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.


Temperature and Conductivity purpose in mudlogging?
Temperature:
Formation evaluation: Changes in mud temperature as it returns from the wellbore can indicate formations being drilled through. For example, a sudden temperature increase might suggest entering a hot zone, potentially containing hydrocarbons. Conversely, a sudden decrease could point to colder formations like gas reservoirs or drilling fluid loss due to fractures or permeable zones and fluid influx Cold formation fluids entering the wellbore can decrease mud temperature. Constant or increasing temperature might also suggest drilling through impermeable formations or encountering lost circulation.
Drill performance monitoring: Monitoring mud temperature helps identify potential drilling problems like lost circulation, stuck pipe, or formation collapse. High temperatures often indicate friction-related issues, while abnormally low temperatures might suggest fluid loss into the formation.
Mud property control: Mud temperature affects its viscosity, density, and other crucial properties. Monitoring temperature allows mud engineers to adjust additives and maintain optimal mud performance for drilling efficiency and borehole stability.
Conductivity:
Formation fluid identification: Mud conductivity, related to its salinity, can indirectly inform about the conductivity of formation fluids encountered. High mud conductivity compared to baseline may indicate encountering saltwater, while a significant decrease could suggest hydrocarbons or freshwater zone. Fluctuations may indicate contamination from formation fluids, drilling fluids from other wells, or external sources.
Lithology identification: Certain rock types with specific mineral compositions can influence mud conductivity. For example, Halite and other formations rich in clay minerals tend to increase mud conductivity, while cleaner sandstones might show minimal change.
Monitoring drilling fluid contamination: Mud conductivity can be affected by contamination from formation fluids, drilling fluids from other wells, or external sources. Tracking changes in conductivity helps mud loggers identify and address potential contamination issues.
       Sudden increase in both temperature and conductivity could strongly suggest encountering a hydrocarbon zone.


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.

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.

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.


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.
 
IGOR:  If you run FMI after sidewall coring, you can orient this core samples because FMI resolution can identify the coring points in the well


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.


Wildcat drilling?
Wildcat drilling refers to drilling for oil or natural gas in areas with no prior proven production. These areas may be: Completely unexplored: virgin territory with little to no geological data. Historically abandoned: areas previously drilled but deemed unproductive. Frontiers: unexplored extensions of existing productive areas.


Offset wells have reservoirs, current well doesn’t, what happened geologically?
There are several possible geological explanations for why your current well doesn’t encounter the same reservoir as offset wells even though they are in close proximity. 
In order to provide a more specific answer, I need some additional information such as:
1. Distance between wells: Knowing the distance (How close are the offset wells to the current well) helps assess the likelihood of geological changes within that range.
2. Well logs and seismic data: If there are available well logs and seismic data for both your well and the offset wells, analyzing these can reveal detailed information about the subsurface and pinpoint potential differences.
3. Geologic setting: If there is information about the general geological setting of the area, such as the type of rock formations, known faults or unconformities, and depositional environments this context can help guide possible explanations.
Once the information listed above is exist, then it is possible to provide a more targeted explanation for why your well might not be encountering the same reservoir. 
Here are some general possibilities:
1. Facies changes: The reservoir rock might not be continuous throughout the area. Sedimentary environments can change laterally, leading to facies variations where reservoir quality diminishes or disappears. 
2. Faulting: Faults can offset and compartmentalize reservoirs, meaning your well drilled into a different block isolated from the one containing the reservoir. 
3. Unconformities: Erosional periods can remove portions of the rock sequence, potentially including the reservoir, before younger sediments are deposited. 
4. Pinch-out: The reservoir formation might naturally thin and eventually disappear in your well’s location. 
5. Drilling and interpretation issues: In some cases, misinterpretations of well logs or drilling problems might lead to an incorrect assessment of the subsurface.


Difference between LWD and MWD?
LWD – for detailed formation evaluation and understanding the reservoir by GR; Resistivity; Neutron and density porosity; Sonic; Formation pressure. 
MWD – for real-time monitoring of wellbore trajectory and drilling efficiency. MWD primarily provides directional information such as: inclination; azimuth, tool face orientation.


Vertical section degree?
Vertical section degree refers to the angle of a specific plane from the Northing Reference (Grid North or True North). This angle usually falls between 0° and 359.99° and helps define the orientation of the planned wellbore trajectory within a horizontal plane. The angle between this plane and the Northing Reference is the “vertical section degree.”


VSP planning and main purpose?
Planning a VSP involves several key steps:
Objectives: Define the specific information you want to obtain from the VSP data. Examples include characterizing the subsurface, identifying formation depths and thicknesses, evaluating reservoir properties, or monitoring production/injection processes.
Well selection: Choose the wellbore based on its location, proximity to the target area, and suitability for VSP measurements (e.g., good borehole conditions).
Source location and type: Determine the location and type of seismic source (e.g., downhole vibrator, surface source) based on desired depth penetration and data quality.
Receiver placement: Decide on the number and depth of geophones to be placed in the wellbore, considering the target depth and desired vertical resolution.
Data acquisition setup: Choose the recording system and parameters (sample rate, filter settings) needed to capture the desired seismic signals.
Logistics and safety: Develop a plan for equipment transport, deployment, and operation, ensuring personnel safety and environmental compliance.
Main purpose of VSP:
– High-resolution subsurface characterization: VSP provides detailed information about the rock properties and interfaces down the wellbore, with much higher resolution than surface seismic reflection data.
– Validation and calibration of surface seismic data: VSP data can be used to tie surface seismic data to depth, improving the accuracy of seismic interpretation and reservoir characterization.
– Reservoir monitoring: VSP can be used to monitor changes in fluid saturation or pressure within a reservoir over time, aiding in production optimization and reservoir management.
– Geomechanical evaluation: VSP data can be used to estimate rock properties like seismic velocities and elastic moduli, crucial for understanding fracture potential and wellbore stability.
Additional factors to consider:
– Cost: VSP is generally more expensive than surface seismic surveys.
– Data processing and interpretation: VSP data analysis requires specialized expertise and software.
– Limitations: VSP is limited to the immediate vicinity of the wellbore and may not provide information about lateral variations.


The main purpose of a sonic log?
Porosity & Permeability determination / Lithology indicator / Identify fractures (by sudden changes in sonic velocity) / Seismic velocity calibration (can improve the accuracy of seismic interpretation) / Elastic properties / Fluid saturation (the proportion of the pore space filled with the fluid) / Detect gas zones (by their low sonic velocity).
 
IGOR: Geophysics:
Seismic tie, Time/Depth relationship, Shear synthetics/AVO, Gas & pore fluid detection, Seismic attributes calibration
Geomechanics (Drilling & Completion):
Mechanical Rock properties, Wellbore stability, Sanding prediction, Select perforation interval
Reservoir characterization:
Overpressure detection, Lithology classification, Azimuthal anisotropy (fracture or stress induced)
Petrophysics:
Porosity via transform, Permeability (Stoneley mode), Radial profiling-invasion/shale alteration, Cement Bond Logging (CBL)


Geological problem faced while drilling or logging (tool stuck), what you have to do as a wellsite geologist?
The specific actions I would take as a wellsite geologist depend heavily on the nature of the geological problem encountered during drilling. However, there’s a general framework we can follow:
Assess the situation and Inform Operations Geologist, Drilling Supervisor:
– Gather information: Collect data from various sources like mud logs, cuttings analysis, LWD logs, drilling parameters, and communication with the drilling team.
– Identify the problem: Understand the symptoms experienced, such as increased torque, lost circulation, slow penetration rate, etc., and identify the potential geological cause.
– Evaluate the severity: Assess the immediate and long-term risks associated with the problem, considering factors like wellbore stability, formation pressure, and potential loss of hydrocarbons.
Develop a response plan:
– Consult with relevant stakeholders: Discuss the problem and your proposed solution with the drilling supervisor, mud engineer, and other experts involved in the operation.
– Consider options: Depending on the problem, potential solutions might include adjusting drilling parameters, changing mud composition, running additional logs, utilizing directional drilling techniques, or even pulling out of the hole and revising the wellbore trajectory.
– Prioritize safety and efficiency: Balance the urgency of resolving the problem with the need to maintain crew safety and ensure cost-effective operation.
Implement and monitor the plan:
– Communicate clearly: Explain the problem and chosen solution to the drilling team and ensure everyone understands the plan and their roles.
– Monitor progress: Closely observe the drilling parameters and other data to assess the effectiveness of the implemented solution.
– Be prepared to adapt: Remain flexible and be ready to adjust the plan if the situation changes or the initial solution proves ineffective.
Every geological problem encountered during drilling is unique, and there’s no one-size-fits-all solution. The role as a wellsite geologist is to use knowledge, critical thinking, and communication skills to identify the problem, develop a responsible plan, and work with the drilling team to overcome the challenge while ensuring safety and operational efficiency.


A wireline tool stuck?
When a wireline tool becomes stuck and the wireline is pulled off at the weak point, the wireline tool must be fished out using the cable head fishing neck. However, the fishing neck may be damaged or bent, and the radial position within the well may be unknown.


What are important roles and responsibilities of a wellsite geologist on a rig? 
A wellsite geologist serves as a multifaceted expert on an oil rig. 
Basically, he plays three primary roles: 
1. Expert Geologist: Analyze 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 geologies, 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, coring & handling, 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.


What is the Stop card purpose?
– Promote a culture of safety;
– Prevent accidents and incidents;
– Improve risk identification and reporting;
– Empower and motivate employees;
– Increase overall awareness.
Stop Card might be used: Observing someone working without proper safety equipment. Noticing damaged equipment or tools being used. Witnessing unsafe work practices or shortcuts being taken. Identifying a potential environmental hazard on the job site. Feeling uncomfortable or unsafe about any aspect of the work being done.


The difference between mudstone and wackestone?
The key difference between mudstone and wackestone is the relative abundance of non-carbonate grains within the rock:
Mudstone: is a mud-supported carbonate rock containing less than 10% grains larger than sand-sized particles (greater than 63 micrometers). It’s primarily composed of fine-grained carbonate mud (micrite).
Wackestone: is also a mud-supported carbonate rock, but it contains more than 10% grains larger than sand-sized particles. 


Mudlogging main backup sensors?
– Drawwork (Hook Position);
– WOH (Hook Load);
– SPP (Stand Pipe Pressure, in order to calculate Flow Rate);
– Flow Paddle (Flow Out indicator);
– Stroke Counters (on Pumps);
– Proximity Sensor (RPM (if no signal is received from the drilling rig);
– Torque Sensor (if no signal is received from the drilling rig);
– Pit Level & Trip Tank Level;
– Gas Equipment.


Main safety for mudlogging unit?
– Pressurized cabins;
– Explosion-Proof Equipment;
– Gas Detection and Alarm Systems;
– Emergency Shutdown Procedures;
– PPE;
– Regular Maintenance and Inspections;
– Safety Trainings;
– Good Housekeeping;
– Communication and Teamwork;


Logs behavior in gas reservoir? 
Resistivity logs: gas zones typically show increases in resistivity due to the non-conductive nature of gas. However, resistivity can also be affected by formation salinity and clay content.
Neutron logs: may show decreases in response due to the lower hydrogen content of gas compared to liquids like water or oil. However, shale content can also decrease neutron response, requiring careful interpretation.
Density logs: usually show decreases in response to gas due to its lower density than surrounding rock and fluids. However, porosity variations can also affect density logs.
Gas: Increases.
Gamma Ray: It depends on reservoir, unconventional shale – high or conventional sand – low/limestone – very low (zero).


What is geosteering?
The correct position of the wellbore in the reservoir. To properly run this job needs to set targets ahead of the bit based on geosteering interpretation and geomodel. Briefly, closely monitoring to resistivity, GR, image log, density & porosity and . If resistivity is high – it means that we are in the reservoir, if resistivity is low – we are out of reservoir.


How do you geosteer a directional well as a wellsite geologist?
Geosteering is a complex process that involves adjusting the drilling trajectory in real-time while drilling to optimize wellbore placement within the target reservoir. 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 tool face or reaming the wellbore. 
4. Last but not least; communicating effectively with all stakeholders for successful well placement. 


What types of motors in BHA? 
1. PDMs – Positive Displacement Motor, also known as mud motor with fixed bend angle.
2. RSSs – Rotary Steerable System, combination of downhole electronics and sensors to control the direction of the drill bit, can be programmed to follow a pre-defined trajectory, or they can be steered in real-time by the driller.  


What is Dogleg (DLS)?
Dogleg severity (DLS) is a measure of how sharply the wellbore changes direction. It’s usually expressed in degrees per unit length. Lower DLS values indicate a more gradual bend, while higher values indicate a sharper bend.
Doglegs can be intentional or unintentional:
Intentional doglegs are planned and created by directional drillers to steer the wellbore around obstacles, access reservoirs located at an angle, or follow the path of the oil or gas deposit.
Unintentional doglegs occur due to various factors like formation changes, drilling tool vibrations, or human error. These can lead to problems like increased drilling costs, difficulty running pipes and tools, and formation damage.


MDT (XPT, fluid tester etc) pressure points, there are few types of probs. What are the types?
There are 3 types of the probe:
1. Single Probe – (different sizes), used for the Pressure Tests and Sampling in normal reservoir.  The main component of the formation tester is an accurate pressure gauge which is attached via a flowline to a probe. The tool is positioned opposite a zone of interest and mechanical rams extended to lock the tool against the borehole wall and isolate the flowline from the mud column by forcing a rubber doughnut surrounding the flow line entry port into the mudcake.
2. Dual Packer (length between the packers can be adjusted from 1 to 3.4 meters). Provides two inflatable packer elements to isolate a borehole interval for testing and/or sampling. Access low-permeability, heavy oil, laminated, and fractured formations. Fitted with the dual-packer module (MRPA), the MDT tester effectively isolates a larger interval of the borehole for conducting a mini-DST or mini-frac testing and fluid sampling as well as Pre-test. 
3. Radial probe (unconventional – Low K), unconsolidated formations, Pore Pressure very close to Pressure bubble point. Pre-test, Sampling, Mini-DST.


MDT planning and what’s logs needed to catch MDT point?
Quad combo logs along with the high-resolution logs like Imager especially for thin-bedded and fractured carbonate reservoirs and NMR to get a clear indication for the free fluid zones indication. The runs better to make as follows:
1. Imager+Sonic (to have enough time for Imager Data processing and transferring)
2. QuadCombo +NMR prior the Formation Testing run


How to detect that you started to drill reservoir as a wellsite geologist?
ROP: may increase significantly.
Mud returns: pay attention to the mud returns coming out of the wellbore when the drill bit enters the reservoir.
Increased flow rate: can indicate a more permeable formation.
WOB: may decrease as the drill bit encounters the softer reservoir rock.
Torque: The torque on the drill string may also decrease as the drill bit enters the reservoir.
Gas: increase but it will be visible after bottoms up.
Fluorescence shows: quick and direct indicator of potential hydrocarbon reservoirs (after bottoms up).
Shaleshakers: In some cases, you may even see the presence of hydrocarbons, such as gas bubbles or oil sheen, in the mud returns.


Sidetrack window. Then drilling. How to check that you are not in previous hole?
Original hole: cement on the shaleshakers. Phenolphtahlein is used as an indicator to test if cement is present in drill cuttings.
Sidetrack (new hole): metal on the shaleshaker first and then cuttings from new formation. 
 

When you start circulation and you have bottoms up you have connection gas, why this connection gas is happened?
It means that you lose ECD due to pumps off. The connection gas can indicate that pressure between hydrostatic pressure exerted by drilling fluid and formation pressure is almost in balance condition. Therefore, when you see the connection gas, you should consider weighting up mud in the system before resuming drilling operation or tripping operation. In addition, the connection could be happened because of swabbing effect when the drill string is worked off bottom prior to making connection. In the other words, In case of connection gas needs to increase MW to the ECD, then monitor the well PP again, if still having increase in PP, go for second ECD again and continue the same until no indications for PP increasing.
 

What is ECD meaning?
ECD is equivalent circulating density. It essentially refers to the effective density of the circulating drilling fluid inside the wellbore when the pumps are running. This effective density takes into account two factors:
1. Hydrostatic pressure: This is the pressure exerted by the weight of the mud column above the point of interest. It increases with depth and mud density.
2. Frictional pressure losses: As the drilling fluid circulates through the annulus (the space between the drill pipe and the wellbore wall), it experiences friction. This friction generates pressure losses that need to be considered.


Why we should stop in a reservoir to circulate bottoms up?
Stopping in a reservoir and circulating bottoms up can serve several purposes such as:
– Confirming that it is reservoir in case of core point;
– Cleaning the wellbore; 
– Changing drilling fluid;
– Pressure Testing (circulation can stabilize the pressure in the formation and enable accurate pressure testing);
– Fluid sampling (after cleaning the wellbore, fresh formation fluids can be collected for analysis);
– Removing mud cake built up during drilling, this facilitates better formation fluid flow and improves productivity;
– Testing wellbore integrity y monitoring pressure changes during circulation, you can identify potential leaks or weak zones in the wellbore, ensuring its structural integrity before completion operations;
– Stimulating the reservoir: In some cases, circulating with specific fluids or additives can stimulate the reservoir by removing blockages or enhancing flow paths, boosting production potential;
 

Wireline tools calibrations?
GR – determination of reservoir thickness / lithology indicator / correlations between wells / estimation of shale vol.
Tool Calibration: At the wellsite, prior to running the tool, the GR is checked and adjusted using a GR jig – a clamp on arm which locates a small GR source of known strength at a fixed distance from the tool.  Basically, no one carries aluminum blocks with nylon on the field. The maximum is jig with monocyte sand is taken and checked. And the same jig can be used for density, because there is Gamma quantum sensors. Jig is source of gamma quanta.
Logging speed – 9 m/min; resolution – 0.9 m.
Influence – Casing / Potassium (KCl mud), need to put in system the data from mud rheology to ignore this affect.
MWD/LWD – the environment requires that the calibration be performed at the workshop and only a verification made at the wellsite.
 
Density Log – Porosity determination / lithology indicator.
Tool Calibration: The primary calibration standards for the density log are fresh water filled blocks of limestone. At the field base, the calibration is regularly checked and adjusted using large blocks of aluminum (high density reference) and nylon or sulphur (low density reference). A small internal source is used to regulate the detector electronics and to check the tool response at the well site prior to and after the logging job.
Logging speed – 9 m/min; resolution – 0.6 – 0.9 m
Influence – Mudcake/ high density barite – mudcake influence is corrected by comparing count rates at a short and long spacing detector. The correction applied to the density measurement is also displayed as a separate curve on the log. The density correction curve therefore serves as a quality check on the density measurements.
 
Neutron Logging – Porosity determination / lithology and gas indicator.
Tool calibration: The primary calibration standard for the neutron tool is a pit containing blocks of fresh water filled limestone of known porosity. At the field base, the calibration is regularly checked and adjusted against the ratio of near and far detector count rates in a standard fresh water filled tanks. Wellsite calibration checks made before and after surveys are carried out with a portable jig containing a small neutron source. (Neutron is also with a source, there is a count rates in the air and count rate in water, 100% water saturation is obtained in water)
Logging speed – 9 m/min; resolution – 0.6 – 0.9 m.
Influence –will record high apparent porosities when contact with the formation is poor and a mud filled space is created between tool and borehole wall.
 
Sonic Log – Porosity determination / lithology indicator / seismic velocity calibration etc.
Tool calibration: Acoustic transit time is measured very accurately using quartz clocks and the tools need no calibration, only electronic checks. The tool response can be tested downhole by recording the Δt in casing, which should be 57 μ sec/ft.
(The acoustics of the cross dipole were checked with a tonometer / tuning fork. In other places I think they just turn on and check for clicks sound).
Influence – In very large (or washed out) holes the first compressional arrival may be through the mud. In such cases the log will record a constant value, the mud transit time. In some cases the problem can be resolved by using a longer spacing or by eccentering the tool close to the borehole wall.
 
Resistivity Laterologs & Spherically Focused Logs – Hydrocarbon saturation determination / Permeability indicator.
Tool calibration: Dual Laterolog, SFL and MSFL are calibrated electronically before and after logging surveys in the well is made. This can be done while the tool is down hole by using precision resistors in the tool, no workshop calibration is required. The tools can also be function tested on surface using a set of clamps and cables to route current through the resistors of known value. (Connect contacts with resistance to the electrodes and look at the resistance. Or induction with a coil).
Also, I can check the laterlog or the induction tool by powering and clicking on verification, this device has internal resistances that the software checks and gives the results whether it passed verification or not. Calibrations and dates can be displayed on the screen.
Logging speed – 18 m/min normal for all resistivity tools.
Influence – In very big holes (wash outs) the pad may lose contact with the formation and give a flat mud resistivity reading. In very sticky holes the pads can become balled up with mudcake or shale and readings become meaningless.
 
SP – Spontaneous Potential Logging – determination of reservoir thickness / permeability indicator / estimation of formation water resistivity.
Tool calibration: No calibration is required for the SP electrodes, though electrical continuity and isolation checks are normally performed on the circuit prior to logging.
Influence – A strong SP deflection requires the following conditions: – Large salinity contrast between mud (filtrate) and formation water / – Clean reservoir next to pure shale / – High mud resistivity Rm (but Rm < infinity) / – Low shale resistivity Rsh or formation resistivity Rt.
Note: Oil based mud renders the SP useless
 
Caliper – diameter of the hole / wash outs.
Calibration of the caliper tool is done manually by rings of known diameters. At the site calibration was also performed running the tool in the casing.
 
Induction Logging – Hydrocarbon saturation determination / Permeability indicator.
Tool calibration: Induction devices are calibrated at the field base, using a zero conductivity environment for the ‘zero’
calibration, and a test loop representing a conductivity of 500 mmho (= 2 ohmm) for the plus calibration. At the well site the ‘plus’ calibration is checked electrically using an internal precision resistor, and the calibration drift during the survey is
assessed by performing the same calibration after the survey. The zero calibration cannot be checked at the well site as there is no practical zero conductivity environment available.
Logging speed – 18 m/min.
Influence – large holes, high salinity muds and across thin formation beds the induction log will generally require significant correction.
 
Imaging log LWD technology:
The MicroScope HD resistivity and high-definition imaging-while-drilling service provides unmatched logging-while-drilling (LWD) imaging for reservoir description, from structural modeling to sedimentology analysis, to enable detailed fracture characterization and completion optimization in conductive drilling fluids.
The MicroScope HD 675 service provides multidepth azimuthal laterolog resistivities and high-definition borehole images in a 8.5-in hole size to enable well placement and geosteering, sedimentology using porosity and texture distribution, formation evaluation in high-resolution, estimation of reserves, structural analysis based on dips and fracture orientation, and fracture characterization for completion design optimization.


Wireline Witness – QA/QC?
1. Preparation prior to logging operations:
All wireline logging tools shall be checked and tested prior to rigging up.
Logging operations shall commence when the hole conditions are stable. A check trip shall be required before running the formation pressure/sampling tool if there were hole problems during the previous run.
The mud specifications shall meet the program specifications. The overbalance shall be at least 200 psi.
Fishing equipment shall be available at the well site for all logging tools. All dimensions, lengths and connections of all the tools shall be recorded.
For formation pressure/sampling logging a plot of expected pressures shall be prepared.
2. Logging operations guidelines:
The hole shall be circulated through the trip tank during logging operations. The hole shall be kept full throughout, and the trip tank volume shall be recorded every 15 minutes. The trend shall be monitored whilst running in and pulling out.
The wireline logging depths shall be set to zero at surface and checked when pulling out to surface. Additional checks shall be made at casing depths and at TD.
If a tool hangs up while running in and the section has not been logged before, log out of the well. If one of the detectors of a combination tool does not function properly, log the remaining detectors which have not been recorded before. When anticipating poor hole conditions, always log in as well as out of the hole to secure data.
If a section has to be repeated, a 150 m section shall be made on each logging run, and a 60 m overlap with previous logging runs shall be made. The repeat section shall be made across an interval of interest.
When running a calliper tool in a section where the top of the logged interval is below the casing shoe a 300 m section over the shoe shall be run to check shoe depth and calliper gauge.
Mud shall be sampled from both the pits and flowline immediately before the end of circulation prior to a logging job for analysis and resistivity measurement. This shall be repeated after check trips if resistivity tools are to be run.
Check trips to bottom shall be required to ensure the hole and mud conditions.
The weak-point tension limit and cable tension limit shall be checked and tool weight in mud calculated before entering open hole. Normal logging tension shall be checked every 300 m in open hole. This is especially important in deviated holes where drag can be significant.
3. Quality control guidelines:
The depth correlation of all the curves on the log must be checked with each other.
The repeat section must be checked with the main log for agreement. The curves must be examined to see if they have sensible values. They shall be compared with logs in nearby wells, which must always be available on the rig.
The correct logging speed must be verified. The speed can be determined from the breaks in the lines at the edges of the log which occur every minute. For example, if the distance is 18 m, the logging speed was 18m/min. For resistivity logs the standard logging speed is 18 m. Statistical nuclear tools require a speed of 18 m/min. The acceptable range is +/- 10 %. Confirm this with the Logging Contractor in advance.
Verification shall be made that there is 60 m overlap between successive logging runs.
The depth discrepancies between successive logging runs must be less than 60 cm.
For the Cement Bond Log, a 100 m section of the free pipe reading during logging must always be recorded (if uncemented sections exist).
4. Formation Pressure Tests guidelines:
When taking pressures the tool shall initially be set for two minutes only. If the pressure does not build up properly the tool shall be unseated and another attempt made.
Plot both the formation pressure and mud pressures as they are taken. Inconsistencies in the mud gradient shall be checked immediately (a smooth mud gradient shall be regarded as a quality check).
5. Highly Deviated Wells guidelines:
Before entering open hole the normal logging tension shall be recorded. It shall be higher than that of a vertical hole and large stretch corrections shall be required.
Checks shall be made to ensure that the tool is moving down the well as the wireline is being run into the hole.
Short tool combinations are easier to get down the hole particularly in areas of high dogleg.
For high deviations or particularly difficult holes, consideration shall be given to other techniques, eg., drillpipe (TLC) or coiled tubing (E-line) conveyed logging tools or the use of logging while drilling tools (LWD).
6. Horizontal Wells guidelines:
Horizontal wells shall be logged either with LWD or TLC techniques (on drill-pipes).
The use of drilling jars are not recommended because of the risk of logging tool damage. It shall not be possible to run jars or HWDP because of ID restrictions for an extended length. This requires enough regular drillpipe at the well site to replace the HWDP’s, drill collars, jars, etc.
The running in speed shall not exceed that used when running a packer on drillpipe. Below the kick-off point, the tools shall tend to lie on the low side of the hole and not be subject to so much bouncing as higher up. Obstructions downhole (eg., liner tops) shall be passed with caution. Break circulation at regular intervals (ie., every 10 stands).
A down log shall be taken while running in. The Logging Contractor procedures shall recommend that the tools do not tag the bottom of the hole but stay a minimum 5m above drillers depth. Depth control shall be checked with the drillpipe during in-run and out-run.
Continuous communication is required between Driller and the wireline unit to ensuring the pulling speed and cable spooling speed are matched, and to minimise reaction time if the tool begins to stick. Minimise downward movement when setting slips, because the calliper will be in the open position.
The cable shall not be slacked off to avoid the risk of damaging it at the side entry sub.
A cable head tension/compression meter readout shall be made available to the Driller on the rig floor.
The string to be spaced out to have latch point in cased hole.
If circulating sub cannot be latched increase cable running speed and check for latching from logging unit.


What is the purpose of using the wax of core, after we cut 1m?
After cutting a 1-meter core sample for analysis, it’s crucial to preserve its original state as much as possible. In some cases, a thin layer of wax (paraffin) is applied to the core as a coating. This serves several purposes:
– Prevents dehydration: The wax seals the core, minimizing moisture loss and preserving the internal structure and textures.
– Protects against contamination: The wax coating acts as a barrier, preventing external fluids or contaminants from entering the core and altering its composition.
– Facilitates handling and storage: The wax provides a smooth surface and reduces potential damage during handling, transport, and storage of the core samples.
In additions, for Visual aid for fracture identification: “wax of core” might refer to a specific technique used to identify fractures in core samples:
– The core sample is polished flat on one end.
– A hot wax solution is poured onto the polished surface and allowed to cool and solidify.
– When the wax is removed, it pulls out small fragments of rock along with it, preferentially from areas with fractures or weaknesses.
– This leaves a visible pattern on the core surface, highlighting the location and orientation of fractures, which can be further analyzed and documented.


Core lab analyzis?
RCAL – Routine core analysis attempts to give only the very basic properties of unpreserved core. These are basic rock dimensions, core porosity, grain density, gas permeability, and water saturation.
SCAL – Special Core Analysis attempts to extend the data provided by routine measurements to situations more representative of reservoir conditions. SCAL data is used to support log and well test data in gaining an understanding of individual well and overall reservoir performance.
 
 
 
 

Coring techniques?
Low invasion: The low-invasion profile coring bits are designed to maximize penetration rate, and minimize drilling fluid filtrate invasion into the core. The benefits: Protect a core from dynamic filtrate invasion. Reduce core damage while improving penetration rates with enhanced face-discharge core bits. Prevent dynamic and static filtrate invasion with custom-designed coring system.
Liquid Trapper: A coring tool which samples core and its fluid contained within pores. The Liquid Trapper consists of a specifically designed liner assembly, which through an inflatable seal system ‘traps’ the liquids escaping from the core during the retrieval of the corebarrel to the surface. Cores and fluids obtained allow the determination of the fluid saturations representative of formation saturations.
Pressurized Coring: Used high pressure to get the core samples in its original conditions to avoid any loss of the fluids. Freezing the core to immobilize the fluids then the core can be depressurize. This drill string conveyed core barrel system is operated in the same way as a conventional double tube core barrel. The design of the LPC allows constant mud circulation throughout coring and POOH to guarantee well stability 2 valves.


Why we drop the ball before starting cut core?
Normally, after RIH w/ core BHA, circulated hole cleans at btm, then drop ball and wait till it reached bottom of BHA, then start cut core. The ball blocks a valve at the top of the core barrel and preventing fluid damage to the core. Ball closes the flow between inner & outer barrel. Indication for the ball already reached Btm & already closed that flow is increasing of pressure.
 

Why we are using DV Tool while run in hole casing?
DV Tool (differential valve) – 2 Stages-cementing tools, used to cement multiple sections behind the same casing string, or to cement a critical long section in multistage. 
 

What is FIT and LOT? Why we are doing LOT?
LOT: you pressure test shoe and formation until formation break down. LOT Is conducted in order to find the fracture pressure (fracture gradient) of formation and shoe. When conducting the LOT, you will pump drilling fluid to until you see the fracture trend of formation. Once formation is fractured, the first pressure that deviated from a trend is typically called Leak Off Pressure. We use the leak off pressure to calculate LOT. 
FIT: you test strength of shoe and formation to designed pressure. FIT is typically used for testing strength of formation and shoe by increasing Bottom Hole Pressure (BHP) to designed pressure. When you do the FIT test, you will increase surface pressure until it reaches the required pressure only. There is no intention to break the formation with FIT. You will do FIT to ensure that you will be able to drill to section target depth and will be able to control the well in case of well control situation without underground blow out.
XLOT:  similar to a leakoff test, but with multiple cycles of shut-in and injection. XLOT is typically to determine the minimum horizontal stress and understand the fracture propagation behavior of the formation. We use FCP (fracture closer pressure) to calculate Sh min.


What is the differential pressure?
Difference of pressure between mud column and formation pressure. Increase in pressure of mud column decreases penetration rate.


Cavings and actions if it is happened at the wellsite?
Cavings shale – I describe it to detect type of caving shale and send an official email to DSV, Ops Geology regarding it. It’s large size of Shale produced without action of the drill bit (not drillable), occurred when Shale became unstable, the shape of the caving shale indicates actions needs to be taken. 
Mechanical cavings shale (shear failure): 
The cavings Shale is (Large size of angular, tabular and blocky to sub blocky), it’s considered active Shale which is recommend to the following action: 
1- Reduce filtrate fluid loss (water loss) as much as we can to be <3-2.6mL in order to minimize swelling rate occurred because of absorption of water inside the formation. 
Pressurized cavings shale:
Cavings related to wellbore stability and breakout pressure. The Cavings shale is (Splintery, elongated, angular & needle shape) It’s considered pressurized cavings shale which is occurred when the drilling became underbalanced (this occurs when the pressure in the wellbore is lower than the pressure of the surrounding rock formations) and the overbalance while drilling is insufficient which is recommend to the following actions: 
1- Increase MW to control on/overcome this pressurized cavings shale. 
2- Reduce filtrate fluid loss (water loss) as much as we can to be <3-2.6mL in order to minimize swelling rate occurred because of absorption of water inside the formation. 
 

What is clay swelling means?
This may occur, because clays are normally saturated with brine water and not with fresh water. This swelling can be prevented with the injection of some additive, for example, sodium chloride, potassium chloride, calcium chloride, or an alcohol or a similar organic material. Practically, before entering inside the formation, we have to reduce filtrate loss and increase KCl as high as possible in a mud and drill this zone with low ROP.
 

What is overpressure?
When drilling shales, the drilling rate normally decreases with depth as the shales become more compact. If the ROP suddenly increases, it can be inferred that an overpressured zone is being encountered. The rate increases because bottom hole conditions change from overbalanced to underbalanced. Undercompacted shales associated with overpressured zones have a much lower electrical resistivity than normally compacted shales. ECD is close to pore pressure (Stop for flow check / Connection Gas  / Cavings).


What is the difference between pore pressure and formation pressure?
PP refers specifically to the pressure of the fluids within the pores of a rock formation. These fluids can be water, oil, gas, or a combination of all three.
FP refers to the pressure of all the fluids and rock matrix within a formation. This includes the pore pressure, as well as the pressure of any fluids that are trapped in fractures or other discontinuities within the rock.
In most cases, the pore pressure and the formation pressure will be the same. However, there can be some situations where the two pressures are different. For example, if a formation contains a lot of fractures, the pressure of the fluids in the fractures may be higher than the pressure of the fluids in the pores. In this case, the formation pressure would be higher than the pore pressure.
 

Pore Pressure Prediction?
There are several methods in order to build geopressure (pore pressure, vertical stress, fracture gradient) or geomechanics (+ SH, Sh, failures, rock mechanics) model.
– Well Log data: analyzing various well log data like Sonic, Resistivity, Density and drilling data – D-exponent, we can identify pressure related trends. Sonic is the best approach because the fluid does not affect the measurements.
– Seismic methods: Utilizing seismic data converted to interval transit time (compressional slowness, DTCO=1/Seismic velocity), which correlate with effective stress and thus pore pressure.
Popular Pore Pressure Prediction Technique:
– The more common and probably more accurate method is the Eaton method (resistivity and sonic) based on shale compaction trends and also takes into effect vertical tectonic stress in the form of the overburden stress. The steps of method:
– Establish normal depth trend in measured property in shales;
– Find the value of the property at the depth where you want to know the pressure;
– Use normal trend line to find the value we would normally expect this depth (Normal Compaction Trend – Basic requirement for early detection of abnormal pressure. The NCT line will represent the normal pore pressure value. It is important to note that a Normal Compaction Trend can be shifted to compensate for unconformities, hole size, hydraulics, hole angle, bit type so as to appear faulted, for this reason the NCT is applied in intervals);
– Calculate effective pressure from Eaton equation and then calculate pore pressure from effective pressure and total pressure (overburden): Pp=Poverburden-Peff.
There is one more popular method: Bowers utilize sing sonic logs to predict pore pressure. 


What is D-exponent?
Normalized ROP or formation drillability which is calculated by drilling rate, weight on bit, rotating speed and bit diameter. For corrected D exp needs to know MW or ECD. 
Where lithology is constant, ‘d’ Exponent will represent:
– the state of compaction (relative porosity);
– differential pressure
A decrease in ‘d’ while drilling in an argillaceous formation is thus related to the degree of undercompaction and of the associated abnormal pressure.


Logs for Pore Pressure Prediction?
Seismic: Primarily used to interpret structural information and approximate formation identification seismic data can be converted to interval transit time, for overpressure detection prior to drilling. The resulting data is similar to a wireline sonic log. The data is then interpreted as for a shale sonic plot. The curves may initially give estimates for the top of the undercompacted zone but across a region provide a profile allowing for the evolution of the over-pressure to be evaluated.
It is also worth mentioning the vertical seismic profile (VSP) tool run on wireline either at the end of the well or at an intermediate logging run. This produces a better-quality seismic profile of the formation than that recorded from surface investigations. The tool sensor is run in the hole at regularly spaced depth intervals and the seismic trace recorded at each point to build up a detailed profile. The tool records sound waves travelling both downwards through the formation from above and upwards from the formation below. By subtracting the former from the latter waves higher it is possible to produce better quality upward travelling waves and hence formation evaluation below the bottom of the hole.
Sound wave velocity through a rock, or any material, is a function of the materials density, pore geometry and elasticity it is possible to derive values for the Poisson’s ratio and modulus of elasticity. This is particularly important for in fracture gradient and stress analysis
 
Sonic: Is the best indicator of pore pressure. Primarily, sonic transit time may be considered as a function of lithology and porosity. If a given lithology, such as a shale is investigated, the sonic response will essentially be a function of porosity variations. If sonic transit times of normally compacted shales are plotted on a logarithmic scale, against depth on a linear scale, a linear trend results and transit time will decrease with depth. The fluid pressure represented by this normal compaction trend will be hydrostatic. If overpressured clay formations are encountered, the data points will diverge from the normal trend, toward higher transit times for a given depth.
From Sonic we can get Dynamic Elastic properties for geomechanics calculations.
 
Density: The bulk density of normally pressured shales increases with compaction, and hence depth. The presence of undercompacted sediments is reflected as a reduction in bulk density. Reading off bulk densities from logs gives an indication of compaction and hence overpressures assuming matrix and fluid densities to be constant.
 
Resistivity: This is a measure of the ability of a formation to conduct an electric current and is one of the earliest methods of wireline detection. The solid matrix is generally non-conductive while the pore space may be filled either with non-conductive hydrocarbons or conductive saline water. Resistivity values are therefore related to the amount and nature of the pore fluid and, ultimately to the degree of porosity. Where all things are equal (homogeneous clay formation and constant fluid properties) a unit decrease in the resistivity reading will correspond to a unit increase in the porosity and hence overpressure.
 
Sonic transit time will decrease with depth.
Porosity decreases with depth.
Clays are represented by high porosity and low permeability.
With normal compaction, porosity decreases and bulk density increases.
Effective stress change associated with the increasing in pore pressure – decreases
 
 
 

Stresses and faults types?

Normal faults: the vertical stress is the largest principal stress (Sh min is the best direction for drilling). 
Strike-slip faults: the vertical stress is the intermediate principal stress (always avoid to drill).
Thrust faults: the vertical stress is the smallest principal stress (SH max is the best direction).


What is the best direction to drill a well (generally)?
Minimum Horizontal Stress direction is the best for drilling because of several advantages compared to the others directions:
Reduced shear stress: When the wellbore is aligned with the minimum stress direction, the shear stress acting on the wellbore walls is minimized. As well as drilling along a direction perpendicular to the plane of maximum UCS (unconfined compressive strength) minimizes the compressive stress acting on the wellbore walls. This reduces the risk of wellbore collapse and formation breakouts.
Enhanced wellbore integrity: Drilling along the minimum stress path allows for a more uniform distribution of stresses around the wellbore, promoting better wellbore integrity and reducing the risk of induced fractures.
Effective hydraulic fracturing: In unconventional reservoirs like shale formations, horizontal wells are often drilled and hydraulically fractured to stimulate hydrocarbon production. Drilling in the minimum stress direction allows for easier and more efficient fracture propagation, maximizing the stimulated reservoir volume (SRV) and ultimately leading to higher production rates.
Optimal fracture geometry: When fractures are created perpendicular to the minimum stress direction, they tend to be wider and more planar, providing better conductivity for fluid flow and hydrocarbon recovery.
Reduced drilling costs: Drilling in the minimum stress direction often requires lower mud weight, which can translate to lower drilling costs due to reduced pump pressure and mud consumption.
Safer drilling operations: The improved wellbore stability associated with drilling along the minimum stress path leads to safer drilling operations and minimizes the risk of wellbore failures.
 
However, it’s important to note that the optimal drilling direction can vary depending on several factors, including:
Formation type: The mechanical properties of the rock formation, such as its strength and brittleness, can influence the preferred drilling direction.
Reservoir characteristics: The presence of faults, fractures, and other geological features can impact the stress distribution and optimal drilling direction.
Completion objectives: Depending on whether the well is intended for production, injection, or other purposes, the preferred drilling direction may differ.
In addition, the best direction to drill the formation like an anticline is perpendicular to the layers of deposits because of: exposing maximum reservoir area; enhancing well productivity.
 

Mechanical and Elastic properties of the rock?
Mechanical: UCS, Friction Angle, Tensile strength;
Elastic: Young’s modulus, Poisson’s Ratio, Bulk modulus, Shear modulus.


Salinity impaction (mud rheology) while drilling?
There is osmosis concept.
Needs to be in the balance between the mud salinity and the formation salinity.
Mud with Low salinity: formation will be swell, especially shale/clay.
Mud with High salinity: formation will be “dry”, reduced fluid movement within the pores. With the high filtrate in the mud – will increase the pore pressure.
 

What does Fast Shear Azimuth and Radial Profiles mean?
Fast shear azimuth is the direction of SHmax from the dipole sonic tool. If you have anisotropy due stresses, then fast and slow shear waves will be different. The polarization gives the SHmax. The radial profiles are about the crossing data between fast and slow shear. If observed a crossing between them, then you have anisotropy due to stresses.
 

What is the difference in Pore Pressure with increasing water depth?
Sv changes and we should observe some difference in PP. As water depth increase also MW window will be narrower. Fracture gradient or Sh min will be reduced as water depth increase.
 

What is the difference between geomechanics and unconventional geomechanics?
First, Geomechanics is always the same just we have different applications for modeling in the industry. There is one application is Geomechanics for unconventional reservoirs, these can be in different reservoir rocks like tight sandstone, intact carbonates, Shales and others. The most popular, is shale unconventional plays, here Geomechanics is important to determine correctly how stresses are acting in the reservoir.  Shales needs to be frac in order to get production, and this frac growth needs to be contained within the reservoir. For this in shales is important to impenetrable rock anisotropy analysis as the vertical elastic and mechanical behavior is different than the horizontal. So here we estimate with the poroelastic equations using both Young Vertical & Horizontal and Poisson Vertical & Horizontal the Min and Max horizontal stresses. Having this calculated it is possible to find some important stress barriers within the reservoir where will be better to frac and contain its growth. 


What is Numerical Simulation in geomechanics?
Numerical simulation is a powerful tool used in geomechanics to model the behavior of soils and rocks under various loading conditions. Any changes in deformation involve Stresses and Deformations, of course the material properties, so you can assign Poisson, Young etc values to the material so the model can represent the material in reality. So, in geomechanics we will model a thing called “a geomodel” coming usually from the geomodelers. Once you have this model, let’s say in Petrel, now we can create cubes of properties like DTCO, DTSM, RHOB, Poisson, Young etc and once we have them, we can follow the Finite Element Workflow used by Visage to run simulations in our whole model or only in the reservoir section. We will apply the earth forces acting on it, these forces are the Overburden, SH max and SH min, and also, we will tell the direction of this forces. With this we will be able to calculate our stresses taking into account perfectly the shape of our subsurface (faults/salt domes/anticlines/etc) and the forces (Shmin and SHmax) will be distributed perfectly around these areas giving you a model more accurate in term of local (in our well trajectory) Shmin, SHmax and their orientation. From here there are many applications that can be used like calculate subsidence, or fault reactivation, seal rock integrity, etc. 
 

What will be the annulus pressure drop in case you have complete losses or if there is no mud return?
The annulus pressure drop would be to the level of the hydraulic pressure of the weight of the fluid in the annulus that will balance off with the reservoir pressure.
 

How to detect a wash pipe?
Decrease in SPP and little effect on flow rate.
 

What is the indicator of twist off? What else if twist off at 200m of BHA?
Sudden drop in SPP, increase pump speed, reduced torque, increase in RPM. If the bit is at 200m when twist off occurs, then hook load decrease will depend on the weight of the BHA. if the BHA (DC, HWDP, MWD, LWD, etc.) was heavy then we would still see drop in hook load.


What is PMCD in drilling operations?
Pressurized-mud-cap drilling is unconventional drilling technique that have been used widely individually, mostly in relation to closed and pressurizable systems and to managed-pressure-drilling (MPD) applications. PMCD is drilling technique used to drill without returns while balancing a full annular fluid column by using a Light Annular Mud (LAM) cap maintained above an open-hole formation that is taking all injected (sacrificial) fluid and drilled cuttings assisted by surface pressure.
The advantages are: prevent lost circulation, drills through depleted zones, improves wellbore integrity, reduces rig time. 
 

What is MPD?
Managed Pressure Drilling (MPD) is a drilling process used to precisely control the annular pressure profile throughout the wellbore. Additional technology and equipment systems are incorporated into conventional drilling systems to achieve the ability to adjust and control the annual pressure profiles downhole.
Managed Pressure Drilling, is the use of specialized equipment (which can include such items as a Rotating Control Device, additional choke manifold, drill string check valves and fluid/solids control equipment among others) to control the pressure in a well being drilled.
An adaptive drilling method used to precisely control the annular pressure throughout a wellbore. After determining the downhole pressure environment, drillers manage wellbore pressure constrained by the limits of formation properties. The annular pressure is kept slightly above the pore pressure to prevent the influx of formation fluids into the wellbore, but it is maintained well below the fracture initiation pressure. Rapid corrective actions can often be implemented in order to deal with observed pressure variations. The MPD process may utilize a variety of techniques including control of back pressure, adjusting mud density, modifying fluid rheology, adjusting the annular fluid level, controlling circulating friction and incorporating hole geometry in the well construction.


HPHT Wells: Problems and Drilling Strategies?
HTHP well is one that has temperature greater than (150°C) and either has a pore-pressure gradient in excess of 0.8 psi/ft or requires the use of well-control equipment at more than 10,000 psi working pressure.
The common problems for drilling HPHT wells:
Narrow operational window: The pressure and temperature gradients in HPHT wells are often very close, leaving a narrow window for safe drilling operations. This means even small fluctuations in pressure or temperature can lead to wellbore instability or kicks.
Well control: Maintaining well control in HPHT wells is critical due to the high pressures involved. Blowouts, where formation fluids escape uncontrollably, can be catastrophic and require specialized equipment and procedures.
Drilling fluid limitations: Conventional water-based drilling fluids often experience limitations at high temperatures, such as gelation and fluid breakdown. This necessitates using specialized synthetic-based muds, which can be more expensive and require stricter environmental regulations.
Equipment limitations: Drilling equipment, including drill pipe, casing, and downhole tools, are subjected to extreme stress in HPHT wells. Special high-performance materials and robust designs are required to ensure their integrity and prevent failures.
Formation instability: High temperatures can weaken formations, making them prone to collapse and causing problems with hole cleaning and wellbore stability.
Cost and time: Drilling HPHT wells is typically more expensive and time-consuming compared to conventional wells due to the specialized equipment, fluids, and expertise required.
The common drilling strategies for HPHT wells:
Detailed well planning and design: Comprehensive pre-drilling planning is crucial for HPHT wells. This includes thorough reservoir characterization, pore pressure and fracture gradient analysis, selection of appropriate drilling fluids and equipment, and contingency planning for potential issues.
Utilizing specialized drilling fluids: Synthetic-based muds formulated for high temperatures and pressures are often used in HPHT wells. These muds maintain their properties under extreme conditions and ensure wellbore stability and hole cleaning.
Real-time monitoring and data analysis: Continuous monitoring of downhole pressure, temperature, and other wellbore parameters is essential for early detection of potential problems and timely decision-making. Advanced data analysis tools can help optimize drilling parameters and mitigate risks.
Wellbore strengthening techniques: Casing with high collapse and burst ratings is used to withstand the high pressures encountered. Additionally, techniques like wellbore strengthening with cementation or expandable liners can be employed to enhance wellbore stability.
Experienced personnel: Drilling HPHT wells requires experienced personnel with specialized knowledge and training in HPHT wellbore management, well control procedures, and use of advanced drilling technologies.


Difference between MDT and DST permeability?
MDT – Provides indirect estimates of permeability through pressure transient analysis, which can be less accurate compared to DST. Ideal for low to medium permeability formations due to its limited flow potential. 
DST – direct measurements of permeability by analyzing the flow rate and pressure data during the test. For medium to high permeability formations due to its higher flow capacity. This method is better and more accurate.
 

DST string for the heavy oil?
A DST string for heavy oil wells requires additional components compared to a conventional DST string to address the challenges posed by the high viscosity of the oil.
Basic Components:
Packer: Isolates the desired formation interval from the wellbore.
Pressure gauge: Measures formation pressure during the test.
Flow control valve: Regulates the flow of fluids from the formation to the surface.
Sampling ports: Allow for collecting fluid samples for further analysis.
Additional Components for Heavy Oil:
Circulation sub: Enables circulation of fluids within the wellbore to clean it before and after the test, reducing the risk of formation plugging due to heavy oil.
Downhole heater: Reduces the viscosity of the heavy oil by applying heat, improving flow rates during the test.
Nitrogen injection line: Injects nitrogen gas into the formation to provide additional pressure assistance, aiding in bringing the heavy oil to the surface.


Surface Well testing for the high gas flowrate well?
Conducting a surface well test (SWT) on a well with a high gas flow rate presents unique challenges compared to testing a conventional well. There are some key consideration:
Equipment selection:
High-capacity flowlines and separators: Standard equipment might not handle the high gas volumes, requiring larger diameter lines and separators with increased processing capacity.
Choke selection: A properly sized choke valve is crucial for controlling the flow rate precisely and safely while preventing backpressure buildup downhole.
Solids removal equipment: High gas flow can carry sand and other solids, necessitating equipment like hydrocyclones or sand filters to prevent damage to downstream equipment.
Safety considerations: Due to the potential for high-pressure gas releases and fire hazards, stringent safety protocols and equipment must be implemented during the test.
Test procedures:
Phased flow rate testing: Gradually increasing the flow rate in stages allows for better assessment of well performance and avoids exceeding equipment limitations or causing formation damage.
Backpressure testing: This specific test helps evaluate the well’s deliverability and reservoir drainage area by flowing the well against a controlled backpressure.
Continuous monitoring: Real-time monitoring of pressure, temperature, flow rate, and other parameters is essential to ensure safe operation and gather accurate data.
Additional considerations:
Environmental impact: High gas flow can lead to significant emissions of methane and other greenhouse gases. Proper planning and mitigation strategies, such as flaring or reinjection, are necessary to minimize environmental impact.
Data analysis: Specialized software and experienced personnel are needed to analyze the complex data generated during the test and accurately interpret reservoir properties and well deliverability.
 

Difference between bottom hole sampling with the DST and MDT?
Both DST and MDT can be used for bottom hole sampling in oil and gas wells, but they differ significantly in their approach, capabilities, and suitability for specific scenarios.
Method:
DST:Employs a larger tool positioned at the end of the drill string. This tool isolates a specific formation interval and allows formation fluids to flow directly to the surface through the drill pipe. Samples are collected at the surface after the fluids have traveled a significant distance through the wellbore.
MDT: Utilizes a smaller probe lowered through the drill string via wireline or coiled tubing. This probe directly accesses the formation at specific points and collects fluid samples in chambers within the tool itself.
Sample volume:
DST:Provides larger volume samples due to its direct flow path from the formation to the surface. This allows for more detailed analysis of the reservoir fluids.
MDT: Offers smaller volume samples as the fluids are collected directly within the probe and do not flow through the entire wellbore. However, advancements in technology have allowed MDT to collect increasingly larger samples.
Sample integrity:
DST: There’s a higher risk of sample contamination because the fluids travel through the drill pipe, which may contain drilling fluids or other contaminants.
MDT: Offers better sample integrity as the fluids are collected directly within the probe, minimizing contamination risks.
Formation characteristics:
DST: Primarily used in medium to high permeability formations due to its reliance on sufficient flow rates to bring fluids to the surface.
MDT: Works well in low to medium permeability formations where flow rates might be limited. Additionally, MDT allows for sampling at multiple points within the formation, providing a more detailed picture of reservoir heterogeneity.
Suitability:
DST: Ideal for obtaining large volume samples and evaluating overall reservoir fluid properties in formations with adequate flow rates.
MDT: Well-suited for collecting representative fluid samples with minimal contamination and evaluating reservoir heterogeneity in formations with varying permeability or where large sample volumes are not crucial.


How to select the MDT points? Where is the point good or not stable? Where you can say that is a good point in terms of recording the pressure?
Selecting optimal MDT points involves careful consideration of several factors:
1. Reservoir Objectives:
Pressure profiling: Aim for points across the entire reservoir interval, capturing variations in pressure due to fluid types, compartmentalization, or other factors.
Fluid sampling: Prioritize points representing different fluid zones (oil, gas, water) and distinct reservoir facies, ensuring representative samples.
Permeability estimation: Choose points within a specific formation layer, avoiding transitions or boundaries, to obtain reliable permeability values.
2. Geological Data:
Formation logs: Use porosity, permeability, and lithology logs to identify representative formation intervals and avoid impermeable zones or mud-filled sections.
Dipmeter data (dipmeter tool): Consider wellbore deviation and formation dip to ensure the probe accesses the intended formation and minimize contamination from adjacent intervals.
3. Operational Considerations:
Depth limitations: Ensure chosen depths can be reached safely within the planned operational window.
Formation stability: Avoid weak formations prone to collapse or wellbore stability issues.
Practical considerations: Distribute points strategically to optimize efficiency and minimize time spent on each point.
Points considered “not good” or unstable for pressure recording include:
Formation boundaries: Transitions between different formations can have unreliable pressure readings due to potential mixing of fluids or pressure imbalances.
Permeable zones near impermeable layers: Pressure might not be representative of the entire formation due to limited communication between layers.
Zones with wellbore instability: Risks of contamination from formation collapse or mud influx can compromise pressure data.
Conversely, “good” points for pressure recording exhibit the following characteristics:
Located within a single, well-defined formation layer: Ensures pressure represents the specific formation characteristics.
Adequate formation stability: Minimizes contamination risks and ensures reliable data.
Sufficient distance from formation boundaries: Avoids potential pressure anomalies due to transitions between formations.
 
 
What is dipmeter tool?
A dipmeter tool is a specialized device used in the oil and gas industry to measure the orientation (dip and strike) of geological layers within a borehole. The tool works by measuring the electrical resistivity of the formation at multiple points around the borehole circumference. By analyzing the variations in resistivity, the tool can determine the angle at which the formation layers intersect the borehole, allowing calculation of dip and strike.


Where is the MDT point is not seal? What the pressure of the point will be? The tool will read what?
If an MDT point doesn’t seal properly, it can lead to several issues and compromise the data collected:
1. Pressure readings:
– The pressure reading at the point will likely be inaccurate and unreliable. It might reflect a mixture of pressures from different formation zones or the wellbore fluid due to the lack of proper isolation.
– The tool might not be able to establish communication with the formation at all, resulting in a failed pressure acquisition.
2. Fluid sampling:
– The collected fluid sample might be contaminated with wellbore fluids or fluids from other formation zones due to the leakage. This will render the sample unrepresentative of the specific formation interval targeted.
3. Additional difficulties:
– Depending on the severity of the leak, the tool might not be able to perform other functionalities like fluid injection or formation cleanup due to insufficient pressure control.
Identifying a non-sealing point:
There are various ways to identify a potential non-sealing point during an MDT operation:
Pressure response: If the pressure response during the setting process deviates significantly from the expected behavior, it can indicate a possible leak.
Fluid properties: Analyzing the collected fluid sample for inconsistencies compared to expected formation fluid properties might suggest contamination.
Real-time monitoring: Advanced tools provide real-time data on pressure, temperature, and other parameters, which can help identify deviations that might indicate a sealing issue.
Addressing a non-sealing point:
If a non-sealing point is suspected, several options can be considered:
Re-setting the probe: Sometimes, a slight re-positioning of the probe within the formation can improve the seal.
Moving to a different point: If re-setting fails, moving to a different location within the formation might be necessary.
Aborting the test: In extreme cases, if multiple attempts to establish a seal fail, the entire MDT operation might need to be aborted to avoid unreliable data and potential safety concerns.
 

What is the tie point in the pressure measurement meaning while MDT?
In the context of pressure measurement during an MDT (Modular Formation Dynamics Tester) operation, the tie point refers to a reference pressure datum used for interpreting and comparing pressure data acquired at different depths within the formation. It serves as a common reference point to account for any hydrostatic pressure exerted by the wellbore fluid column.
The concept:
Hydrostatic pressure: As depth increases in a wellbore, the pressure exerted by the weight of the fluid column above the tool also increases. This is known as hydrostatic pressure.
Formation pressure: The pressure of the fluids naturally existing within the formation, independent of the wellbore fluid.
Since the MDT tool measures the total pressure, which includes both the formation pressure and the hydrostatic pressure, a reference point is needed to isolate the formation pressure of interest.
Establishing the tie point:
There are two common approaches to establish the tie point in MDT operations:
1. Shut-in pressure at a non-reservoir zone: The pressure is measured at a depth within the wellbore known not to be connected to a reservoir. This pressure is assumed to represent solely the hydrostatic pressure at that depth.
2. Fluid gradient extrapolation: If a suitable non-reservoir zone is unavailable, the pressure data from multiple depths within the formation can be plotted, and the hydrostatic pressure gradient can be extrapolated to a chosen reference depth (usually the deepest measurement point) to estimate the tie point pressure.
Benefits of using a tie point:
Standardization: Allows for comparison of pressure data acquired at different depths within the wellbore by removing the influence of varying hydrostatic pressure.
Formation pressure interpretation: Enables the isolation and analysis of formation pressure, providing valuable insights into reservoir characteristics like pressure depletion or compartmentalization.


Hydraulic fracking and its impact on reservoir productivity?
Fracking, is a well stimulation technique widely used in the oil and gas industry to enhance the productivity of wells, particularly in unconventional reservoirs like shale formations.
Here’s how it impacts reservoir productivity:
Increased Permeability:
Fracture creation: Fracking involves injecting a high-pressure fluid (typically water mixed with proppant and additives) into a wellbore formation, creating fractures that extend several meters away from the wellbore.
Enhanced fluid flow path: These fractures act as conduits, increasing the effective wellbore area and providing a low-resistance pathway for oil and gas to flow from the reservoir rock matrix towards the wellbore.
Improved Drainage Area:
Larger reservoir volume accessed: By creating fractures, fracking allows the well to drain a larger volume of the reservoir compared to relying solely on the natural permeability of the rock.
Increased wellbore contact: The extended reach of the fractures increases the wellbore’s contact with the productive reservoir zone, leading to a higher influx of fluids.
Bypassing Formation Damage:
Natural flow impediments: Formations can experience damage due to drilling operations or naturally occurring minerals, hindering fluid flow.
Fracture bypass: Fracking can bypass these near-wellbore damage zones, allowing oil and gas to flow more freely from deeper within the formation.
Impact on Productivity:
Increased production rates: Due to the combined effects of increased permeability, improved drainage area, and bypassing formation damage, fracking can significantly boost well production rates, especially in low-permeability reservoirs where natural flow is limited.
Longer well life: By accessing a larger reservoir volume and mitigating formation damage, fracking can potentially extend the productive life of a well.
However, it’s important to consider the following points: Fracking is not effective in all types of reservoirs and needs careful evaluation based on reservoir characteristics.
 

Explain the different rock mechanics properties relevant to oil and gas production (e.g., Young’s modulus, Poisson’s ratio, permeability, etc.)?
1. Strength and Elasticity:
Young’s Modulus (E): This measures the rock’s stiffness or resistance to elastic deformation under stress. A higher Young’s modulus indicates a stiffer rock, less prone to deformation. Knowing this value is crucial for wellbore stability analysis and designing effective casing and completion strategies.
Poisson’s Ratio (ν): This ratio represents the proportionality between the rock’s strain in one direction (e.g., compression) and the strain in the perpendicular direction (e.g., expansion). It helps understand how the rock will deform under stress and is used in wellbore stability analysis and modeling.
2. Failure and Breakage:
Unconfined Compressive Strength (UCS): This measures the maximum stress a rock cube can withstand before fracturing under uniaxial compression. It helps assess the rock’s ability to resist fracturing during drilling and production activities.
Tensile Strength: This is the stress required to pull a rock apart. While not directly measured as often, it provides insights into the rock’s susceptibility to fracturing, especially during hydraulic fracturing operations.
3. Fluid Flow:
Permeability (k): This property signifies the ability of a rock to allow fluids to flow through its pore spaces. It’s a crucial parameter for evaluating reservoir productivity and designing production strategies. Higher permeability facilitates easier fluid flow towards the wellbore.
Porosity (φ): This represents the percentage of void space within a rock that can be occupied by fluids. While not directly affecting flow rate, porosity is often used alongside permeability to estimate reservoir fluid volume and potential production.
4. Other Important Properties:
Brittleness: This is an indicator of a rock’s tendency to fracture rather than bend under stress. A higher brittleness value suggests a higher likelihood of fracturing during stimulation techniques like hydraulic fracturing.
Thermal Expansion: This property describes the change in rock volume due to temperature variations. It’s relevant for wellbore stability analysis, as significant temperature changes during drilling and production can induce stresses in the formation.
 

Pressure drawdown test process?
This is the difference between the reservoir pressure (shut-in bottomhole pressure) and the pressure at the wellbore (flowing bottomhole pressure) when fluid is being produced. Higher drawdown pressure means a stronger force pulling fluid towards the wellbore.
A pressure drawdown test is a method used in the oil and gas industry to evaluate the properties of a reservoir and well. By analyzing the pressure data obtained from a drawdown test, engineers gain valuable insights into the reservoir’s ability to produce fluids.
Preparation:
-Well shut-in: The well is shut down and isolated from production for a specific period. This allows the reservoir pressure to reach equilibrium throughout the formation. The duration of this shut-in period depends on various factors like reservoir characteristics and desired test objectives.
-Equipment installation: Downhole pressure gauges and other monitoring equipment are deployed in the wellbore. These tools record the pressure changes during the test.
Drawdown phase:
–Production initiation: The well is opened for production at a constant flow rate. This creates a pressure reduction around the wellbore, known as drawdown.
-Pressure monitoring: During production, the downhole pressure gauges continuously record the pressure decline at various time intervals. This data is crucial for analyzing reservoir properties
Data analysis:
-Pressure interpretation: Once the test is complete, the collected pressure data is analyzed using specialized software and wellbore flow models. This analysis helps identify characteristics like:
Reservoir permeability: This indicates the ease with which fluids can flow through the rock formation.
Skin factor: This reflects any damage or impairment near the wellbore that affects flow.
Reservoir pressure distribution: This provides insights into the pressure behavior within the formation.
 

The other questions:
 
1D, 3D & 4D geomechanics workflow
Seismic acquisition & interpretation
*What is the tie point in the pressure measurement? The point should be good, or not stable, or tied, or not sealed, what is the tie point means?
 
Production from a well unexpectedly declines. What steps would you take to diagnose the problem and propose solutions?
The drilling team encounters unexpected pressure while drilling through a formation. How do you balance operational safety with obtaining geological information?
You have conflicting interpretations of reservoir properties from seismic and well log data. How do you reconcile these differences and make informed recommendations?
Describe your experience working with drilling and production teams to optimize wellbore operations.
 
2. Describe the various types of wellbore stability issues (e.g., borehole collapse, fracturing, sand production) and their mitigation strategies.
3. How do you perform a geomechanical analysis of a reservoir for hydraulic fracturing operations?
4. Discuss the factors influencing subsidence and its implications for surface facilities and infrastructure.
5. Explain the role of numerical modeling in geomechanics applications for oil and gas projects.
6. Walk through the process of designing a casing and cementing program for a wellbore.
7. Describe the methods used to monitor wellbore integrity and identify potential geomechanical risks.
 
Problem-solving and Decision-making:
 
1. You encounter unexpected pressure during a drilling operation. How do you assess the situation and recommend appropriate actions?
-Situation: During a recent hydraulic fracturing job in a tight formation, we observed abnormally high fracture pressure exceeding our pre-job predictions.
 
Task: I was responsible for evaluating the geomechanical stability of the wellbore and recommending mitigation strategies.
 
Action: I performed the following:
 
Analyzed wellbore logs and seismic data to assess formation properties and fracture geometry.
Conducted numerical simulations to model the stress distribution and potential fracture propagation.
Consulted with the drilling and reservoir engineering teams to gather operational data and discuss alternatives.
Result: Based on the analysis, I recommended adjusting the fracturing fluid pressure and flow rate to maintain controlled fracture growth and preventing wellbore instability. This approach mitigated the risk of uncontrolled fractures and allowed for successful completion of the stimulation operation without compromising wellbore integrity.
 
 
2. An offshore platform experiences increased subsidence. What steps would you take to diagnose the cause and propose solutions?
3. A hydraulic fracturing operation results in induced seismicity. How do you analyze the data and manage the associated risks?
4. The wellbore trajectory needs to be modified due to geological complexities. How do you ensure the revised geomechanical stability of the wellbore?
 
Communication and Teamwork:
 
1. Describe your experience working with drilling, production, and reservoir engineering teams to optimize wellbore design and operations.
2. How do you effectively communicate complex geomechanical concepts to non-technical personnel?
3. Give an example of a time when you collaborated with colleagues to develop a geomechanics solution for a production issue.
4. How do you manage conflicting data or interpretations within a project team?
5. Describe your approach to written and verbal reporting of geomechanics analyses and recommendations.
 
Industry Awareness:
 
1. Discuss the current trends and challenges in geomechanics applications for oil and gas production.
2. What are the regulatory requirements pertaining to geomechanics in your region?
3. How do you stay up-to-date on new technologies and advancements in geomechanics engineering?