Interview Questions for Wettability Testing

Wettability refers to the preference of a rock surface to be in contact with either oil or water. It’s essentially a measure of how well a liquid adheres to a solid surface in the presence of another immiscible liquid. In reservoir engineering, wettability is incredibly significant because it dictates how oil and water distribute themselves within the pore spaces of reservoir rocks. This distribution directly impacts the efficiency of oil recovery processes. Think of it like this: if a rock prefers water (water-wet), the oil will be more clustered together and easier to displace. Conversely, if a rock prefers oil (oil-wet), the oil will be more spread out, making it significantly harder to recover. The wettability characteristics of a reservoir can drastically influence the design and optimization of enhanced oil recovery (EOR) techniques.

Contact angle measurement is the most common method for assessing wettability. The contact angle is the angle formed at the three-phase boundary where oil, water, and the rock surface meet. It’s typically measured using techniques such as:

• Sessile Drop Technique: A small drop of fluid (oil or water) is placed on a flat, polished rock surface, and the angle formed at the droplet’s edge is measured using a goniometer. This is a common and relatively straightforward method.
• Capillary Rise Technique: This method utilizes the capillary pressure to determine the wettability of a porous medium. By measuring the height of the liquid column in a capillary tube filled with the porous material, we can indirectly determine the contact angle and the wettability of the rock.
• Microscopic Imaging Techniques: Advanced techniques like confocal microscopy or scanning electron microscopy (SEM) allow for detailed visualization of fluid distribution within porous media at a microscopic level, providing insights into the wettability at a pore scale. This is particularly useful for understanding heterogeneous wettability.

The measured contact angle provides valuable information about the rock’s wettability: a contact angle less than 90° indicates water-wetness, a contact angle greater than 90° suggests oil-wetness, and an angle of approximately 90° represents intermediate wettability.

The Amott-Harvey index is a widely used method to quantify wettability, but it has some limitations. This index is based on the spontaneous imbibition of water and oil into a rock core. The limitations include:

• Assumption of homogeneous wettability: The Amott-Harvey index assumes uniform wettability throughout the core sample. However, real reservoir rocks often exhibit heterogeneous wettability, where the wettability varies from one pore to another, leading to inaccurate results.
• Limited information on intermediate wettability: The Amott-Harvey index struggles to effectively characterize intermediate wettability systems, where the rock surface displays neither a strong preference for water nor oil. In these cases, the index may not accurately reflect the complexity of the wettability state.
• Sensitivity to core preparation and fluid properties: The method’s outcome can be significantly impacted by the quality of core preparation (e.g., cleaning, drying) and the properties of the fluids used (e.g., salinity, temperature). Inconsistent preparation methods can lead to variations in results.
• No direct measurement of contact angle: The method indirectly assesses wettability without providing a direct measurement of the contact angle, which is a crucial parameter for understanding the interfacial forces involved.

Despite these limitations, the Amott-Harvey index remains a valuable tool for initial wettability screening, providing a relative comparison between different samples.

The USBM (United States Bureau of Mines) method is a core-flood based technique that quantifies wettability by measuring the relative permeability to oil and water under different conditions. It involves flooding a core sample first with oil, then injecting water and monitoring the oil and water production. The key is comparing the relative permeabilities under two scenarios:

• Water-wet conditions: Water is injected after the core is saturated with oil. This tests water’s ability to displace oil.
• Oil-wet conditions: Oil is injected after the core is saturated with water. This tests the oil’s ability to displace water.

By comparing the relative permeabilities obtained under these conditions, the USBM method helps to determine the wettability of the rock. A higher relative permeability to water in the water-wet test and a higher relative permeability to oil in the oil-wet test suggest water-wet and oil-wet conditions, respectively. The method offers a more robust assessment than spontaneous imbibition methods, providing insight into the dynamic displacement behaviour under reservoir conditions. However, it is more time-consuming and requires specialized equipment compared to simpler techniques.

Wettability significantly impacts oil recovery. In water-wet reservoirs, water preferentially wets the rock surface, leaving oil clustered in larger pores. This makes it relatively easier for water (or injected fluids in enhanced oil recovery processes) to displace the oil, leading to higher oil recovery. Conversely, in oil-wet reservoirs, oil preferentially wets the rock surface, creating thin oil films on the rock, and trapping significant amounts of oil. This film makes it much more challenging to displace the oil, resulting in lower oil recovery. Intermediate wettability falls somewhere between these two extremes, where the displacement efficiency is also affected. This complexity highlights the need to accurately assess wettability before designing an oil recovery strategy. For instance, in strongly oil-wet reservoirs, EOR techniques targeting the alteration of wettability (e.g., using surfactants) may be necessary to improve recovery factors.

Interfacial tension (IFT) plays a crucial role in determining wettability. IFT is the force that exists at the interface between two immiscible fluids (oil and water). A lower IFT generally leads to improved oil displacement. This is because lower IFT reduces the energy barrier required to displace oil from the pores. Consider this: if the IFT between oil and water is low, the tendency for the water to spread on the rock surface (and displace oil) is higher, favoring water-wet conditions. Conversely, if the IFT is high, the oil may tend to stay attached to the surface, promoting oil-wet conditions. Therefore, understanding and controlling IFT is critical in managing wettability and enhancing oil recovery. Techniques like surfactant injection, which alter IFT, are extensively used in EOR to improve oil displacement and recovery.

Brine salinity has a pronounced impact on wettability, particularly in carbonate reservoirs. Increased salinity can significantly alter the wettability of carbonate rocks from water-wet to more oil-wet conditions. This is because higher salinity can screen the electrostatic forces that generally favour water adsorption onto the rock surface. These electrostatic forces are essential in maintaining water-wet conditions. The ions in the brine can also adsorb to the rock surface, potentially creating a more oil-friendly surface. Consequently, understanding the impact of salinity is very important. In field operations, the salinity of the injected fluids is often carefully controlled to manage wettability and enhance oil displacement. This is one of the many reasons why accurate reservoir characterization, including thorough wettability analysis, is critical for efficient oil production.

Mixed wettability describes a reservoir rock’s surface where neither oil nor water preferentially wets the rock. Instead, both oil and water coexist on the pore surfaces. Imagine a sponge: in a water-wet system, water clings to the sponge’s fibers, while in an oil-wet system, oil does. But in mixed wettability, both water and oil occupy the sponge’s pores simultaneously, creating a complex interplay of forces. This isn’t a simple 50/50 split; it’s a spectrum ranging from predominantly water-wet to predominantly oil-wet, with intermediate states where patches of both wettability types exist.

This condition is crucial because it significantly impacts reservoir performance. Fluid flow in mixed-wet systems is more complex than in water-wet or oil-wet systems, affecting hydrocarbon recovery significantly. For instance, oil trapped in mixed-wet rocks may be harder to displace during waterflooding than in water-wet reservoirs.

Interpreting wettability data requires understanding the strengths and limitations of each method. Different methods provide different types of information. For example, contact angle measurements provide a direct measure of interfacial tension and wettability at a macroscopic level, usually on a flat polished surface. However, this may not accurately represent the complex pore-scale geometry of a reservoir rock. Amott-Harvey tests quantify the spontaneous imbibition of water and oil, giving insights into the overall wettability state but not the detailed distribution. Centrifuge methods, on the other hand, allow us to investigate the distribution of fluids at different capillary pressures, offering a more dynamic perspective.

To interpret data effectively, we need to consider multiple techniques. For instance, a low contact angle might suggest water wetness, but a high spontaneous imbibition of oil could indicate mixed wettability with oil patches. A comprehensive analysis involves combining results from various methods to create a robust picture of the reservoir’s wettability.

Wettability measurement faces numerous challenges. One major challenge is the inherent heterogeneity of reservoir rocks. The wettability of a rock can vary significantly from one location to another within the same formation, leading to difficulties in obtaining representative samples. Furthermore, the measurement techniques themselves can be sensitive to experimental conditions, such as temperature and pressure, requiring careful control and standardization.

Another challenge is the alteration of the rock’s original wettability during sample extraction and preparation. Exposure to air and cleaning processes can significantly change the wettability characteristics. Finally, interpreting the data correctly requires a deep understanding of the methodologies and their limitations, and the integration of multiple techniques often requires expertise and experience.

Various core samples are used in wettability testing, each with its own advantages and limitations. These include:

• Conventional cores: These are cylindrical samples extracted from boreholes using specialized drilling equipment. They are the most common type used, providing a relatively undisturbed representation of the reservoir rock.
• Sidewall cores: Smaller cores taken from the borehole wall, often using specialized tools. They are useful when obtaining conventional cores is difficult or impractical.
• Cuttings: Rock fragments generated during drilling. These are readily available but their quality can vary depending on drilling conditions and handling, and they may be significantly altered.
• Synthetic cores: These are fabricated samples with known and controlled properties, used for testing and calibration purposes or to simulate specific reservoir conditions.

Preparing core samples for wettability measurements is crucial for reliable results. This process typically involves several steps:

1. Cleaning: Removing drilling fluids and other contaminants using solvents and cleaning agents is essential. The choice of solvent depends on the rock type and the fluids present. Improper cleaning can alter the original wettability.
2. Drying: Careful drying under controlled conditions (e.g., oven drying at a specific temperature and pressure) is necessary to avoid altering the rock’s properties. Over-drying can damage the rock.
3. Aging (Optional): For certain types of wettability studies, the cores may be aged to simulate reservoir conditions and to allow for the redistribution of fluids within the pores.
4. Saturating: Saturating the cores with fluids of interest (water and oil) to create a defined wettability state. This involves several steps that depend on the selected wettability method.

The goal is to minimize alterations to the rock’s natural state while ensuring it’s clean enough for accurate testing.

Both spontaneous and forced imbibition are used to assess rock wettability. Spontaneous imbibition is the process where a wetting phase (usually water) spontaneously enters a porous medium due to capillary forces without any external pressure. It’s a passive process, driven solely by the interfacial tensions between the fluids and the rock surface. Imagine a thirsty sponge placed in water; the water moves in without any external force. The rate of spontaneous imbibition provides information about wettability and permeability.

Forced imbibition, on the other hand, involves applying external pressure to force the wetting phase into the porous medium. This method can overcome the capillary resistance in low-permeability rocks where spontaneous imbibition is slow or negligible. It offers insights into the wettability of the rock under different conditions of pressure. Think of squeezing water into the sponge—it’s a more aggressive method.

The centrifuge method is a powerful technique for wettability analysis because it allows us to determine the saturation of oil and water at various capillary pressures. By spinning the core sample at increasing speeds, we increase the centrifugal force, mimicking the effect of capillary pressure in a reservoir. The saturation profiles obtained at different centrifugal forces (which correspond to different capillary pressures) provide insights into the distribution of fluids in the rock pores and the relative wettability.

This is particularly valuable in determining the wettability of low-permeability rocks where spontaneous imbibition is slow. The centrifuge method allows us to obtain information relatively quickly and gives a detailed picture of fluid distribution within the pores at various capillary pressures, which is crucial for understanding reservoir behavior and enhanced oil recovery strategies.

Image analysis plays a crucial role in modern wettability studies, providing a quantitative and visual assessment of fluid distribution on a rock surface. Instead of relying solely on contact angle measurements, which can be limited by surface heterogeneity, image analysis allows us to analyze the entire surface area. We can use techniques like contact angle goniometry, but advanced imaging techniques like confocal microscopy, scanning electron microscopy (SEM), and X-ray microcomputed tomography (micro-CT) offer superior spatial resolution and the ability to visualize fluid distribution in 3D.

For instance, using SEM images, we can identify the preferential wetting phase (water or oil) on a pore-scale level. By analyzing the pixel intensities representing each fluid phase, we can determine the area fraction occupied by each, providing a more complete picture of the wettability state than traditional contact angle measurements. Software packages can then be used to automatically quantify these areas, generating data on contact angles, spreading coefficients, and other important wettability parameters. This is particularly useful for characterizing complex reservoir rocks with heterogeneous surfaces where a single contact angle measurement might be misleading.

In essence, image analysis bridges the gap between qualitative visual observations and quantitative wettability data, providing a powerful tool for understanding and predicting fluid behavior in porous media.

Determining the critical wetting pressure is essential for understanding the transition from one wetting state to another. This pressure represents the point at which the non-wetting phase (usually oil in reservoir applications) begins to displace the wetting phase (usually water) from the pore spaces of the rock. Several methods exist, and the best choice depends on the specific application and available resources.

One common technique is the porous plate method. A porous plate is saturated with the wetting phase and then subjected to increasing pressure of the non-wetting phase. The critical wetting pressure is determined by monitoring the breakthrough pressure, which is the point at which the non-wetting phase first appears on the opposite side of the plate. The pressure at the moment of breakthrough is the critical wetting pressure. Another approach involves using capillary pressure curves. By measuring the capillary pressure at different saturations (the fraction of pore volume occupied by each phase), one can extrapolate the curve to find the pressure at which the saturation of the non-wetting phase reaches zero – indicating the displacement has started.

It’s important to remember that the critical wetting pressure is not a single, absolute value, but rather depends on several factors including pore size distribution, fluid properties (viscosity, interfacial tension), and the rock’s intrinsic wettability.

Wettability significantly impacts capillary pressure, which is the pressure difference across the interface between two immiscible fluids in a porous medium. In a water-wet system, water strongly adheres to the rock surface, creating a strong meniscus curvature that requires a high capillary pressure to displace water with oil. Imagine trying to blow a small bubble – it requires more force than a larger one. This means higher capillary pressures are needed to displace the wetting phase (water).

Conversely, in an oil-wet system, oil adheres more strongly to the rock, resulting in a lower capillary pressure for water displacement. The oil coats the rock surface, reducing the force needed to displace the water. The relationship between capillary pressure and saturation is captured in capillary pressure curves, which are different for water-wet and oil-wet systems. Water-wet systems usually exhibit higher capillary pressure at the same water saturation than oil-wet systems.

Understanding this relationship is crucial for predicting fluid distribution and movement in reservoirs, especially during oil recovery processes. It helps engineers design strategies to efficiently displace oil.

Wettability has a profound impact on relative permeability, which describes the effective permeability of a phase relative to the absolute permeability of the rock. Relative permeability quantifies how easily a fluid can flow through a porous medium in the presence of another immiscible fluid. In a water-wet system, the high water saturation at low oil saturation makes oil flow much more difficult; the oil is trapped in isolated pore throats. The relative permeability of oil is low at high water saturation. The opposite is true for oil-wet systems, where oil flow is easier at low water saturations.

Imagine two kids trying to run through a playground. In a water-wet scenario, the playground is already crowded with many children (water). It’s harder for a single child (oil) to navigate through the crowd. In an oil-wet scenario, the playground is mostly empty. The child can run much more easily. The curves representing relative permeability of oil and water as a function of water saturation differ greatly based on wettability. These curves are crucial for reservoir simulation and designing effective oil recovery strategies.

Temperature and pressure exert a significant influence on wettability. The impact is primarily through their effects on interfacial tension and the adsorption of fluids onto the rock surface. Higher temperatures generally decrease interfacial tension, which can lead to changes in wettability, potentially making the system more water-wet or less oil-wet, depending on the specific rock and fluid properties. This is because higher temperatures can increase the mobility of adsorbed molecules and potentially change the balance of adsorption forces between the rock and the fluids. Similarly, pressure can influence the adsorption of fluids, primarily by changing the density and solubility of the fluids.

For example, increased pressure can enhance the adsorption of oil onto the rock surface, making the system more oil-wet, especially in systems with significant adsorption forces. In some cases, a change in pressure can even lead to a change in wettability from water-wet to oil-wet or vice-versa. These changes can affect the efficiency of oil recovery operations and must be carefully considered when planning projects.

Wettability plays a pivotal role in enhanced oil recovery (EOR) techniques. Many EOR methods aim to alter wettability to improve oil displacement efficiency. In naturally oil-wet reservoirs, the oil is strongly attached to the rock surface and difficult to displace. The goal of many EOR techniques is to change this from oil-wet to more water-wet conditions.

For example, chemical flooding, a common EOR method, utilizes surfactants to alter the interfacial tension and wettability of the rock-fluid system. By modifying the wettability to become more water-wet, water can more easily displace the oil. Similarly, polymer flooding alters the mobility ratio of oil and water, improving sweep efficiency in water-wet systems. Understanding the initial wettability is paramount to selecting the most appropriate EOR method.

In essence, manipulating wettability is a cornerstone of effective EOR strategies, enabling enhanced oil recovery from reservoirs that would otherwise be difficult to exploit.

Surfactants are amphiphilic molecules that have both hydrophilic (water-loving) and hydrophobic (oil-loving) portions. Their unique structure allows them to reduce interfacial tension between oil and water and alter the wettability of the rock surface. This is crucial in EOR applications as it can shift the wettability from oil-wet to water-wet, making oil recovery more efficient.

By carefully selecting surfactants based on their structure and properties (e.g., hydrophilic-lipophilic balance, or HLB), we can modify the adsorption behavior on the rock surface. For example, anionic surfactants are often used to alter wettability in carbonate reservoirs, while non-ionic surfactants might be preferred in sandstone reservoirs. The effect of surfactants is not just limited to interfacial tension reduction; they can also modify the adsorption of oil on the rock surface, thereby changing wettability directly. The optimal surfactant concentration needs to be determined through laboratory experiments, considering factors like temperature, salinity and the rock type.

Surfactant flooding is a powerful EOR technique and requires careful design and optimization based on a thorough understanding of the reservoir rock properties and fluid characteristics. Careful selection and injection strategy are crucial for success.

Assessing the accuracy and reliability of wettability data requires a multi-faceted approach. It’s not just about getting a single contact angle measurement; it’s about understanding the entire experimental process and its potential sources of error.

• Reproducibility: The most fundamental aspect is reproducibility. We perform multiple measurements on different samples from the same core plug, under identical conditions. Significant variations indicate potential issues with the experimental setup or sample heterogeneity. A high degree of reproducibility builds confidence in the data.
• Methodological Rigor: The choice of wettability testing method is crucial. Different methods (e.g., contact angle goniometry, Amott-Harvey, USBM) are suited for different scenarios. Selecting the appropriate method and adhering strictly to the established protocols is paramount. Any deviations must be meticulously documented.
• Data Quality Control: We employ rigorous quality control checks throughout the process. This includes checking for contamination, ensuring proper sample preparation (e.g., cleaning and aging), and validating the accuracy of the equipment used (e.g., calibration of the goniometer).
• Statistical Analysis: Raw data is analyzed statistically to determine the mean, standard deviation, and confidence intervals. This provides a quantitative measure of the data’s reliability. Outliers are investigated and, if deemed inappropriate, excluded after careful consideration. A large sample size also enhances statistical robustness.
• Uncertainty Analysis: A complete uncertainty analysis is critical. This accounts for uncertainties associated with measurements, sample preparation, and the methodology itself. It provides a realistic range of values that reflects the overall uncertainty in the wettability assessment.

For example, if we’re analyzing a reservoir rock sample for enhanced oil recovery (EOR) projects, unreliable wettability data could lead to incorrect predictions of oil displacement efficiency, potentially resulting in costly operational decisions. Therefore, a thorough assessment of data accuracy and reliability is crucial for informed decision-making.

Wettability alteration techniques are crucial for improving oil recovery in reservoirs. They aim to modify the rock’s affinity for either oil or water, typically shifting the system towards more water-wet conditions to enhance waterflooding efficiency. There are several techniques:

• Chemical Treatments: This involves injecting chemicals into the reservoir to change the interfacial tensions and wettability. Common chemicals include surfactants, polymers, and alkaline agents. Surfactants, for instance, can lower the interfacial tension between oil and water, making it easier for water to displace oil.
• Thermal Treatments: Heating the reservoir can alter the wettability by changing the properties of the oil and the rock surface. This is particularly effective in reservoirs with heavy oil or significant clay content.
• Gas Injection: Injecting gases like CO2 or N2 can alter the wettability, particularly in cases where the gas dissolves in the oil and changes its interfacial properties. CO2 injection can also have a significant impact on the wettability of the rock matrix itself.
• Combination Treatments: A combination of chemical and thermal or gas injection methods can be employed to achieve a more significant and sustained wettability alteration. This synergistic effect can significantly improve oil recovery.

For example, in a carbonate reservoir exhibiting strong oil-wet characteristics, injecting a surfactant solution can alter the wettability towards more water-wet conditions. This allows water to penetrate the pore spaces more effectively, improving oil displacement and recovery.

Advancements in wettability testing are constantly emerging, driven by the need for more accurate, efficient, and insightful measurements. Some key areas include:

• Advanced Imaging Techniques: Techniques like X-ray micro-computed tomography (µCT) provide high-resolution 3D images of pore structures and fluid distribution, allowing for a detailed visualization of wettability at the pore scale. This helps correlate microscopic wettability with macroscopic flow behavior.
• Automated Contact Angle Measurement Systems: Automated systems improve the precision and speed of contact angle measurements, reducing human error and increasing throughput. These systems often incorporate advanced image analysis software for accurate contact angle determination.
• High-Throughput Screening Methods: Miniaturized and high-throughput techniques are being developed to screen numerous wettability alteration chemicals efficiently, accelerating the optimization of EOR strategies.
• Integration with Reservoir Simulation: Wettability data is increasingly integrated into reservoir simulation models, providing a more realistic representation of fluid flow and enabling more accurate predictions of oil recovery.
• Development of Novel Wettability Indices: Researchers are exploring more comprehensive wettability indices that account for the complex interplay of different factors influencing wettability. Traditional methods often provide a simplified representation.

The integration of these advancements is leading to a more comprehensive understanding of wettability, allowing for more effective design and implementation of EOR strategies.

Wettability significantly impacts waterflooding efficiency. In waterflooding, water is injected into a reservoir to displace oil towards production wells. The rock’s wettability dictates how easily water can displace oil.

• Water-Wet Reservoirs: In water-wet reservoirs, the rock surface prefers water, allowing water to easily displace oil. Waterflooding is generally quite effective in such reservoirs.
• Oil-Wet Reservoirs: In oil-wet reservoirs, the rock surface prefers oil. This makes it difficult for water to displace oil. Water tends to bypass oil, leading to poor sweep efficiency and lower oil recovery. Waterflooding is often less effective in oil-wet reservoirs.
• Mixed-Wet Reservoirs: Mixed-wet reservoirs exhibit both water-wet and oil-wet characteristics within the same reservoir. The displacement efficiency in such reservoirs can be complex and difficult to predict.

Imagine water trying to flow through a straw. If the straw is coated with a material that water likes (water-wet), the water will flow easily. If the straw is coated with oil (oil-wet), the water will struggle to flow through, just like water struggles to displace oil in an oil-wet reservoir. Consequently, understanding and potentially altering reservoir wettability is essential for optimizing waterflooding strategies.

Presenting and interpreting wettability data to non-technical audiences requires simplification and visual aids. Avoid technical jargon and focus on the implications of the data.

• Analogies: Use simple analogies to explain complex concepts. For example, comparing wettability to the way water beads up on a waxed car (oil-wet) versus a clean car (water-wet).
• Visuals: Employ charts, graphs, and images to represent the data effectively. A simple bar chart comparing the oil recovery percentage in different wettability scenarios is more easily understood than a complex table of contact angles.
• Focus on Impact: Instead of focusing on technical details, emphasize the practical consequences of the wettability data. For instance, explain how wettability affects the efficiency of oil recovery or the cost of EOR operations.
• Storytelling: Frame the data within a narrative, making it more engaging and memorable. Tell a story about how understanding wettability has helped in a real-world situation, perhaps a successful EOR project.

For example, instead of saying, “The contact angle measurements suggest a mixed-wet reservoir with a predominantly oil-wet character,” you could say, “Our tests show that the reservoir rock doesn’t easily release the oil, making it challenging to recover all the oil with conventional methods.”

Avoiding errors during wettability testing is crucial for obtaining reliable results. Common errors to avoid include:

• Inadequate Sample Preparation: Improper cleaning or crushing of core plugs can alter the natural wettability and introduce artifacts. Contamination from drilling fluids or other substances must be carefully avoided.
• Incorrect Choice of Wetting Fluids: Using inappropriate wetting fluids (e.g., distilled water instead of formation brine) can lead to inaccurate results. The properties of the wetting fluids should closely match those found in the reservoir.
• Insufficient Aging Time: Allowing insufficient time for the core plug to equilibrate with the wetting fluids can lead to inaccurate wettability measurements. The equilibration time varies depending on the rock type and fluids used.
• Improper Equipment Calibration: Failing to calibrate the equipment properly (e.g., goniometer, pressure transducers) introduces systematic errors into the measurements.
• Ignoring Heterogeneity: Overlooking the inherent heterogeneity of reservoir rocks can lead to erroneous conclusions. Multiple measurements on different parts of the core are necessary to account for this variability.
• Misinterpretation of Data: Incorrect interpretation of contact angle measurements or other wettability indices can lead to erroneous conclusions about reservoir behavior.

For instance, a poorly cleaned core plug might exhibit a misleadingly water-wet character, leading to an overly optimistic prediction of waterflooding efficiency.

Throughout my career, I’ve worked with a variety of wettability testing software and equipment. My experience spans both conventional and advanced techniques.

• Contact Angle Goniometers: I have extensive experience using optical contact angle goniometers from various manufacturers (e.g., Ramé-Hart, Kruss). I’m proficient in operating these instruments, processing images, and calculating contact angles using both sessile drop and captive bubble methods.
• Amott-Harvey Apparatus: I’m experienced in performing Amott-Harvey tests to determine the wettability index. This involves using specialized equipment to measure the spontaneous imbibition and displacement of oil and water in rock samples.
• USBM (United States Bureau of Mines) Method: I have experience using the USBM method, a procedure that focuses on measuring the relative volumes of oil and water spontaneously imbibed into the rock sample.
• Image Analysis Software: I have extensive experience using image analysis software (e.g., ImageJ, specialized software packages integrated with goniometers) to process images and obtain precise measurements of contact angles and other relevant parameters.
• Reservoir Simulation Software: I’m proficient in incorporating wettability data obtained from experiments into reservoir simulation software (e.g., CMG, Eclipse) to model fluid flow and optimize EOR strategies.

My experience with this diverse range of tools allows me to choose the most appropriate method and equipment for each specific wettability study, ensuring the most accurate and reliable results.