Wellsite Geologist Interview
Questions and Answers
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Q1. What are important roles and responsibilities of a wellsite geologist on a rig?
Ans. A wellsite geologist serves as a multifaceted expert on an oil rig. Basically he plays three primary roles:
1. Expert Geologist: Analyse and interpret geological data, including logs, cuttings, and core samples, to identify and characterize formations, evaluate potential hydrocarbon zones, and assess reservoir quality. As well as identify overpressure zones and estimate formation pressure and advise MW for the safety of operation.
2. Operations Coordinator: Oversee geological operations on the rig, coordinating with operations geologis, company man, drillers, directional drillers, logging engineers and other team members to ensure drilling activities align with geological objectives.
3. Data And Quality Manager: Ensures that data and logs are being presented on company recommended formats. It is also his essential duty to ensure that all geological data being collected is consistently accurate and meets established standards.
Key responsibilities of a wellsite geologist include:
Preparing and submitting geological reports and logs on daily basis.
Interpreting logs and data to provide informed recommendations to the client
Witnessing and coordinating various operations, such as wireline logging, conventional coring, and directional drilling
Participating in daily meetings to update the team on geological findings and progress
Compiling a comprehensive final well report upon completion of the well
Q2. What happens in the pre-job meeting between a wellsite geologist (WSG) and an operations geologist (Ops. Geo) at the client’s office?
Ans. The pre-job meeting between a wellsite geologist and an operations geologist is held in client’s office before going to the rig. For wellsite geologist it is a critical opportunity to align on the drilling and geology plan for the well. The Ops Geo will typically provide the WSG with the following information:
A written drilling and geology plan
A brief overview of the geology and structural setting of the field
The objectives of the well
Any anticipated challenges
A logging program
Copies of offset mud logs and wireline logs, along with any changes in reporting and logging formats
The WSG will review this information and ask clarifying questions. During the discussion the two share their own insights and recommendations based on their experience.
In addition to the technical discussion, the pre-job meeting is also a good opportunity to meet the geology team consisting of geophysicist, Petrophysicist, exploration geologist and the manager etc.
Q3. What are the roles and responsibilities of an operations geologist?
Ans.
The role of operations geologist requires several years of wellsite geology experience. The successful candidate is required to plan and manage wellsite geological operations, interpreting geological data, and managing related datasets. This involves close collaboration with geophysicists, reservoir engineers, and drilling engineers. Strong leadership, communication, and analytical skills are essential.
Job Responsibilities:
Wellsite Operation Planning & Management:
1. Develop drilling and data acquisition plans in collaboration with relevant teams (geophysics, reservoir, drilling).
2. Prepare tenders for geological services, evaluate bids, and select contractors.
3. Quality control data acquisition and processing.
4. Generate and distribute geological reports during drilling operations.
5. Supervise wellsite geologists and subcontractors.
6. Plan well trajectory and provide geosteering expertise as needed.
7. Collaborate with the team to determine drilling strategy.
8. Provide 24/7 wellsite activity monitoring (office and wellsite).
Geological Data Interpretation:
1. Interpret geological, drilling, and core sample data for post-well analysis.
2. Manage geological service reports, including well final reports from subcontractors.
3. Prepare and review technical reports and proposals.
Data Management:
1. Load and quality control geological datasets.
2. Manage and maintain geological datasets and the internal database.
Other Important Points:
Key Skills: Strong understanding of wellsite operations, geological data interpretation, and data management. Excellent collaboration, communication, and leadership skills. Proficiency in relevant software and tools. Ability to work in a demanding environment and handle 24/7 monitoring as needed. Experience with geosteering is a plus.
Collaboration: This role requires extensive collaboration with multidisciplinary teams.
Reporting: Generating and reviewing technical reports is a key responsibility.
Data Focus: Significant emphasis is placed on data quality control and management.
Application: Interested candidates should send their CVs to [email address removed] with “Operation Geologist” in the subject line.
Q4. How do you estimate the net pay for your morning report on a quick-look basis?
Ans. A wellsite geologist utilizes a combination of logs to estimate net pay on a quick-look basis in the following manner:
1. Establish a sand line on the gamma ray log to identify potential sandstone intervals
2. Determine a hydrocarbon cut-off on the resistivity log to distinguish hydrocarbon-bearing zones
3. Mark oil-bearing and gas-bearing reservoirs by analysing the GR, resistivity, neutron density cross-overs, and gas log.
4. Calculate the net pay thickness by summing the individual oil and gas pay intervals
5. Indicate possible oil pay and possible gas pay zones based on low resistivity, low porosity, or contamination in the lithology
This quick-look net pay estimation provides an initial assessment of the well’s hydrocarbon potential and helps in further evaluation and decision-making processes.
Q4. How do you estimate the net pay for your morning report on a quick-look basis?
Ans. A wellsite geologist utilizes a combination of logs to estimate net pay on a quick-look basis in the following manner:
1. Establish a sand line on the gamma ray log to identify potential sandstone intervals
2. Determine a hydrocarbon cut-off on the resistivity log to distinguish hydrocarbon-bearing zones
3. Mark oil-bearing and gas-bearing reservoirs by analysing the GR, resistivity, neutron density cross-overs, and gas log.
4. Calculate the net pay thickness by summing the individual oil and gas pay intervals
5. Indicate possible oil pay and possible gas pay zones based on low resistivity, low porosity, or contamination in the lithology
This quick-look net pay estimation provides an initial assessment of the well’s hydrocarbon potential and helps in further evaluation and decision-making processes.
Q5. What is the effect of dolomitization on reservoir characteristics?
Ans. Dolomitization is a diagenetic process that replaces calcium carbonate (calcite) with magnesium carbonate (dolomite) in sedimentary rocks. This process often enhances reservoir quality by increasing porosity and permeability.
Additional Notes Supplied by Mr. Danis S.
Difference between limestone reservoir and dolomite reservoir?
Both limestone and dolomite are sedimentary rocks composed mainly of calcium carbonate (CaCO3), but they have key differences that impact their properties as hydrocarbon reservoirs:
Porosity and Permeability:
Limestone: Can have high porosity and permeability due to various factors like fossil fragments, internal molds, and dissolution features. However, these features can be susceptible to filling and pore occlusion over time, reducing porosity and permeability.
Dolomite: Generally, has lower initial porosity than limestone but tends to retain its porosity better at deeper depths due to its resistance to compaction. Dolomite can also develop enhanced porosity and permeability through fracturing and dissolution processes.
Reservoir Quality:
Limestone: Can be excellent reservoirs when they have high porosity, permeability, and good connectivity. However, they can be more susceptible to diagenetic alterations that reduce reservoir quality.
Dolomite: Often considered better reservoirs than limestones due to their better porosity preservation at depth and potential for enhanced permeability through fracturing and dissolution. However, dolomitization can be patchy, creating heterogeneity in reservoir quality.
Others:
Dissolution: Dolomite is less soluble than calcite, making it more resistant to acidic fluids and weathering.
Fracturing: Dolomites may be more prone to fracturing than limestones due to their different mechanical properties.
Overall:
Dolomite generally has better long-term porosity preservation and may have higher potential for enhanced permeability, making it often a more favorable reservoir rock.
What is the effect of dolomitization on reservoir characteristics?
Dolomitization is a diagenetic process that replaces calcium carbonate (calcite) with magnesium carbonate (dolomite) in sedimentary rocks. This process often enhances reservoir quality by increasing porosity and permeability.
Q6. If we get a kick, what information will you pass to the operations geologist?
Ans. If a kick occurs, the wellsite geologist has to immediately inform the operations geologist and provide the following information:
1. Depth of the kick
2. Latest structural correlation of the wellbore
3. Events leading up to the kick, including ongoing operation, mud weight, gas readings and hole
condition etc.
4. Duration and intensity of the drill break
5. Total gas and pit volume gain
6. Shut-in drill pipe pressure (SIDPP) and shut-in casing pressure (SICPP)
7. Estimated kill mud weight
8. Difference in formation pressure as per the kick and from logs/calculations
The idea is to be fully prepared with information and suggestion before you call town.
Q7. What will be your concerns while drilling in an old field that has good quality clastic reservoirs?
Ans. Old oil and gas fields usually have depleted reservoirs which may present several challenges. Therefore we must be vigilant and may anticipate:
1. Minor to moderate mud losses due to the pressure differential between the wellbore and the surrounding depleted formations
2. Differential sticking, if the hydrostatic and formation pressures differential is significant and depleted reservoirs are porous and permeable, we must seriously be concerned to avoid drillstring or wireline tools getting stuck
Additional notes provided by Danis S. on problems related to depleted reservoirs
Problems while drilling Depleted reservoir?
Drilling through depleted reservoirs can present some common problems encountered and potential mitigation strategies:
Wellbore Stability:
Fracture instability: Depleted formations have lower pore pressure, reducing their support for the wellbore and increasing the risk of borehole collapse, especially in fractured zones. Mitigation: Use high-mud-weight fluids, casing/liner placement optimization, borehole strengthening techniques (cement or resin plugging), and real-time drilling parameter adjustments.
Lost Circulation:
Increased risk due to lower pressure disparity: Lower reservoir pressure can lead to fluid loss into the formation, resulting in lost circulation and potential drilling fluid contamination. Mitigation: Use mud with appropriate loss control additives, controlled mud pressure application, managed drilling parameters, and close monitoring of mud pit levels.
Differentiation Issues:
Difficulties in estimating pore pressure and fracture pressure: Reduced pressure gradients in depleted zones make it harder to differentiate between pore pressure and fracture pressure, increasing the risk of wellbore kicks or blowouts. Mitigation: Conduct detailed pre-drill pore pressure analysis, utilize real-time mud logging and seismic data, implement formation pressure testing, and maintain tight mud pressure control.
Drilling Efficiency:
Slower drilling rates due to increased formation hardness: Depleted formations with hydrocarbon removal can be cemented or compacted, leading to slower drilling rates and higher bit wear. Mitigation: Optimize bit selection with harder materials and abrasion resistance, adjust drilling parameters for efficient cutting removal, and consider alternative completion methods like multilateral or horizontal wells.
Formation Evaluation:
Challenges in interpreting mud logs and wireline logs: Changes in rock properties due to depletion can affect log responses, making formation evaluation and hydrocarbon identification more complex. Mitigation: Utilize integrated datasets for interpretation including mud logs, wireline logs, seismic data, and core data (if available), consider advanced logging techniques like nuclear magnetic resonance (NMR) logs, and involve experienced geologists for data analysis.
Additional Challenges:
– Potential corrosion issues: Increased hydrogen sulfide content in depleted reservoirs can pose corrosion risks to drilling equipment.
– Environmental considerations: Produced water re-injection or disposal needs to be handled responsibly during and after drilling operations.
– Remember: Thorough pre-drill planning, real-time monitoring, and experienced personnel are crucial to mitigate these challenges and ensure successful drilling operations in depleted reservoirs. Consider consulting with wellbore stability specialists, mud engineers, and experienced drilling supervisors for optimal solutions.
By recognizing these potential problems and implementing appropriate mitigation strategies, drilling through depleted reservoirs can be achieved safely and efficiently, contributing to valuable resource exploration and production.
Q8. After running the first set of electric logs, the wireline engineer gives you the printout. How will you QC the logs?
Ans. Quality control (QC) of wireline logs is crucial to ensure the accuracy and reliability of the logs. The wellsite geologist should perform the following QC checks:
1. Verify the accuracy and completeness of information on the log heading including the scales on various tracks.
2. Examine the consistency of log curves, identify any missing or unusual patterns on the log curves that may indicate errors or inconsistencies.
3. Check that log calibrations are within the acceptable range and that any comments provided by the logging engineer are appropriate and informative.
Q9. What are the various steps involved in taking formation fluid sample on wireline?
Ans. Collecting fluid samples using wireline tools provides valuable information about formation fluids and reservoir characteristics. The process typically involves the following steps:
1. Correlate the depth of the wireline tool with the geological formations encountered.
2. Position the wireline tool probe at the desired sampling depth and record the formation pressure.
3. Pump out to remove any contaminant (MF) until you see fresh reservoir fluids.
4. Identify fluid using OFA, resistivity and temperature.
5. Open the sample chamber and collect the fluid sample.
Q10. How do you geosteer a directional well?
Ans. Geosteering is the process of controlling the trajectory of a directional wellbore to reach the desired target while maintaining wellbore stability and avoiding formation damage. The wellsite geologist plays a crucial role in geosteering by:
1. Plotting directional data on horizontal and vertical section plots to visualize the actual wellbore trajectory compared to the planned path.
2. Analysing the plotted trajectories to identify any deviations from the planned path and assess their severity.
3. Collaborating with operations geologist, company man and directional driller to make informed decisions about corrective actions, such as adjusting the toolface or reaming the wellbore.
4. Last but not least; communicating effectively with all stack holders is of paramount importance for successful well placement.
Q. Who designs the logging program?
Ans. Logging programmes are designed mainly by Petrophysicist in consultation with operations geologist, exploration geologist or development geologist, geophysicist, reservoir engineer as per the logging objectives. Selection of appropriate tools depend largely on the nature of well and the uncertainties in our understanding of subsurface formations. For example in exploration stage the main objectives are to look for reservoirs and source rock, presence and potential of hydrocarbons. Whereas in development stage the main focus is on volumetric estimate of hydrocarbon and geological modelling of the field. In the rest of the field productive life the focus is limited to monitoring the field-wise distribution of hydrocarbon and reservoir pressures. A logging plan is therefore designed keeping these fundamental points in mind. A wellsite geologist is usually not involved in the preparation of logging plan.
Q. What are the objectives of wireline logging, a wellsite geologist is most involved with?
Ans. A wellsite geologist is most focused on the following points during and after logging:
1. Witnessing logging operation and QC of the logs
2. Identifying hydrocarbon bearing reservoirs
3. Identifying lithologies
4. Determining structural position of the well with respect to offset well (Performing correlation)
5. Performing pressure tests. Taking fluid samples and rock samples.
Q. What is a caliper log? How is it recorded? What are its uses?
Ans. A caliper log is a continuous record of measurements of hole diameter and shape. The caliper tool has several spring-loaded arms (typically 2, 4, or more) that press against the borehole wall. As the tool moves up the well, the arms adjust to the changing hole diameter. This movement of arms is converted to electrical signal according to hole sizes.
The Caliper log is valuable for several reasons:
1. It helps identify problems in the borehole, such as wash-outs (enlarged sections), cave-ins, or swelling of formations like shale.
2. The information can be used to correct other well logs that might be affected by the size or shape of the borehole.
3. With the help of Caliper log an accurate hole volume and cement slurry volume is calculated before cementing the casing.
Note:
Caliper log is checked inside casing. If it is reading casing ID correctly the tool is properly calibrated.
GR LOGGING
Q. What does GR tool measure?
Ans. GR log records natural radioactivity of rocks. The GR emission or radiation in rocks results due to decay of radioactive minerals such as uranium, thorium, potassium.
Q. What are the uses of GR Log?
Ans. GR log has many important uses:
1.Lithology identification
2. Estimation of reservoir thickness
3. Correlation with offset wells
4. Shale volume estimation
5. Depth Matching, the gamma ray tool is part of every run and almost every tool combination. It has a high reliability and a high vertical resolution, hence very useful in correlation and depth matching even when recorded inside the casing.
6. Identification of facies and depositional Environments: GR logs are very useful in identifying various parts deltaic environments such as Fluvial Channels, Bell shape fining upward, Funnel shape coarsening upward, Proximal deep sea Fans etc.
Q. What is the recording principle of GR tool?
Ans. Certain elements like potassium, uranium and thorium are naturally radioactive. These elements are found in most sedimentary rocks in varying quantities. In simple term, GR tool uses scintillation detector that absorb Gamma Rays and produce electrical energy that is proportional to the GR being emitted by formations.
There are two types of GR logs: One is simply called GR that records total radioactivity of the formation. The other is called Spectral GR. That records the Gamma Rays of individual elements like uranium, thorium and potassium. Spectral GR helps in identifying feldspar and mica rich sands from shale.
GR is plotted on first track of the log along with SP and Caliper. It uses API units on scale. The scale selected may vary from company to company or field to field from 0 to 200 or 0 to 150 or even 0 to 100. Sometimes GR is recorded inside casing for correlation purpose in which case the scale could be as low as 0 to 50.
Simple calibration check is carried out on rig floor before survey (before the tool is run in the hole) and after survey (when the tool is pulled out of hole after logging) by using a radioactive source of accurately known radioactivity at a fixed distance from the tool.
Q. How to QC GR log at the time of wireline logging?
Following are some of the important points that a geologist should keep in mind:
1. Keep GR log from offset well and mud log of current well when you are witnessing the logging. Ensure GR is responding prominently to bed boundaries and thin beds like coal, dolomite etc.
2. If the reservoirs are thinly bedded, advisable to maintain low speed (~1500 ft/hr) to get better resolution of thin sand beds. Otherwise, 2000 to 3000 ft/hr. speed gives good resolution of GR log.
3. Ensure before survey and after survey calibration on GR tool is performed and results are shown on the log.
4. Ensure there are no gaps, kinks or straight line on the log. Occasionally you may see spikes, reading 100 to 200 API units. These are recorded against thin beds of black organic rich shale often called hot shale. These can be ignored.
5. Ensure that GR log is consistent with other logs on the screen or on the print. Consistency between the log means that all logs are responding to a new lithology at exactly the same depth. For example if a coal bed is encountered, GR will read less, resistivity will increase density will decrease and neutron porosity will increase. Ensue the response is coming at the same depth. If not point it out wireline engineer.
Q. What are typical GR response in various lithologies?
Shale: GR log gives high readings against clay, claystone and shale (roughly speaking 60 to 80 API units). Some time we can get as high as 150 to 200 API units against some very thin shale beds. These shale beds are unusually rich in radioactive materials and are called hot shales.
Sandstone/Sand: Clean sand and sandstones have very low GR readings less than 20 but as argillaceous material increases GR readings also increase. Sand with high GR readings 40 to 60 are called dirty sand (these are empirical values. Please do not take them literally). GR values in siltstone varies from 50 to 70.
Coal, limestone and dolomite read low values of GR. Usually 10 to 30 units.
Anhydrite and halite show very low GR readings less than 15 units, unless they have some traces of potassium.
Notes:
It should be appropriate to note that wireline tools are run in combination with other tools, for example first run normally has GR-SP-Caliper (in first track) Shallow Resistivity-Med Res-Deep Res. (in second track) Density Neutron (in third track). Each tool has its own designated optimum speed. So, the tool with the lowest speed decides the speed of the tool.
Also please note the wireline logging is recorded while tools are being pulled upward. In this case the proper stretch on the cable gives correct depth. We also record down log (while running in hole at a fast speed ~10000 ft/hr.) down log is not on depth because of slack on cable and the quality of log is also poor because of its running speed. It is a standard practice among wellsite geologists to ask wireline engineer to record down log just in case tool becomes faulty or hole becomes bad and somehow, we cannot record the log. In which case something is better than nothing.
Q. What is VShale? Why do we need to calculate it? How do we calculate shale volume?
Ans. Shale volume (Vshale) represents the disseminated volume of shale or clay within reservoir rock. There are two reasons why it is essential to find out shale volume:
1. Clay minerals, acts as a barrier to fluid flow and can significantly impact reservoir quality.
2. Presence of clay minerals in reservoir rock effect Rt (true formation resistivity) which is used to calculate water saturation. If we do not remove the effect of presence of clay minerals in reservoir rock then we will get Sw (water saturation) readings higher than what it actually is, thus leading us to ignore certain potential hydrocarbon reservoirs.
GR log is the primary tool for estimating Vshale. In order to calculate Vshale, we first have to calculate Gamma Ray Index (IGR) and then using IGR value on Shale Volume Chart we find out shale volume. The graphical chart is provided by logging companies.
IGR = (GR(log) – GR(min)) / (GR(max) – GR(min))
Where:
IGR: Gamma Ray Index (in decimal)
GR(log): Gamma Ray reading of the formation at depth of interest (in API units)
GR(min): Minimum gamma ray value (clean sand or carbonate formation) (in API units)
GR(max): Maximum gamma ray value (shale formation) (in API units)
Q20. What do you know about Spectral GR?
Ans. GR log tells us the total GR radiation coming out of a certain minerals (let’s say formation) Spectral Gamma Ray log on the other hand gives GR values coming out from individual minerals like potassium, uranium and thorium. This in turn gives valuable information about formation’s mineralogy, leading to better reservoir characterization, fracture identification, and overall understanding of the subsurface geology. However, the increased cost and complexity of interpretation require careful consideration in selecting SGR tool. This is why it usually run in exploratory wells.
Notes:
A Spectral Gamma Ray (SGR) log is an advanced tool used in well logging that goes beyond the basic gamma ray log. While a traditional gamma ray log simply measures the total natural radiation emanating from a formation, an SGR log takes it a step further. It analyzes the energy spectrum of the gamma rays, allowing geologists to identify and quantify the specific radioactive elements present:
Potassium (K): Often associated with clays and illites.
Thorium (Th): Often linked to clays and heavy minerals.
Uranium (U): Can indicate organic matter, diagenetic processes, or fractures filled with uranium.
Applications of SGR Logs:
Clay Volume Estimation: By analyzing the combined response of K and Th, geologists can estimate the amount of clay minerals present in the formation. This is crucial for characterizing source rocks, reservoir quality, and potential wellbore stability issues.
Lithology Identification: The relative abundance of K, Th, and U helps differentiate between different rock types, such as sandstones, shales, limestones, and even coals.
Fracture Identification: Uranium can migrate and concentrate in fractures. SGR logs can help identify these fractures, which are important for understanding fluid flow and potential production zones.
Hydrocarbon Identification: While not a direct indicator, variations in U content can sometimes be linked to the presence of organic matter, which may be associated with hydrocarbons.
Advantages of SGR Logs:
Detailed Information: Provides a more comprehensive picture of the formation’s mineralogy compared to a basic gamma ray log.
Improved Shaley Sand Analysis: Helps differentiate between clay and dispersed organic matter, leading to more accurate porosity calculations in shaley sand formations.
Fracture and Fluid Flow Characterization: Identifies fractures and potential pathways for fluids based on U distribution.
Disadvantages of SGR Logs:
Cost: SGR tools are generally more expensive than basic gamma ray tools.
Interpretation Complexity: Analyzing the spectral data requires more expertise compared to a simple total gamma ray count.
Environmental Effects: Borehole fluids and tool response can affect the interpretation of the SGR log.
SP LOG
Q. What is Spontaneous Potential Log (SP)
The SP log, also called the self-potential log, is a well-established technique used to analyze rock formations down a borehole. It measures the natural electrical potential difference (measured in millivolts) between an electrode in the borehole and a reference electrode at the surface.
Q. How is SP log recorded ?
SP relies on the natural electrical currents that flow within the earth due to differences in salinity between the drilling mud and the formation water. These currents arise from:
1. Electrochemical processes: Interactions between the various chemicals in rocks and fluids create tiny electrical potentials.
2. Electrokinetic effects: Movement of charged ions (electrolytes) in the fluids relative to the rock creates another source of electrical potential.
The SP log measures the cumulative effect of these processes. To record SP log we need salinity difference between mud and formation water. This is why SP log cannot be recorded in oil base mud.
Q20. What are the uses of SP Log:
Ans. This simple, which is usually provided free of cost by some wireline companies ha multiple uses:
1. Identifying permeable zones: Shales are typically impermeable and have a stable SP signature. Deviations from this baseline on the SP log indicate permeable formations like sandstones or limestones.
2. Estimating formation water salinity (Rw): The direction and magnitude of the deflection in the SP log depend on the salinity contrast between the mud filtrate and formation water. By analyzing the SP curve, geologists can estimate the salinity of the formation water. In good old days calculating RW was a rule, now an exception.
3. Assessing formation clay content: Shales with high clay content have a characteristic SP response. This helps geologists identify and quantify clay-rich zones.
4. Correlating formations across wellbores: The distinctive SP signature of specific formations can be used to correlate them between different wells drilled in a particular area.
Q. What are the weaknesses of SP log?
Ans. 1. Limited information: SP only provides a qualitative assessment of formation properties. Other logging tools are needed for a more comprehensive evaluation.
2. Environmental sensitivity: SP readings can be affected by borehole conditions like mud type and salinity, requiring careful interpretation.
3. Limited applicability: SP is ineffective in non-conductive environments like air-filled boreholes or those filled with oil-based drilling muds.
Q. What is static SP (SPP) ?
Static SP (SSP), also referred to as static spontaneous potential, represents the ideal or theoretical SP response you would get under specific conditions.
Here’s how it relates to the regular SP log:
Regular SP vs. Static SP:
The regular SP log measures the actual electrical potential difference encountered in the borehole. This can be influenced by various factors like:
Borehole size and mud properties
Formation thickness and permeability
Invasion of mud filtrate into the formation
Static SP, on the other hand, represents the maximum SP that would be recorded if:
The formation is thick, clean (no clay), highly porous, and permeable.
There’s no mud filtrate invasion into the formation.
Current flow within the formation is completely restricted, forcing all current to travel through the borehole fluid.
Q. Why is Static SP Important?
The actual SP log often deviates from the ideal static SP due to the factors mentioned above. However, understanding the static SP helps us:
1. Interpret the measured SP: By comparing the measured SP with the expected static SP for a specific formation type, geologists can assess the influence of factors like mud invasion or bed thickness.
2. Correct the SP log: Various correction charts and methods are available to adjust the measured SP closer to the theoretical static SP, providing a more accurate representation of the formation properties.
In essence, static SP serves as a reference point for understanding and interpreting the actual SP log data. It helps account for various environmental factors and allows for a more accurate evaluation of the formation’s electrical properties.
Q. How can we calculate RW from SP?
Calculating formation water resistivity (Rw) from the SP log is an indirect process that requires additional information and often involves specialized charts or software. Here’s a general overview of the steps involved, along with some limitations:
Steps:
Data Gathering:
1. SP reading: Identify the SP deflection (in millivolts) from the shale baseline for a clean and thick formation zone (ideally greater than 20 ft).
2. Mud filtrate resistivity (Rmf): Obtain the resistivity of the mud filtrate at the formation temperature, typically found on the well log header or from mud engineer.
3. Formation temperature (BHT): This is also usually available from the well log header.
4. SP Correction: The measured SP might be influenced by factors like borehole conditions. Some methods involve shifting the SP curve on charts or using software to account for these effects and get a value closer to the true formation SP.
5. Chart or Software Lookup: Specialized charts or software are used to relate the corrected SP value, formation temperature, and mud filtrate resistivity to a formation water resistivity (Rw) value. These charts typically involve grids with SP on one axis, temperature on another, and outputting a value of Rmf/Rw.
Example:
Measured SP deflection = -70 mV (negative deflection indicates higher formation water resistivity than mud filtrate)
Mud Filtrate Resistivity (Rmf) at formation temperature = 1.0 ohm-meter
Formation Temperature (BHT) = 150°F
Using a chart:
Locate the corrected SP value (assuming -70 mV after correction) on the SP axis of the chart.
Follow the SP grid line to the line representing the formation temperature (150°F).
From this intersection point, move horizontally to read the value on the Rmf/Rw axis. Let’s say this value is 8.0.
Calculation:
Rw = Rmf / (Rmf/Rw) = 1.0 ohm-meter / 8.0 = 0.125 ohm-meter (This is the estimated formation water resistivity)
Important Points:
This is a simplified example, and actual calculations might involve more complex equations or software.
The accuracy of the Rw determination depends on the validity of the assumptions made (clean formation, thick bed) and the quality of the SP correction process.
Other logging tools like resistivity logs can provide more direct measurements of formation resistivity, which can be used to validate or refine the Rw estimated from SP.
RESISTIVITY LOGING
Q. What are the uses of Resistivity Logs?
Ans. Resistivity logs are primarily used to pick hydrocarbon zones and to calculate Water Saturation (SW).
Their secondary uses may be listed as:
1. Lithology indicator
2. Facies and electro-facies analysis
3. Structural correlation
4. Determination of overpressure
5. Indications of compaction, and the investigation of source rocks.
Q. Looking at resistivity log; how will you differentiate hydrocarbon zone from water zone?
Ans. Resistivity tools record formation resistivity which depends on rock matrix and nature of fluid in the pore spaces. On a very basic level if the pore fluid contained in the pores are oil and gas, the formation resistivity will be high. However if pores are filled with water the formation resistivity will be low.
Q. What are two basic type of resistivity tools. Do comment on their application?
Ans. Resistivity tools are divided into two groups based on resistivity measurement methods:
1. Electrode Resistivity Tools (Laterolog); ideally used in conductive mud (salt water based mud)
2. Induction Resistivity Tools; ideally used in nonconductive mud like (fresh water mud & OBM)
Q. How do laterolog tools measure resistivity?
Ans. Laterolog (Electrode Resistivity) tools, measure formation resistivity by directly injecting current through the transmitting electrode (called transmitter) into the formation where it travels certain distance and returns back to tool, where it is recorded by receiving electrode (receiver). The drop in the voltage between transmitter and receiver is proportional to formation resistivity.
Q30. Laterolog based resistivity logs are further divided into three types what are they and what is the basis of classification?
Ans. These tools are further divided into deep resistivity (LLd) medium resistivity tool (LLm) and shallow resistivity tool (LLs) based on their depth of investigation which varies from company to company but typically deep laterolog (LLd) records formation resistivity with lateral depth of investigation that may range from 5 ft to 8 ft depending on company and tool version. Medium resistivity (LLm) may have depth of investigation a few ft. Whereas shallow resistivity is records a few inches into the formation.
Q. How do Induction tool record formation resistivity in well filled with nonconductive mud?
Ans. These tools use the principle of electromagnetic induction to create eddy currents in the formation and measure their response in the formation. Induction tools are ideal for fresh water muds, OBM or air drilled wells. Their depth of investigation is deeper than laterolog tools (8 to 10 ft). By the way induction tools also record deep, medium and shallow resistivity logs.
Q. How do we decide which type resistivity tool should be run in hole?
Ans. The choice of tool depends on specific well conditions (mud type, formation characteristics) and desired information (shallow vs. deep resistivity, near-wellbore vs. invaded zone).
Q. What are the advantages and disadvantages of laterolog tools?
Ans. These tools work well in conductive mud (salt water based muds). Laterolog tools are good for near-wellbore evaluation. Their main disadvantages are their sensitivity to borehole conditions. Also these tools are less effective in high resistivity formations.
Q. What are the advantages and disadvantages of Induction tools?
Ans. Induction tools are less sensitive to borehole effects, work well in nonconductive muds. They have deeper depth of investigation compare to laterolog.
Disadvantages: In formations with extremely high resistivity (above 150 ohm-m or so), the induced signal in the formation becomes weak, leading to reduced accuracy and resolution. Induction tools are also less sensitive to thin beds compared to some laterolog tools. This can make it difficult to accurately differentiate between thin layers with varying resistivity.
Q. Dual laterolog and Array Induction tools are newer and advanced version of Induction and Laterolog tools; what do you know about them?
Ans. Array induction tools offer a more detailed resistivity profile with improved invasion characterization and reduced environmental effects. Dual laterolog tools provide deeper investigation with less mud influence, better accuracy in saline mud environments, and improved bed resolution.
Notes:
Both array induction tools and dual laterolog tools are advancements over their single-measurement counterparts. Here’s a breakdown of their advantages:
Array Induction Tools:
Multiple Investigation Depths: Unlike single-point induction tools, array tools have multiple transmitter and receiver coils spaced along their body. This allows them to take measurements at various investigation depths – shallow, medium, and deep – within a single logging run. This provides a more detailed resistivity profile of the formation.
Improved Invasion Characterization: With data from multiple depths, array tools can better differentiate between uninvaded formation (true resistivity, Rt), the invaded zone (resistivity influenced by mud filtrate, Rxo), and the borehole itself. This is crucial for accurate evaluation of hydrocarbon zones.
Reduced Environmental Effects: Array tools offer improved processing techniques to account for borehole effects like mud salinity and tool eccentricity, leading to more reliable resistivity measurements.
Dual Laterolog Tools:
Deeper Investigation with Less Mud Influence: Compared to single laterolog tools, dual laterolog tools have two current paths with different focusing mechanisms. This allows them to investigate deeper into the formation while minimizing the influence of highly conductive mud on the measurement.
Improved Accuracy in Saline Mud Environments: Dual laterolog tools provide a more reliable resistivity reading in wells drilled with conductive muds, where single laterolog tools can be significantly affected.
Better Bed Resolution: The dual current paths of these tools can offer better sensitivity for resolving resistivity variations in thin formations compared to single laterolog tools.
Q. What are microresistivity logs? Why do we need to record them?
Ans. Microresistivity logs recorded by tools called Microlaterolog and MSFL. These tools work in both conductive and nonconductive muds. They record resistivity within few inches of borehole wall. Here’s why we need to record microresistivity logs:
Detailed Information about Near-Borehole Zone:
Mud Filtrate Invasion: Drilling mud filtrate invades the formation around the wellbore, affecting the resistivity readings of deeper resistivity tools. Microresistivity logs help assess the invasion profile by directly measuring the resistivity of the invaded zone.
Permeability Evaluation: Permeable formations allow drilling mud filtrate to invade deeper. By identifying changes in resistivity within the shallow zone, microresistivity logs can help identify potentially productive zones.
Mudcake Characterization: The drilling process can leave behind a mudcake on the borehole wall. Microresistivity logs can help identify the presence and thickness of the mudcake, which can affect other wellbore measurements.
Benefits of Microresistivity Logs:
High Vertical Resolution: Microresistivity tools provide a very detailed picture of resistivity variations within a short depth, allowing for better identification of thin beds and subtle changes in formation properties.
Improved Formation Evaluation: By offering information about the near-borehole zone, microresistivity logs help in more accurate reservoir characterization, leading to better decision-making during well completion and production stages.
While some newer tools like array induction might offer similar functionalities, microresistivity logs remain valuable for their high-resolution data and ability to directly assess the invaded zone near the borehole wall.
Q. How do wellsite geologists witness and QC resistivity logs before during and after logging operation?
Ans.
Before Logging:
1. Tools availability: Ensure main tools and back up tools are available on site
2. Tool Calibration Check: Verify that the resistivity tool has been recently calibrated and the calibration certificates are available for review. This ensures the accuracy of the measurements.
During Logging:
Real-time Monitoring: 1. While logging, observe the real-time resistivity log data. Look for any unexpected spikes, gaps, or inconsistencies that might indicate tool malfunction or environmental issues. If for any reason log curves look bad ask engineer to repeat the section (relog the bad looking section).
2. Ensure log scales are same as used in offshore wells. If wildcat or exploratory well discuss log scales with operation geologist. They may vary company to company and even field to field.
3. Logs consistency: Ensure all curves (GR, Resistivity, neutron density etc.) are consistent with each other. This means each log is seeing the same formation at the same depth and responding the way it should.
4. Environmental Corrections: Discuss with the logging engineer the environmental corrections have been applied to the data. Understanding these corrections helps interpret the resistivity values accurately.
After Logging:
Log QC Checks: Review the final processed resistivity logs for any data errors or inconsistencies. This can be done in three parts:
1. Check log heading for accuracy of information provided on it. Make sure that blanks on header form have all been filled. Also look for engineer’s technical remarks. These could be very useful for Petrophysicist at the time of interpretations.
2. Look at the log body (curves section), make sure log curves are labelled properly, casing shoe depth, any bad hole encountered, Section TD depth etc. Again check for log curves consistency.
3. Make sure before survey and after survey results are provided on log (look at the bottom part of the log) Check calibration boxes at the bottom part of the log. They should all be within tolerance.
4. Repeat section if performed is attached with the main log.
Additional Tips:
1. Study offset logs and familiarize yourself with resistivity log responses in various lithologies: Understanding how different formation types and borehole conditions affect resistivity readings allows you to better perform QC.
2. Maintain communication: Maintain open communication with the logging engineer, throughout the operation. Discuss any concerns or questions you might have. By following these steps, you can effectively witness and perform QC on resistivity logs, ensuring the data collected is accurate and reliable for further analysis and well evaluation.
Q. What do you understand by water saturation and hydrocarbon saturation?
Ans. Water saturation denotes to ratio of water in the pores of reservoir rock. It means the fraction of the pore spaces occupied by water. It is either expressed as a decimal (between 0 and 1) or as a percentage (0% to 100%). So we can say water saturation refers to percentage of pore space that is occupied by water. If Sw is 100% it means the reservoir is filled with water. If water saturation is 50%, it means pore space is filled 50% with water and 50% with hydrocarbon. Sw cut off is a percentage of water saturation above which the reservoir will not produce commercial hydrocarbons. For example for a certain field Sw cut off is 70% it means all the reservoirs showing SW below 70% would be considered commercially productive hydrocarbon reservoirs. Reservoirs with more than 70% Sw will be ignored in reserve estimate as they are water wet. Unfortunately we cannot directly measure Sw. We have to calculate it using log data. By the way 1-Sw = Hs (Hydrocarbon saturation). It can also be said 100 – Sw % = Hs
Q. What data do we need to calculate Sw?
Ans. Calculating Sw is a crucial step in reservoir evaluation, as it helps determine the amount of recoverable hydrocarbons (oil and gas) present. However, directly measuring Sw downhole is not possible. Instead, geologists rely on a combination of data and interpretation methods:
Data Required to calculate Sw:
1. Porosity Logs: Neutron porosity or density porosity logs measure the total pore space volume in the formation.
2. Resistivity Logs: These logs, like laterolog or induction tools, measure the electrical resistance of the formation. Resistivity is most affected by the type of fluid filling the pores (water conducts electricity better than oil or gas).
3. Formation Water Resistivity (Rw): This is the electrical resistivity of the formation water itself, typically measured in a laboratory setting. (Can also be calculated from SP log)
4. GR log: to measure shale volume in reservoir rock.
Q40. How do we calculate Sw?
Ans. Several mathematical models and equations have been designed to calculate Sw. These models involve complex relationships between resistivity, porosity, and the properties of the formation and fluids in the pores. Many of these equations and models are locally fine-tuned or modified to accommodate field complexities. All that is in the domain of Petrophysicist’s responsibility. For wellsite geologist a basic understanding of Archie’s equation is sufficient.
Q. Please explain Archies equation used to calculate SW in simple term
Ans. Archie’s equation provide a simple tool to calculate Water Saturation (Sw) in reservoir rocks. Before looking at the equation let’s understand the basic premise the equation is built upon:
Imagine a rock like a sponge. The total volume of holes in the sponge is its porosity (Φ). Ideally, we want all these holes filled with oil, but some will always have water. Archie’s equation helps estimate how much water occupies those holes based on how easily electricity travels through the rock (resistivity).
Easy electricity flow means low resistivity. This suggests the pores are filled with conductive saltwater, meaning high Water Saturation (Sw).
Difficult electricity flow means high resistivity. This suggests less conductive oil is filling the pores, meaning lower Water Saturation (Sw).
Here is how Archie’s equation look like:
Sw = [a * Rw / (Φ^m * Rt)]^(1/n)
Sw: Water saturation (values in decimal, between 0 and 1)
Rw: Resistivity of the formation water (measured in a lab / can also be calculated from SP log).
a: A constant related to the flow path of electricity (Tortuosity Factor, often assumed to be 1).
m: A measure of how well the rock conducts electricity (called the cementation factor, typically between 1.7 and 2.0).
Φ: The porosity of the rock (measured by porosity logs like neutron, density and sonic).
Rt: The deep resistivity of the rock measured by resistivity tools (laterolog or induction).
Archie’s saturation exponent (n): This exponent describes the influence of water saturation on the overall resistivity of the rock. It usually falls between 1.8 and 4.0, but a value of 2.0 is commonly used as a starting point.
Please bear in mind, this is a simplified version of Archie’s equation, that is good enough to give a rough estimate and may not be perfect in all situations (where we have complex geology and different fluid types).
DENSITY LOGGING
Q. What is density?
Density refers to how tightly the particles of a substance are packed together. In simpler terms, it’s a measure of how much mass is crammed into a certain volume. The scientific definition says density is the mass per unit volume of a material. It’s usually represented by the symbol ρ (rho).
There’s a formula to calculate density: ρ = m/V, where:
ρ (rho) is density
m is the mass of the substance
V is the volume of the substance
In oil industry, the commonly used unit for density is: Gram per cubic centimetre (g/cm³)
Q. In oil industry, when we talk about density of lithology, what are we talking about matrix density or bulk density?
Ans. When referring to the average density of a rock or lithology, we’re talking about bulk density. Here’s why:
Bulk density is the standard measure used in geology. It considers the total volume of rock, including any pores, cracks, or air spaces. This reflects the overall density of the rock in its natural state.
Matrix density, on the other hand, refers to the density of the solid material (mineral grains only), excluding any pores or voids. This value is more relevant for individual minerals within the rock.
Wellsite Geologists are typically interested in bulk density because it largely depends on amount of porosity and fluids in pores. And it is bulk density that is presented on density log.
Matrix density comes into play if you want to study specific mineral composition of a rock and how it affects its overall properties.
Q. What are the uses of density log as recorded by wireline or LWD tools?
Ans. In oil well exploration, a density log, recorded by wireline or LWD logging, have many important applications. Some of the important uses are:
1. Porosity Determination: The primary function of a density log is to estimate formation porosity. Porosity is an important requirement in calculating water saturation and hydrocarbon saturation.
2. Lithology Identification: While density alone doesn’t definitively identify rock types, it can be very helpful when combined with other l ogs like neutron, GR and resistivity logs.
3. Detecting Oil and Gas Zones:Density Neutron logs crossover can help wellsite geologist in picking gas, oil and water zones as well as their contacts.
4. Detecting Overpressure zone: Density increase with depth due to increasing overburden pressure. Therefore any deviation or reduction in density values may indicate an overpressure zone.
Q. What lithologies can you identify based on density / neutron logs?
Ans. Salt, Anhydrite and coal can be easily identified looking at density – neutron logs:
Salt has 2.0 sg density and 0% neutron porosity
Anhydrite has 2.9 sg density and 0% neutron porosity
Coal has about 1.5 sg density and very high porosity (>40%)
Also all three lithologies show very low GR.
Q. What is the recording principle of density log using wireline?
Ans. Density tool has a nuclear source Cesium-137 that sends high energy gamma rays into the formation. These gamma rays upon colliding with electrons of formation atoms: 1. lose their energies 2. Get scattered (this is called Compton scattering). These low energy GR are captured by two detectors. Short range detector (placed 7” away from the source) and the long range detector (placed about 16” away from the source). High density formation have more atoms and therefore more electrons so most GRs are scattered more and high number of low energy GRs reach the detector. If formation density is low, it means it has less number of atoms and less number of electrons and less collision of GRs take place with electrons. Therefore less number of low energy GRs get back to detectors where these are counted and converted to density as per calibration.
Q. How do we convert wireline density data into formation porosity?
Converting wireline density data into formation porosity involves a simple formula and some key assumptions:
Formula: We use the following equation:
Φ = (ρma – ρb) / (ρma – ρf)
where:
Φ (phi): is the formation porosity (a value between 0 and 1)
ρma (rhoma) is the matrix density of the rock (g/cm³). This can be found on net or in database.
ρb (rhob): is the bulk density of the formation measured by the density log (g/cm³)
ρf (rhof): is the density of the fluid filling the pores (g/cm³)
Assumptions:
We need to know the matrix density (ρma) of the rock. This value is freely available on net and in data base.
We need to assume the density of the fluid filling the pores (ρf). This is usually water or brine, with a density of around 1.0 g/cm³ for freshwater and 1.1 g/cm³ for saltwater.
Interpretation:
The higher the difference between the matrix density and the bulk density (ρma – ρb), the higher the porosity will be. This is because a larger difference indicates more void space filled with the lower-density fluid.
Notes:
It should be noted that density logs are often used in conjunction with other porosity logs, like neutron and sonic logs, to improve the accuracy of porosity estimation.
Common Lithologies their bulk densities and matrix densities:
Here’s a list of some important lithologies encountered while drilling an oil well, along with their typical bulk density and matrix density ranges:
Lithology. Bulk Density / Matrix Density
Shale. 2.0 – 2.8 / 2.5 – 2.9
Sandstone 1.8 – 2.5 / 2.6 – 2.8
Limestone 2.4 – 2.8 / 2.7 – 2.9
Dolomite 2.7 – 2.9 / 2.8 – 3.0
Coal 1.2 – 1.8 / 1.2 – 1.8
Salt (Halite). 2.0 – 2.2 / 2.1 – 2.2
Anhydrite 2.8 – 3.2 / 2.9 – 3.3
Q. How should a wellsite geologist witness and QC a density log during logging operation?
Ans. wellsite geologist plays a crucial role in ensuring the quality and accuracy of a density log during wireline logging operations. Here’s a breakdown of how he can witness and perform QC (Quality Control) before, during, and after the logging process:
Before the Logging Run:
Pre-Job Meeting: Participate in the pre-job meeting with the logging engineer. Discuss the logging program, objectives, and any specific concerns for the well such as high deviation, hole condition, abnormal pressure zone if any.
Tool Calibration Check: Verify that the density logging tool has been recently calibrated and is functioning properly. Calibration reports should be reviewed.
Logging Parameters: Ensure the logging speed, scale and units are appropriate for the formation and the desired level of detail.
Formation Information: Provide the logging crew with any available geological information about the well, including expected lithologies and formation tops.
During the Logging Run:
1. Monitoring Logging Data: Observe the real-time density log curve as it is acquired. Look for any unexpected spikes, gaps, or inconsistencies in the data that might indicate tool malfunction or borehole issues. Repeat log over questionable section.
2. Mud Properties: Be aware of the mud properties being used during drilling. Density logs can be affected by the density of the drilling mud and percentage of barite, so this information is crucial to be placed on log for accurate interpretation.
3. Depth Correlation: Ensure that the depth of the logged data corresponds accurately to the well depth. Verify depth markers and reference logs (like GR Log) to confirm proper depth encoding.
4. Repeatability should be within 0.05 g/cm3, except in a washed out hole.
5. The delta rho should be mainly positive except in dense baritic muds or over gas zones
After the Logging Run:
Data Review: Carefully review the final processed density log with the wireline engineer. Identify any anomalies or questionable data points.
Comparison with Other Logs: Compare the density log response with other well logs acquired (e.g., neutron log, sonic log). This can help identify potential issues or corroborate formation interpretations.
Calibration Check Verification: Ensure tool calibration is valid and tool response is within tolerance.
Log Header and scales: Ensure all information are provided on header and they are correct. All scales are as advised and match with offset wells.
Q. What is delta Rho? what is its significance?
Ans. Delta rho (Δρ) refers to the magnitude of the correction applied to the long spacing detector of a density measurement. In other words Delta rho indicates how much the raw measurement from the long spacing detector needs to be adjusted to get an accurate density value.
A high delta rho (typically above ±0.15 g/cm³) suggests that the correction might be significant and the accuracy of the density measurement might be compromised. This can happen due to:
Borehole conditions: A rough or irregular borehole wall (borehole rugosity) can affect the density tool’s reading.
Mud cake: A thick layer of mud cake on the borehole wall, especially if it contains dense minerals like barite or hematite, can increase the apparent density measured by the tool.
Therefore, monitoring delta rho is a crucial part of density log quality control (QC). If delta rho is consistently high, it might be necessary to investigate the borehole conditions or consider alternative logging methods for accurate formation porosity evaluation.
Q50. How do you account for the influence of borehole conditions (mud weight, invasion, washout, rugosity etc.) on density log readings, and how does this affect your interpretation of formation porosity?
High mud weight and invasion can influence density log readings. Denser mud can mask formation density, while mud filtrate invasion can affect the density response in the near-wellbore region. Density tool collects density data from very close to bore hole wall, therefore hole washout and hole rugosity also severely effects the quality of density data. However most of these adverse effects can be compensated to a great extent by using porosity correction charts or software.
Q. What is the role of density log in calculating water saturation?
The density log plays an indirect but crucial role in calculating water saturation (Sw). It provides an accurate estimate of formation porosity. Formation porosity and resistivity are fundamental requirements of Archies equation to calculate Sw.
Q. What do you know about PEF?
Ans. The PEF curve on a density track reflects the photoelectric absorption properties of the formation. When gamma rays emitted by the logging tool interact with densely packed atoms in the formation, they can sometime get completely absorbed by electrons. This absorption process is called photoelectric absorption and the plotted curve is called PEF (Photoelectric factor). PEF is recorded in units of barns/electron (b/e)
Denser formations like limestone and dolomite show high PEF value compare to lighter formation like sandstone and shale.
Q. What are the applications of PEF?
Ans. While PEF doesn’t directly measure density, it provides valuable information for formation evaluation when used in conjunction with the density log:
1. Lithology Identification: By comparing the PEF response with the density log, geologists can differentiate between certain rock types. For example, limestone (high PEF, high density) can be distinguished from sandstone (lower PEF, lower density).
2. Gas Zone Detection: Gas, consisting mainly of low atomic number elements, has a very low PEF.
A significant decrease in PEF alongside a decrease in density on the density log can be indicative of a gas-filled zone.
3. Complementary to Density Log: PEF can be particularly helpful in situations where the density log response might be ambiguous.
For instance, some formations like dolomite and limestone might have similar density values. However, their PEF responses can be distinct, aiding in differentiation.
Notes:
Here are typical PEF ranges for some common sedimentary rocks:
Sedimentary Rock & PEF values in barns/electron
Limestone: 4.5 – 5.5
Dolomite: 4.0 – 5.0
Sandstone: 2.0 – 3.5
Shale: 2.5 – 4.0 (can vary depending on clay content)
Coal: 1.5 – 2.0
Salt (Halite): 2.0 – 2.2
Q. What do you know about Azimuthal Density?
Ans. While standard density tool records one density data at one depth, Azimuthal density tool records a number density readings at one depth. In other words it records a number of density data all around the borehole wall. Also the tool has a good vertical resolution recording series of data samples every 4 to 8”.
Q. What are the uses of azimuthal density?
Since it can give density readings in all the four quadrant of hole (N,S,E,W), or up, down, left, right quadrant as it is called in horizontal section of the hole, the tool can be very helpful in Geosteering a horizontal section (when the tool is run on LWD). If the bit is getting out of porous reservoir drain, the density will start increasing. So the correction is quickly made by steering the bit away from the quadrant showing higher density. Another use of azimuthal density is in determining the formations dip and strike direction for better understanding the reservoirs in 3D.
NEUTRON LOGGING
Q. In wireline logging, what are three important porosity tools?
Ans. The three important porosity tools are:
1. Density Tool
2. Neutron Tool
3. Sonic Tool
Q. Do these porosity tools directly measure formation porosity?
Ans. No. None of the tools perform direct porosity measurement. These tools measure certain petrophysical properties of formation. Using these properties and making certain assumptions the formation porosity is calculated. Measurements on conventional core provide direct porosity and permeability readings.
Q. What is the principle of neutron logging?
Ans. The neutron tool has a nuclear source and two detectors. The nuclear source continuously emits stream of high energy neutrons. These neutrons upon entering the formation colloid with the hydrogen atoms and lose their energy and slow down. These low energy neutrns are picked up by two detectors on the tool. An overwhelming majority of hydrogen atoms are found in water, oil and gas, which fill the pore spaces. So by counting hydrogen atoms, the software estimates the amount of porosity in the rock.
Q. What do you know about Compensated Neutron Log (CNL)?
Ans. This is an improved version of old neutron tool with two detectors placed at some distances from the source. Neutron logs are sensitive to borehole size. CNL tool by comparing readings from near and far detectors can compensate borehole size effects to get more accurate measurements.
Q60. What are the uses of neutron logs in well log data interpretation?
Ans. The primary application of neutron log is to determine the porosity of formation. Apart from this the neutron logs in combination with other logs like density and resistivity logs can identify gas zone, oil zone and water zone. Gas/oil, gas/water and oil/water contacts can also be identified easily. Neutron log with density log can also be used to identify certain lithologies
Q. Presence of clay minerals lead to overestimation of neutron porosity; why?
Ans. Clay minerals contain bound water (immobile water), which to neutron tool looks like free water (porosity). Petrophysicist can correct the shale effect using other logs like GR.
Q. Why do neutron and density logs read wrong porosity in gas bearing zones?
Ans. Neutron tools read way below the actual porosity and density tools show more than the actual porosity in gas bearing zones. There are two reasons for that:
Both these tools are calibrated in formation (limestone) which is filled 100% with fresh water
The physics of measurement of these tools is also responsible (to a larger extent) for the wrong reading in gas zone.
Neutron tool in way count hydrogen atoms (mostly present in pore fluid) and relates it to amount of porosity. More hydrogen atoms mean more porosity and less hydrogen atoms mean less porosity. Neutron tool sees less hydrogen atoms in a gas zone compare to oil or water zone. Therefore it thinks the zone has low porosity, which actually is not the case.
Similarly density tool counts electrons in formation. The tool is also calibrated in water filled formation. Gas has less number of electrons than formation or water. In gas zone density tool sees less number of electrons and thinks that formation is less dense in other words more porous.
Because density tool sees more than actual porosity and neutron tool sees less than actual porosity; their curves cross each other in gas zone. This cross over is a good and reliable indicator of gas zone.
Q. What is the ideal environment for Neutron tool to read correct porosity?
Ans. A neutron tool is calibrated in fresh water filled limestone. Therefore if the lithology is limestone and pore fluid is fresh water we can directly read porosity. In case formation lithology is different and pore fluid is not fresh water than we have to apply many corrections. Two things that adversely effect the neutron porosity readings are shale and gas apart from hole size.
Q. What is Master Calibration? Which wireline tools need master calibration?
Ans. Master Calibration is a critical procedure performed in wireline company base (workshop) every three months or so. This calibration mostly performed on tools containing nuclear sources, like density and neutron tools. It ensures tool’s measurements are accurate and reliable for downhole logging. As a part of QC wellsite geologist has to record the date of last master calibration. It should not be older than three months.
Q. What is the protocol to witness the neutron logging? How would you QC neutron log?
Ans. 1. Attend pre-job meeting. 2. Find out the nature of source whether nuclear or electronic source being used in the tool 3. If nuclear source is being used, Verify Master Calibration is less than three months old. 4. Record all events and timings. Record your observations.
Q. How would you QC neutron log?
Ans. By observing the following QC steps, one can have confidence in the quality of the acquired data;
1. Check all calibrations: Before Survey, After Survey as well as the date of Master Calibration
2. Review the neutron porosity curve for any spikes, gaps, or inconsistencies that might indicate tool malfunction or data processing errors.
3. Compare your neutron log with the offset well neutron log to see if any significant discrepancies exist
4. Ensure log is on depth, consistent with other log curves.
5. Check accuracy of information on log heading. Check log scale.
Q. What are the challenges faced during density and neutron logging?
Ans. There are many challenges that a wireline logging engineer has to face in logging with these tools:
1. As both these tools use nuclear sources, therefore government body permission is required to move the sources from base to rig-site and vice versa.
2. Loading and unloading nuclear sources require strict safety protocols. Only trained people with radioactive badges are allowed to involve with the operation.
3. Special care has to taken during the logging to avoid tool getting stuck
In the event tool get stuck in the hole. All precaution should be taken to avoid getting cable snapped. Immediately inform company man and operations geologist about the situation.
Take time and let the engineer try his best to unstuck the tool.
4. In case tool does not come free. Ensure that drilling team and G&G team are on the same page in deciding to snap the cable.
If for some reason tool cannot be fished out then a difficult decision to plug and abandon the well has to be taken. This has its own implications. The radioactive source poses a significant environmental contamination risk. Regulatory agencies would likely become involved in containment and mitigation efforts.
Q. What are the scales used for neutron and density logs?
Ans. The units and scales used for neutron and density logs can vary depending on the specific tool and logging company, dominant lithology, type of fluid in pores. So various scales are in use. For a wellsite geologist a good practice could be to use the same scale as used in offset wells to be consistent and to make accurate correlation.
Traditionally neutron logs are displayed in porosity units (p.u.). This is dimensionless unit because it represents a relative neutron response compared to a reference baseline. The conventional neutron scale is 0 to 100 p.u. Otherwise you may see limestone porosity scale, dolomite porosity scale or sandstone porosity scale depending upon the dominant lithology in the hole section. This is to be decided by Petrophysicist from town. If wellsite geologist has to decide on scale; use the same as in offset well log. Or discuss with operation geologist.
Density logs are typically displayed in grams per cubic centimeter (g/cm³). This unit directly represents the formation’s bulk density. The common scale for density logs is 1.65 g/cm³ to 2.95 g/cm³. This range covers the typical density range of most formations (sandstone, limestone, dolomite).
Q. How do we determine porosity from Neutron Log?
Ans. Porosity readings are directly read from the log provided log scale is appropriate. This is good enough for quick look interpretation purpose. However accurate porosity is obtained in town after correcting the log readings for borehole environment, clay content and fluid type.
SONIC LOGGING
Q70. What is Sonic log? What are its important uses?
Ans. A sonic log also known as acoustic log is a record of velocity of sound waves in formations. The sonic velocity depends mainly upon rock matrix and pore spaces among many other things. A sonic log plays vital role in hydrocarbon exploration. It has multiple uses but the following could be regarded as important ones:
Porosity determination
Lithology identification
Overpressure detection and estimation
Seismic velocity calibration
Q. What is the measuring principle of sonic log?
Ans. The sonic tool has a acoustic transmitter and two receivers placed some distances apart on the tool. When the tool is activated, the transmitter emits a high amplitude sound wave which travels along borehole wall and is picked up by near and far receivers. The measuring unit is delta t (interval transit time) in microseconds/ft. There are different types of sonic logging tools, but the basic principle remains the same.
Q. What is difference between interval transit time and sonic velocity.
Ans. Both measure travel time of sound pulse in formation. Interval transit time (delta t) is measured in microseconds/ft while sonic velocity is measured in ft/seconds.
Notes:
Lithology Interval Transit Time (micro sec /ft)
Sandstone. 51 – 55.5 (Quartz 56)
Limestone. 43.5 – 48 (Calcite 49)
Dolomite. 38.5 – 43.5 (Dolomite 44)
Fresh Water 218
Salt Water. 189
Casing. 57
Q. How can we convert interval transit time in formation porosity?
Ans. The formation travel time can be converted into formation porosity according to Wyllie equation:
Porosity = (delta t log – delta t ma) / (delta t fluid – delta ma)
Where delta t log = log readings
delta t matrix = delta t reading of solid rock grain. This is taken from the chart for the predominant reservoir rock.
delta t fluid is delta t reading in dominant fluid. This reading is also taken from the chart. (See the list of delta t readings in matrix and fluid in previous Q&A)
One drawback in this equation is that it assumes uniform matrix and uniform fluid in pore spaces, which in reality may not be the case. Therefore corrections are applied to improve the accuracy of porosity.
Q. Using porosity logs, how will you calculate secondary porosity (additional porosity induced by vugs and microfractures)in limestone?
Ans. Sonic tool basically records only primary porosity (vugs and microfractures if unconnected do not influence sonic transit time).
Whereas density tool records both primary and secondary porosity as one without differentiating between them. So we can calculate secondary porosity by subtracting sonic porosity from density porosity (Density Porosity – Sonic Porosity = Secondary porosity)
Note:
A better option could be to take the average of density and neutron porosity (Neutron porosity also includes primary and secondary porosity) and subtract sonic porosity from it. If the average of neutron density porosities is equal to sonic porosity, it would mean there is no secondary porosity in the rock but if the Neutron/density porosity is greater than sonic porosity that would mean that secondary porosity exists and can be found out by subtracting the average of N/D porosity from sonic porosity.
Q. How do you QC Sonic Log?
Ans. The only important check on sonic tool is to find out how much the tool is reading inside casing. It should read 57 microseconds/ft as interval transit time. If not ask questions. During logging up keep an eye on log curves that there are no cycle skipping or gaps or unusual curve. If this happens, ask engineer to repeat the unusual section with a slow speed. One should also compare the sonic log with other well logs, such as gamma ray and density logs as well as with sonic logs of offset well. These comparisons can help identify inconsistencies or potential errors in the log.
Q. What is integrated Travel Time (ITT)? What is its importance?
Ans. Integrated Travel Time (ITT) refers to the total one-way time for an acoustic wave to travel through a section of formation (between two depth points). It is essentially a one-way, average acoustic time of a sound wave. ITT on a sonic log is displayed as a series of pips on the side of sonic track. Each pip represents a millisecond and larger ones represent 10 milliseconds.
By simply counting the pips between two depths, we can quickly estimate the average travel time for that interval. This is particularly useful for correlating the sonic log with seismic data, which also relies on sonic travel times.
Q. What do you understand by Cycle skipping on sonic log?
Ans. Cycle skipping happens when a weak sound wave is generated by the transmitter or it becomes weak during it travel to the point that it cannot trigger the receiver to get record (in other words its strength falls below the threshold of detection). The next wave may be strong and gets recorded. When this happens, along transit time is displayed on the log. This phenomenon is called Cycle Skipping. There could be many causes for this to happen:
Poor borehole conditions: Large borehole washouts can lead to a weaker signal reaching the receivers.
Low formation strength: Unconsolidated formations or those with fractures can dampen the acoustic wave.
Gas presence: Gas bubbles in the formation or borehole fluid can significantly attenuate the signal.
Tool limitations: In rare cases, the sonic tool itself might have a weak transmitter or malfunctioning receiver.
Q. What are different types of Sonic Tools available with wireline logging companies? What do you know about them?
Ans. There are two main categories of sonic tools used in wireline logging:
Conventional sonic tools: These tools measure the compressional wave travel time through the formation using a single source and one or more receivers. Here are some common types:
Basic sonic tools: They use a single source and one receiver. They provide good vertical resolution but have a shallow depth of investigation (limited to a few inches into the formation).
Long-spaced sonic tools: These tools have multiple receivers spaced farther apart along the tool body. This allows them to investigate a deeper formation zone (up to a foot or more) and can be helpful in identifying thin beds.
Borehole Compensated Sonic Tools (BCST): These tools use additional receivers to account for the travel time through the borehole fluid (mud), providing a more accurate formation travel time, especially in situations with large or irregular boreholes.
Dipole sonic tools: These are a more advanced type of sonic tool that emit two different types of acoustic waves: a compressional wave and a shear wave. They use multiple receivers to capture the travel times of both waves. Here’s a breakdown:
Monopole-dipole sonic tools: These tools can emit both compressional and shear waves using a single source that can switch between operating modes. They provide additional information about the formation’s mechanical properties compared to single-well sonic tools.
Dual-source dipole sonic tools: These tools have separate sources for the compressional and shear waves, allowing for more precise measurement of their respective travel times. This can be particularly valuable in complex formations.
Notes:
Dipole sonic tools offer several advantages over conventional sonic tools in wellbore logging:
1. Shear Wave Measurement:
Conventional tools only measure the compressional wave, which is limited in its ability to characterize some formation properties.
Dipole tools can measure shear waves in addition to compressional waves. Shear waves travel slower than compressional waves and are more sensitive to the formation’s rigidity and pore-filling fluids.
2. Improved Formation Evaluation:
By measuring both compressional and shear waves, dipole tools can provide a more comprehensive picture of the formation. This allows for:
Improved porosity estimation: The ratio of compressional to shear wave velocity can be used to calculate formation porosity more accurately, especially in complex formations where conventional methods might struggle.
Lithology identification: The different travel times of compressional and shear waves can help identify different rock types based on their elastic properties.
Fracture detection: The presence of fractures can affect the propagation of both compressional and shear waves, aiding in fracture identification within the formation.
3. Applications in Challenging Formations:
Conventional tools can struggle in formations with slow compressional wave velocities, such as shales or unconsolidated sands.
Dipole tools can sometimes measure shear waves even when compressional wave velocities are slow, providing valuable data in these challenging formations.
4. Deeper Depth of Investigation:
While not always the case, some dipole tools may have a deeper depth of investigation compared to conventional tools. This allows for a better understanding of the formation properties beyond the immediate borehole wall.
Please also note:
Dipole sonic tools are generally more complex and expensive than conventional tools.
Data processing and interpretation of dipole sonic logs can be more involved due to the additional information they provide.
The effectiveness of dipole tools can vary depending on the formation properties and wellbore conditions.
Overall, dipole sonic tools offer a valuable step forward in formation evaluation compared to conventional tools, particularly when a more detailed understanding of the formation’s mechanical properties is required.
Q. What are the applications of MDT tool?
Ans. Two important applications of MDT tool are:
Pressure Testing: It gives us 1. an accurate formation pressure. 2. A good estimate of formation permeability.
Plotting pressure gradient can tell us nature of fluid and depth of fluid contacts. 4. Helps in identifying zones of abnormal pressure.
Reservoir fluid sampling: 1. Pumping out fluid and conducting Optical Fluid Analysis (OFA) to avoid taking unwanted or contaminated fluid. 2.Collecting multiple samples from different reservoirs in one run. Can use different sizes of chambers to collect different volumes of fluids. 3. Sample can be collected at reservoir pressure and temperature to perform phase studies in lab.
WIRELINE PRESSURE TESTING AND SAMPLING
Q. 80 What are the names of Schlumberger MDT equivalent of Halliburton and Baker Hughes tools?
Ans. Halliburton equivalent of MDT tool is called Reservoir Description Tool (RDT) (Latest version is called ‘Reservoir Xaminer’). Baker Hughes equivalent of MDT tool is called FTeX. (Formation Pressure Tester)
Q. If MDT is a modular tool; what are its various modules?
Ans. Modular design of the tool adds flexibility and customization of tool on rig itself. The four main modules are as follows:
1. MRPC (Power Cartridge): Converts AC to DC power and supply it to various parts of the tool.
2. MRHY (Hydraulic Module): Has a motor, pump and hydraulic oil tank. The hydraulic power is used to set and retract packer and probe.
3. MRPS (Single Probe): The single probe module contains probe, packer and telescopic back support. It also contains highly accurate and sensitive quartz pressure gauge (CQG) and strain gauge and 20 CC pretest chamber plus the temperature and resistivity sensors. This unit sets the probe and packer to take pressure tests and fluid samples.
4. MRSC (Modular Sample Chambers) This module houses sample chambers which come in three sizes: 1 gal. 2 ¾ gal. and 6 gal.
5. Pump-out and LFA Modules: are used to identify formation fluid flowing from formation into the tool. LFA module does the optical analysis in real time and let us know whether it is mud-filtrate or water or oil or gas. This helps in avoiding contaminations (mud-filtrate) and take true formation fluid such as water, oil or gs.
Q. Describe various steps and processes involved in doing a pressure test and sampling?
Ans. Various steps and processes involved in taking pressure test and fluid sample are as follows:
1. Perform Correlation: Correlation is performed using GR tool to make sure the MDT tool is reading correct depth. If we are testing thin reservoirs then correlation is performed frequently to avoid ‘tight test’. But if the reservoirs are thick then, a correlation every 500 ft or more is sufficient.
2. Note down Hydrostatic Pressure: Upon reaching the setting depth point, hydrostatic pressure is noted prior to setting the tool.
3. Set the tool: This involves hydraulically pushing the packer and probe towards the borehole wall. The rubber packer tightly seals and isolates the probe from mud and hydraulic pressure, exposing the probe only to formation pressure and formation fluid.
4. Perform Pretest: In performing pretest, a small volume of formation fluid (20cc) is withdrawn into pretest chamber. Pressure is then allowed to build up and stabilize. It may take from a few tens of seconds to several minutes (up to 20 minutes or so) depending upon the reservoir porosity and permeability. Stable formation pressure reading is noted when third decimal value of pressure read by quartz gauge repeats itself for at least three times.
5. Decide to take sample: If a sample is also requested at the pressure test point and the pressure test results are good; that is the test is valid; it showed quick build up and stabilisation of pressure indicating good porosity and permeability. Then a decision can be taken to go ahead and start sampling process.
6. Perform Pump Out: Porous and permeable reservoirs are usually heavily invaded with mud filtrate, therefore prior to opening a sample-chamber we have to pump out filtrate and dump it into the annulus. When fresh formation fluid (water, oil or gas) starts flowing we open the chamber and collect the sample. This is done based on Live Fluid Analysis (LFA).
7. Live Fluid Analysis (LFA): This component of MDT tool optically analyses formation fluid downhole in real-time. It plays critical role in deciding when to open sample chamber.
8. Taking Sample: After pumping out contaminant like mud filtrate; chamber is open for the sample when we see uncontaminated formation fluid like water, oil or gas. Sometimes there are chambers of various sizes, so it is to be decided which size of chamber is to be opened. Some times the objective is not to take sample but find out the nature o fluid. This sometime is done to establish resistivity cut off between water and hydrocarbon bearing reservoirs.
Q. How do you describe pressure test results in your remark column?
Ans. Followings are different terms that we use to describe a test based on pretest profile:
Good or Valid Test: When pressure profile builds and stabilizes rather quickly. The test is said to be valid or good test.
Tight Test: In tight test pressure profile either does not build or builds up extremely slowly. This happens when the reservoir is tight or shaly. This can also happen if the probe is set in shale due to poor or loss of correlation. If we are confident about correlation, we move probe one foot up or down and try again.
Lost Seal or Seal Failure: This happens when packer is not properly set either due to wash out at test depth or the packer has worn out. Here pressure profile tries to build but soon goes back to read hydrostatic pressure.
Plugging: This is causedwhen lose sand gets into probe and momentarily blocks the fluid flowing in. This may happen for a short time and test is concluded to be good. Or it can totally block the flow line forcing wireline engineer to abandon the test and withdraw the probe. Sometimes a pretest inside casing or in shale may help unplugging the line.
Q. What do you understand by fluid typing?
Ans. Fluid typing deals with identifying reservoir fluid (whether it is oil or gas or both) and the properties of fluid such as viscosity, density, API gravity, GOR etc.
Q80. What do you understand by reservoir compartmentalization? What causes it?
Ans. Reservoir compartmentalization refers to division in a hydrocarbon reservoir into separate and isolated sections. Fluids in different compartments may have different properties, pressure and production behaviour. Faults, Unconformities, Diagenesis and lateral variations in reservoir properties may lead to reservoir compartmentalisation.
Q. How do we identify the presence of disconnected compartments in a reservoir or isolated reservoirs using MDT pressure test data?
Ans. We can identify different compartments by plotting accurate pressure test data and pressure gradients. Consistent pressure gradients indicate a connected reservoir with uniform fluid properties. Abrupt shift in pressure gradient or multiple pressure gradients suggest different compartments in a reservoir or disconnected reservoirs with different fluid characteristics.
Q. What is pump out? What is its significance in wireline fluid sampling?
Ans. It is a strong and powerful hydraulic pump fitted in MDT. Pump out along with LFA (Live fluid Analysis) is used to analyze and dump unwanted and contaminated fluid (mud filtrate) prior to opening sample chamber to collect clean formation fluid. Sometime we have to pump out 20 to 30 gallons of mud filtrate before we see clean formation fluid.
Q. If critically important pressure test or sampling is to be conducted in a sticky hole section; how should one proceed?
Ans. To start with inform company man as well as operations geologist about the hole condition at point of interest, so that people are mentally prepared for any eventuality. Second proceed with caution; perform depth correlation; choose the best looking point for setting the probe. Once the tool is set, slack the cable. Try to spend as little time as possible on test and sampling. Retract the tool as soon as the objective is achieved.
SIDE WALL CORING
Q. What is side wall coring? what are its main objectives?
Ans. Wireline side coring is a process of extracting small cylindrical samples of the formation from the borehole wall. This process is carried out using a SWC tool, which is lowered into the open hole on a cable.
The primary objectives of side wall coring are:
1. Core Sample Acquisition: To obtain physical rock samples for detailed laboratory analysis.
2. Lithology Determination: To accurately identify the rock type and mineral composition of the formation.
3. Reservoir Characterization: To evaluate reservoir properties such as porosity, permeability, and fluid saturation.
Formation Evaluation: To calibrate and verify other logging measurements.
4. Hydrocarbon Identification: To directly detect and analyse hydrocarbons in the rock sample.
5. Fracture Analysis: To study the orientation, size, and distribution of fractures in the formation.
6. To carry out sources rock studies and paleontological studies.
Q90. What are two different types of side wall coring mechanisms? What is difference between the cores obtained by two different processes?
Ans.Ans. Two different tools and mechanism can be used to obtain side wall cores:
1. Percussion type: Here a SWC Gun is run with a set of 30 core barrels called bullets which are fired using small explosive charges. The bullets are fired one by one at required depth. As an empty cylindrical bullet is fired, it gets embedded in the bore hole wall. The bullet remains connected to the gun with the help of steel string and is retrieved by applying minor force. The size of side wall core varies from 1.25″ to 1.75″ in length and about 0.7” to 1” in diameter. Percussion coring is more successful in medium hard formation. In percussion coring two to four guns can be combined in one run.(number of guns may vary from company to company). Each gun has 30 bullets.
2. Rotary Type: Rotary type side wall cores are obtained using a small barrel and a diamond rotary bit. Here a bit drills laterally into the wall of the hole and collect a cylindrical core in a small barrel. These cores are more or less same in size as percussion cores, however new generation rotary tools may cut core up to 2.5” in length and 1.5” in diameter. Also successful in very hard formation. Number of cores depend on length and size of core barrel as well as size of cores. Usually 50 cores are taken using rotary bit.
Q. What are advantages and limitations of sidewall cores compare to conventional cores?
Ans. SWC provide direct physical samples quickly and in cost effective manner. SWC points can be selected and recovered for variety of objectives; for example in one run we can take cores from reservoir rock for the purpose of reservoir characterization. One can also take cores from source rock to study its maturity, similarly cores can also be cut from oil, gas and water zones. These options may not always be available when cutting conventional core. However the major limitation is core size and often poor recovery, (especially if the formation is very hard or very soft). Conventional coring though expensive and time consuming, yet it is often preferred because of large and continuous size of core that facilitate many type of studies and analysis.
Q. What precautions operations geologist and wellsite geologist must take while planning, executing and transporting side wall cores?
Ans. Many dozens of side wall cores can be taken with many different objectives in one run. The objectives may vary from source rock studies to paleontological to reservoir characterization to reservoir fluid identification to physical studies of lithologies. Accordingly points are selected by operations geologist and sent to wellsite geologist. Usually objective of core is mentioned against each core depth to handle the cores with added caution. Operations geologist also alerts the lab in town about the on going side wall coring program. Informs them about the studies to be conducted on various cores and approximate time of arrival of cores.
Wellsite geologist along with the list of coring points also provides wireline engineer with mudlog, GR, density and sonic logs so that the engineer can get an idea about the hardness of rocks and according decide the quantity of explosives. Before shooting for core wellsite geologist witness the depth correlation using GR log.
Wellsite geologist must be present with the wireline engineer at time of recovering the cores from the gun. He should make note of any broken or lost bullet and misfired bullet if any. He is also there to ensure cores are handled with utmost care to ensure whole core recovery. Wellsite geologist also ensures that cores are placed in the right jars which are pre-labelled with depth
Wellsite geologist describes these cores quickly for lithology, textures and oil shows as well as notes down the recovery and length of core with minimum breakage. If mudlogger is allowed to describe the cores he should specifically be instructed to maintain their integrity.
Cores should immediately be packed after description. It is first wrapped in thin film and then in aluminium foil before placing in the jar and tightly sealing and labelling. Ensure the card board boxes specially designed for the jars are not damaged and are properly taped around and labelled. Further Ensure these are sent to town by first available flight and operation geologist is informed about it, so that he can arrange to rush them to lab.
To safely and efficiently execute the coring operation, wellsite geologist plans to get wireline crew and tools on board in time, coordinates with drilling crew, prioritises safety throughout the operations and ensures compliances with all safety protocols.
Q. What are the roles and responsibilities of a wellsite geologist during coring operations? answer can be found in the above text.
Q. Why do we perform side wall coring at the end of logging operation?
Ans. Sidewall coring is typically conducted after logging operations for two key reasons:
1. Logging provides essential data about the formation, including lithology, porosity, permeability, and fluid content.
2. Logging data helps in targeting various objective zones and precise depth determination. This helps in maximising the value of cores.
Extra Notes on side wall cores from Denis S.
Sidewall core planning?
Sidewall core planning, similar to conventional core planning, involves determining the optimal depth, number, and orientation of sidewall core samples to be retrieved during logging operations.
Objectives and Requirements:
– Data requirements: Similar to conventional core, define the geological and reservoir data needed (lithology, porosity, permeability, fractures). However, sidewall cores are smaller and provide less detail, so focus on specific key points.
– Target formations: Identify formations of interest based on potential hydrocarbon zones, lithology changes, or uncertainties in well log interpretations.
– Operational constraints: Consider factors like logging tool capabilities, wellbore conditions, and potential drilling interference.
Sidewall Core Point Selection:
– Depth selection: Use well logs, seismic data, and any available core data to identify specific depths within the target formations for core retrieval.
– Core density: Depending on objectives and budget, plan for multiple cores within the target interval or focus on key horizons. Spacing between cores should consider formation thickness and desired data resolution.
– Formation orientation: If core orientation is crucial, identify intervals with predictable bedding or utilize tools like borehole image logs to assist in future interpretation.
Core Retrieval and Analysis:
– Sidewall coring tools: Choose the appropriate tool based on wellbore conditions, formation type, and desired core size. Common tools include rotary sidewall corers and wireline-conveyed corers.
– Sample handling and preservation: Proper handling and labeling are crucial for maintaining core integrity and orientation. Follow similar procedures as for conventional cores, with additional caution due to their smaller size.
– Analysis options: Sidewall cores are typically analyzed using similar techniques as conventional cores, like thin sections, porosity/permeability measurements, and geochemical analysis. However, adapted methods may be required due to their limited size.
Key Differences from Conventional Core Planning:
– Smaller sample size: Sidewall cores provide less detailed information compared to conventional cores, necessitating focused data acquisition strategies.
– Limited sample orientation: Retrieving accurate core orientation can be challenging with sidewall coring, impacting some geological interpretations.
– Faster deployment and lower cost: Sidewall coring operations are generally faster and more cost-effective than conventional coring, making them advantageous in certain situations.
CONVENTIONAL CORING
Q. Why do we cut conventional cores, despite the operation being so time consuming and expensive; moreover when there is always an option of taking side wall cores?
Ans. Conventional cores have certain absolute advantages over side wall cores and advanced wireline logs, as they provide:
1. A large, continuous sample of the formation, allowing for detailed analysis of rock properties, mineralogy, and fluid content.
2. High-quality data for petrophysical analysis, which can be used to calibrate reservoir models and equations for porosity, permeability, and saturation calculations, this improves the quality of reservoir characterization and production forecasting.
3. A large size core offer an opportunity to perform special core analysis (SCA) and tests, such as relative permeability, capillary pressure, and wettability measurements, which are critical for understanding reservoir performance.
4. Conventional cores serve as a reference standard for calibrating and validating data from certain advanced logs such as FMI, side wall core and MDT.
5. By virtue of their large size, conventional cores allow direct visual inspection of rock properties, including texture, bedding, fractures, and other features, which can provide valuable insights into reservoir heterogeneity and depositional environment.
The above advantages are overwhelming in case of wildcat and exploration wells. However, in development and production wells alternative methods such as side wall coring, MDT sampling, and advanced logging such as FMI may be sufficient to obtain the required information.
Q. Who are the people in the team that take the decision to cut core? What are their considerations?
Ans. Actually nature of well impacts the coring decision more than the people involved. In fact who will take decision is also decided by the nature of well, being drilled. For example if it is a wildcat or an exploration well, it is the exploration geologist and his team including operations geologist and petrophysicist, who will act as decision maker. In exploration stage G&G team needs huge amount of data to understand subsurface geology in all its form.
On the other hand, conventional cores in development wells also play crucial role but here coring decision is made by a team consisting of development geologist, operations geologist, petrophysicist and reservoir engineer as well as drilling engineer. Development geologist needs core data to understand many aspects of subsurface geology and reservoir characteristics. Petrophysicist requires core data for calibrating log interpretations and developing accurate petrophysical models. Reservoir engineer monitors reservoir performance and needs core data to optimise production, as well as to run simulations and strategize completion design. While drilling engineer shows his concern about extra time and cost as well as the risks involved in the venture and encourages team to look for other options.
Q. What are the roles and responsibilities of an operations geologist in core management (from planning stage to core logistics and data distribution)?
An operations geologist plays a pivotal role in the entire lifecycle of a core, from planning to data dissemination. His various responsibilities in various stages may be summarised as below:
Planning Stage
1. Participates in G&G meetings to determines the optimal core intervals. This involves integrating data from seismic, well logs, and offset wells.
2. Communicates the expected core recovery targets to the drilling team.
3. Develops protocols for core handling, packaging, and transportation to ensure personnel safety and data integrity.
4. Coordinates with geologists, petrophysicists and reservoir engineers to determine the necessary core analysis tests.
Core Logistics
1. Oversees the logistics of core transportation, storage, and distribution to various laboratories for analysis.
2. If required,conducts preliminary core descriptions to identify key lithological units, sedimentary structures, and potential reservoir zones. (Usually done by wellsite geologist)
3. Participates in core sampling for various analyses, such as petrophysical, geochemical, and paleontological studies.
4. Ensures the quality of core data by implementing quality control measures during core handling and analysis.
Data Distribution and Interpretation
1. Organizes and manages core data, including core descriptions, photographs, and analytical results.
2. Compiles various reports from different studies.Prepares core reports summary. Makes a note on lessons learned and recommendations.
Additional Responsibilities
1. Monitors core-related costs and identifies opportunities for cost reduction.
2. Assesses potential risks associated with coring operations and implements mitigation measures.
3. Ensures compliance with HSE regulations during core handling and transportation.
By effectively fulfilling these responsibilities, the operations geologist contributes significantly to the success of coring operation.
Q. What are the responsibilities of a wellsite geologist prior to cutting a conventional core?
Ans. The wellsite geologist plays a critical role in ensuring the successful execution of conventional coring plan. His responsibilities prior to coring can be summarised as below:
Two weeks before expected coring job: 1. Call operations geologist to clarify if there is any uncertainty or contradiction in coring programme. Ensure all the offset logs and mudlogs are available on rig. If not request them now. Sometime far away wells show better correlation than nearer ones, so be generous in demanding more logs.
2. Clarify who will provide consumables; mudlogging company, coring company or the oil company? A tentative list is given here. Decide the quantity as per need:
o Core Boxes (Length of Core in ft /3 + 20%)
o Plenty of Rags
o Permanent Ink Markers. Red, Blue, Black.
o Measuring Tape
o Strong Masking Tapes
o Gloves, Safety Glasses, Masks,
o Hammer, Nails, in case wooden boxes are to be used
o Wax and Wax Bath if some parts of the core are to be preserved.
4 days before the coring operation: discuss with company man about the upcoming coring programme. Objectives, formation and length of core. Also let him know the need of a core processing area, (area where core is to be brought down, cleaned, cut and packed) which should ideally be away from main activity area, well lit and open. Also let him know, when the coring engineer and his stuff is expected to arrive on rig. Around this time inform mudloggers to collect some strong pellets on to which core boxes will be placed and secured for transportation. Usually core pellets are available on rig, but some time they are all sent to town to manage space on the rig. Ensure consumable have arrived on rig by this time. If not call the supplier and find out the status. Ensure all the consumables have arrived as requested. Secure them. If core boxes are made of card board, ensure they are kept at a safe place, away from rain and water. When you get chance, brief the operations geologist about these efforts, so that he does not have to wonder as to what preparations are being done.
2 days before the coring operation: The coring engineer should have arrived on rig by now. If he has, make sure that all his tools and spares have arrived on the rig. In case something is missing, let company man and operations geologist know and help engineer in getting it to the rig at the earliest.
As we approach coring point, pay full attention to correlation with offset wells. Discuss with operations geologist how many ft needs to be drilled in the reservoir before stopping drilling (Ideally 3 to 5 ft is good to ensure good sample for confirmation of reservoir). Discuss correlation with operations geologist or exploration geologist and ensure every one is on the same page. Check mud logs to see the drilling behaviour at coring point. For example if it is sand, how was it drilled in offset wells, what was drill break like and at what WOB. A good practice is to advise driller to maintain constant drilling parameters, so that any variation in ROP could reflect change in lithology. Instruct driller to stop drilling if a drill break is encountered. Circulate hole. If sand is present let company man and operations geologist know before deciding to POOH. Picking core point is a crucial job of wellsite geologist. Picking it too early will get you more of non-reservoir rocks and picking too late will make you lose the objective reservoir.
Q. What are the main points a wellsite geologist must pay attention during cutting a conventional core?
1. While coring maintain a detailed chronology of events and observation. This job can also be entrusted to data engineer. A specially formatted sheet containing Time, Depth and Observations as headings can be provided to data engineer / mudlogger, where they can record their observations including sudden changes in ROP, WOB, SPP, TG.
2. Discuss with data engineer if it is possible to record drilling parameters every half foot during coring or at least every one foot. These observations will help in analysing the reasons for poor recovery if it happens. Sudden increase in torque and stabilizing at higher than average level may indicate a jammed inner core barrel. If the barrel becomes jammed no further core can be cut. Sudden loss in SPP may indicate a broken core.
3. Instruct sample catcher to collect spot samples every two ft. If ROP happens to be fast increase the interval accordingly.
Q100. What are the key responsibilities of a wellsite geologist after cutting a conventional core?
Ans.
After the core has been cut to designated length, it is broken and pulled out of hole. POOH with core barrel may take several hours. This period may be used to prepare and label core boxes if not already done. At this stage, it is sufficient to write core box #1 of.., 2 of.., 3 of…, COMPANY NAME, WELL NAME and T for top and B for bottom. The depth of core in each box and box’s total number can be written at later stage when these are known.
1. Ensure pallets and all other material including cloth bags are available in the core processing area.
2. When core barrel is pulled to rig floor, only required personnel should be present with proper PPE.
3. In accordance to safety protocol, coring engineer or data engineer should check for H2S using handheld H2S detector. If all clear, the core bit is broken and a small piece of core recovered; often time this part of core is broken into pieces. Geologist should mentally note its orientation and transfer it into the box according to top and bottom marked on the box.
4. While handling core on the rig, two most important points that a wellsite geologist should bear in mind are: A. maintain the orientation of core and B. Putting the core in the right box. Maintaining orientation of core becomes more challenging if bare core is pulled out of core barrel. However if the core is in a sleeve or in fiberglass tube, then it is easy to maintain the orientation as most core barrels have red and black line drawn on them. The red line is on the right side and black line is on the left side when core is placed right side up. Another helpful point in orienting the core is that each fiberglass tube is of thirty ft long if 90 ft core is to be cut three fiberglass tubes will be connected and placed in the core barrel. Each fiberglass tube has box type connection at the bottom and pin type connection at the top. So knowing this arrangement of connection one can orient the core.
5. When bare core is extracted from the core barrel, the coring engineer breaks it into 3 ft or 1m pieces. These pieces are immediately placed in core boxes following the top bottom marks on the box and box number. Wellsite geologist must supervise this part of operation carefully.
6. Once all the core pieces are placed in the boxes; they are cleaned using damp rags. Red and black lines are drawn in such a way that looking at core right side up, the red line is on the right side and black on the left. This helps in maintaining the orientation of all pieces of core. Each core piece in the box is measured and depth is written on cores and boxes. Box #1 carries the first core. On its top side the depth from where the coring started is written. Then the core is measured and the length is added and written on the bottom side. On box number 2 the bottom depth of core #1 will go to the top of core and box #2 and so on till the last box. On the bottom side of last box the depth will be same at which the coring was stopped only if the core recovery is 100%. The depth at the bottom of last box will be different if the recovery is less than 100%. Draw chevrons on the black line pointing top of the core. Following information goes on each box: company name, well name, Top, Bottom side of the core, Box no. xx of xx, Depth from xxx to xxx for each core box.
7. Before packing the core, complete the missing depths and box numbers, take photographs and samples from every meter or every 3 ft for description purpose; use plastic bag inside the cloth bag and label the depth before putting the core chips and pieces. Use dirty rags and pieces of card board as padding in the boxes to avoid core moving and rolling during transportation.
8. Once the core boxes are packed. Place them on pallets (not more than for layers of boxes on one pallet) and secure them with strong string.
9. Describe core chips and samples including structure if visible and oil shows. Send core description report to town as soon as possible.
10. Prepare transmittal advice showing company name, well name, Core No. x. cut from xxx to xxx. Recovery xx% , date and time of dispatch, list of boxes containing box number, and the depth from xxxx to xxxx for each box. Make several copies including one to your file and one to operations geologist. Arrange the boat and inform the town about boat ETD and ETA.
Q. What are the basic studies conducted on conventional core in a lab?
Ans. Followings are the basic rock properties that are studied in lab:
Gamma Ray: GR log of core is prepared to exactly correlate the core with logs. Now days even spectral GR analysis can be performed on cores.
Whole Core Analysis: Full diameter core analysis, also known as whole core analysis, involves studying the complete, uncut length of a core sample. This is different from traditional core analysis where small plugs are taken from the core for testing. This study helps in identifying:
o Heterogeneous formations: When the rock formation has uneven properties, like carbonates or fractured rocks, small core plugs might not accurately represent the overall rock characteristics. A full-diameter core gives a more complete picture.
o Large pore spaces: In some rocks, the pores are very large (like in vugs or fractures). Small core plugs might miss these, leading to inaccurate results.
o Better representation of reservoir conditions: Analysing the entire core gives a better understanding of how the rock behaves under real reservoir conditions.
Slabbing: Slabbing could be done across the core or along the core length. This allows detailed observation of core and understanding depositional environment.
Porosity and Permeability Studies: Advance lab techniques provide comprehensive and accurate measurements of rock properties like porosity and permeability which are essential for reservoir modelling and engineering studies.
Core Plugging: Plugs are small cylindrical samples cut from conventional core.Studies on core plugs are considered to be most accurate and precise because of their standard size. Many different types of analyses on plugs are performed efficiently and accurately such as porosity, permeability, relative permeability, fluid saturation, capillary pressure, mineral composition and geomechanical studies to assess the rock strength.
Fluid Saturations: This is an important study that determines the percentage of pores filled with single or mutiple fluids. Petrophysicist use the results of this analysis to calibrate their calculated SW (water saturation).
Source Rock an Biostratigraphical Studies: These studies are conducted on shale and certain parts of limestone rocks.
ADDITIONAL NOTES ON CORE PLANNING, SUPPLIED BY DENIS S.
Core planning procedures?
There is an international standard API RP40 for planning a core sampling program.
Planning begins by listing the objectives of the coring program:
– Clearly define the geological and reservoir objectives.
– Specify the types of data required (e.g., lithology, porosity, permeability, fluid saturations, geomechanical properties) and the desired level of resolution.
– Consider any logistical constraints, such as rig time availability and core handling facilities.
Data Gathering and Review:
– Thoroughly analyze available geological and geophysical data (well logs, seismic surveys, regional studies) to identify potential coring intervals and optimize core placement.
– Consult with geologists, petrophysicists, reservoir engineers, and drilling engineers to gather their input and expertise.
Core Point Selection:
– Select specific depths or intervals for core retrieval based on the objectives and data analysis.
– Consider factors such as: Formation boundaries, Lithological changes, Potential hydrocarbon zones, Zones of interest for reservoir characterization, Areas with uncertainty in well log interpretations.
Core Interval Design:
– Determine the length of each core run, considering factors like: Formation thickness, Data requirements, Cost implications,
Core handling and storage capabilities.
– Plan for potential contingencies, such as encountering unexpected geological features or drilling challenges.
Core Handling and Analysis Plan:
– Outline procedures for core handling, preservation, transportation, and laboratory analysis.
– Ensure proper core orientation and labeling for accurate interpretation.
– Designate a core laboratory and schedule analysis based on data requirements and project timelines.
Communication and Coordination:
– Clearly communicate the core plan to all involved parties, including drilling crew, geologists, engineers, and laboratory personnel.
– Ensure proper coordination and seamless execution of core retrieval and analysis activities.
Additional Considerations:
– Core-Orienting Tools: Deploy tools to determine core orientation relative to true north and formation dip, crucial for geological interpretation.
– Special Core Analysis: Plan for potential special core analysis (SCAL) to measure fluid flow properties under reservoir conditions if required for reservoir characterization.
– Core Preservation: Implement appropriate preservation techniques (e.g., refrigeration, vacuum sealing) to maintain core integrity and prevent contamination.
– Data Integration: Integrate core data with other geological and geophysical information for comprehensive reservoir understanding and modeling.
ADDITIONAL NOTES ON CORE HANDLING AND MARKING AFTER RECOVERY (BY DENIS S.)
Core handling and marking after recovery?
1 – Core points according drilling program. Catching core points:
fix drilling parameters (RPM, WOB, FLOW RATE) before coring interval, then see firstly apereas that formation change (ROP changing), 2m drill and circulate bottoms up, check gas readings (chromatograph – (high C1 – gas no cutting samples / high C3 4 5 – oil) and TG – and check shaleshackers for oil or gas bubbles, take cutting sample by mudloggers and find an evidence of oil saturation by oil shows.
2 – Safety meeting prior to core barrel recovery and check H2S while pooling out and laying down.
3 – Visually check for oil drops at the bottom of core barrel and take a chip sample from bottom to confirm the next coring interval.
4 – Once the inner tube with core laid down with the laydown cradle to the processing area (cut walks) spectral GR logging will be done. Then, marked with orientation black & red lines (Marking of core by Black and Red indelible markers, taped together should be from top to bottom as red color in right side and black color in left side). 1m cut marks, well numbers depths and top, bottom words of each 1 m, photography the end face for every 1 m. Chip samples will be taken at the cut ends.
5 – Supervisor at the rig site should select a sample from every 9 m of core for wax preservation for geochemical surveys (porous oil saturated sample).
6 – The 1m sections will be rubber capped, fastened with clips, and placed to wooden core boxes for transportation to core analysis lab.
Q. What is an FMI log? What are its uses in oil exploration?
Ans. FMI stands for Formation MicroImager. It’s a high-resolution imaging tool used in the oil well logging to capture detailed images of the borehole wall. Essentially, it provides geological information on formations surrounding the well, including:
Sedimentary structures
Fractures
Bedding planes
Voids and inclusions
Borehole conditions (e.g., washouts, mud cakes)
Q. What are some of the sedimentary structures and other geological feature that can be identified using FMI log?
Ans. Followings are important sedimentary structures that can easily be identified after processing the FMI log:
Stratification: Identification of bedding planes, thickness, and orientation.
Ripple marks: Recognition of current direction and depositional environment
Cross-bedding: Determination of depositional environment and paleocurrent direction.
Graded bedding:Identification of depositional energy changes.
Bioturbation: Recognition of biological activity and depositional environment.
Other geological features that can be identified on FMI logs are:
Fractures: Identification of orientation, aperture, density, and conductivity.
Faults: Detection of displacement and fault plane orientation. Some time other logs are needed to confirm fault plane.
Voids and inclusions: Identification of cavities, mineralization, and other inclusions.
Borehole conditions:Assessment of washouts, mud cakes, and borehole stability.
Lithology: Indirect identification of rock types based on resistivity contrasts.
Q. How does FMI tool work?
Ans. The FMI tool uses a series of button electrodes to measure the resistivity of the formation at very high resolution. The electrodes (which are hundreds in numbers) are typically arranged in a circular or near-circular pattern around the tool to provide a 360-degree view of the borehole wall.
When an electrical current is applied to an electrode, it spreads out radially into the formation. The resistivity of the formation affects the current flow. The other electrodes measure the potential difference caused by this current flow. These resistivity measurements are then converted into images that show the geological features of the formation, such as fractures, laminations etc.
Please note, the FMI tool doesn’t operate on the principle of transmitters and receivers in the traditional sense like conventional resistivity tools. The button electrodes act as both transmitters and receivers of electrical current. This arrangement provides very high vertical resolution ( a few mm). Also the depth of investigation is deliberately kept very shallow (a few centimetres) that further helps to enhance resolution.
Q. What is the role of wellsite geologist during FMI logging operation?
Ans. While comprehensive QC is performed in office or data processing centre by experts, the wellsite geologist is expected to conduct basic QC checks, such as:
1. Observe the logging process to ensure it is conducted according to plan
2. Verify that the tool is responding appropriately to changes in formation properties
3. Check for any anomalies or inconsistencies in the acquired data
4. Record information such as tool specifications, operational parameters, and any issues encountered, like
borehole washouts and thick mud cakes, which can affect the quality of log.
Q 100. What role does FMI (Formation Microimager) plays in picking up coring point? (Q&A SUPPLIED BY DENIS S.)
FMI log in catching coring depth?
FMI logs play a crucial role in catching coring depth and optimizing core retrieval:
Precise Depth Correlation:
– High-resolution images: FMI logs provide detailed images of the borehole wall, capturing fine-scale geological features and formation boundaries with exceptional clarity.
– Depth markers: Distinctive features like bed boundaries, fractures, or lithological changes seen in the FMI log can serve as precise depth markers, allowing for accurate correlation between log data and core samples.
– Depth matching: By matching these features with corresponding features observed in the retrieved core, geologists can confidently confirm the exact depth from which the core was recovered.
Identifying Optimal Coring Intervals:
– Reservoir characterization: FMI logs reveal critical information about reservoir properties, including: Fracture distribution and intensity; Bedding orientation and dip; Lithology variations; Structural features like faults and folds.
– Targeted coring: This information guides geologists in selecting the most promising and informative intervals for coring, ensuring the retrieval of representative and valuable core samples.
Fracture Analysis and Core Orientation:
– Fracture characterization: FMI logs excel at delineating fractures, providing details on their: Orientation; Aperture; Density; Connectivity.
– Core orientation optimization: This knowledge aids in determining the optimal core orientation to capture the most representative fracture network within the core, crucial for accurate fracture analysis and reservoir modeling.
Evaluating Core Recovery:
– Post-coring assessment: Comparing FMI logs acquired before and after coring reveals areas where core recovery was successful and where potential gaps or poor recovery occurred.
– Targeted re-coring: This information can guide decisions on whether to re-core specific intervals to obtain a more complete and representative core dataset.
Correlating Core and Log Data:
– Precise depth control: The accurate depth correlation enabled by FMI logs ensures reliable integration of core data with other logging data (e.g., porosity, resistivity, sonic logs) for comprehensive reservoir characterization.
– Enhanced interpretation: This combined dataset provides a more holistic understanding of the reservoir’s geological and petrophysical properties, leading to more informed reservoir evaluation and development decisions.
In summary, FMI logs are invaluable tools for optimizing coring operations and maximizing the value of core data. Their high-resolution images and detailed geological information empower geologists to: Catch coring depth with confidence; Select optimal coring intervals; Analyze fractures and guide core orientation; Evaluate core recovery; Efficiently integrate core and log data. By effectively utilizing FMI logs, geologists can significantly enhance the quality and utility of core data, leading to better reservoir understanding and decision-making.
Q&A ON NMR LOGGING
Q110. What do you know about NMR logging?
Ans. Nuclear Magnetic Resonance is a powerful tool for reservoir characterization. Being expensive, it is usually run in exploratory wells. It provides lithology independent porosity, permeability, pore and grain size distribution, irreducible fluid volume and moveable fluid volume. It also provides water saturation that is independent of formation water salinity
Q. What is the recording principle of NMR tool?
Ans. The Schlumberger NMR tool works by using a strong magnet to align the nuclei (proton) of formation fluid with the magnetic field and then a short burst of radio waves is given that temporarily misalign (or disturb the alignment) of the molecules, which after a little time (called relaxation time / T2) align back with magnetic field. As they realign, they emit a signal that is measured by the tool. Long relaxation times correspond with large pores and more mobile water, while shorter relaxation times correspond with small pores and less mobile water
The strength of the signal tells us how much is porosity in the rock and how quickly the signal decays tells us how much is permeability.
Note: Depth of investigation of NMR tool ranges from 1.25” to 4” and vertical resolution varies from 4” to 18” depending on tool settings. NMR logging speed can vary between 1500 ft/hr to 3000 ft/hr.
Q. What are the responsibilities of wellsite geologist during NMR logging operation?
Ans. As usual a wellsite geologist has to witness the logging process and QC the log. Several important points are listed in this regard:
Witness the entire logging operation to ensure that it is conducted according to standard procedures and safety guidelines.
Monitor the logging speed and depth intervals
Document any observations or issues that arise during the logging operation.
Record the logging parameters, tool settings, and any relevant environmental conditions.
Wellsite geologists are not expected to provide the interpretation of NMR logging data. Basic interpretation is performed by wireline engineer; wellsite geologist however should ensure the interpretation matches with his quick look logs interpretation. Any discrepancy should be brought to the attention of wireline engineer and operations geologist. Further, detailed analysis and interpretations are usually done in data processing centres of logging company.
Additional Notes:
Coordinate with the logging engineers to ensure that the NMR logging operation is planned and executed effectively.
Provide mudlog and other geological input (such as presence of pyrite and ferro magnesian minerals if present as significant traces) to the logging engineers to help them optimize the logging parameters.
Ask wireline engineer if he has noticed variations in magnetic field or in tool orientation? As these can affect NMR signals, leading to inaccurate measurements. Make a note of it.
Find out formation water resistivity from offset well data (or from town) and let wireline engineer know. High salinity fluids can reduce the NMR signals, making it difficult to accurately measure porosity and permeability.
Q&A ON FMI LOGGING
Q. What is an FMI log? What are its uses in oil exploration?
FMI stands for Formation MicroImager. It’s a high-resolution imaging tool used in the oil well logging to capture detailed images of the borehole wall. Essentially, it provides geological information on formations surrounding the well, including:
Sedimentary structures
Fractures
Bedding planes
Voids and inclusions
Borehole conditions (e.g., washouts, mud cakes)
Q. What are some of the sedimentary structures and geological feature that can be identified using FMI log?
Ans. Followings are important sedimentary structures that can easily be identified after processing the FMI log:
Stratification: Identification of bedding planes, thickness, and orientation.
Ripple marks: Recognition of current direction and depositional environment
Cross-bedding:Determination of depositional environment and paleocurrent direction.
Graded bedding:Identification of depositional energy changes.
Bioturbation: Recognition of biological activity and depositional environment.
Other geological features that can be identified on FMI logs are:
Fractures: Identification of orientation, aperture, density, and conductivity.
Faults: Detection of displacement and fault plane orientation. Some time other logs are needed to confirm fault plane.
Voids and inclusions: Identification of cavities, mineralization, and other inclusions.
Borehole conditions:Assessment of washouts, mud cakes, and borehole stability.
Lithology: Indirect identification of rock types based on resistivity contrasts.
Q. How does FMI tool work?
Ans. The FMI tool uses a series of button electrodes to measure the resistivity of the formation at very high resolution. The electrodes (which are hundreds in numbers) are typically arranged in a circular or near-circular pattern around the tool to provide a 360-degree view of the borehole wall.
When an electrical current is applied to an electrode, it spreads out radially into the formation. The resistivity of the formation affects the current flow. The other electrodes measure the potential difference caused by this current flow. These resistivity measurements are then converted into images that show the geological features of the formation, such as fractures, laminations etc.
Please note, the FMI tool doesn’t operate on the principle of transmitters and receivers in the traditional sense like conventional resistivity tools. The button electrodes act as both transmitters and receivers of electrical current. This arrangement provides very high vertical resolution ( a few mm). Also the depth of investigation is deliberately kept very shallow (a few centimetres) that further helps to enhance resolution.
Q. What is the role of wellsite geologist during FMI logging operation?
Ans. While comprehensive QC is performed in office or in data processing centre by experts, the wellsite geologist is expected to conduct basic QC checks, such as:
· Observe the logging process to ensure it is conducted according to plan
· Verify that the tool is responding appropriately to changes in formation properties
· Check for any anomalies or inconsistencies in the acquired data
· Record information such as tool specifications, operational parameters, and any issues encountered.
SEISMIC LOGGING (CHECK SHOT AND VSP)
Q. What are check shots? What is their significance?
Check shots involve sending down a special tool, often called a geophone, into the wellbore. This geophone records the arrival times of seismic waves generated by surface sources. The primary goal of check shots is to determine the accurate depth of the seismic horizons encountered during drilling operations. This information is essential for several reasons:
Correlation: Check shots help correlate seismic data obtained from surface surveys with the actual geological formations encountered in the wellbore. This correlation is vital for accurate geological interpretation and well planning.
Depth Conversion: By knowing the depth of seismic horizons, geophysicists can convert seismic times into depths, allowing for more precise depth control during drilling operations.
Q110. How Check Shots are performed?
Ans. A check shot operation can be broken down into various stages for easy understanding:
1. A geophone on wireline tool is lowered into the wellbore to a specific depth.
2. A seismic energy source on surface, such as an air gun in offshore or a vibroseis truck at land rig, is activated on the surface.
3. When the seismic waves from the surface source reach the geophone, they are recorded.
4. The depth of the geophone and the arrival time of the seismic waves are recorded simultaneously.
5. The recorded data, consisting of seismic arrival times and corresponding depths, is analyzed using specialized software. This analysis helps determine the precise depth of the seismic horizon.
6. To ensure accuracy and consistency, check shots are often performed at multiple depths (500 ft to 1000 ft depth interval) within the wellbore. This allows for a more comprehensive understanding of the subsurface geology.
Key Considerations:
Timing: The timing of the seismic source activation and geophone positioning is crucial for accurate measurements.
Environmental Factors: Factors like noise and vibrations can interfere with seismic wave recordings. Therefore, the check shot operation is typically conducted in a controlled environment.
Equipment Calibration: Calibration of the geophone and maintaining optimum pressure in the compressor for air gun is critical.
Q. what are the roles and responsibilities of wellsite geologist in arranging and managing check shot operation?
Ans. A wellsite geologist is responsible in ensuring the successful execution and accuracy of check shot operations. His key responsibilities may be summarised as below:
Planning and Coordination:
The wellsite geologist coordinates with the wireline company to schedule check shot operations and manage logistics.
He ensures that all safety protocols are followed during the operation, including the proper use of safety equipment and adherence to industry standards.
Data Acquisition:
The geologist monitors the entire check shot process, ensuring that the geophone is positioned at the correct depths and that the seismic source is activated at the appropriate time.
He verifies the quality of the recorded seismic data, checking for any anomalies or inconsistencies that might affect the accuracy of the results.
In summary, the wellsite geologist’s expertise and knowledge are essential for ensuring the accuracy and effectiveness of check shot operations. Wellsite geologists are usually not required for making decisions regarding well placement and reservoir development.
Q. What is difference between check shot and VSP?
Check shot and Vertical Seismic Profile (VSP) are both seismic surveying techniques used in the oil well, but they have distinct purposes and methodologies.
The purpose of check shot is to determine the accurate depth of seismic horizon encountered during drilling. It is primarily used for depth control and correlation of seismic data with wellbore information.
VSP is designed to obtain detailed image of the subsurface along the wellbore, including information on reservoir properties, fractures, and velocities. It Provides a more comprehensive understanding of the subsurface geology in the vicinity of the wellbore.
In summary, check shots are primarily used for depth control and correlation, while VSP provides a more detailed image of the subsurface geology along the wellbore.
Q. What is a seismic horizon?
Ans. A seismic horizon is a boundary or interface between rock layers with different acoustic properties. These differences can be caused by changes in rock type, porosity, fluid content, or other geological factors.
In seismic data, seismic horizons are typically represented as continuous lines or surfaces that delineate the boundaries between different rock formations. They are identified based on changes in seismic amplitude, frequency, or other seismic attributes.
Seismic horizons are crucial for understanding the subsurface geology and interpreting seismic data. They can be used to identify potential hydrocarbon reservoirs, map faults and other structural features, and correlate seismic data with well logs and other geological information.
Q. How do wellsite geologist witness and QC check shot operation?
Wellsite geologists ensure the efficiency of operation and accuracy of check shot data. Here’s how they typically participate:
Witnessing the Operation
1. The geologist is physically present during the entire check shot operation. This allows them to observe the process first hand and verify that it’s being conducted according to established procedures.
2. The geologist verifies that all safety protocols are being followed, such as wearing appropriate personal protective equipment (PPE) and adhering to safe work practices.
3. The geologist maintains detailed records of the check shot operation, including the date, time, location, equipment used, and any relevant observations.
QC Check Points
1. The geologist checks the quality of the recorded seismic data, looking for any anomalies or inconsistencies that might affect the accuracy of the results. This includes verifying the signal strength, noise levels, and overall clarity of the data.
2. They verify the accuracy of the depth measurements taken during the operation, ensuring that the geophone is positioned at the correct depth.
3. The geologist checks the synchronization between the seismic source activation and the geophone recording to ensure that the data is accurate.
4. They compare the check shot data with the existing seismic data from surface surveys to verify correlation and consistency.
Q. What are the challenges that are usually faced during check shot or VSP operations that a wellsite geologist should be aware of?
Wellsite geologists should be aware of several challenges that can affect the accuracy and reliability of check shot and VSP operations. These include:
Equipment-Related Issues
Faulty or poorly anchored geophones can lead to inaccurate seismic wave recordings, compromising the quality of the data.
Malfunctions or reduced efficiency of the seismic source can result in insufficient energy generation, affecting the signal quality. For example, if we are using air gun, the improper pressure in the air compressor may effect the signal strength and the quality of data.
Environmental Factors
External noise sources, such as drilling operations, Heavy machinery, or traffic, can contaminate the seismic signal, making it difficult to accurately interpret.
Vibrations from the drilling rig or other equipment can introduce noise into the seismic recordings, affecting data quality.
Operational Challenges
Inaccurate synchronization between the seismic source activation and geophone recording can result in mismatched data.
Inaccurate depth measurements can lead to miscorrelation of seismic horizons with the wellbore.
Errors in data analysis, such as incorrect processing techniques or human error, can affect the accuracy of the results.
Geological Factors
Complex geological formations with multiple seismic horizons or lateral variations can make it difficult to accurately correlate seismic data with the wellbore.
Anisotropic formations can introduce distortions into the seismic signal, making it challenging to interpret accurately.
The presence of gas in the formation can affect seismic wave propagation, leading to velocity variations and potential errors in depth conversion.
By being aware of these potential pitfalls and taking appropriate measures to mitigate them, wellsite geologists can help ensure the accuracy and reliability of check shot and VSP operations and the subsequent geological interpretation.
Q. How do wellsite geologists analyse and interpret check shot and VSP data on the rig?
Wellsite geologists are not involved with seismic data interpretation on rig. They are tasked with efficient and safe execution of operation and acquiring accurate and good quality data. However as the check shot or VSP operation proceeds wellsite geologist keep updating TWT vs TVDSS plot.
Additional Note:
Wellsite geologists are not involved with seismic data interpretation on rigs however the job is performed in office by operations geologists, development geologists and geophysicists. For basic understanding here is a break down of interpretation.
1. Visual Inspection:
Time-Depth Plots: The geologist creates time-depth plots to visualize the relationship between seismic arrival times and depth. This helps identify key seismic horizons and correlate them with geological formations.
Amplitude Analysis: Amplitude variations in the seismic data can provide clues about the properties of the encountered formations, such as porosity and fluid content.
2. Software Tools:
Seismic Processing Software: Specialized software is used to process and analyze the seismic data. This includes tasks like noise reduction, filtering, and velocity analysis.
Geophysical Modeling Software: Modeling software can be used to create 2D or 3D geological models based on the check shot data and other geophysical information. These models help visualize the subsurface structure and identify potential reservoir zones.
3. Geological Interpretation:
Correlation with Seismic Data: The geologist correlates the check shot data with the existing seismic data from surface surveys to refine the understanding of the subsurface geology.
Formation Identification: Based on the seismic characteristics and geological knowledge, the geologist identifies the different geological formations encountered in the wellbore.
Reservoir Evaluation: The geologist evaluates the potential reservoir properties of the encountered formations,such as porosity, permeability, and fluid saturation. This involves using the check shot data in conjunction with other geological information, such as well logs and core samples.
Depth Conversion: The geologist converts seismic times into depths using the check shot data, providing a more accurate picture of the formation depths.
4. Decision Making:
Drilling Decisions: Based on the interpretation of the check shot data, the geologist may provide recommendations regarding drilling decisions, such as adjusting drilling parameters or making decisions about casing placement.
Formation Evaluation: The geologist assists in evaluating the properties of the encountered formations, such as porosity and permeability, using the check shot data in conjunction with other geological information.
Key Considerations:
Data Quality: The accuracy of the interpretation depends on the quality of the check shot data. Ensuring accurate data acquisition and processing is essential.
Geological Context: The geologist must consider the overall geological setting and regional trends when interpreting the check shot data.
Integration with Other Data: The check shot data is often integrated with other geological information, such as well logs and core samples, to provide a more comprehensive understanding of the subsurface.
By following these steps and using appropriate tools and techniques, operations geologists and development geologists can effectively analyze and interpret check shot data to make informed decisions about drilling operations and reservoir development.
Q. What is Two way time vs TVDSS plot? what are its uses and significance?
Ans. A TWT vs TVDSS plot is essentially a scatter plot where the x-axis represents TWT and the y-axis represents TVDSS. Each point on the plot corresponds to a specific subsurface reflector.
Preparing this plot during seismic logging is crucial on the rig for several reasons:
Depth Conversion: It allows for the conversion of seismic travel times (TWT) into actual depths (TVDSS). This is essential for accurately locating subsurface features and structures.
Structural Interpretation: By analyzing the shape of the plot, geologists can identify structural features such as faults, folds, and unconformities. These features can have significant implications for hydrocarbon exploration and production.
Stratigraphic Correlation: TWT vs TVDSS plots can be used to correlate seismic horizons between different wells or seismic lines, helping to identify stratigraphic units and their lateral extent.
Q. How many geophones are used in check shot and VSP surveys?
The primary purpose of a check shot is to determine the accurate depth of seismic horizons. A single geophone is sufficient for this task, as it records the arrival times of seismic waves at a specific depth within the wellbore.
Multiple geophones (few to few dozens) might be used in vertical seismic profiling (VSP), where the objective is to obtain a detailed image of the subsurface along the wellbore. However, for the specific task of check shots, a single geophone is generally adequate.
Q. What are different type of VSPs?
Ans. VSPs can be acquired by positioning energy source at different places, accordingly they are named differently:
zero-offset
offset VSP
walkaway VSP
Walk-above VSP
Salt-proximity
Seismic While Drilling
In Zero-offset, energy source is placed near the wellbore, while in offset sources Air gun or vibroseis are at a distance. Walkaway sources move farther away from fixed receivers. Walk-above VSP, are conducted in highly deviated and horizontal wells. Here energy source is positioned directly above the geophones in the hole. Salt-proximity VSP surveys use source on salt domes to define salt-sediment interfaces.
Seismic-while-drilling (SWD) VSPs, use the noise of the drill bit as the source and the geophones are placed on surface. This is also called Drill Noise VSP. Here the data quality is usually very poor.
One point that should be noted here is that the basic functioning of tool and QC procedures for different type of VSPs are same. It is just the acquiring methods that are little different.
Q120. Why do we prefer to perform VSP survey in cased hole compare to open hole?
Data quality in seismic surveys is generally better in cased hole environments compared to open hole.
Here’s why:
Cased hole provides a more stable environment for the geophone, reducing the risk of movement or damage that can affect data quality.
The casing can help isolate the geophone from external noise sources, such as drilling operations or surface vibrations, leading to cleaner seismic signals.
In some cases, the casing can improve the coupling between the geophone and the formation, resulting in better signal transmission.
However, there are also some advantages to open hole seismic surveys, such as:
Open hole allows for direct contact between the geophone and the formation, which can improve signal quality in certain geological conditions.
In some cases, open hole can reduce the attenuation of seismic waves, leading to clearer signals.
Q . What are different types of energy sources used in seismic surveys performed on oil rigs?
Ans. Seismic surveys performed on oil rigs primarily utilize two types of energy sources:
Explosive Sources:
Dynamite: The most traditional and widely used explosive source. It involves detonating charges at the surface to generate seismic waves.
Other Explosives: Other types of explosives, such as TNT or ANFO (Ammonium Nitrate Fuel Oil), can also be used depending on specific requirements.
Non-Explosive Sources:
Vibroseis: A mechanical device that generates vibrations by oscillating a large vibrating plate on the surface. It offers a more controlled and environmentally friendly alternative to explosive sources.
Air Guns: These devices release compressed air into the water, generating seismic waves. They are commonly used on offshore rigs.
The choice of energy source depends on various factors, including:
Environmental regulations: Some regions have restrictions on the use of explosive sources.
Depth of exploration: Deeper targets may require more powerful sources like explosives.
Sensitivity: The sensitivity of the surrounding environment to seismic vibrations is also a consideration.
Both explosive and non-explosive sources have their advantages and disadvantages, and the optimal choice often depends on the specific requirements of the seismic survey.
Q. What do you know about geophones?
Ans. Geophones are basically receivers of seismic signals (waves) in wellbores. Some common types :
1. Single-Component Geophones:
Vertical Geophones are most commonly used in check shot operation. They are designed to measure vertical ground motion.
Horizontal Geophones measure horizontal ground motion in a specific direction (e.g., north-south, east-west).
2. Three-Component Geophones:
Triaxial Geophones measure ground motion in all three directions (vertical and horizontal). Frequently used in VSP. Help in performing detailed seismic analysis, particularly in anisotropic formations or for studying fracture orientation.
3. Geophone Arrays:
Geophone arrays consist of multiple geophones arranged in a specific pattern. They help in improving signal-to-noise ratio, enhancing resolution, and studying wavefield propagation.
Q. How will you identify improper anchoring of a geophone during VSP operation?
Ans. Several indicators can suggest that a geophone is not properly anchored:
Inconsistent Readings: If the geophone is loose, it can move within the wellbore, leading to inconsistent or erroneous readings.
Noise Interference: A loose geophone may be more susceptible to noise interference from the wellbore environment, such as drilling fluid or vibrations.
Calibration Issues: Improper anchoring can affect the geophone’s calibration, leading to inaccurate measurements.
Q. If we have to perform walkaway VSP on an offshore rig, logistics become an important job for wellsite geologist; What are important pre-planning and logistic points that he should pay attention to?
Conducting a walk-away VSP (WAVP) on an offshore rig presents unique logistical challenges due to the remote environment and potential weather conditions. Here are some key pre-planning and logistical points that the wellsite geologist should pay attention to:
1. Weather Forecasting and Planning:
Weather Windows: Identify suitable weather windows for the WAVP operation, considering factors like wind speed, wave height, and visibility. In bad offshore weather, it is difficult and time consuming to position the boat and shooting point.
Develop contingency plans for adverse weather conditions, such as delaying the operation by running a different log like CBL/VDL etc. or cancellation of VSP.
2. Vessel and Equipment Preparation:
Vessel Availability: Ensure that the necessary vessel or platform is available for the WAVP operation and that it is equipped with appropriate safety features. We also need an experienced captain to handle the boat efficiently in rough weather.
Equipment Readiness: Verify that all required equipment, including the geophone, wireline cable, seismic source, and data acquisition system, is in good working condition and ready for deployment at short notice.
3. Safety Procedures:
Offshore Safety Regulations: Adhere to all offshore safety regulations and guidelines, including those related to emergency procedures and personal protective equipment (PPE).
Risk Assessment: Conduct a thorough risk assessment to identify potential hazards and develop mitigation strategies.
4. Logistics and Supply Chain:
Equipment Transportation: Coordinate the transportation of the necessary equipment to the offshore location, ensuring timely delivery and proper handling.
Supply Chain Management: Establish a reliable supply chain to ensure that essential supplies and spare parts are readily available.
5. Personnel Training and Certification:
Offshore Training: Ensure that all personnel involved in the WAVP operation have the necessary offshore training and certifications.
Specialized Skills: Identify individuals with specialized skills, such as seismic data acquisition or marine operations, and assign them appropriate roles.
6. Communication and Coordination:
Clear Communication: Establish clear communication channels between the wellsite team, the wireline crew,and other relevant parties.
Coordination with Vessel Crew: Coordinate with the vessel crew to ensure that the WAVP operation is integrated into the overall vessel schedule and operations.
By carefully considering these pre-planning and logistical points, the wellsite geologist can help ensure the successful and efficient execution of an offshore walk-away VSP survey.
Q. Is it advisable to perform walkaway VSP in a vertical well?
Ans. Yes, it is advisable to perform walk-away VSP (WAVP) in a vertical well.
While WAVP is often associated with deviated or horizontal wells, it can also be effectively used in vertical wells. The key advantage of WAVP in vertical wells is the ability to obtain a wider range of incident angles between the seismic waves and the subsurface formations. This can provide valuable information about the subsurface geology, including the detection of faults, fractures, and other structural features.
Here are some specific benefits of performing WAVP in a vertical well:
Improved Depth Penetration: The wider angular coverage can lead to improved depth penetration, allowing for the exploration of deeper targets.
Anisotropy Analysis: WAVP is particularly useful for studying anisotropy in the subsurface, which can affect the propagation of seismic waves. This information is essential for accurate seismic interpretation and reservoir characterization.
Reservoir Delineation: WAVP can help delineate reservoir boundaries and identify lateral variations in reservoir properties more accurately than normal VSP.
Fracture Detection: WAVP is sensitive to the presence of fractures in the subsurface, making it a valuable tool for studying fractured reservoirs.
While the specific benefits of WAVP may vary depending on the geological setting and wellbore configuration, it is generally considered a valuable tool for geophysical exploration in both vertical and deviated wells.
Q. What is difference between a surface seismic survey and a VSP survey?
Surface seismic surveys and Vertical Seismic Profile (VSP) surveys are both used to gather information about the subsurface geology, but they differ in their approach and technique.
Surface Seismic Survey involves acquiring seismic data from the surface using seismic sources (like dynamite or vibroseis) and geophones placed on the surface.
The data is processed to produce 2D or 3D seismic images of the surface. These images provide a general overview of the subsurface structure, including the location of faults, folds, and potential hydrocarbon reservoirs.
On the other hand VSP survey involves placing a geophone or array of geophones down a wellbore and producing seismic waves at the surface that travel down along the hole and get recorded by geophones. The seismic data thus gathered, provides a detailed image of the subsurface along the wellbore, aiding in reservoir characterization, fracture detection, and velocity analysis.
In summary, surface seismic surveys provide a broader overview of the subsurface, while VSP surveys offer a more detailed look at the geology along a specific wellbore.
Q. What is difference between geophones and hydrophones used in VSP survey?
Geophones and hydrophones are both used in VSP surveys to measure seismic waves, but they are designed for different environments.
Geophones are primarily used in VSP surveys to measure seismic waves propagating through solid rock.
Hydrophones primarily used near the air gun in marine VSP surveys to record the time of origin of seismic.
Q . What are common problems often encountered with geophones and hydrophones during seismic logging?
Both geophones and hydrophones can face various challenges during VSP surveys:
Drilling noise, marine traffic, and other external sources can interfere with the seismic signal, reducing data quality.
Problems with the wireline cable, such as stretching or breakage, can affect data transmission and geophone positioning.
Extreme temperature, pressure, or corrosive environments can impact the performance of geophones and hydrophones.
Accurate and secure installation of geophones in the wellbore can be challenging, especially in complex geological formations or deviated wells.
To address these challenges, wireline companies carry out regular services and maintenance on the equipment, including functionality tests and calibration
Q. Do we use hydrophone while conducting check shot. What is the role of hydrophone during VSP surveys?
No, hydrophones are not typically used in check shot surveys.
Check shot surveys primarily involve measuring the travel time of seismic waves through the wellbore to determine the depth of seismic horizons. This is typically done using geophones, which are designed to measure ground motion.
Role of Hydrophones in VSP Surveys
Hydrophones are primarily used in marine VSP surveys where the geophone is placed in the water. In these cases, hydrophones are used to record the seismic waves propagating through the water.
Geophones measure ground motion, while hydrophones measure water pressure variations.
Q130. What is seismic inversion?
Ans. Seismic inversion in simple term is a process to create a picture of subsurface geology, including structures and other features using the sound waves.
There are different inversion techniques and approaches used for the purpose.
Q. Please explain these three types of inversion techniques: Full-Waveform Inversion, Bayesian Inversion and Joint Inversion?
Full-Waveform Inversion (FWI)
This technique uses the entire waveform (or shape) of the seismic signal to create a detailed image of the Earth’s subsurface. FWI compares the observed seismic data with synthetic data generated from a model of the Earth. By iteratively adjusting the model to minimize the difference between the observed and synthetic data, FWI can create highly accurate subsurface images.
Bayesian Inversion:
It combines prior information (like geological models) with new data (seismic observations) to estimate the most likely properties of the subsurface. Bayesian inversion uses probability theory to quantify the uncertainty in the estimated parameters. It calculates the probability of different models given the observed data and prior information.
Joint Inversion:
Joint inversion combines information from different geophysical datasets (like seismic, gravity, and magnetic data) to create a more comprehensive understanding of the subsurface. Joint inversion simultaneously inverts multiple geophysical datasets to estimate the same set of subsurface parameters. By combining information from different sources, it can improve the accuracy and resolution of the results.
In summary, these three inversion techniques offer different approaches to reconstructing the Earth’s subsurface. FWI focuses on the waveform, Bayesian inversion incorporates prior information and uncertainty, and joint inversion combines information from multiple datasets. The choice of technique depends on the specific application and the available data.
Q&A ON DIRECTIONAL DRILLING
Q. What are the applications of directional drilling?
Ans. The directional drilling can be applied in the following situations:
1. Sidetracking.
2. Drilling to avoid geological problems.
3. Controlling vertical holes.
4. Drilling beneath inaccessible locations.
5. Offshore development drilling and extended reach drilling.
6. Multilateral well.
7. Shoreline drilling.
8. Horizontal drilling.
9. Relief Well drilling.
Q. What is horizontal drilling? Why do we need to indulge in horizontal drilling?
Ans. Horizontal drilling is becoming more common in the oil industry; briefly it is a drilling process in which a directional well is turned horizontally at a predetermined depth. The primary functions of the horizontal drilling are:
1. Increasing the drainage area of the platform.
2. Mitigate gas coning or water coning problems.
3. Increased penetration of the producing formation.
4. Increase the efficiency of enhanced oil recovery (EOR) techniques.
5. Improve the productivity of natural fractured reservoirs by intersecting a number of vertical fractures.
Q. What do you understand by well trajectory?
Ans. Well Trajectory is the planned path designed to drill a directional well. This is prepared in town by a team consisting of geologist, drilling engineer and directional expert. It shows stand by stand theoretical MD, TVD, Inclination and Azimuth. Graphically the plan is presented in two charts:
1. Plane View that shows azimuthal plan (Northing / Easting) or the direction in which the well will be drilled.
2. Vertical View: It is a plot of vertical section against TVD.
These two plots give a 3D idea of the well; that is its deviation from vertical axis and the direction in which the well will go. DD tries to strictly follow this plan, while drilling the well.
Q. What is your understanding on geosteering?
Ans. There are two objectives of geosteering:
1. To follow the planned trajectory strictly throughout the course of directional drilling
2. If needed, to fine tune the trajectory based on realtime structural correlation. However, any modification in trajectory, however minor, should first be discussed with the geologist in town.
Q. What are the well-bore stability issues that a wellsite geologist must be aware of during directional drilling?
Ans. The wellsite geologist should be aware of potential wellbore stability challenges such as shale instability, lost circulation, or stuck pipe that can be more pronounced in directional wells. Understanding drilling fluid properties and their impact on wellbore stability and drilling efficiency is also important, especially in directional wells where challenges like hole cleaning and torque and drag can be amplified.
Q. Name three Survey methods?
Ans. Magnetic, Gyro and INS could be cited as being widely in use these days.
Notes:
Three commonly used surveying methods in directional drilling are:
Magnetic Surveys: Utilize the Earth’s magnetic field to determine the wellbore’s inclination (angle from vertical) and azimuth (direction relative to North). This method uses highly advanced compass type device called magnetometer, which are kept inside MWD tool.
Gyro Surveys: Employ gyroscopes to measure the wellbore’s inclination and azimuth independent of magnetic fields. These are more accurate and more definitive surveys; typically conducted using wireline tools or more advanced MWD systems.
Inertial Navigation Systems (INS): Combine accelerometers and gyroscopes to continuously track the wellbore’s position and orientation in three-dimensional space. These are increasingly integrated into high-end MWD/LWD tools for real-time, high-accuracy surveying.
Each method has its own advantages and limitations, and the choice of survey method often depends on factors like drilling depth, wellbore complexity, magnetic interference, and cost considerations.
Q. What data do you input in ‘Survey Spread Sheet’ What output data do you get?
Ans. We enter MD, Inclination and Azimuth data taken from a survey station. The spread sheet calculates and outputs: TVD, Northing, Easing, Vertical Section and Dog Leg.
Q. What do you understand by these directional terms: Northing, Easting, Vertical Section?
Ans. Northing represents the distance a wellbore has moved northward from a reference point. It’s plotted on “y-coordinate” on a plain view plot, where increasing values indicate movement further north.
Easting represents the distance a wellbore has moved eastward from a reference point. It is plotted on “x-coordinate” on a plain view plot, with higher values signifying movement further east.
Vertical Section: It is graphical representation that shows the wellbore’s path in a vertical plane. This provides a side view of the wellbore’s trajectory, highlighting changes in inclination and TVD. In terms of calculation, a Vertical Section can also be described as horizontal distance of well-bore that moves in the direction of the final target per each station or in total.
Notes:
Here are some other directional terms, wellsite geologist should have a clear idea about:
Azimuth: The horizontal angle, measured clockwise from North, defining the direction the wellbore is heading.
Inclination: The angle at which the wellbore deviates from vertical. It is measured in degrees from 0° (vertical) to 90° (horizontal).
Build Rate: The rate at which the inclination of the wellbore increases, typically expressed in degrees per 100 feet (or meters) of drilled length.
Turn Rate (or Dogleg Severity): The rate at which the wellbore changes direction in the horizontal plane (azimuth), also expressed in degrees per 100 feet (or meters).
Kickoff Point (KOP): The point in the wellbore where intentional deviation from vertical begins.
Target: The specific subsurface location (in terms of TVD and coordinates) that the wellbore is aiming to reach.
Plain View: It is plot of northing and easting. Northings are plotted on Y axis and eastings are plotted on X axis. This plot tells us which direction the hole is being drilled.
Vertical View: It is a plot where vertical section is plotted (on X axis) against TVD (on Y axis). It shows a well bore path in vertical plane.
Build: Increasing the inclination of the wellbore
Landing Point: The depth at which the well become horizontal.
Q. 140. What are different methods used to calculate directional results?
Ans. There are several calculation methods with varying degrees of accuracy:
1. Minimum Curvature Method
Most Common Method: Widely used in the industry due to its simplicity and reasonable accuracy.
Assumption: Assumes a smooth, continuous curve between survey points.
Calculation: Utilizes mathematical formulas to calculate the wellbore’s 3D coordinates (North, East, TVD) at each survey station, considering changes in azimuth and inclination.
2. Balanced Tangential Method
Alternative Method: Used when the minimum curvature method results in unrealistic wellbore trajectories,especially in wells with high dogleg severity.
Concept: Divides the wellbore into segments and assumes a straight line (tangent) between survey points, with adjustments to balance the curve.
3. Radius of Curvature Method
Less Common: Primarily used in specific scenarios where the wellbore follows a circular arc.
Calculation: Employs the radius of curvature to determine the wellbore path between survey points.
4. Average Angle Method
Simplest Method: Suitable for rough estimations or when limited survey data is available.
Assumption: Assumes a constant azimuth and inclination between survey points.
Remarks:
Survey Interval: The frequency of surveys influences the accuracy of calculations. Shorter intervals generally lead to more precise results.
Software Tools: These days nobody uses calculator to calculate directional results, hence equations have not been mentioned. Many softwares are available to calculate and graphically display the results.
Survey Data Quality: Accurate and reliable survey measurements are essential for obtaining meaningful directional results.
Q. What coordinate system does a directional driller use?
Ans. A directional driller uses both the local grid system as well as UTM. The origin for Northing and Easting is usually referenced with the surface location of the well. Wellsite geologists usually use local coordinates.
Q. What is meant by vertical section direction? What is its significance?
Ans. Vertical Section Direction (VSD), often causes confusion and misunderstanding between wellsite geologist and operations geologist or development geologist, if they are using different VSD. Therefore its concept should be clearly understood. In the context of oil well drilling, VSD refers to the specific azimuth or compass bearing along which the Vertical Section is measured.
In simpler terms, it is the direction on a map or compass that we use as a reference to measure how much horizontal progress the wellbore is making towards its target.
Key Points about VSD:
Reference Direction: The VSD serves as a baseline or reference direction to calculate the horizontal advancement of the wellbore.
Target Orientation: Typically, the VSD is aligned with the azimuth of the final target or the intended direction of the well’s vertical section. Some time the azimuth from the last deviation data from the proposed deviation plan is taken as VSD.
Measurement: The vertical section is the horizontal distance covered by the wellbore, measured along this VSD.
Importance in Directional Drilling: In directional drilling, where the wellbore is intentionally steered, the VSD is critical for tracking the well’s progress towards the target and making necessary adjustments to the drilling trajectory.
In a nut shell: The Vertical Section Direction is the reference azimuth used to measure the horizontal advancement of the wellbore towards its target. It’s a crucial parameter in directional drilling for tracking progress and making informed decisions about the well’s trajectory.
Q. What do you understand by tool face? What is its role in directional drilling?
Ans. Tool face shows the orientation of the bit in simple terms: High side or Low side, Left or Right. Using the analogy of a clock: 12 O’clock will mark high side, 6 O’clock will mark Low side. 3 O’ Clock would mean right side and 9 O’Clock would mean Left Side. Tool face is measured from 0 deg. to 359 deg. 0 deg. represents the high side of the hole. The reference point is usually a scribed line on drill collar or MWD tool.
Role of Tool Face in directional drilling: Tool face is used to control the orientation of bit in desired direction. For example if the tool face is set at 3 O’clock (90deg.), the bit will tend to drill to the right side.
Directional driller also uses Tool face to QC deviation data and correcting it for magnetic interference.
Also, it is worth noting that tool face works in two modes. In vertical or near vertical well, it works in gravity mode (GTF) and in deviated and horizontal section sections it works in magnetic mode (MTF)
Q. What is a Totco survey tool? How does it work? what are its advantages and disadvantages?
Ans. A Totco survey tool is a mechanical, single-shot inclination-only survey tool used in the oil and gas industry to measure the inclination (drift) of a wellbore. It is often used in vertical wells or in the initial vertical sections of deviated wells where directional information is not critical.
How it works
Pendulum and Stylus: The core mechanism consists of a pendulum with a stylus attached. When the tool is lowered into the wellbore, the pendulum swings to align itself with the gravity vector, indicating the inclination of the hole.
Timer and Paper Disc: The tool has a timer mechanism that triggers a punch at a predetermined time. The punch marks a small hole on a circular paper disc, which is marked with concentric circles representing different inclination angles.
Interpretation: The position of the punch mark on the paper disc indicates the inclination of the wellbore at the time of the survey.
Advantages
Simplicity and Cost-effectiveness: Totco tools are run by drillers and are very simple and inexpensive compared to more advanced survey tools like MWD or gyro surveys.
Ease of Use: They are easy to operate and do not require specialized training or equipment.
Reliability: Totco tools are generally reliable and can withstand harsh downhole conditions.
Disadvantages
Limited Information: They only provide inclination data, not azimuth (direction).
Single-Shot: They can only take one measurement per run, making them less efficient than multi-shot tools.
Accuracy: Their accuracy is lower than that of electronic or gyroscopic survey tools.
Manual Interpretation: The paper disc needs to be retrieved and interpreted manually, which can be time-consuming and prone to errors.
Use Cases
Vertical Wells: Totco tools are commonly used in vertical wells to monitor and control wellbore inclination.
Initial Sections of Deviated Wells: They can be used in the initial vertical sections of deviated wells before more sophisticated directional tools are deployed.
Cost-sensitive Operations: They are a suitable option for cost-sensitive operations where high accuracy is not critical.
Overall, Totco survey tools are a simple and cost-effective solution for measuring wellbore inclination in specific scenarios. However,
their limitations in terms of information, accuracy, and efficiency should be considered when choosing a survey tool.
Q. What do you know about Whipstock?
Ans. A whipstock is a wedge shaped deflecting device which is set either in open hole or cased hole to deflect the bit. We have both retrievable and non-retrievable type whipstocks. They are simple but time consuming devices.
Q. How does a jetting operation kicks off a vertical well?
Ans. The purpose of jetting operation is to deviate a vertical well in soft formation. Jetting is normally performed using a tooth bit with one large nozzle and to plugged (blank) nozzles. While jetting the string is kept stationary with no rotation
Q. What do you know about directional drilling with conventional BHAs?
Ans. Because of their poor control over direction and inclination Rotary BHAs are rarely used in directional drilling these days. However to answer the question, there are three types of conventional rotary BHAs:
1. Building Assemblies, these assemblies are designed on Fulcrum Principle to increase the angle.
2. Dropping Assemblies, these assemblies are designed on Pendulum Principle to decrease the inclination.
3. Holding Assemblies, these assemblies are designed on Stabilization Principle to maintain the inclination.
These BHA are cheap to adopt and can be operated by regular driller but the number of trips required to correct the direction and inclination offsets the savings.
Q. What is steerable Assembly?
Ans. A steerable BHA is one that allows directional driller to change the direction and inclination of bit through the surface controlled drilling parameters such as WOB, RPM and FR. These BHAs build and turn in sliding mode and hold in drilling (rotation)mode. They are fitted with downhole motors. There are two types of down hole motors:
1. Turbine Motor
2. Positive Displacement Motor (PDM)
Q. What do you know about downhole mud motors used in steerable BHAs?
Ans. There are basically two types of downhole motors. Turbine and PDM. Turbine motors have now become less popular compare to Positive Displacement Motors. A PDM consists of many parts but the more prominent are rubber moulded spiral shaped stator and a solid steel rotor which is helical shaped. It rotates when mud under pressure is passed through the space between rotor and stator. This rotation in turn rotates and orient the bit to carry out directional drilling.
Positive displacement motors converted directional drilling from being an art to science. In other words these motors put the directional control in the hands of directional driller. These motors can achieve high build rates of up to 30 degrees / 100ft. Also, these motors offer simultaneous build and turns.
There are some disadvantages also associated with mud motors, like slow ROP, occasional high dog legs and poor hole cleaning, that increases the risk of pipe stuck.
Q. 150 What are Rotary Steerable Systems (RSS)?
Ans. Rotary Steerable Systems (RSS) use modern drilling technology in directional drilling. They replace traditional tools like mud motors by using specialized downhole equipment. RSS enables continuous rotation of the drill string during directional drilling, eliminating the sliding motion found in conventional systems. RSS has gained popularity due to the rising demand for drilling Extended Reach Drilling (ERD) wells, where the capabilities of steerable motors proved inadequate for efficient drilling. RSS is particularly beneficial in offshore drilling, where complex ERD horizontal wells with intricate well trajectories are encountered. Mud motors are often unsuitable for these ERD wells, and their use might not be financially viable even if technically possible
Q. What are the advantages of Rotary Steerable Systems over Mud motors?
Ans. Rotary Steerable Systems (RSS) offer active steering, real-time trajectory adjustments, smooth wellbores, and compatibility with MWD/LWD tools. Other advantages include improved ROP, reduced friction, easier tripping, and enhanced hole cleaning. Limitations involve energy loss through friction, potential mechanical damage due to high rotary speeds.
Q. What are the two operating principles of RSS?
Ans. The two operating principle of Rotary Steerable Systems are:
Push the bit working principle
Point the bit working principle
Push the Bit RSS: Push-the-bit rotary steerable systems steer by applying side force to the bit using pads. This force makes the bit cut sideways into the formation, creating a curved hole. These systems require short gauge bits, which allow for quick and precise steering but may lead to a spiralled hole under high side-loading.
Point the Bit RSS: Point-the-bit rotary steerable systems steer by tilting the bit in the desired drilling direction, eliminating side loading on the bit. This allows the use of longer gauge bits, preventing hole spiralling. However, these systems are slower to respond to trajectory changes and have lower dogleg severity capability compared to push-the-bit systems.
Additional Notes:
Push the bit systems offer rapid steering response but are sensitive to borehole conditions and can lead to wellbore quality issues. Point the bit systems are less affected by wellbore conditions and offer better hole quality but are slower to respond and have mechanical limitations.
QUESTIONS ON PRODUCTION TESTING
Q. What are the primary objectives of production testing, and how do these objectives influence decision-making in oil and gas operations?
Ans. Production testing aims to evaluate reservoir potential, characterize fluids, understand reservoir characteristics, and assess well performance. This data helps decide whether to complete a well, how to complete it, and how to plan for production and surface facility design.
Q. Can you describe the different types of production tests and explain the specific information each test provides?
Ans. Common types include Drill Stem Tests (DSTs) for initial reservoir evaluation, flowing well tests to measure production under different conditions, and pressure transient tests to analyze reservoir properties like permeability and boundaries.
Q. How does a wellsite geologist contribute to the production testing process, and what are their key responsibilities during each phase (pre-test, during test, post-test)?
Ans. The wellsite geologist is crucial in fluid identification, monitoring changes in fluid composition, sample collection, data integration, and communication. They ensure representative samples are collected, integrate test data with geological information, and communicate observations to the engineering team.
Notes:
Duties and Responsibilities of a Wellsite Geologist
2.1 Pre-Test Activities
Well Testing Programme: Wellsite geologist should critically go through the entire DST programme. Any doubt or ambiguity must be clarified either with operations geologist or production engineer. Also keep mudlogging, wireline and LWD data about the zone of interest and be ready to share it with team at any time.
Preparing Sampling Equipment: Ensure proper equipment is available for collecting and storing fluid samples and gas samples to be sent to town.
Witnessing perforation: Wellsite geologist is required to witness correlation and perforation operation.
Safety Checks: Participate in pre-test safety meetings and ensure compliance with safety procedures.
2.2 During Test Activities
During production testing, geologist make observational notes as well as on reservoir pressures and flow rates under varying conditions and send reports to office on regular intervals. More importantly they are involved with several tests that are conducted on the produced oil and gas and formation water to assess their properties and understand their impact on production and facilities. Here’s a breakdown of these tests and their significance:
Oil Tests:
API Gravity: Measures the density of the oil compared to water. It’s crucial for determining the oil’s quality and price. Lighter oils have higher API gravity and are generally more valuable.
BS&W (Basic Sediment and Water): Determines the percentage of sediment and water present in the oil. High BS&W can cause corrosion and damage to processing equipment.
Viscosity: Measures the oil’s resistance to flow. It influences the ease of transporting and processing the oil.
Pour Point: Indicates the lowest temperature at which the oil will flow. Important for handling and transportation in cold environments.
Flash Point: The lowest temperature at which the oil’s vapours ignite. Crucial for safety and storage considerations.
Gas Chromatography (GC): Analyzes the gas, identifying the different gases and there percentages. This helps in reservoir characterization and refining processes.
Formation Water Tests:
Salinity: Measures the concentration of dissolved salts in the water. High salinity can cause scaling and corrosion in production equipment.
pH: Indicates the acidity or alkalinity of the water. It can affect the compatibility of the water with production equipment and the environment.
Ion Chromatography: Analyzes the specific ions present in the water, such as chloride, sulphate, calcium, and magnesium. This helps in understanding scaling potential and water treatment requirements.
Compatibility Tests: Assess the compatibility of the formation water with injected fluids (e.g., in waterflooding operations) to prevent formation damage.
Overall Significance:
The tests conducted on oil and formation water during production testing provide critical information for:
Optimizing Production: Adjusting production parameters to maximize recovery and minimize operational issues.
Designing Surface Facilities: Selecting appropriate equipment and processes for handling and treating produced fluids.
Ensuring Safety: Identifying and mitigating potential hazards associated with the produced fluids.
Protecting the Environment: Minimizing the environmental impact of oil and gas operations.
By conducting these tests and analyzing the results, the wellsite geologist and engineering team can make informed decisions to ensure safe, efficient, and environmentally responsible production.
2.3 Post-Test Activities
Sample Handling and Shipping: Ensure proper handling, labelling, and shipping of samples to the laboratory.
Data Compilation and Reporting: Compile all data and observations into a comprehensive well test report.
Contributing to Data Analysis: Collaborate with reservoir engineers in interpreting the test data.
Q. What specific tests are conducted on oil and formation water during production testing, and why is this information important for production optimisation and facility design?
Ans. Oil tests include API gravity, BS&W, viscosity, pour point, and flash point. Formation water tests include salinity, pH, and ion chromatography. These tests help optimize production, design surface facilities, ensure safety, and protect the environment.
Q. How do you ensure the quality and representativeness of fluid samples collected during production testing, and what are the potential consequences of sample contamination?
Ans. Sample contamination can lead to inaccurate fluid analysis and incorrect decisions. The geologist must use proper sampling techniques, appropriate containers, and careful labeling to prevent contamination.
Q. What are the key parameters monitored during production testing, and how is this data used to assess reservoir characteristics and well performance?
Ans. Key parameters include flow rates, pressures, and temperatures under varying conditions. This data is used to estimate reservoir properties like permeability, fault, boundary and identify potential issues like skin damage or near-wellbore problems.
Q. How do you integrate well test data with other geological information (logs, cuttings, core data) to build a comprehensive understanding of the reservoir?
Ans. By combining well test data with other geological information, a more complete picture of the reservoir emerges. For example, if logs show good porosity and the well test confirms this with high flow rates, it indicates a productive reservoir.
Q. 160 What are some of the challenges and pitfalls a wellsite geologist might encounter during production testing, and how can these be mitigated?
Ans.Challenges include ensuring data quality, managing time constraints, effective communication, and maintaining safety. These can be mitigated through careful planning, attention to detail, and clear communication.
Q. What are the essential components of a well test report, and how should this information be communicated to the team in town?
Ans.The report should include well information, geological summary, test data, fluid descriptions, observations, interpretations, and recommendations. This should be communicated clearly and promptly to aid in decision-making.
Notes:
The wellsite geologist’s report is a crucial document providing valuable information for decision-making. It should include:
Well Information: Well name, location, and objectives of the test.
Geological Summary: Formation tops, lithology, and any significant geological features encountered.
Test Data: Flow rates, pressures, temperatures, and other relevant data.
Fluid Descriptions: Detailed descriptions of oil, gas, and water samples.
Gas Analysis: Results of gas chromatography analysis.
Observations and Interpretations: The geologist’s interpretations of the data and their implications for reservoir characterization and production potential.
Recommendations: Suggestions for future testing or production strategies.
Q. How can a wellsite geologist contribute to optimizing production strategies and maximizing the value of hydrocarbon resources based on the results of production testing?
Ans. By providing accurate and timely information on reservoir characteristics, fluid properties, and well performance, the wellsite geologist helps in making informed decisions about production strategies, completion methods, and facility design, ultimately maximizing hydrocarbon recovery.
Q. What are important reservoir engineering concepts that an operations geologist must be aware of?
Ans. Here are 10 fundamental topics that are crucial for senior wellsite and operations geologists, along with explanations and their importance:
1. VolumetricsDeals with: Estimating the original hydrocarbons in place (OHIP) within a reservoir. This involves determining the reservoir’s gross rock volume, net-to-gross ratio, porosity, hydrocarbon saturation, and formation volume factors.
Importance: Accurate volumetrics are the foundation of reserve estimation and field development planning. As a senior geologist, you’ll be heavily involved in providing the geological inputs (like net-to-gross and porosity) for these calculations.
{Reserves Estimation: Estimating hydrocarbon volumes: Determining the amount of oil and gas that can be recovered from the reservoir (original oil in place – OOIP, and recoverable reserves). This involves volumetric calculations and material balance analysis.
Classifying reserves: Categorizing reserves based on their certainty (proven, probable, possible) according to industry standards (e.g., SPE PRMS).}
2. Material Balance Deals with: Understanding the dynamic behavior of the reservoir by analyzing pressure changes and production data over time. It helps in determining drive mechanisms (e.g., water drive, gas cap drive) and predicting future reservoir performance.
Importance: Helps you anticipate production trends, identify potential problems like water breakthrough, and optimize production strategies.
{Material balance: Grasp the basic principles of material balance and how it’s used to analyze reservoir performance and predict future behavior.}
3. Drive Mechanisms Deals with: The natural energy sources within a reservoir that drive hydrocarbons to the surface. These include water drive, gas cap drive, solution gas drive, and gravity drainage.
Importance: Knowing the dominant drive mechanism helps predict reservoir behavior, recovery factors, and the most effective production methods.
4. Fluid Properties Deals with: Understanding the physical and chemical properties of reservoir fluids (oil, gas, and water), such as density, viscosity, compressibility, and phase behavior.
Importance: These properties influence fluid flow in the reservoir and through the wellbore, impacting production rates and well design.
5. Relative Permeability Deals with: Describes the ability of multiple fluids (oil, gas, water) to flow simultaneously through the reservoir rock.
Importance: Essential for understanding multiphase flow, predicting water or gas breakthrough, and optimizing production strategies.
6. Well Testing Deals with: Analyzing pressure and flow rate data acquired during well tests to determine reservoir properties (permeability, skin factor, reservoir pressure) and assess well performance.
Importance: Provides critical information for reservoir characterization, production forecasting, and well completion optimization. You’ll often be involved in planning and supervising well tests.
7. Decline Curve Analysis Deals with: Analyzing historical production data to forecast future production rates and estimate ultimate recovery.
Importance: Aids in production planning, reserve estimation, and economic evaluation of the field.
8. Enhanced Oil Recovery (EOR) Deals with: Techniques used to increase oil recovery beyond primary and secondary methods. These include gas injection, waterflooding, chemical flooding, and thermal recovery.
Importance: As fields mature, understanding EOR options becomes crucial for maximizing recovery and extending field life.
9. Reservoir Simulation Deals with: Building numerical models of the reservoir to simulate fluid flow and predict reservoir performance under various operating conditions.
Importance: A powerful tool for evaluating development scenarios, optimizing well placement and production strategies, and assessing the impact of EOR methods.
10. Formation Damage Deals with: Impairment of reservoir permeability near the wellbore due to drilling fluids, completion fluids, or fines migration, reducing production rates.
Importance: Understanding the causes and prevention of formation damage is crucial for optimizing well productivity. You’ll play a key role in selecting drilling and completion fluids to minimize formation damage.
By having a good understanding of these reservoir engineering concepts, operations geologists will be better equipped to Communicate effectively with reservoir engineers as well as understand the issues being discussed in the office.
Q. What is PVT Analysis? What is its significance?
Ans. PVT Analysis is performed in laboratory to measure the properties of reservoir fluids at different pressures and temperatures. By applying the data to various mathematical models that predict the behaviour of fluids under different conditions, reservoir engineers can understand phase behaviour, and can optimize production strategies, design efficient facilities, and maximize the recovery of hydrocarbons from a reservoir.
Additional notes:
Phase behaviour, in the context of reservoir engineering, refers to how the different fluids (oil, gas, and water) present in a reservoir rock behave and interact with each other under varying conditions of pressure and temperature. PVT analysis help us understand how fluid exist in various phases (liquid gas or a mix) and how their properties change within the reservoir.
Here’s why understanding phase behaviour is crucial in reservoir engineering:
Fluid Characterization: Knowing the phase behaviour helps us understand the composition of the reservoir fluids, including the types of hydrocarbons present and their relative amounts. This is essential for predicting how the reservoir will perform.
Production Forecasting: Phase behavior influences how much oil and gas can be recovered from a reservoir. As pressure and temperature change during production, the phases can change, impacting fluid flow and ultimately the recovery factor.
Facilities Design: Designing surface facilities like separators and pipelines requires knowledge of the phase behavior of the produced fluids. This ensures efficient separation and transportation of oil, gas, and water.
Enhanced Oil Recovery: Techniques like gas injection rely heavily on understanding phase behavior. Injecting gas can change the properties of the oil, making it easier to recover.
Key Concepts in Phase Behavior:
Phase Diagrams: These diagrams visually represent the phases present at different pressure and temperature conditions. They help predict how the fluid will behave as it moves from the reservoir to the surface.
Saturation Pressure: This refers to the pressure at which a liquid starts to vaporize (bubble point) or a gas starts to condense (dew point).
Critical Point: The point where the liquid and gas phases become indistinguishable.
Retrograde Condensation: A phenomenon where liquid hydrocarbons condense out of gas as pressure decreases, which can happen in certain gas condensate reservoirs.
Tools for Studying Phase Behavior:
What are the primary reservoir drive mechanisms, and how do they influence production strategies?
Answer: The main drive mechanisms are water drive, gas cap drive, solution gas drive, and gravity drainage. Each mechanism impacts production decline rates, ultimate recovery, and the types of artificial lift or enhanced oil recovery methods that might be suitable.
How do you estimate the original oil in place (OOIP) in a reservoir, and what geological factors are critical in this calculation?
Ans: OOIP is estimated using the volumetric equation: OOIP = (Area x Thickness x Net-to-Gross x Porosity x Oil Saturation) / Formation Volume Factor. Accurate geological mapping, core analysis, and log interpretation are crucial for determining net-to-gross, porosity, and saturation.
Explain the concept of relative permeability and its importance in understanding multi-phase flow in a reservoir?
Ans: Relative permeability describes the ability of different fluids (oil, gas, water) to flow simultaneously through the reservoir rock. It helps predict water or gas breakthrough, optimize production rates, and design appropriate well completions.
Q. What are the key objectives of a well test, and how do you use the data obtained to characterize reservoir properties?
Ans: Well tests help determine reservoir properties like permeability, skin factor, and reservoir pressure. Pressure and flow rate data are analyzed using techniques like pressure transient analysis to estimate these parameters and assess well performance.
Q. What do you understand by Skin Factor?
Ans. It’s a dimensionless number that represents the resistance to fluid flow near the wellbore. A positive skin means there’s extra resistance (like that milkshake gunk), while a negative skin means flow is enhanced.
Causes: It can be caused by things like:
1. Drilling mud or cement invading the rock pores.
2. Fine particles clogging the spaces near the wellbore.
3. Damage to the rock formation during drilling.
Impact: Skin affects how easily oil and gas can flow into the well, impacting production rates.
Additional notes: As one hears a lot about skin factor during production testing, here are a few more notes:
If the calculations show negative skin number, it means the perforated area around bore hole is in good shape and production is increasingly unhindered with increasingly negative skin number. On the other hand a positive skin shows damaged or partially blocked reservoir area at perforation point. Read more…
Good Skin (Negative Skin)
Skin Factor: Less than 0 (e.g., -1, -2, -5)
What it means: Flow is enhanced near the wellbore. This can happen due to stimulation treatments that create fractures or improve permeability.
Impact: Higher production rates than expected for the reservoir.
Neutral Skin
Skin Factor: Around 0
What it means: No significant resistance or enhancement to flow near the wellbore.
Impact: Production is as expected for the reservoir’s natural properties.
Slightly Impaired Skin
Skin Factor: 0 to 5
What it means: Some minor damage or resistance to flow near the wellbore.
Impact: Slightly reduced production rates. May not require immediate intervention.
Moderately Impaired Skin
Skin Factor: 5 to 10
What it means: Noticeable damage or resistance to flow.
Impact: Production is significantly impacted. Intervention (like acidizing or fracturing) might be considered to improve flow.
Severely Impaired Skin
Skin Factor: Greater than 10 (e.g., 15, 20, 50)
What it means: Major damage or blockage near the wellbore.
Impact: Production is severely restricted. Intervention is likely necessary to restore flow.
Important Notes:
These are general guidelines. The “badness” of a skin factor also depends on the reservoir’s overall permeability. A skin of 5 might be a bigger problem in a low-permeability reservoir than in a high-permeability one.
Skin can change over time due to factors like scale deposition or fines migration. Regular well monitoring is important to track skin and plan interventions if needed.
By understanding skin factor, you can better assess well performance and contribute to decisions about well stimulation or remediation.
Q170. How do you interpret production decline curves, and what insights can you gain from them regarding reservoir performance?
Answer: Decline curve analysis involves plotting production rates over time and fitting them to different decline curve models (exponential, hyperbolic, harmonic). This helps forecast future production, estimate ultimate recovery, and identify potential changes in reservoir conditions.
Q. What are the common causes of formation damage, and how can they be mitigated during drilling and completion operations?
Answer: Formation damage can be caused by drilling fluid invasion, fines migration, or scale deposition. Mitigation strategies include using appropriate drilling and completion fluids, optimizing drilling parameters, and employing formation damage prevention techniques.
Q. Describe your experience with different Enhanced Oil Recovery (EOR) methods, and how do you assess their suitability for a specific reservoir?
Answer: (The geologist should describe their experience with methods like waterflooding, gas injection, or chemical flooding. They should also discuss factors like reservoir properties, oil viscosity, and economic considerations when evaluating EOR feasibility.)
Q. What do you know about cased hole completion? How do you compare it with open hole completion?
Cased hole completion is a well completion method where the wellbore is lined with steel casing and cemented before production. This process involves:
Running Casing: Lowering steel casing into the drilled wellbore for structural support.
Cementing: Pumping cement into the space between the casing and wellbore to secure the casing and isolate formations.
Well Logging: Evaluating the cement bond and identifying potential production zones.
Perforation: Using shaped charges to create holes in the casing and cement, allowing fluid flow.
Production Tubing Installation: Placing tubing inside the casing for hydrocarbon flow to the surface.
Well Testing and Production: Testing well performance and then initiating production.
Advantages: Wellbore stability, zonal isolation, perforation flexibility, enhanced safety, and long-term durability.
Disadvantages: Higher costs, reduced formation access compared to open hole completions, and potential damage during perforation.
Q. What do you know about Gas Oil Ratio (GOR)
Ans. GOR is a key parameter in reservoir engineering, indicating the amount of gas associated with each barrel of oil in a reservoir.
Additional Notes:
Types of GOR
1. Solution GOR
Solution GOR, also known as dissolved GOR, refers to the amount of gas dissolved in crude oil at reservoir conditions. When pressure drops below the bubble-point pressure during production, gas starts to come out of the solution, altering the reservoir’s fluid dynamics.
2. Producing GOR
This represents the GOR measured at the surface during production. It accounts for the total gas and oil produced and often changes over time due to reservoir depletion or production adjustments.
Significance of GOR
1. Reservoir Characterization
GOR helps identify fluid types within the reservoir, such as black oil, volatile oil, or gas condensate. For instance:
Low GOR (< 1,000 scf/STB): Typically indicates black oil reservoirs.
Medium GOR (1,000–5,000 scf/STB): Indicates volatile oil reservoirs.
High GOR (> 5,000 scf/STB): Often signifies gas condensate reservoirs.
scf: Stands for “standard cubic feet”. It’s a unit of volume for natural gas, standardized to a specific temperature and pressure.
STB: Stands for “stock tank barrel”. It’s a unit of volume for crude oil, specifically the volume the oil occupies after being separated from gas and water at surface conditions.
2. Production Optimization
Monitoring GOR aids in evaluating reservoir performance and designing optimal production strategies. An increasing GOR can indicate gas breakthrough, reservoir depletion, or coning issues.
3. Well Performance Monitoring
Variations in GOR provide insights into production anomalies, such as water or gas channeling, and help guide remedial actions.
Factors Influencing GOR
1. Reservoir Pressure and Temperature
GOR is highly sensitive to pressure and temperature conditions. As pressure declines during production, gas may evolve from the liquid phase, leading to an increase in GOR.
2. Reservoir Drive Mechanisms
Solution gas drive reservoirs exhibit a rapidly increasing GOR as pressure drops.
Water drive reservoirs may maintain a more stable GOR due to pressure support.
3. Completion and Production Techniques
Inappropriate well completions or excessive drawdown can lead to gas or water coning, altering the GOR.
Applications of GOR
1. Reservoir Simulation and Forecasting
GOR data is a key input in reservoir simulation models, aiding in production forecasting and economic evaluation.
2. Enhanced Oil Recovery (EOR) Decisions
A stable or declining GOR may suggest the reservoir has not yet reached its full depletion, while an increasing GOR might indicate the need for EOR techniques, such as gas injection.
3. Field Development Planning
GOR influences the selection of surface facilities, such as separators, compressors, and pipelines, ensuring they can handle the expected gas and oil production volumes.
Q.
Q. What is the impact of clay minerals on reservoir permeability?
Permeability is a measure of a rock’s ability to transmit fluids through its pore spaces. It is a key property determining how easily oil, gas, or water can flow within a reservoir.
How Clay Minerals Affect Permeability
1. Reduction in Pore Size and Connectivity
Clay minerals often form within the pore spaces or coat the grain surfaces of reservoir rocks. Their presence reduces the effective pore size and interrupts connectivity between pores, limiting fluid flow.
Swelling clays like smectite expand in the presence of water, further decreasing pore space and permeability.
2. Clay Distribution and Morphology
Pore-lining clays: These form thin coatings around grains and have a moderate impact on permeability.
Pore-filling clays: These occupy pore spaces and can severely restrict permeability.
Dispersed clays: These fine particles can migrate during production, plugging pore throats and reducing permeability over time.
3. Chemical Interactions
Clay minerals interact with drilling and formation fluids, causing swelling, dispersion, or flocculation, all of which exacerbate permeability loss.
High cation exchange capacity (CEC) clays like smectite are particularly reactive, making fluid management critical in reservoirs with significant clay content.
Challenges in Clay-Rich Reservoirs
Formation Damage: Drilling and completion activities can mobilize clays, leading to blockages in pore throats.
Water Sensitivity: The influx of water during production or enhanced recovery operations can activate swelling or migrating clays.
Compaction and Diagenesis: Under burial conditions, clays may recrystallize or compact, further reducing pore space.
Managing Clay-Related Permeability Challenges
1. Reservoir Characterization
Use advanced logging tools (e.g., spectral gamma-ray logs) and core analysis to identify clay types and distribution.
Apply X-ray diffraction (XRD) and scanning electron microscopy (SEM) to quantify and visualize clay content.
2. Optimized Drilling and Completion Fluids
Design fluid systems that minimize interaction with reactive clays (e.g., using potassium-based or oil-based muds).
Incorporate clay stabilizers to prevent swelling or dispersion.
3. Stimulation Techniques
Hydraulic fracturing can bypass low-permeability zones by creating new flow paths.
Acidizing treatments may dissolve clays in certain reservoirs, although care must be taken to avoid secondary precipitation.
4. Enhanced Recovery Strategies
Use tailored water injection systems (e.g., low-salinity water) to minimize adverse interactions with clay minerals.
Q.
Q. How do you integrate geological data with reservoir engineering data to optimize well placement and completion strategies?
Answer: Geological data (structural maps, facies models, fault interpretations) helps identify sweet spots and potential drilling hazards. Integrating this with reservoir engineering data (pressure data, permeability maps) allows for optimal well placement and completion design to maximize productivity.
Q. How do you contribute to reservoir simulation studies, and how do you use the results to informed field development decisions?
Answer: Geologists provide critical inputs for reservoir simulation models, such as geological structure, rock properties, and fluid distributions. Simulation results help evaluate different development scenarios, optimize well placement and production strategies, and assess the impact of EOR methods
Q. What is Pressure Transient Analysis? What is its Significance?
Ans. Think of it like this: you throw a pebble into a still pond, and ripples spread out. By analyzing the energy of ripples (amplitude and wavelength), you can learn about the pond’s size and depth. Pressure transient analysis is similar! Here, pressure and flow rate data are analyzed using special software to estimate these parameters and assess well performance.
It involves analyzing pressure changes in a well over time after a disturbance (like starting or stopping production). This “disturbance” creates a pressure “ripple” that travels through the reservoir.
How it works: Engineers use specialized software to plot pressure data and match it to theoretical models. This helps them estimate reservoir properties like:
Permeability: How easily fluids flow through the rock.
Skin factor: The resistance near the wellbore (our “gunk” example).
Reservoir pressure: The average pressure in the formation.
Boundaries: The presence of nearby faults or aquifers.
Why it’s important: It helps understand reservoir behavior, optimize well performance, and make informed decisions about field development.
So, by analyzing the pressure “ripples” from well tests, engineers can get a clearer picture of what’s happening deep underground and make sure the well is producing as efficiently as possible.
MWD / LWD LOGGING
Q. What is difference between MWD and LWD loggings?
ANS. While both MWD (Measurement While Drilling) and LWD (Logging While Drilling) tools are closely interlinked and run together they have different functionalities:
MWD (Measurement While Drilling)
Primary Function: Focuses primarily on directional drilling and providing real-time data for wellbore placement.
Data Types:
1. Directional data: Inclination, azimuth, and toolface.
2. Drilling mechanics data: Weight on bit, torque, and bottom hole pressure (ECD).
3. Basic formation evaluation data: May include gamma ray measurements.
Data Transmission: Typically relies on mud pulse telemetry, transmitting data in real-time as the well is drilled.
Applications:
1. Real Time Data Transmission
2. Geosteering.
LWD (Logging While Drilling)
Primary Function: Focuses on formation evaluation and providing detailed information about the subsurface geology.
Data Types:
Detailed formation evaluation data: Resistivity, density, neutron porosity, sonic velocity.
Advanced measurements: Nuclear magnetic resonance (NMR), formation pressure testing, and borehole imaging….not commonly used.
Data Transmission: Data is stored within the tool and retrieved when the tool is brought back to the surface.
Applications:
1. Lithology identification and correlation.
2. Reservoir characterization.
3. Pore pressure and fracture gradient estimation.
4. Fluid identification and analysis.
5. Geomechanical analysis
Q180. How do you compare between LWD and wireline logging?
Ans. Logging While Drilling (LWD) and Wireline logging are both crucial techniques for acquiring subsurface data in the oil and gas industry. While LWD has seen rapid advancements, leading to solutions for critical drilling challenges and improved safety, cost-effectiveness, and indirectly, production, it hasn’t completely replaced wireline logging. The decision to use LWD, wireline, or a combination of both depends on various technical and economic factors.
Both LWD and wireline logging can provide measurements for: Gamma ray, induction resistivity, laterolog resistivity, density, neutron porosity, spectroscopy, caliper, borehole images, acoustic velocity, Vertical Seismic Profiling (VSP), Nuclear Magnetic Resonance (NMR), pressure sampling, fluid sampling, well placement, permeability, fluid typing, and sigma.
Here’s a detailed comparison of their advantages and disadvantages:
Advantages:
1. Logging While Drilling (LWD):
Early Data Acquisition: Data is acquired shortly after the drill bit passes, minimizing mud invasion effects and providing a more accurate representation of formation properties.
Real-Time Decision Making: Crucial for geological decisions during drilling, allowing for adjustments to well trajectory and drilling parameters.
Challenging Environments: More suitable for deviated, horizontal, and unstable boreholes where wireline logging can be difficult or impossible.
Precise Well Placement: Enables accurate geosteering and well placement optimization.
Reduced Non-Productive Time (NPT): By acquiring data while drilling, it reduces the need for dedicated logging runs, saving rig time and cost.
2. Wireline Logging:
Tool Versatility and Precision: Smaller, lighter, and more delicate tools allow for a wider range of specialized measurements and potentially more precise data acquisition in certain applications.
Accurate Depth Measurement: Wireline logging typically offers highly accurate depth measurements.
High Data Transmission Rates: The use of a cable enables high data speeds, facilitating the transmission of large volumes of data.
Excellent Borehole Contact: Wireline tools often achieve better borehole contact, potentially leading to improved data quality in certain situations.
Continuous Power and Communication: The cable provides continuous power and two-way communication with the tools, allowing for real-time adjustments and control.
Cased Hole Logging: Essential for evaluating formations and reservoir properties in cased holes, which is not readily achievable with LWD.
Cost-Effective in Specific Scenarios: While LWD can be more cost-effective overall by reducing NPT, wireline logging might be cheaper for simpler, vertical wells with stable boreholes.
Disadvantages:
1. Logging While Drilling (LWD):
Tool Size and Handling: Larger, heavier, and more robust tools require specialized handling equipment and can be more challenging to deploy.
Data Transmission Limitations: Data transmission rates can be limited by mud pulse telemetry, particularly in challenging drilling conditions.
Limited Real-Time Control: While some LWD systems offer limited two-way communication, the degree of control is less than with wireline logging. Most operations are pre-programmed.
Power Source: LWD tools typically rely on batteries or mud turbines for power, which can be less reliable than the continuous power supplied by a wireline cable.
Vibrations and Stick-Slip: LWD tools are subject to vibrations, stick-slip, and other drilling dynamics, which can affect data quality and tool reliability.
Higher Initial Cost: LWD services often have a higher initial cost compared to wireline logging.
2. Wireline Logging:
Time Consumption: Requires a dedicated logging run after drilling is completed, adding to rig time and cost.
Delayed Data Acquisition: Measurements are taken after drilling, potentially after significant mud invasion has occurred, affecting the accuracy of some measurements.
Limited Coverage: Wireline tools don’t rotate like LWD tools, potentially limiting the circumferential coverage of the wellbore.
Challenging Deviated Wells: Running wireline tools in highly deviated or horizontal wells can be difficult and risky, requiring specialized equipment and procedures.
Susceptibility to Hole Conditions: Poor hole conditions (e.g., washouts, tight spots) can hinder wireline operations and compromise data quality.
Conclusion:
The choice between LWD and wireline logging is not a simple one. It depends on a complex interplay of factors, including:
Well type and trajectory: (vertical, deviated, horizontal)
Expected borehole conditions: (stable, unstable, fractured)
Data requirements: (specific measurements needed)
Cost considerations: (balancing initial cost with overall time savings)
Operational risks: (potential for stuck tools, lost time)
While LWD offers significant advantages in specific situations, it is unlikely to completely replace wireline logging in the near future. Often, a combined approach, utilizing both LWD and wireline, provides the most comprehensive and cost-effective solution. LWD can provide critical real-time data during drilling, while wireline logging can be used to acquire more detailed and specialized measurements after the well has been drilled. The optimal strategy is to carefully evaluate the specific requirements of each well and choose the logging methods that best meet those needs.
Q. What is difference between the same logs recorded by LWD and Wireline in terms of log quality, measurement methods and tools?
Ans. LWD and wireline logging provide similar measurements of good quality. The data acquired by both methods leads to similar interpretations and results. However, there are differences in data density, data transmission methods, and tools that may decide which method to choose on a particular well.
Log Quality:
LWD:Pros: Less borehole disturbance on log quality due to measurements being taken shortly after drilling. Reduced invasion of drilling fluids into the formation. Potentially better data quality in unstable formations.
Realtime LWD logs can help in correlation and calculating net pay on the go; thus helping in taking timely decisions.
Cons: Can be affected by drilling vibrations and sometime by mud properties. Real-time data may have lower resolution or missing data due to telemetry limitations.
Wireline:
Pros: Higher resolution data at fast logging speeds and higher data density. More sophisticated tools with advanced measurement capabilities.
Cons: More susceptible to borehole rugosity and fluid invasion. Can be challenging to deploy in highly deviated or unstable wells.
Tools being sophisticated and being run on wireline encounter problems in running in tight hole section and get held up by hole bridge
If tool gets stuck only limited amount of pull can be applied to free it which may not always be sufficient.
Measurement Methods:
LWD:Measurements are taken “while drilling,” with sensors integrated into the drill string.
Data is transmitted to the surface in real-time (with some limitations) or stored in tool memory.
Wireline:Measurements are taken after drilling is complete, with tools lowered into the wellbore on a wireline cable.
Data is transmitted continuously to the surface via the wireline.
Tools and Technologies:
LWD:Tools are designed to withstand harsh downhole conditions (temperature, pressure, vibration).
Typically more rugged and compact than wireline tools.
Offer a range of measurements, including gamma ray, resistivity, density, neutron porosity, sonic, and imaging.
Wireline:Wider variety of specialized tools available for specific measurements (e.g., formation testing, NMR, spectral gamma ray).
Can include more sophisticated sensors and technologies for higher resolution and accuracy.
Q. What are the factors that affect selection of logging method between LWD and Wireline logging?
Ans. Choosing between Logging While Drilling (LWD) and Wireline logging depends on several key factors:
1. Real-time Needs:
LWD: Provides real-time data crucial for making immediate drilling decisions, like steering the well (geosteering), and evaluating formation properties as drilling progresses.
Wireline: Data is acquired after drilling of a section is complete, making it less suitable for time-sensitive decisions during drilling.
2. Formation Evaluation Objectives:
LWD: Offers measurements focused on essential properties for drilling optimization and initial formation evaluation.
Wireline: Provides a wider range of measurements and more detailed analysis for comprehensive reservoir characterization.
3. Wellbore Conditions:
LWD: Better suited for challenging wellbores (e.g., high-angle, horizontal) where wireline access is difficult or risky.
Wireline: May be preferred in stable, vertical wells where tool conveyance is straightforward.
4. Operational Efficiency and Cost:
LWD: Can improve efficiency by acquiring data while drilling, potentially reducing rig time and overall costs.
Wireline: Requires dedicated logging runs, which can add to operational time and expenses.
5. Data Accuracy and Resolution:
LWD: Data can be affected by drilling conditions and may have lower resolution compared to wireline.
Wireline: Generally offers higher resolution data due to more controlled logging environment and advanced tools.
In summary:
Choose LWD when real-time data, challenging wellbores, or operational efficiency are paramount.
Choose Wireline for comprehensive formation evaluation, higher data resolution, and when detailed analysis is crucial.
Often, a combination of LWD and Wireline logging is used to leverage the strengths of both methods. LWD provides critical real-time information during drilling, while Wireline logging offers more detailed insights for subsequent reservoir characterization and management decisions.
Q. What are different types of telemetry methods used in MWD/LWD logging. Please tell their advantages and disadvantages?
Ans. MWD and LWD tools rely on telemetry systems to transmit valuable data from the downhole environment to the surface for real-time monitoring and analysis. Here are the main types of telemetry used in these tools:
1. Mud Pulse Telemetry:
Mechanism: Encodes data into pressure pulses within the drilling mud. These pulses are generated by a valve in the tool that modulates mud flow, creating pressure fluctuations that travel up the mud column to the surface.
Advantages:
Well-established and reliable technology.
Relatively low cost compared to other methods.
Can transmit data while drilling.
Disadvantages:
Limited data transmission rate.
Susceptible to noise from mud circulation and borehole conditions.
2. Electromagnetic Telemetry:
Mechanism: Transmits data through the formation using electromagnetic waves. The tool generates a signal that propagates through the rock and is picked up by receivers at the surface.
Advantages:
Higher data transmission rates than mud pulse.
Less affected by mud properties and borehole conditions.
Can transmit data through casing.
Disadvantages:
More expensive than mud pulse telemetry.
Signal attenuation can be a challenge in certain formations.
Requires specialized equipment and expertise.
Some companies also use special drill pipe to transmit signals; while still other use acoustic signals to transmit data. These methods have their advantages and disadvantages but they are not commonly in use.
Q. Where do MWD telemetry mud pluses travel, inside the drill pipe or through the annulus?
Ans. MWD telemetry mud pulses travel inside the drill pipe.
Here’s how it works:
Downhole: The MWD tool generates pressure pulses in the drilling mud by restricting the mud flow.
Drill pipe: These pressure pulses propagate up the drill string inside the drill pipe.
Surface: Sensors at the surface detect these pressure fluctuations.
Decoding: The pressure variations are decoded into data that provides information about the well’s direction, inclination, and GR, Res, Neutron, Density, Sonic data.
Why inside the drill pipe?
Less attenuation: Pressure pulses are less likely to be distorted or weakened within the confined space of the drill pipe.
Noise reduction: The drill pipe helps to shield the signals from external noise in the annulus, which can interfere with data transmission.
Controlled environment: The mud flow within the drill pipe is more controlled, ensuring more reliable signal transmission.
Q. What are the common problems encountered with MWD / LWD tools that can hamper drilling progress? What can a wellsite geologist do to void or mitigate such problems?
Ans.MWD/LWD tools are essential for modern drilling operations, but they can encounter problems that hamper progress. Here’s a breakdown of common issues and how to avoid or handle them:
1. Tool Failure: Electronics, sensors, or mechanical components can fail due to harsh downhole conditions (temperature, pressure, vibration). Therefore wellsite geologist should ensure that a contingency plan exists in place.
2. Battery Problems: Limited battery life, temperature sensitivity, and damage from shock/vibration can lead to power loss. Ensure engineers do not run half used batteries. Always insist on new batteries.
3. Signal Loss or Interference: Data transmission can be disrupted by mud properties, borehole conditions, or electrical interference.
4. Sticking: Tools can get stuck in the borehole due to friction, borehole instability, or improper drilling practices. To avoid or reduce the chances of getting stuck:
Optimize drilling parameters (WOB, RPM).
Use appropriate drilling fluids and mud weight.
Implement proper hole cleaning procedures.
5. Depth Control Issues: Inaccurate depth measurements can lead to misinterpretation of data and incorrect wellbore placement. Ensure drawworks sensor is properly calibrated. Double check depth against known geological markers.
6. Data Quality: Data can be affected by noise, vibration, or environmental factors, leading to inaccurate readings. Advisable to use optimized drilling parameters and use tools with environmental correction
7. Magnetic Interference: Magnetic interference from nearby steel components or formations can affect tool measurements, particularly directional data. To avoid:
Use non-magnetic drill collars near the MWD tool.
Apply magnetic correction algorithms to the data.
Consider alternative directional measurement technologies.
Q. Why do MWD Tools sometimes lose signal?
Ans. MWD tools in drilling operations can lose signal when tagging bottom due to:
Signal attenuation: Environmental factors weaken the signal.Vibrations and shocks: Physical forces disrupt the tool’s electronics.
Borehole conditions: Pressure and mud weight affect signal stability. Metal-to-metal contact: Interference from bit-formation contact disrupts transmission.
Understanding these causes helps mitigate risks and maintain communication.
Q. What are the issues that you have encountered with regard to data density in LWD logging? How do you manage these issues?
Ans. Data density in LWD logging refers to the amount of data acquired per foot or per meter of the borehole. While high data density is generally desirable for detailed formation evaluation, several issues can arise:
1. Data Transmission Bottlenecks:
Challenge: Transmitting large volumes of high-density data in real-time can strain telemetry systems, especially with mud-pulse technology. This can lead to lags, data compression artifacts, and even data loss.
Suggestions:
Ask LWD engineer to optimise data compression techniques.
Prioritize essential measurements for real-time transmission.
Utilize high-speed telemetry systems (e.g., electromagnetic telemetry).
Store high-density data in tool memory for later retrieval.
2. Storage Limitations:
Challenge: LWD tools have limited memory capacity for storing high-density data. This can restrict the logging interval or the number of sensors that can be run simultaneously.
Suggestions:
Optimize data acquisition parameters to balance density with storage capacity.
Utilize tools with larger memory capacity.
Prioritize the most critical measurements for recording.
3. Resolution vs. Depth of Investigation:
Challenge: Increasing data density involves increasing the sampling rate, which can sometimes come at the expense of depth of investigation. This trade-off needs to be considered based on the specific formation evaluation objectives.
Suggestions:
Carefully select logging tools and parameters to balance resolution and depth of investigation.
Utilize multiple sensors with different depths of investigation to obtain a comprehensive understanding of the formation.
6. Data Quality Issues:
Challenge: High-density data acquisition can be more susceptible to noise and other data quality issues, especially in challenging drilling environments.
Suggestions:
Implement quality control measures to ensure data integrity.
Utilize noise reduction techniques in data processing.
Optimize drilling parameters to minimize vibrations and improve data quality.
By carefully considering these data density-related issues and implementing appropriate mitigation strategies, wellsite geologists can effectively utilize LWD technology to obtain valuable formation evaluation data while optimizing operational efficiency and cost-effectiveness.
Q. What are the issues encountered with MWD/LWD tool batteries?
(Please be aware this question was valid in my days….more than 10 years ago, With evolving battery technologies this may not be an issue any more)
Ans. MWD/LWD tools rely on batteries to power their downhole electronics and sensors. These batteries are specially designed to withstand the harsh conditions of high temperatures, high pressures, and shock and vibration. However, they can still present some challenges:
Limited lifespan: Affected by temperature, usage, and tool health.
Temperature sensitivity: High temperatures can reduce performance and lifespan. Requires appropriate battery selection and thermal management.
Shock and vibration: Can damage battery components.
Pressure effects: High pressures can compromise battery integrity.
Battery management: Proper charging, storage, and handling are crucial.
Q190. Now days LWD/MWD companies are replacing tool batteries with other technologies. What are these?
Ans. Technology is constantly evolving, and companies are exploring alternatives to traditional batteries to power their downhole tools. Here are some of the leading techniques:
1. Mud Turbines: (Currently most in use)
How they work: These small turbines are integrated into the LWD/MWD tool and are driven by the flow of drilling mud. They convert the kinetic energy of the mud into electrical energy to power the tool’s electronics.
Advantages: Eliminate the need for batteries, potentially increasing tool lifespan and reducing environmental impact.
Limitations: Power output depends on mud flow rate, which can vary during drilling operations. May not be suitable for all drilling environments.
2. Piezoelectric Generators:
How they work: These devices utilize piezoelectric materials that generate electricity when subjected to mechanical stress or vibration. The vibrations from the drilling process itself can be harnessed to power the tool.
Advantages: Can provide a continuous power source as long as drilling is ongoing. No need for batteries or external power.
Limitations: Technology is still under development and may not be as efficient as other methods. Power output can vary depending on drilling conditions.
3. Wireless Power Transmission:
How it works: Energy is transmitted wirelessly from the surface to the downhole tool using electromagnetic fields or acoustic waves.
Advantages: Eliminates the need for downhole batteries and their associated limitations.
Limitations: Technology is still in its early stages and faces challenges in transmitting power efficiently through long distances and complex geological formations.
4. Hybrid Systems:
How they work: Combine batteries with other power sources, such as mud turbines or piezoelectric generators. This approach provides backup power and extends the operational life of the tool.
Advantages: Offers increased reliability and flexibility. Can optimize power usage depending on drilling conditions.
Limitations: Adds complexity to the tool design and may require more sophisticated power management systems.
These alternative power sources aim to overcome the limitations of traditional batteries, such as limited lifespan, temperature sensitivity, and environmental concerns. As technology advances, we can expect to see wider adoption of these innovative techniques in LWD/MWD operations, leading to more efficient and sustainable drilling practices.
Q. What is meant by stick and slip in MWD/LWD logging? What are its causes and how to mitigate the situation?
Ans. Stick-slip is a damaging phenomenon that can occur during drilling operations, affecting both MWD and LWD tools. It’s characterized by an irregular, jerky motion of the drill string, where the bit / drill string alternately sticks to the borehole wall and then slips forward. This creates harmful vibrations and torque fluctuations that can damage the drilling equipment, including the sensitive electronics in MWD/LWD tools.
Causes of Stick-Slip:
Friction: The primary cause is excessive friction between the drill string and the borehole wall. This friction can be exacerbated by factors such as:
High borehole inclination: Friction increases in deviated or horizontal wells.
Reactive formations: Some formations absorb water and become more prone to sticking.
Insufficient lubrication: Inadequate drilling fluid properties or low flow rates can reduce lubrication.
Drill string design: BHA (Bottom Hole Assembly) design can influence friction.
Torque Fluctuations: Variations in torque applied to the drill string can contribute to stick-slip. These fluctuations can be caused by inconsistent weight-on-bit (WOB) or rotary speed.
Consequences of Stick-Slip:
Damage to MWD/LWD tools: The vibrations and shocks can damage sensors, electronics, and connections, leading to data loss or tool failure.
Drill string damage: Can cause fatigue and wear on drill pipe, BHA components, and the bit.
Reduced drilling efficiency: Stick-slip leads to slower rates of penetration (ROP) and increased drilling time.
Wellbore instability: Can contribute to borehole enlargement, washouts, and other problems.
Suggestions on how to Mitigating Stick-Slip:
Optimize Drilling Parameters:
Reduce WOB: Lowering the weight on bit can decrease friction.
Increase Rotary Speed: Higher RPM can help maintain continuous rotation.
Smooth Torque Application: Maintain consistent drilling parameters and avoid sudden changes.
Improve Drilling Fluid Properties:
Increase Lubricity: Use drilling fluids with high lubricity to reduce friction.
Maintain Sufficient Flow Rate: Ensure adequate circulation to carry cuttings and provide cooling.
BHA Design:
Use Stabilizers: Properly placed stabilizers can reduce contact between the drill string and the borehole wall.
Optimize BHA Length: Shorter BHAs can be less prone to stick-slip.
Advanced Technologies:
Rotary Steerable Systems (RSS): RSS can provide smoother rotation and reduce stick-slip.
Vibration Monitoring and Control Systems: Real-time monitoring and automated control systems can help detect and mitigate stick-slip.
By understanding the causes and consequences of stick-slip and implementing appropriate mitigation strategies, wellsite geologists and drilling engineers can help ensure smoother drilling operations, protect MWD/LWD tools, and improve overall drilling efficiency.
Q. What are the challenges with regard to quality of real time LWD logs that are faced by wellsite geologists and how to tackle them?
Ans. Real-time LWD data is incredibly valuable, but it comes with its own set of challenges. Here are some that wellsite geologists face, along with how to tackle them:
1. Data Quality Affected by Drilling Environment: Drilling mud, borehole rugosity, vibration, and even the rate of penetration can influence LWD readings, particularly those sensitive to borehole conditions (e.g., density, neutron).
Suggestions: Optimize drilling parameters to minimize vibration and ensure good borehole conditions.
2. Limited Data Rates and Resolution: Real-time data transmission can be limited by data rate constraints. This can result in lower resolution and missing part of logs. If this happens, it becomes difficult to use realtime log for correlation and net pay calculation.
Suggestions:
Prioritize the most critical measurements for real-time transmission.
Utilize data compression techniques to maximize data transfer.
Signal Interference and Noise: The transmission environment can introduce noise into the LWD signal, affecting data quality. This is particularly true for mud-pulse telemetry.
Suggestions:
1. Optimize mud properties to improve signal transmission.
2. Ask LWD engineer to employ noise reduction techniques in data processing.
Q. “What are the advantages and disadvantages of real-time logs compared to memory logs acquisition? How do these factors influence your decisions on the rig?”
Ans. Real-time LWD logs allow immediate correlation, identifying a hydrocarbon bearing zones; thus helping in quick decisions. However, realtime logs can be limited by data transmission rates and susceptible to signal noise. Where as memory logs have good resolution and noise free curves but these logs are made available only when the tool is pulled to surface.
Q. What are key elements of reservoir characterisation and modelling?
Ans. Effective reservoir management relies on a comprehensive understanding of rock and fluid properties, achieved through integrated analysis and modeling. This process can be broadly categorized into several key components:
Direct Data Acquisition and Static Modeling:
Core Data Analysis: Provides direct, measured values of rock properties and fluid characteristics through the analysis of core samples.
Geological Modeling: Constructs a three-dimensional representation of the reservoir’s geological framework, encompassing structural features, stratigraphic layers, and the spatial distribution of rock properties.
Petrophysical Analysis and Modeling:
Petrophysical Modeling: Develops quantitative models of essential rock properties such as porosity, permeability, and capillary pressure.
Rock Typing: Categorizes reservoir rocks into distinct types based on their petrophysical properties, enabling better prediction of reservoir behavior.
Fluid Typing: Classifies reservoir fluids based on their physical properties, facilitating accurate fluid behavior modeling.
Reservoir Engineering and Dynamic Modeling:
Reservoir Simulation: Utilizes numerical models to simulate fluid flow within the reservoir, predicting pressure, fluid saturation, and production rates.
Fluid Properties Analysis: Gathers and analyzes data on the physical properties of reservoir fluids, including density, viscosity, and compressibility.
Well and Production Data Analysis: Compiles and analyzes historical production data, well performance records, and other relevant information to understand reservoir behavior.
History Matching: Refines the reservoir simulation model by adjusting parameters to align with observed historical production data.
Prediction and Forecasting: Leverages the calibrated reservoir model to predict future reservoir performance and production outcomes.
Uncertainty Analysis: Quantifies the uncertainties associated with reservoir predictions through sensitivity analyses and probabilistic methods.
Q. What is your experience with advanced LWD technologies, such as borehole imaging, NMR, and formation pressure testing?
Ans. Borehole images help wellsite geologists see fractures and small-scale geological features. NMR independently tells us pore size distribution and fluid typing (nature of fluid…whether oil, gas or water), while formation pressure testing allows for direct measurement of reservoir pressure and fluid sampling. These technologies have significantly helped wellsite geologists to confidently identify and characterise reservoirs on the rig itself.
Assorted Questions
Q. What is your understanding on hole balooning?
Ans. Ballooning, also known as “Wellbore Breathing,” “Supercharging,” or “Micro-fracturing,” describes a complex pressure-related phenomenon often encountered in challenging drilling environments such as deep wells, High-Pressure/High-Temperature (HPHT) wells, and low-permeability formations like shale. It arises from the elastic (and sometimes plastic) deformation of the wellbore due to pressure variations during drilling operations.
During drilling, the wellbore pressure, maintained by the drilling mud column, is carefully controlled within a narrow margin—above the formation’s pore pressure to prevent influx and below the fracture pressure to avoid formation damage. This pressure range is termed the “drilling window” or “mud window.” HPHT wells are particularly susceptible to ballooning due to their characteristically narrow drilling windows, making pressure management extremely critical.
The Equivalent Circulating Density (ECD), which represents the effective density of the drilling mud including the effects of annular friction and cuttings transport, can exceed the formation’s fracture gradient during active circulation. This can lead to a situation where the formation, especially in low-permeability environments, experiences a “micro-fracturing” or “dilation” effect. The formation effectively “balloons” or expands slightly to accommodate the increased pressure, absorbing a portion of the drilling fluid. This fluid loss, although often small, can be significant.
When circulation ceases (pumps are turned off), the dynamic component of the ECD (annular friction) disappears. The static mud column pressure then drops, potentially falling below the now-slightly-reduced fracture gradient of the “ballooned” formation. This pressure reduction allows the formation to relax, and the previously injected drilling fluid, sometimes mixed with formation fluids, flows back into the wellbore. The volume of this returned fluid may not equal the volume lost, as some fluid may remain trapped in the dilated formation or have migrated further into the formation matrix. This difference can be attributed to several factors including formation compressibility, fluid viscosity, and the extent of formation damage. Furthermore, the returned fluid’s composition can provide valuable insights into the reservoir’s characteristics and potential for formation damage.
The “ballooning” effect can be further compounded by factors like temperature variations, which influence mud density and formation stress. In HPHT wells, these thermal effects are more pronounced, further complicating pressure management and increasing the risk of ballooning. Understanding and accurately predicting ballooning behavior is crucial for safe and efficient drilling operations, requiring sophisticated wellbore stability analysis that considers both the poroelastic properties of the formation and the dynamic behavior of the drilling mud.
Q. What do you understand by wettability? What is its significance in oil recovery?
Ans. The interaction between rock, oil, and water within a reservoir, known as wettability, is a critical factor in determining how much oil can be recovered. Wettability, significantly impacts oil recovery. Reservoir rocks can be water-wet (preferring water flow), oil-wet (preferring oil flow), or neutrally-wet (no preference).
Notes on Wettability:
Optimal oil recovery is fundamentally dependent upon a thorough comprehension of wettability, the critical property that dictates the relative preference of a reservoir rock for either oil or water. Categorizing rocks as water-wet, oil-wet, or neutrally-wet is the first step in unlocking a reservoir’s potential.
Profound Effects of Wettability on Oil Extraction:
Severe Oil Entrapment: In water-wet systems, a significant challenge arises as oil becomes irrevocably trapped within the intricate network of pore spaces, dramatically hindering efficient extraction.
Inefficient Water Invasion: Conversely, oil-wet systems suffer from the detrimental effect of water bypassing valuable oil reserves, resulting in substantially reduced displacement efficiency.
Determining Residual Oil: A Wettability Imperative: The ultimate amount of oil left behind after waterflooding, the residual oil saturation, is not arbitrary; it is a direct consequence of the reservoir’s wettability characteristics.
Wettability’s Control Over Fluid Flow: The relative permeability, the very essence of fluid movement within the reservoir, is meticulously modulated by wettability, acting as a crucial regulator of oil and water flow.
Wettability: A Decisive Factor in Enhanced Oil Recovery (EOR):
Maximizing Waterflooding Efficiency: Waterflooding, a foundational EOR technique, achieves its peak efficiency in water-wet reservoirs, where oil displacement is naturally favored.
Strategic Wettability Alteration with Chemical Flooding: Chemical flooding leverages the power of surfactants to deliberately alter wettability, enabling a targeted approach to significantly boost oil recovery.
Optimizing Miscible Gas Injection: Miscible gas injection, another powerful EOR method, experiences enhanced performance in water-wet environments, facilitating superior gas distribution and oil mobilization.
Q. Describe the key reservoir characteristics of coral reef reservoirs and explain how these characteristics contribute to hydrocarbon accumulation and production.
Ans. Coral reefs can make excellent hydrocarbon reservoirs due to a unique combination of factors. Here are some of the key reservoir characteristics:
High Porosity: As seen in the figures, coral reefs often exhibit high porosity, particularly vuggy porosity, resulting from the original skeletal structure of the corals and subsequent diagenetic processes. This provides ample space for hydrocarbons to accumulate.
Good Permeability: The interconnected network of pores and vugs within the reef framework facilitates good permeability. This allows for efficient fluid flow, which is crucial for hydrocarbon migration and production.
Favorable Lithology: Coral reefs are primarily composed of calcium carbonate, which transforms into limestone over time. Limestone is a well-known reservoir rock with good porosity and permeability characteristics.
Trap Formation: Reefs often form distinct topographic highs that can act as structural traps, preventing the escape of hydrocarbons. The lagoonal setting, with barrier reefs further offshore, can create stratigraphic traps as well.
How these characteristics contribute to hydrocarbon accumulation and production:
Porosity provides the storage space for hydrocarbons within the reservoir. Higher porosity generally equates to greater hydrocarbon storage capacity.
Permeability allows hydrocarbons to migrate through the reservoir and into production wells. Good permeability ensures efficient extraction of hydrocarbons.
Limestone as a reservoir rock provides a stable framework for the reservoir and can maintain its porosity and permeability under reservoir conditions.
Traps are essential for preventing the hydrocarbons from migrating out of the reservoir. Effective traps ensure the accumulation of hydrocarbons over geological time.
In addition to these points, a strong answer might also include:
Discussion of diagenetic processes (e.g., dolomitization, dissolution) that can enhance porosity and permeability in coral reefs.
Mention of potential challenges in coral reef reservoirs, such as heterogeneity and the possibility of low permeability zones.
Reference to specific examples of coral reef reservoirs around the world.
Q. What is the significance of carbon isotope analysis?
Ans. Real-time analysis of carbon isotopes in methane, ethane, and propane (δ13C of C1, C2, and C3) helps wellsite geologists quickly figure out:
Where the gas came from: Was it formed by microbes (biogenic) or from buried organic matter cooked over time (thermogenic)?
How mature the gas is: Is it ready to produce or still needs more cooking time underground?
How the gas moved: Did it migrate through faults or connected reservoirs?
This instant information helps make better decisions on the rig, saving time and money.
Notes:
Real-time isotopic analyses of δ13C of C1, C2, and C3 involve the measurement of carbon isotope ratios in methane (C1), ethane (C2), and propane (C3) gases as they are being produced or extracted. This technique provides valuable insights into the origin, maturity, and migration pathways of hydrocarbons. Here’s a breakdown:
Isotopes: Atoms of the same element (like carbon) can have different numbers of neutrons. These different forms are called isotopes. Carbon has two stable isotopes, 12C and 13C.
δ13C: This represents the ratio of 13C to 12C in a sample, relative to a standard. It’s expressed in parts per thousand (‰). Variations in δ13C values can indicate different sources of carbon.
C1, C2, and C3: These refer to the hydrocarbons methane (CH4), ethane (C2H6), and propane (C3H8), respectively. They are the primary components of natural gas.
Real-time analysis: This means the measurements are taken immediately as the gases are being produced, rather than collecting samples and analyzing them later in a lab. This provides continuous data and allows for quick decision-making.
Applications of Real-Time Isotopic Analyses:
Determining the origin of gas: Different sources of hydrocarbons (e.g., thermogenic, biogenic) have distinct δ13C values. By analyzing the δ13C of C1, C2, and C3, it’s possible to identify the source of the gas.
Assessing gas maturity: The δ13C values of hydrocarbons change as they mature. Real-time isotopic analysis can help determine the maturity level of the gas, which is crucial for evaluating its economic potential.
Identifying migration pathways: Changes in δ13C values can also reveal how hydrocarbons have migrated through geological formations. This information can be used to understand reservoir connectivity and optimize production strategies.
Monitoring production: Real-time isotopic analyses can be used to monitor changes in gas composition over time, which can help identify production problems or changes in reservoir conditions.
Benefits of Real-Time Analysis:
Faster results: Real-time analysis provides immediate data, allowing for quicker decision-making during drilling and production operations.
Continuous monitoring: This technique provides a continuous stream of data, giving a more complete picture of reservoir conditions.
Reduced costs: By providing real-time insights, this technology can help optimize drilling and production operations, potentially reducing costs.
Overall, real-time isotopic analyses of δ13C of C1, C2, and C3 are powerful tools for understanding and managing hydrocarbon resources. They provide valuable information about the origin, maturity, and migration of gases, which can be used to make informed decisions during exploration, production, and reservoir management.
Describe the various mechanisms that contribute to fault sealing in sedimentary basins, emphasizing the role of shale smear and diagenetic processes.
Ans. There are many mechanisms that can lead to sealing of fault plane
1. Shale Smear
When faults cut through alternating layers of sandstone and shale, the displacement can result in the smearing of shale along the fault plane. This creates a low-permeability barrier, preventing fluid flow. The effectiveness of shale smear is often evaluated using the Shale Smear Factor (SSF).
2. Clay Gouge and Cataclasis
Fault movement can cause the grinding and crushing of rock particles, forming fine-grained materials called fault gouge. If the gouge consists of clay-rich material, it can significantly reduce permeability and act as a seal.
3. Diagenetic Processes
Post-faulting processes, such as cementation, mineral precipitation, or compaction, can reduce the porosity and permeability of the fault zone. Diagenetic sealing is especially common in faults within carbonate or sandstone reservoirs.
4. Stress-Induced Sealing
In some cases, the stress field around a fault can cause fractures to close, thereby reducing permeability. This is particularly relevant in reservoirs undergoing active tectonic compression.
Q.200 Explain the significance of fault sealing in hydrocarbon exploration and production. How does fault sealing influence reservoir compartmentalization and what are the implications for fluid migration and leakage?
Ans. ignificance of Fault Sealing
1. Hydrocarbon Trapping
Fault sealing plays a vital role in creating and preserving hydrocarbon traps. Sealed faults can act as lateral barriers, enabling hydrocarbons to accumulate in structural or stratigraphic traps.
2. Reservoir Compartmentalization
Sealed faults can divide a reservoir into separate compartments, each with its own pressure regime and fluid properties. This can significantly impact production strategies and recovery efficiency.
3. Mitigation of Fluid Leakage
Understanding fault sealing helps mitigate risks associated with fluid migration, such as hydrocarbon leakage to the surface or contamination of freshwater aquifers.