Dependent Displacement in Carbonate Rocks. SCA2011-21. 2011. Available online: https://jgmaas.com/SCA/2011/SCA2011-21.pdf (accessed on 23 February 2024).
  26. Rohilla, N.; Ravikiran, R.; Carlisle, C.T.; Jones, N.; Davis, M.B.; Finch, K.B.H. Design of a Robust ASP Formulation for Clay Rich and Moderate Permeability Sandstone Reservoir: From Laboratory to Single Well Chemical Tracer Test in the Field. In Proceedings of the SPE-DOE Improved Oil Recovery Symposium Proceedings, Tulsa, OK, USA, 11–13 April 2016. [Google Scholar] [CrossRef]
  27. Mohan, K.; Gupta, R.; Mohanty, K.K. Wettability altering secondary oil recovery in carbonate rocks. Energy Fuels 2011, 25, 3966–3973. [Google Scholar] [CrossRef]
  28. Patil, P.D.; Rohilla, N.; Katiyar, A.; Yu, W.; Nelson, C.; Falcone, S.; Rozowski, P. Surfactant Based EOR for Tight Oil Unconventional Reservoirs through Wettability Alteration: Novel Surfactant Formulations and Their Efficacy to Induce Spontaneous Imbibition. In Proceedings of the SPE/AAPG/SEG Unconventional Resources Technology Conference 2018, URTC 2018, Houston, TX, USA, 23–25 July 2018. [Google Scholar] [CrossRef]
  29. Patil, P.D.; Rohilla, N.; Katiyar, A.; Yu, W.; Falcone, S.; Nelson, C.; Rozowski, P. Surfactant Based EOR for Tight oil Reservoirs through Wettability Alteration: Novel Surfactant Formulations and Their Efficacy to Induce Spontaneous Imbibition. In Proceedings of the Society of Petroleum Engineers-SPE EOR Conference at Oil and Gas West Asia 2018, Muscat, Oman, 21–23 March 2016. [Google Scholar] [CrossRef]
  30. Standnes, D.C. Analysis of oil recovery rates for spontaneous imbibition of aqueous surfactant solutions into preferential oil-wet carbonates by estimation of capillary diffusivity coefficients. Colloids Surf. A Physicochem. Eng. Asp. 2004, 251, 93–101. [Google Scholar] [CrossRef]
  31. Standnes, D.C.; Austad, T. Wettability alteration in chalk 2. Mechanism for wettability alteration from oil-wet to water-wet using surfactants. J. Pet. Sci. Eng. 2000, 28, 123–143. [Google Scholar] [CrossRef]
  32. Standnes, D.C.; Austad, T. Wettability alteration in carbonates: Low-cost ammonium surfactants based on bio-derivatives from the coconut palm as active chemicals to change the wettability form oil-wet to water-wet conditions. Colloids Surf. A Physicochem. Eng. Asp. 2003, 218, 161–173. [Google Scholar] [CrossRef]
  33. Standnes, D.C.; Austad, T. Nontoxic low-cost amines as wettability alteration chemicals in carbonates. J. Pet. Sci. Eng. 2003, 39, 431–446. [Google Scholar] [CrossRef]
  34. Strand, S.; Standnes, D.C.; Austad, T. Spontaneous imbibition of aqueous surfactant solutions into neutral to oil-wet carbonate cores: Effects of brine salinity and composition. Energy Fuels 2003, 17, 1133–1144. [Google Scholar] [CrossRef]
  35. Seethepalli, A.; Adibhatla, B.; Mohanty, K.K. Physicochemical interactions during surfactant flooding of fractured carbonate reservoirs. SPE J. 2004, 9, 411–418. [Google Scholar] [CrossRef]
  36. Xie, X.; Weiss, W.W.; Tong, Z.; Morrow, N.R. Improved oil recovery from carbonate reservoirs by chemical stimulation. SPE J. 2005, 10, 276–285. [Google Scholar] [CrossRef]
  37. Gupta, R.; Mohan, K.; Mohanty, K.K. Surfactant Screening for Wettability Alteration in Oil-Wet Fractured Carbonates. In Proceedings of the SPE Annual Technical Conference and Exhibition, New Orleans, LA, USA, 4–7 October 2009. [Google Scholar] [CrossRef]
  38. Sharma, G.; Mohanty, K.K. Wettability alteration in high-temperature and high-salinity carbonate reservoirs. SPE J. 2013, 18, 646–655. [Google Scholar] [CrossRef]
  39. Bennetzen, M.V.; Mogensen, K.; Frank, S.; Mohanty, K. Dilute surfactant flooding studies in a low-permeability oil-wet Middle East carbonate. In Proceedings of the Society of Petroleum Engineers-International Petroleum Technology Conference 2014, IPTC 2014: Unlocking Energy Through Innovation, Technology and Capability, Kuala Lumpur, Malaysia, 10–12 December 2014. [Google Scholar] [CrossRef]
  40. Pal, M.; Gilani, S.F.; Tarsaulia, G.; Geremia, G. SPE-190373-MS Offshore Surfactant Injectivity Trials: From Core to Successful Field Trials in the Al-Shaheen Field. In Proceedings of the SPE EOR Conference at Oil and Gas West Asia, Muscat, Oman, 26–28 March 2018. [Google Scholar] [CrossRef]
  41. Rohilla, N.; Katiyar, A.; Saxena, P.; Pal, M.; Rozowski, P.; Gentilucci, A. Successful Wettability Alteration Pilot in an Offshore Reservoir: Laboratory Analysis to Support Planning, Implementation and Interpretation; IOR: Austria, 2021; Available online: https://www.earthdoc.org/content/papers/10.3997/2214-4609.202133124 (accessed on 23 February 2024).
  42. Pal, M.; Saxena, P.; Rohilla, N.; Katiyar, A.; Rozowski, P.; Knight, T. Successful Wettability Alteration Pilot in Offshore Reservoir: Pilot Planning, Execution, Monitoring and Interpretation. 2021. Available online: https://www.earthdoc.org/content/papers/10.3997/2214-4609.202133109?crawler=true (accessed on 23 February 2024).
  43. Malik, S.; Makauskas, P.; Karaliūtė, V.; Pal, M.; Sharma, R. Assessing the geological storage potential of CO2 in Baltic Basin: A case study of Lithuanian hydrocarbon and deep saline reservoirs. Int. J. Greenh. Gas Control 2024, 133, 104097. [Google Scholar] [CrossRef]
  44. Chavan, H.K.; Sinharay, R.K.; Kumar, V.; Patel, D. An approach of using machine learning classification for screening of enhanced oil recovery techniques. Pet. Sci. Technol. 2023, 1–19. [Google Scholar] [CrossRef]
  45. Aminzadeh, F.; Temizel, C.; Hajizadeh, Y. Machine Learning Applications in Enhanced Oil Recovery (EOR). In Artificial Intelligence and Data Analytics for Energy Exploration and Production; Wiley: Hoboken, NJ, USA, 2022. [Google Scholar] [CrossRef]
  46. You, J.; Ampomah, W.; Sun, Q.; Kutsienyo, E.J.; Balch, R.S.; Dai, Z.; Cather, M.; Zhang, X. Machine learning based co-optimization of carbon dioxide sequestration and oil recovery in CO2-EOR project. J. Clean Prod. 2020, 260, 120866. [Google Scholar] [CrossRef]
  47. Cheraghi, Y.; Kord, S.; Mashayekhizadeh, V. Application of machine learning techniques for selecting the most suitable enhanced oil recovery method; challenges and opportunities. J. Pet. Sci. Eng. 2021, 205, 108761. [Google Scholar] [CrossRef]
  48. Salehi, E.; Mohammadi, M.R.; Hemmati-Sarapardeh, A.; Mahdavi, V.R.; Gentzis, T.; Liu, B.; Ostadhassan, M. Modeling Interfacial Tension of N2/CO2 Mixture + n-Alkanes with Machine Learning Methods: Application to EOR in Conventional and Unconventional Reservoirs by Flue Gas Injection. Minerals 2022, 12, 252. [Google Scholar] [CrossRef]
  49. Pirizadeh, M.; Alemohammad, N.; Manthouri, M.; Pirizadeh, M. A new approach for ranking enhanced oil recovery methods based on multi-gene genetic programming. Pet. Sci. Technol. 2023, 41, 64–85. [Google Scholar] [CrossRef]
  50. Karovic-Maricic, V.; Lekovic, B.; Danilovic, D. Factors influencing successful implementation of enhanced oil recovery projects. Podzemn. Rad. 2014, 22, 41–50. [Google Scholar] [CrossRef]
  51. McDougall, S.R.; Sorbie, K.S. The Impact of Wettability on Waterflooding: Pore-Scale Simulation. SPE Res. Eng. 1995, 10, 208–213. [Google Scholar] [CrossRef]
  52. Al-Nofli, K.; Pourafshary, P.; Mosavat, N.; Shafiei, A. Effect of Initial Wettability on Performance of Smart Water Flooding in Carbonate Reservoirs—An Experimental Investigation with IOR Implications. Energies 2018, 11, 1394. [Google Scholar] [CrossRef]
  53. Agbalaka, C.; Dandekar, A.Y.; Patil, S.L.; Khataniar, S.; Hemsath, J.R. The Effect of Wettability on Oil Recovery: A Review. In Proceedings of the SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 20–22 October 2008. [Google Scholar] [CrossRef]
Energies 17 02726 g003
Figure 3. Declining production forecast of the oil field under investigation for injection improvement and EOR; different colors show production contribution from different reservoirs within the field; names of field are hidden due to data confidentiality.
Figure 3. Declining production forecast of the oil field under investigation for injection improvement and EOR; different colors show production contribution from different reservoirs within the field; names of field are hidden due to data confidentiality.
Energies 17 02726 g003
Energies 17 02726 g004
Figure 4. Methodology flowchart.
Figure 4. Methodology flowchart.
Energies 17 02726 g004
Energies 17 02726 g005
Figure 5. EOR recovery mechanizing.
Figure 5. EOR recovery mechanizing.
Energies 17 02726 g005
Energies 17 02726 g006
Figure 6. Figure showing an oil-wet and water-wet surface of rock. Images show behavior of oil molecule on surface of rock, which is immersed in brine.
Figure 6. Figure showing an oil-wet and water-wet surface of rock. Images show behavior of oil molecule on surface of rock, which is immersed in brine.
Energies 17 02726 g006
Energies 17 02726 g007
Figure 7. Figure showing reservoir fluid and brine interaction with surfactant solution using a calcite plate.
Figure 7. Figure showing reservoir fluid and brine interaction with surfactant solution using a calcite plate.
Energies 17 02726 g007
Energies 17 02726 g008
Figure 8. Figure showing rock sample from the field saturated with reservoir oil for 4 weeks, and then subsequently dipped in surfactant solution.
Figure 8. Figure showing rock sample from the field saturated with reservoir oil for 4 weeks, and then subsequently dipped in surfactant solution.
Energies 17 02726 g008
Energies 17 02726 g009
Figure 9. Potential cost savings in terms of injection capacity by using surfactant injection.
Figure 9. Potential cost savings in terms of injection capacity by using surfactant injection.
Energies 17 02726 g009
Table 1. Field data used for EOR screening.
Table 1. Field data used for EOR screening.
Field Name/LocationGargzdai Reservoir (Western Lithuania)
Geological basinBaltic basin
Formation nameCambrian
Discovery year1960–1970
Type of rock (sandstone/carbonate/shale)Sandstone
Rock heterogeneity infoVery heterogeneous (0.01–100 md)
Mineral composition95% or more quartz
Clay content (% of clay in rock)3–7, some placed up to 20
Average porosity, %1–12
Average permeability, md0.01–100
Depth, m1975–1992.5
Reservoir area (acres)200 sq. km—total 8 reservoirs
Average pay thickness, m70–80 m
Reservoir temperature, °C85
Original reservoir pressure, psi2750
Injection well bottom hole pressure, psi3000
Initial oil and water saturation ratios30–56% residual oil saturation
Average connate water saturation, %~20
Current oil cut, %High water cut up to 90–95
Secondary recovery, %27% (with water flood)
Start year of water flooding/injection21+ years
Current average daily injection rate per well (Water) bbls/day500
Number of producing wells11 wells
Number of injection wells4
Oil production from entire field, bbl/day~200 (from 4 wells—around 60 bb/day)
Well configuration—horizontal/verticalVertical
Well spacing per well, meters300–1000
Current average daily injection rate per well (Water), m3/day500 (~3200 bbls per day)
Reservoir Mechanism
Primary producing mechanismWater flooding
Current injection rate, m3/day500
Average wellhead injection pressure and BHP, bars250–350 (depending on wells)
Water Properties
Density of original connate/formation water, kg/m31127
Salinity/total dissolved solids: Original formation water, wt %20
Oil Properties
API43.4
Viscosity at reservoir temperature, cp0.63–0.8 (in situ),
1.44 (dead oil)
Other information
Reservoir pressure, bars220
WettabilityOil-wet
Initial water saturation, %26
Recovery factor, %27
Well spacing, ha/well98
Average reservoir thickness, m9.15
Table 2. Dicelytics software input.
Table 2. Dicelytics software input.
ParameterValue
API Gravity43.4
Oil Viscosity1.44
Residual Oil Saturation30%
Depth, ft6479.659
Temperature, °C85
Permeability, md100
Porosity10%
FormationSandstone
Thickness>20 ft No dip
CompositionHigh % C1–C7
Table 3. Dicelytics software screening test result for Table 2 input data.
Table 3. Dicelytics software screening test result for Table 2 input data.
Flooding MethodResult
HOT WATER100.00%
CHEMICAL80.78%
I-HC62.37%
I-CO241.84%
POLYMER21.32%
Table 4. Dicelytics software screening test result for Table 2 data, reducing viscosity to 0.8 cp.
Table 4. Dicelytics software screening test result for Table 2 data, reducing viscosity to 0.8 cp.
Flooding MethodResult
HOT WATER100.00%
I-CO280.63%
CHEMICAL60.21%
I-HC41.49%
POLYMER21.07%
Table 5. Dicelytics software screening test result for Table 2 data, reducing viscosity to 0.63 cp.
Table 5. Dicelytics software screening test result for Table 2 data, reducing viscosity to 0.63 cp.
Flooding MethodResult
HOT WATER100.00%
CHEMICAL75.71%
I-HC52.29%
POLYMER26.58%
Table 6. Table showing oil-wetness and corresponding contact angle.
Table 6. Table showing oil-wetness and corresponding contact angle.
Wetting ConditionContact Angle (Degrees)
Moderately water–wet30–75
Neutrally wet75–105
Moderately oil–wet105–150
Strongly oil–wet150–180
Disclaimer/Publisher’s Note: The statements, opinions and data contained in all publications are solely those of the individual author(s) and contributor(s) and not of MDPI and/or the editor(s). MDPI and/or the editor(s) disclaim responsibility for any injury to people or property resulting from any ideas, methods, instructions or products referred to in the content.

Share and Cite

MDPI and ACS Style

Dangi, S.L.; Pal, M. Enhancing Injectivity in Lithuanian Hydrocarbon Reservoirs through Wettability-Altering Surfactant Injection. Energies 2024, 17, 2726. https://doi.org/10.3390/en17112726

AMA Style

Dangi SL, Pal M. Enhancing Injectivity in Lithuanian Hydrocarbon Reservoirs through Wettability-Altering Surfactant Injection. Energies. 2024; 17(11):2726. https://doi.org/10.3390/en17112726

Chicago/Turabian Style

Dangi, Shankar Lal, and Mayur Pal. 2024. "Enhancing Injectivity in Lithuanian Hydrocarbon Reservoirs through Wettability-Altering Surfactant Injection" Energies 17, no. 11: 2726. https://doi.org/10.3390/en17112726

APA Style

Dangi, S. L., & Pal, M. (2024). Enhancing Injectivity in Lithuanian Hydrocarbon Reservoirs through Wettability-Altering Surfactant Injection. Energies, 17(11), 2726. https://doi.org/10.3390/en17112726

Note that from the first issue of 2016, this journal uses article numbers instead of page numbers. See further details here.

Article Metrics

Back to TopTop