Data Engineer Interview
Questions and Answers
General Questions
Q.1 What are job responsibilities of a data engineer:
Ans. Being manager of the mudlogging unit, a data engineer has multiple responsibilities, important among these are:
1. Ensure unit is running smoothly and safely. All sensors and equipment are functioning and properly calibrated. All safety protocols are being followed by the mudlogging team.
2. Prepare different types of reports and logs including pressure logs and hydraulics reports.
3. Discuss drilling related issues with client and drilling supervisor
4. Participate and guide team in rigging up and rigging down mudlogging unit
5. Participate in various technical and safety meetings.
Q. How does an onshore rig up differs from an offshore rig up?
Ans. Rigging up of mudlogging unit in onshore environment is rather temporary in nature. For each well MLU has to move from location to location. Therefore, cables are not always run on trays. Ample space is available so no issues in placing extra containers and consumables. Space on offshore rig is a constraint therefore, spares and consumables are to be squeezed inside unit. Offshore rig up is more permanent in nature, the unit may be there for 1 to 2 years or even more. Therefore cables are run along the trays and sensors are welded and secured more tightly. Safety and precautions are always at higher level due to limited space to move around.
Q. Which oil field has been most difficult for you to drill so far? What challenges did you face?
Ans. Mention the most difficult field that you have experienced with regard to geological and drilling related problems eg. Overpressure, mudlosses, pipe sticking, sidetracks etc. and be able to discuss those problems in detail. Also mention what have learned there. Do not mention problems related to mudlogging unit and equipment and how you solved them. That is not the intention of the question.
Q. What are the latest advancement in mudlogging operation / What are the advance tools that have been recently added to latest and most advanced mudlogging units?
Ans. New techniques included in the latest mudlogging units are: (1) high frequency, improved accuracy monitoring of drilling parameters (2) enhanced cuttings image acquisition and processing (3) direct measurements on cuttings, including grain-density, spectral GR, NMR, XRD, XRF and (4) sophisticated mud gas analysis capabilities.
Q. What are drilling related problems that you have encountered with clay, claystone and shale?
Ans. Gumbo blocking flow line, possum belly and shale shaker
Claystone being very plastic formation creates hole ballooning affect if mud weight is high. It can also swell and create tight hole condition
Q. What are the surface-controlled drilling parameters that effect ROP?
Ans. Many parameters such as WOB, RPM, Flow Rate, mud hydraulics, MW and Bit Size do effect rate of penetration.
Q. What are drilling related factors that may influence gas readings?
Ans. 1. ROP 2. Hole Size 3. Flow Rate 4. Degasser Efficiency 5. Differential pressure 6. Surface losses. Increasing first four parameters will tend to increase gas readings; while increasing the last two parameters will tend to decrease gas readings.
How does temperature data help us in detecting over pressure zone?
Ans. As heat flows from center of the earth to surface of the earth, the geothermal gradient increases with depth almost at constant rate but if an overpressure zone is encountered the geothermal gradient increase at a faster rate than in normal pressure zone. The reason for that is that overpressure zones are under-compacted (more porous), therefore they contain more water. As water is bad conductor of heat it mostly retains the heat instead of passing all of it upward. This is why, the temperature gradient increases at a faster rate inside over pressure zone. This is also the reason why we encounter a lower than normal temperature gradient (zone of heat starvation) just above the overpressure zone. This layer sometime called seal, is usually compact and hard with negligible porosities and permeabilities.
More over please note, the mud temperature-out-data as recorded by mudlogging unit is affected by a number of factors, therefore it is advisable to be extra careful in tracing geothermal gradient. Perhaps plotting temperature data from MWD tools may yield better results.
Q. If a sensor is giving suspicious readings how would you trouble shoot it?
Ans. . Logical steps usually taken are: First have a look at the sensor for its displacement or physical damage as well as check its response or functionality. If that is OK, check for the integrity of cable and connections. If all things look good so far, check and recalibrate sensor. If the problem still persists call for technical assistance from town, there may be problem with electronic channel or PCB.
Q. How does chromatograph separate C1, C2, C3 etc. from the gas mixture that is coming from degasser?
Ans. A chromatograph contains usually two spring shaped aluminum tubes called columns, which are usually filled with micro-beads of silica. These silica beads are tightly packed in such a way that a low permeability or a tortuous path is created for the gases to pass through. Therefore, lighter gases like C1, C2 move ahead followed by heavier gases like C3, C4 and C5. Thus, the gas mixture is broken down into its components.
Q10. How do you evaluate formation for hydrocarbons using mudlogging data?
Ans. By checking lithology characteristics, evaluating oil shows and looking at chromatographic analyses. We may also do gas ratio plots to have an idea about nature of reservoir fluid. Gas ratio plots are more reliable if we are using constant volume degasser.
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Q . What is hole ballooning? What causes it? How can it mislead us into wrong MW strategy?
Ans. Formation ballooning happens in weak rocks (plastic formations) during drilling. Two mechanisms are cited for this to happen:
Drilling fluid escapes into microfractures in the rock when the pumps are on, then flows back when they’re off.
The hole section against plastic formation gets enlarged due to high hydrostatic pressure when the pumps are on. When pumps are off the hole section gets back to normal size and extra mud is expelled out.
This can be mistaken for a well kick, increasing MW only worsen the situation, leading to wasted time. Monitoring fluid levels and keeping ECD low can help prevent hole ballooning.
Notes:
Formation Ballooning in Oil Well Drilling
Formation ballooning, also known as wellbore breathing or micro-fracturing, is a phenomenon that occurs during drilling in weak formations, especially those with pre-existing microfractures. It’s characterized by the wellbore temporarily losing drilling fluid while the pumps are on and then regaining the fluid when the pumps are shut off.
Here’s a breakdown of the process:
ECD Exceeds Formation Strength: When drilling fluid is circulated (pumps on), the Equivalent Circulating Density (ECD) increases. If the ECD exceeds the pressure required to open the formation’s microfractures, some drilling fluid escapes into these fractures.
Fluid Loss and Misinterpretation: This fluid loss can be misinterpreted as a kick (influx of formation fluids like oil or gas) from the wellbore. However, in ballooning, the influx is just the return of the previously lost drilling fluid.
Pumps Off, Fluid Returns: When the pumps are turned off, the ECD drops because there’s no longer additional pressure from circulation. This decrease in pressure allows the microfractures to close, forcing the trapped drilling fluid back into the wellbore.
Implications of Formation Ballooning
Ballooning can lead to several issues if not properly identified and managed:
Misdiagnosis as a Kick: Mistaking ballooning for a kick can lead to unnecessary well control procedures, wasting time and resources.
Exacerbating the Problem: Standard well control procedures for a kick often involve increasing mud weight. In ballooning, this can actually worsen the situation by further opening the microfractures and causing more significant fluid loss.
Delayed Drilling Progress: Fluid loss and regaining control can significantly slow down drilling operations.
Formation Damage: Excessive ballooning can damage the formation by enlarging the microfractures, potentially impacting reservoir quality.
Dealing with Formation Ballooning
Here are some strategies to address ballooning:
Close Monitoring: Carefully monitor drilling fluid volumes and pressures during circulation and connection breaks (when pumps are off) to identify ballooning patterns.
ECD Management: Maintain the ECD below the formation’s fracture pressure to avoid creating new fractures and minimize fluid loss.
Drilling Fluid Selection: Utilize drilling fluids designed for weak formations, which may help to minimize fluid loss into the microfractures.
By understanding formation ballooning and implementing proper mitigation strategies, drillers can avoid unnecessary well control procedures, maintain wellbore stability, and ensure efficient drilling progress.
Q. It is said that there is an inverse relationship between RPM and formation compressive strength. What do you understand by this statement?
Ans. It simply means that in soft formation faster the RPM faster will be ROP but in hard formation slower RPM favours faster ROP. Lower RPM and WOB in very hard formation avoids premature bit worn out.
Q. How can we find out mud pump efficiency?
Always run a carbide test when drilling out casing shoe. At this time the entire mud circulation is within the casing the diameter of which is known precisely. The difference between the calculated and actual lag time can be attribu1ted to pump efficiency. This pump efficiency (as factor or percentage) will then always be applied for the forthcoming open hole section. It is unlikely to change unless the drillers change the liner of the pump and/or its pistons.
Note that this pump efficiency was calculated for one of the two pumps or both pumps running together. The pump efficiency needs to be established again if any of the relevant parameters (number of pumps running, speed, liner size, etc.) is changed. (See also page 82).
n practise, cutings will always be late realtive to the nominal lag time and gas can be early. The difference between the calculated lag time depends on cuttings size and density, the mud density and the annular velocity and type of flow (laminar or turbulent).
Q. Sometimes we drill very high quality sand reservoirs full of oil, yet we do not see oil fluorescence in the cutting. What could be a logical explanation for that?
Ans. If the oil reservoir is made up of coarse sandstone, which is poorly consolidated, then the sand gains become loose during their transportation in the annulus and gets thoroughly washed specially if the mud is oil based. Hence we do not see oil fluorescence.
Q. What are three important rock types that are required to form commercial hydrocarbon accumulations?
A. The source rock. The reservoir rock. The cap rock.
Theory & Concepts of Formation Pressure
Q. What is normal formation pressure? How does it originate?
Ans. A formation pressure is said to be normal if it is equal to hydrostatic pressure at any given depth. Only one condition is required for its origin, that is all the pore spaces (hence the fluid in them) should remain vertically inter-connected all the way to surface.
When sediments are deposited in a water body, the pore spaces are large and filled with water. With continued deposition of sediments and increasing weight of overlying sediments, the sediments at the bottom part keep getting compacted with reducing effect on porosity. As porosity reduces, extra water gets expelled only if the pores are inter-connected to surface. In this normal situation, since the pores and water in them are interconnected to surface, the water at any depth bears the weight of the overlying water only therefore, the pressure on the fluid in the pore spaces remains hydrostatic. In terms of equivalent MW, 8.33 ppg to 9ppg depending on the salinity of water.
Q What is abnormal formation pressure? How does it originate?
Ans. Any formation pressure that is either less than normal formation pressure or more than normal formation pressure is called abnormal formation pressure. When the formation pressure is less than normal formation pressure it is called subnormal or depleted formation pressure. This type of pressure is often encountered in hydrocarbon reservoirs of old oil and gas fields, which have been under production for many years. Due to over-production sometimes the pore pressure or the reservoir pressure gets depleted down to 2.5 ppg. You should exercise utmost caution, If you are going to drill a new development well in an old field that has been under active production for many years. While drilling, depleted porous and permeable reservoirs create significant differential pressure that can cause differential sticking of drill pipe or wireline.
Formation pressure that is more than normal formation pressure (>9ppg Eq.MW) is called overpressure. Overpressure is not a random occurrence; it’s a consequence of various geological processes. Here are some key mechanisms that lead to overpressure generation:
Compaction Disequilibrium: In basins of rapid sedimentation such as in deltaic regions, sometimes layers of clay/claystone /shales get quickly deposited. Being impervious rocks these beds block the vertical movement of formation fluid. Formation fluid thus trapped had to bear not only the weight of overlying fluid but also the vertical stress, that is the weight of overlying solid rock grains called matrix. (The two downward acting pressures are collectively called overburden pressure). This application of extra pressure on normally pressured formation fluid creates overpressure or abnormally high formation pressure.
Faults and Aquifer Compartmentalization: Imagine a sandstone reservoir at 4500ft TVD with normal formation pressure (2000 psi / 8.56 ppgEMW). Later due to reverse faulting the sandstone with its formation pressure of 2000 psi moves up to 3500 ft TVD. Due to sealing nature of fault plane and sand bed’s juxtaposition against shale, the pore pressure in the sandstone of hanging wall side would remain at 2000 psi (10.99 ppgEMW). In other words if you are drilling at 4500 ft tvd. on footwall side you will require approximately 9.0 ppg MW but if you are drilling on hanging wall side you will need to have 11.5 ppg MW at 3500’tvd to drill through the sandstone safely.
Tectonic Activity: Mountain building and other tectonic forces can compress formations, squeezing pore fluids and elevating pore pressure.
Diagenetic Processes: Chemical reactions within formations can release fluids that contribute to overpressure, particularly during the conversion of organic matter to kerogen. Another example of diagenetic process is the conversion of montmorillonite to illite with increasing depth. This process also releases water that has to be squeezed in the limited pore space available, which further increases formation pressure.
Hydrocarbon Generation: The very process of hydrocarbon generation, especially the creation of methane gas, which tend occupies larger volume in pore spaces can significantly increase pore pressure.
Understanding these mechanisms allows geologists to carefully select pressure predicting tools and avoid pitfalls.
Notes: Formation pressure remain normal as long as the fluid in the pore spaces remains under the hydrostatic pressure of overlying fluid in the interconnected pore space. However, nature sometimes applies extra pressure from various sources to increase normal pressure to abnormally high pressure. This extra pressure may come in the form of overburden pressure due to compaction in equilibrium or in the form of horizontal stress from regional tectonic activity or due to due to diagenetic process which create extra fluid that has to be accommodated within the existing pore volume.
Q. Can you briefly summarize the conclusions of current research papers on origin of overpressure? OR, What is recent thinking on the origin of overpressure?
Ans. A casual look at recent research papers on the subject of overpressure origin seems to suggest the followings:
1. Multi-causation nature of overpressure: Overpressure is a result of a combination of geological processes rather than a single cause. The dominant mechanisms contributing to overpressure generation include Compaction Disequilibrium, Faults and Aquifer Compartmentalization, diagenetic processes, regional tectonic activity, hydrocarbon generation.
2. Basin level study: Current researches tend to cover entire basin rather than a small area or a field. This allows the study of multiple causes at play to generate overpressure.
3. Current researches are making use of analytical modelling techniques, sophisticated algorithms and AI to get better understanding and make more accurate overpressure prediction.
Q. What drilling problems are caused by excessively high hydrostatic pressure ( excessive overbalance) in the hole?
Ans. If we use very high MW without any reason, following problems will occur:
1. Slow drilling progress
2. Seepage to total mud loss
3. Damage to formation, that may result in poor quality electric logs and pressure tests
4. High differential pressure may lead to differential sticking of drill pipe and wireline.
Q20. What drilling problems are caused if hydrostatic pressure becomes less than formation pressure?
Ans. If underbalanced situation is created in the hole, it may result in the following drilling related problems:
1. Kick that may lead to blow out
2. Instable hole condition generating large amount of cavings and total gas
3. Less than required hydrostatic pressure may lead to hole collapse that may cause mechanical stuck up.
Q. What is overburden pressure? Why do we need to calculate it?
Ans. Overburden pressure or overburden stress is a pressure exerted by the overlying rocks (matrix + fluid). Knowledge of distribution overburden stress is important to estimate formation pressure and formation fracture gradient. In tectonically inactive areas the least principal stress + Formation pressure = Fracture pressure
Overburden Stress gradient is also used to calculate Formation pressure and formation fracture pressure. However it should be noted that use of overburden stress values require complex calculations and complex models to get meaningful results.
Q. Can you explain the concept of overburden stress distribution in subsurface rocks?
Ans. Sedimentary rocks are always subjected to very complex set of forces, we may call them stress fields. These forces or stresses are generated due to overlying rocks (Overburden), regional tectonics and gravity.
Knowing the distribution and orientation of stresses on a given sedimentary rock that is buried in the earths crust is extremely difficult. Therefore for oil field related calculations we use a simple model of stress distribution. This simplified model assumes that at any given point on sedimentary rock in a wellbore, the forces act from thee different directions; one vertical (principal stress vertically acting from top to bottom, this is called Principal Vertical Axis, which shows the maximum value of stress) and two horizontal axes (one may be assumed from right to left and the other from front to back. Of these axes one is intermediate in value and the other is least in value ). It is extremely difficult to calculate the values of stress in X,Y or Z directions by a data engineer. Therefore based on various studies and calculation it is agreed that least principal stress axis is 1/3 of vertical stress axis (maximum stress). 1/3rd is actually a ballpark number. It may vary from area to area from ½ to ¼ of vertical stress. Poisson’s ratio provide more accurate number to calculate least principal stress.
The importance of knowing least stress axis and its value is that it is needed in calculating fracture pressure:
Fracture pressure = Least stress value + FP
Any way in summary: maximum vertical stress (S) is calculated from average bulk density (using wireline density log). S is than divided by Poisson’s ratio or if poisson’s ratio is unknow than by 0.33 to get least stress. Least stress value plus formation pressure will give the Fracture Pressure.
Why do we need to know fracture pressure? So that we do not increase hydrostatic pressure (or MW) in the hole to the point where it can fracture formation and cause mudloss or if circulating out a kick, do not cause underground blow out.
Performing LOT serves the same purpose. It tells us at what pressure formation will fracture just below the shoe (that being the weakest point in the entire open hole section). So we never try to increase hydrostatic pressure near to fracture pressure.
What is Poisson’s ratio? Why do we need to know Poisson’s Ratio?
Poisson’s ratio is the ratio between vertical and horizontal stress. Knowing poisson’s ration correctly we can calculate least principal axis more accurately.
Q. What are three different operations that tell you the exact formation pressure?
Ans. 1. Wireline formation pressure tests
2. DST or production tests
3. Kicks
Q. What are common logs that are used to pick overpressure zone by data engineers during the course of drilling.
Ans. There are many logs but more common are d’exponent, sigma log, sonic log, density log and resistivity log.
Q. What key characteristics of an overpressured zone do pressure logs focus on to identify high-pressure formation?
Ans. Allpressure logs exploit the most important characteristic of all overpressure zones, that is their under-compactness due to trapped fluid. This is why overpressure zones tend to drill faster, have comparatively lesser density, lower resistivity and lower sonic speed. These are typical characteristics of an overpressure zone that pressure logs take advantage in picking high pressure formations. Any sustained deviation from the normal trend is suspected due to overpressure. A rough rule of thumb is: More the deviation from the trend, more the formation pressure.
Q10. What is d’exponent? How does it pick an overpressure zone?
Ans. Drilling exponent plot reflects the drill-ability (ROP) of formation as per its compaction alone. During drilling ROP depends on many factors such as compaction or density of formation, WOB, RPM, FR, Bit size, MW etc. D’exponent equation removes the effects of surface controlled parameters (such as WOB, RPM, Bit size, FR and MW) to calculate ROP as per the compactness of formation. As the hardness of rocks increases with depth the drill-ability of rocks slows down. Therefore any deviation from slowing trend indicates under-compaction or overpressure zone.
Q. What is Sigma Log? How does it differ from d’exponent?
Ans. A sigma log is another tool like d’exponent that is some time used to pick overpressure zone by data engineers. Sigma log also uses drilling parameters like ROP, hole diameter, RPM and WOB to calculate rock strength in psi. Many corrections are applied to the basic equation to arrive at final equation called sigma 0.
The basic principle of Sigma log is same as D’Exponent, that is the compaction or the strength increases with depth, however when an undercompacted zone or low strength formation is encountered the plotted trend shifts to left indicating overpressure. The difference between d’exponent and sigma log, therefore lies in the approach not in the end result.
While d’exponent requires a thick shale formation to set the trend; Sigma log is independent of shale. It therefore works very well in limestone. D’exponent takes into consideration bit type whereas ,Sigma log does not.
Q. How do you pick overpressure zone using electric logs such as density log, resistivity log and sonic log?
Ans. Electriclogs are normally plotted on 1/500 scale to see the physical characteristics of rocks in detail. However it is not possible to see the compaction trend on this scale. Therefore we plot electric logs data (mainly sonic density and resistivity) on a compressed scale eg. 1/10000 scale. On this scale it is easy to see the normal compaction trend with depth. Any deflection from normal trend would most probably be due to under-compaction or overpressure. Sonic, resistivity and density data now days can be acquired in real time from LWD logs.
Notes:
As the depth increases the formations become more and more compact and dense. We know that sonic waves travel faster in harder rocks and slower in softer formations. Therefore if we plot sonic velocity against depth we will see a trend of increasing velocity but if we encounter an overpressure zone (undercompacted formation) the sonic velocity will decrease. This deflection in compaction trend will indicate an overpressure zone. Similarly density and resistivity will increase with the as formations become more and more hard. However if an undercompacted or overpressure zone is encountered both density and resistivity will start decreasing and will shift away from normal compaction trend, making it easy to pick overpressure zone.
QUESTIONS ON BASIC EQUATIONS TO CALCULATE FORMATION PRESSURE
Q30. What are different methods used to calculate overpressure using log data?
Ans. There are three commonly employed equations that can be used on d’exponent and electric log data to calculate formation pressure. These are:
Equivalent Depth method
Ratio Method
Eaton Method
Please do not delete this field. After duplicating this field I add more questions and answers
Q. What is Equivalent Depth Method used to predict formation pressure?
Ans. Here the underlying principle is that for any point at depth A in under-compacted zone there exist a similar level of normal compaction at shallower depth B. And that the formation pore fluid at point A is subjected to overburden stress that exists between points A to B. Therefore this method requires the knowledge of Overburden Stress Gradient.
The following equation has been designed to estimate formation pressure:
FP at Depth A = Overburden gradient at Depth A – (TVD at depth B / tvd at depth A) x (overburden gradient at depth B – Formation pressure at depth B)
If not known from local area, S can be taken as 2 to 2.31 and FP at depth B as normal 1.05 sg
Example:
Depth at A = 3000m
Depth at B = 2800m
Overburden gradient at A (S) = 2.2 sg
Formation Press at point B= 1.05
Overburden gradient at B = 2.0 sg
2.2-(2800/3000) x 2.0 – 1.05
2.2 – 0.93 x 0.95
2.2 – 0.886
FP at depth 3000m = 1.314 sg
Q. How does Ratio Method predicts overpressure?
Ans. Ratio Method is based on the idea that the difference in the values of DCN (normal trend) and DCS (calculated value of D’Exponent) is proportional to increase in formation pressure. The more the distance or difference in values more would be the formation pressure. Following is the mathematical expression of this method:
PF = H x (DCN/DCS)
In some cases a correction coefficient is added to make the equation more flexible:
PF = C x H (DCN/DCS)
The correction coefficient remains same as long as the cause of overpressure condition remain same.
Q. What is Eaton Method commonly used to predict formation overpressure?
Ans. The Eaton method is based on the observation that the changes in the overburden gradient govern the ratio between the observed and normal values of a given parameter. This method is commonly applied on d’exponent, sonic log data, density log data and resistivity log data.
D’Exponent Equation
PF = S – (S – H) (DCS/DCN)^1.2
Sonic Equation
PF = S – (S – H) (delta t normal / delta t observed)^3.0
Resistivity Equation
PF = S – (S-H) (Rsh normal / Rsh observed)^1.2
Example:
D’exponent equation: (Eaton Method)
FP = S – [ (S – nFP) x (dco / dcn)^1.2]
Where:
FP = Formation Pressure
S = Overburden Stress (MWE) 19.0 ppg
nFP = Normal formation pressure (MWE) 8.5 ppg
dco = Observed d’exponent = 1.0
dcn = Normal d’exponent = 1.5
Example of calculation:
FP = 19 – [ (19-8.5) x (1.0 /1.5)^1.25]
FP = 19 – (10.5 x 0.602)
FP = 19 – 6.321
FP = 12.68 ppg (EMW)
Q. How do we calculate Over Burden Pressure?
Overburden stress (S) Formula:
S = s + P
where
S = Overburden
s = Matrix Stress (vertical stress)
P = Pore Pressure (Formation Pressure)
S is usually taken from field average data catalogue or calculated at site using density log.
S(z) = g * integrale (z) (ρ(z) dz)
where:
S(z) is the overburden stress at depth z
g is the acceleration due to gravity (approximately 9.81 m/s²)
ρ(z) is the bulk density of the formation at depth z (obtained from the density log)
integrale (z) (ρ(z) dz) represents the definite integral of the bulk density function with respect to depth z
Explanation:
Density Log: This wellbore logging tool measures the density of the formations around the borehole.
Integration: The formula essentially performs a summation of the product of density and a small depth increment throughout the entire depth interval of interest (z). This summation approximates the total weight of the rocks above a specific depth.
Gravity: The acceleration due to gravity (g) converts the calculated weight into a stress value (force per unit area).
Pore pressure calculation from sonic logs:
During drilling pore pressure calculation can be done using sonic logs (from LWD). Sonic transit time, DT (micro seconds / foot), will decrease with depth as the compaction of the formation increases due to reduction in porosity. Sonic is plotted against tvd. on semilog paper. The plot will show decreasing trend with depth, (increasing trend if sonic velocity ft/second is plotted, however sonic velocity is usually not used for FP calculation). The deviation from the normal trend is taken as an indication of overpressure. For approximate formation pressure following Eaton Equation is used:
FP = S – (S – nFP) x ( DTn / DTo)^3.0
Where:
FP = Pore Pressure
S = Overburden
nFP = Normal Pore Pressure
DTn = Normal Sonic DT
DTo = Observed Sonic DT
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Pore pressure calculation from resistivity logs:
Solid rock matrix has very high resistivity. With depth as compaction and density increases, porosity reduces, this causes resistivity to increase with depth. Any reduction in the resistivity could be due to under-compaction and high porosity, which is a very significant characteristic of overpressure zone
Bear in mind that resistivity may also change due to changes in salinity in pore water. Resistivity logs are frequently used to calculate formation pressure as LWD logs are available in real time. Following is Eaton’s Equation to calculate formation pressure from resistivity data:
FP = S – (S – nFP) x ( Rn / Ro)^1.2
Where:
FP = Pore Pressure
S = Overburden
nFP = Normal Formation Pressure
Rn = Normal Resistivity
Ro = Observed Resistivity
Q. What are some of the main limitations of conventional methods in formation pressure evaluation?
All types of log methods for real time formation pressure evaluation are based on one assumption:
That every well has a thick section of shale with increasing compaction, on which a normal trend line can be set. Any departure from normal compaction can be taken as indication of overpressure zone. Simple equations are designed to handle this simple assumption.
However, in real world we do not always encounter best case scenario. The absence of a thick section of shale may pause a problem in setting the trend line or presence of fault may suddenly bring you abnormally high pressure face to face without any warning or a silent tectonic activity going on in the area may bring you sudden surprises. More and more current researches are supporting multi-causal origin of overpressure. Therefore without having a comprehensive knowledge of the field, pressure engineers and data engineers may not defend there calculations and estimations of overpressure.
Q. As a pressure engineer or data engineer, what should be your approach in estimating overpressure and advising drilling supervisor on appropriate MW?
Ans. We should not form our opinion based on any single indicator but should carefully take wholistic view before coming to a conclusion. That is we should look at all the indicators such as pressure logs, density log, shale factor plots as well as empirical observations before advising client on MW. In my opinion empirical observations of an experienced pressure engineer or data engineers and wellsite geologists are more important and should be used to calibrate pressure logs such as d’exponent, sonic log, density logs and resistivity logs.
Q. What are empirical observations on drilling parameters that will convince you that we are drilling through an overpressure zone?
Ans. There are many empirical observations like increasing ROP trend, increasing total gas trend, appearance of connection gas and pump off gas, appearance shale cavings (pressure cavings), increase in torque and drag on connections. Presence of all or most of these indications is a sure sign of overpessure zone
Q. What do you mean by LCT or SIT? When and how do we perform this test?
Ans. Long connection test (LCT as called by Total Indonesie) or Static Influx test (SIT as called by Chevron) are two different terms for the same test. This test is performed in overpressure zone to have an idea how closely hydrostatic pressure is balancing formation pressure. Both LCT and SIT are performed in exactly the same way. After stand down, the well is circulated for ten minutes to get rid of any formation gas. Then the circulation is stopped for five minutes while very slowly reciprocation drill pipe. This to allow formation gas to flow into the bore hole under static
Q. What are geochemical methods that help us in picking overpressure zones during the course of drilling?
Ans. Geochemical methods offer valuable clues about overpressure zones while drilling by analyzing the formation fluids and drilled cuttings. Here are some key techniques:
1. Analysis of Formation Gas Composition:
Wet Gas Indicators: Increased concentration of C3 gas compare to C2 (C3/C2 ratio) can indicate maturation of organic matter at elevated temperatures often associated with overpressured zones. Non-hydrocarbon Gases: Presence of gases like nitrogen (N2) or carbon dioxide (CO2) can point towards specific overpressure mechanisms, such as igneous intrusions releasing N2 or organic matter breakdown generating CO2.
2. Clay Mineral Analysis:
Illite/Smectite Ratio: Transformation of smectite clay to illite happens at higher temperatures and pressures. An increased smectite content in cuttings compared to illite (shale Factor performed by titration) suggests a possibility of encountering an overpressured zone.
3. Vitrinite Reflectance (VR):
VR measures the amount of light reflected by organic matter (vitrinite) in cuttings. Higher VR values indicate greater thermal maturity, that is expected to increase with depth (increasing pressure and temperature). Overpressure is known to supress thermal maturity and VR. Therefore lower than expected VR could be linked with overpressure zone. (Not always a reliable indicator nor the method is used in mudlogging units).
Q 40. What are the advantages and disadvantages of d’exponent in over pressure detection?
The d-exponent (also known as corrected d-exponent or dc-exponent) is a well-established method in mudlogging for overpressure detection. Here’s a breakdown of its advantages and disadvantages:
Advantages:
Simplicity: The calculation for d-exponent is relatively straightforward, requiring readily available drilling parameters like Rate of Penetration (ROP), rotary speed, Weight on Bit (WOB), bit diameter, and mud weight.
Real-time monitoring: d-exponent can be calculated continuously while drilling, allowing for quick identification of potential overpressure zones.
Trend analysis: By plotting the d-exponent value against depth, mudloggers can identify deviations from the expected trend, which might indicate a transition to an overpressured formation.
Cost-effective: Since it relies on existing drilling data, d-exponent doesn’t require additional downhole tools or complex measurements, making it a cost-effective approach.
Disadvantages:
Limited applicability: The d-exponent method is primarily based on the concept of normal compaction in shale formations. It might not be as accurate in formations like carbonates or sandstones with different compaction behavior.
Mud weight dependence: The original d-exponent calculation doesn’t account for changes in mud weight. The corrected d-exponent (dc-exponent) addresses this, but requires additional considerations.
Indirect indicator: d-exponent is an indirect indicator of pore pressure. Deviations can be caused by factors other than overpressure, such as changes in formation properties or drilling efficiency.
Limited accuracy in complex wells: In tectonically active areas d’exponent is not effective tool. Also in highly deviated or horizontal wells, the d-exponent might not accurately reflect the downhole stresses due to the influence of wellbore geometry on drilling parameters.
Overall, the d-exponent remains a valuable tool for mudlogging, especially in conjunction with gas readings and other pressure logs using sonic and resistivity data. The simplicity and real-time monitoring capabilities make d’exponent a good starting point, but its limitations should be kept in mind in complex situations.
Q. What are the characteristics of geological basins prone to overpressure?
Geological basins with specific characteristics are more prone to developing zones of overpressure. Here’s a breakdown of these key features:
Basin History:
Rapid Burial: Basins with a history of rapid sedimentation lead to quick burial of organic matter and pore fluids. This rapid burial can trap fluids before they have a chance to escape, leading to overpressure.
Limited Fluid Expulsion: The presence of impermeable layers like caprocks or salt domes can hinder the natural expulsion of pore fluids during compaction. This trapped fluid contributes to overpressure development.
Tectonic Activity: Tectonic processes like compressional forces or strike-slip faulting can cause pore pressure imbalances within the basin. This can lead to localized zones of overpressure.
Basin Geochemistry:
Presence of Source Rocks: Basins rich in organic matter-rich source rocks have the potential to generate hydrocarbons during thermal maturation. This gas generation can significantly increase pore pressure within the formation.
Sedimentary Processes:
Predominance of Fine-Grained Sediments: Basins dominated by fine-grained sediments like shales have lower permeability compared to coarser formations like sandstones. This low permeability restricts fluid flow and hinders pore pressure equilibration, promoting overpressure development.
Additional Factors:
Diagenetic Processes: Chemical and physical changes occurring within the basin rocks, like the transformation of smectite clay to illite, can indicate past exposure to elevated temperatures and pressures associated with overpressure.
Hydrodynamic Regimes: Basins with restricted fluid flow due to factors like limited connection to external fluid sources or compartmentalization by faults can experience overpressure development.
By understanding these characteristics, geologists can identify basins with a higher risk of encountering overpressure zones during drilling operations. This allows for proactive well planning and implementation of appropriate drilling practices to ensure wellbore stability and safety.
It’s important to note that these characteristics often occur together, and the likelihood of overpressure increases with the presence of multiple factors.
Can a shallower zone become overpressured by getting a recharge from deeper formation?
Ans. Shallower porous formation may some time get recharged from deeper formation through fault plane, fractures or through conduits along the poorly cemented casing of an old well. The deeper formation may have normal pressure but the same pressure at shallower depth will behave abnormally very high. These recharged zones and zones that get uplifted due to faulting are very difficult to pick on d’exponent or on other pressure logs. Unless one has prior warning from the offset wells, these zones will almost always result in a kick or even in severe kick or blow out if the zone happened to be gas bearing.
********** Mud Hydraulics ***********
Q . What is drilling fluid? What critical functions does it perform?
Ans. Oil well drilling fluid is called mud on rigs. It is a specially formulated heavy, viscous fluid which is circulated through a wellbore while drilling for oil and gas. It serves several critical functions:
Carries Rock Cuttings: The mud helps remove rock cuttings created by the drill bit as it drills into the formations, transporting them to the surface for disposal.
Cools and Lubricates the Drill Bit: Drilling generates friction and heat. The mud circulation helps cool the drill bit and lubricate the drill string, reducing wear and tear.
Controls Well Pressure: Drilling mud exerts hydrostatic pressure against the wellbore walls, preventing formation fluids (like oil, gas, or water) from entering the wellbore uncontrollably. This helps maintain wellbore stability and prevent blowouts.
Supports Wellbore Walls: The mud helps stabilize exposed rock formations within the wellbore, preventing them from collapsing and hindering the drilling process.
Q. There are different types of muds; what do you know about them?
Ans. There are three main types of drilling fluids:
Water-based muds (WBMs): The most common type, using fresh water or salt water (brine) or a combination as the base fluid with various additives for viscosity, lubrication, and formation control.
Oil-based muds (OBMs): Utilize oil as the base fluid, offering superior lubrication and wellbore stability, but requiring stricter environmental regulations due to their oil content.
Synthetic-based muds (SBMs): A compromise between WBMs and OBMs, using synthetic lubricants that offer good performance with lower environmental impact than OBMs.
Q. What are mud additives? Why do we use them in drilling fluid? Give a few examples of additives?
Ans. Drilling fluid additives are chemicals additionally used to alter chemical and physical properties of mud. For example, barite is used as a weighting material to increase the density of the mud or oil is added to increase lubricity of the mud.
Notes:
Drilling mud additives are chemicals used to enhance the capability of mud. Here is a breakdown of some common types of additives:
Weighting agents increase the weight of the drilling mud. This is necessary to counteract the pressure of the rock formations being drilled through. Exaple: Barite, Galena, Hematite
Thinning agents make the drilling mud thinner and easier to pump. thinners reduce the attractive forces between clay particles in the mud,
resulting in reductions in YP, gel strength and vis. Example: lignosulphanates
Filtration control agents these absorb and hold water in the mud and form a filter cake, which reduces the rate of water loss. These include CMC and starch
pH control agents are used to maintain the correct acidity or alkalinity of the drilling mud. This is important for the performance of other additives. Caustic Soda (NaOH) is added to mud, keeping the pH above 8 to aid the
solubility of thinning agents. Caustic Soda also gives better yield to bentonite.
Lost circulation material (LCM) is added to the drilling mud to help prevent mud loss into the rock formations. Examples: walnut shells, Calcium carbonate etc.
Q. What do you understand by total pressure loss?
Ans. For an easy understanding, pressure loss can be considered as the amount of energy spent to circulate mud in the hole. Total pressure loss depends upon geometry of drill string, geometry of hole, mud properties and depth of bit. Entire circulatory system can be divided into three major parts: drill pipe, bit and annulus. Amount of energy required to move the mud from top of drill-pipe to bottom of BHA is called Pressure Loss in DP
Energy spent to make mud pass through bit nozzles is called Bit Pressure loss. Energy spent to make the mud move from bottom of hole to surface of hole is called Annular pressure loss. Maximum pressure (roughly 50 to 65%) is lost through the bit nozzles.
Q. What is rheology? What are some of the rheological properties of mud?
Ans. Rheology is the study of flow behaviour of mud under pressure. Some of the rheological properties of mud are PV, YP, Gel
Notes:
Plastic Viscosity (PV): Plastic viscosity indicates resistance of mud to flow due to mechanical friction. Plastic viscosity plays an important role in hole cleaning and keeping barite in suspension. Also it reduces turbulence in open hole section to avoid hole wash out. Ideally it should not be higher than needed. Higher than optimum PV will create higher than optimum pressure loss.
PV is a function of solids in the like bentonite, barite and other additives. More the solids more will be viscosity.
For quick field measurements and routine mud property monitoring, subtracting Fann viscometer readings at 600 rpm and 300 rpm gives a quick estimate plastic viscosity in centipoise.
Plastic Viscosity (cP) = Θ600 – Θ300 in
Yield Point (YP): Yield point indicates the amount of resistance that a stationary mud will show before it moves. It may also be stated that it is amount of force required in order to move a stationary drilling mud. In more technical term, YP represents the attractive forces among the colloidal particles.
In engineering and material science YP is described as a point on stress, strain curve where the elastic deformation ends and plastic deformation begins. In elastic deformation, a material regains its original shape after the stress is removed.
A suitable YP helps suspending cuttings in the mud and stabilises open hole by forming thin mud cack. Yield Point is measured using viscometer
YP = Readings at 300rpm – PV (Lbs/100ft)
In top hole section where large amount of cuttings are generated high YP is preferred to efficiently remove the cuttings.
Drilled solids such as type of clay, and contaminants such as CO2, salt and anhydrite tend to effect yield point.
Gel strength: is another crucial property of drilling fluids that impacts mud behaviour and hydraulics downhole. It is a measure of capacity of mud to hold the cuttings and barite in suspension during non-circulation period.
Gel Strength is measured using viscometer on 3RPM at three different times 10 sec. 10 mins and 30 mins. After the mud is put to rest. The readings are reported in units like pounds per 100 square feet (lb/100ft²)
Good gel strength helps the mud to keep cuttings in suspension when there is no circulation. This prevents cuttings from settling on the bottom of the wellbore and on top of bit, which can lead to problems like pipe sticking or formation collapse.
Q. Give example of Newtonian and Nonnewtonian fluids?
Ans. Water, diesel, petrol are examples of Newtonian fluid, where as mud, honey, milkshake are examples of nonnewtonian fluids.
Q. What do you understand by Mud Hydraulics?
Mud hydraulics deals with the mud flowing under pressure in the hole and directing that energy or hydraulic force to break formation and remove cuttings from underneath the bit and from annulus.
Optimized hydraulics improve rate of penetration, reduces stress and fatigue on equipment like mud pumps and avoids build of cuttings in the annulus and thus mechanical stuck up.
Q. What are different models used to understand flow behaviour of mud under pressure?
Ans. Usually there are three models employed understand the flow behaviour of mud under pressure. The knowledge of these models is important to accurately calculate mud hydraulics:
Bingham Plastic Model:
Power Law Model:
Herschel-Bulkley Model:
Bingham Plastic Model:
The Bingham plastic model describes mud flow behaviour with two key features:
Yield Point: Think of it as the initial stiffness of the mud. Until enough pressure is applied (like squeezing mayonnaise), the mud won’t budge. This yield point helps the mud hold onto drilled cuttings even when the circulation pump is off.
Plastic Viscosity: Once the yield point is overcome, the mud starts to flow. The plastic viscosity determines how easily it flows after that. A lower viscosity mud flows more readily, which is good for pumping efficiency. But a very low viscosity mud might not carry cuttings as well.
So, the Bingham plastic model helps engineers understand how drilling mud will flow under different pressures. This is crucial for:
Preventing the wellbore from collapsing
Carrying away drilled cuttings
Optimizing pump pressure
By adding additives (chemicals) to the mud, mud engineer can control the yield point and plastic viscosity to achieve the desired flow properties for their drilling operation. Bear in mind Bingham Plastic model is a very simple model that does not take into account all the complexities of drilling mud. Therefore the results on hydraulic reports may not be accurate.
Power Law Model:
Mud isn’t like water – it can be thick and sluggish. The Power Law helps us understand how this mud flows under pressure.
Imagine a thick milkshake. When you don’t stir it (no stress), it’s thick and barely flows. But when you stir it hard (apply stress), it thins out and flows more easily. Power law helps us understand this behavior.
Here’s the power law equation:
Shear stress = K x (Shear rate)^n
This equation says that the amount of resistance to flow (shear stress) depends on two things:
K (Consistency index): This number tells you how thick the fluid is at rest (no stress applied). A higher K means a thicker fluid, like the milkshake before stirring.
n (Behavior index): This number tells you how much the fluid thins out with stress. Here’s the key:
n < 1: The fluid thins out as stress increases (shear thinning). This is our milkshake! The more you stir (stress), the thinner it gets (lower shear stress).
n = 1: This is a special case – it describes a Newtonian fluid, like water. No matter how much you stir it, the resistance to flow (viscosity) stays the same.
n > 1: This is less common, but it describes fluids that get thicker with stress (shear thickening). Imagine a mixture of cornstarch and water. When you push on it quickly (stress), it stiffens up (higher shear stress).
So, by knowing the K and n values of the drilling mud using the Power Law, engineers can:
Pick the right mud for the job: A thicker mud (higher K) might be needed for a weak rock formation, while a thinner mud (lower K) might be better for carrying cuttings.
Adjust the mud properties: By adding different materials, they can change the K and n values to get the desired flow behavior.
Predict how the mud will flow under pressure: This helps ensure the drilling operation runs smoothly and efficiently.
In short Power Law is a tool that helps understand and control the flow of drilling mud, which is essential for safe and successful drilling!
Herschel-Bulkley Model: For highly complex mud formulations or under specific downhole conditions, more advanced models like Herschel-Bulkley might be used, which combine features of both Bingham Plastic and Power Law models.
This model combines features of both Bingham plastic and Power Law.
It considers a yield stress, like the Bingham plastic model.
It also accounts for the shear thinning behavior described by the Power Law model.
Imagine honey again. At rest, it’s stiff (yield stress). But once you stir it (shear), it thins out (shear thinning). The Herschel-Bulkley model captures both these aspects.
Benefits of Herschel-Bulkley:
By considering both yield stress and shear thinning, it provides a more accurate description of how the mud will flow under different drilling conditions (varying pressure and movement).
This helps engineers predict how the mud will behave inside the wellbore, ensuring:
Efficient drilling
Proper cooling of the drill bit
Preventing formation damage
Q50. What are specific muds that favour: 1. Bingham Plastic Model. 2. Power aw. 3. Herschel and Bulkley Model?
Ans. Here’s a breakdown of mud types suited for different rheological models:
1. Bingham Plastic Model:
This model is generally less preferred for drilling muds due to limitations in capturing shear thinning behaviour, a common characteristic.
However, some muds with a distinct yield stress might be considered somewhat suitable for the Bingham Plastic model. Examples include:
High-solids content muds: These muds contain a high concentration of drilled solids (formation cuttings) which can create a more structured, yield stress-like behaviour.
Bentonite-based muds with high clay content: Bentonite clay can impart a yield stress-like characteristic to drilling fluids, especially at higher concentrations. However, even these muds often exhibit some degree of shear thinning.
2. Power Law Model:
This model is a better fit for most drilling muds due to its ability to represent shear thinning behaviour. Here are some common mud types:
Water-based muds: These muds, including native mud and many drilling fluid formulations, typically exhibit shear thinning. The Power Law model effectively captures this behaviour.
Synthetic-based muds (SBMs): Many SBMs also exhibit shear thinning and can be modeled well with the Power Law model.
Oil-based muds (OBMs): While some OBMs might have a slight yield stress, their dominant characteristic is shear thinning, making the Power Law model a good choice.
3. Herschel-Bulkley Model:
This model offers a more comprehensive approach by combining features of Bingham Plastic and Power Law models. It’s suitable for muds with a combination of yield stress and shear thinning behaviour. Here are some potential candidates:
High-performance drilling fluids: These muds might be formulated with specific additives that influence both yield stress and shear thinning characteristics.
Drilling muds with a blend of clays: Using a combination of clays with varying yield stress and shear thinning tendencies can create mud behaviour that the Herschel-Bulkley model can better represent.
Mud formulations for specific downhole conditions: In situations where precise control of both yield stress and shear thinning is crucial, the Herschel-Bulkley model might be preferred for calculations.
Important Note:
The selection of the most appropriate model depends on the specific mud composition and the drilling engineer’s judgment. While the Power Law model is generally more applicable, real-world muds can have complex rheology. Consulting with mud engineer is recommended for critical applications or when mud behaviour deviates significantly from the typical characteristics mentioned above. Your software usually offers you a choice of model to be used to prepare your hydraulics report. You can calculate mud hydraulics using different models and see which model is giving you more accurate total pressure losses (close to SPP)
Q. When company man asks you to simulate optimum hydraulic conditions; What is he asking you to do?
Ans. He is basically asking to calculate the optimum total pressure loss in the circulatory system or what should be the optimum SPP. He is asking us to calculate the nozzle sizes that will give him either the optimum impact force at the bit or the maximum horsepower at the bit as well as a flow rate that will avoid turbulence in the open hole section and generate a laminar flow. He is also asking us what is the slip velocity given the mud properties and the hole geometry. What is the ECD at the bottom of hole? We answer all these questions in our hydraulics report.
Q. How do you optimize bit hydraulics ?
Ans. There are two methods to optimize bit hydraulics depending upon which hole section we are drilling.
Maximum Bit Hydraulic Impact Force
Maximum Bit Hydraulic Horse Power
Maximum bit hydraulic impact force is achieved when flow rate and nozzle sizes are selected in such a way that 48% of total pressure is lost across the bit nozzles. This method is usually employed when drilling shallow hole. Shallow hole sections have large hole diameter and are usually drilled faster as the formations at shallow depths are not very hard. Drilling fast a large diameter hole generates large amount of cuttings. In shallower sections since formation is not very compacted, ROP is not our concern, here our concern is to remove large amount of cuttings from the annulus.
When you employ this concept you use only 48% of pressure drop at the bit. That means you are using only 48% of energy at the bit and rest 52% of energy elsewhere in the circulating system. A significant amount of pressure drop or energy is consumed in the annulus to lift and transport the cutting from the annulus.
Maximum Bit Hydraulic Horse Power, as per this concept maximum bit efficiency is achieved when you select the flow rate and nozzle sizes that cause a pressure drop of 65% of total pressure loss across at the bit. Across the bit means, through the three nozzles of the bit.
This concept is used in the deeper section of hole where the hole diameter is small and formations are usually hard to very hard. In small hole sections eg. 8 ½” hole or 6” hole, the amount of cuttings generated are small (due to small diameter of hole) and also due to slower ROP as the formations at deeper depths are more compacted. So in smaller hole-section our focus shift from removing the cuttings to drilling hole at faster ROP. In this scenario the maximum bit hydraulic horse power is beneficial. Here we consume 65% of pressure drop (or hydraulic energy) at bit, that not only helps in removing the cuttings underneath the bit but also in fracturing the formation underneath the bit to help the bit drill more efficiently.
Q. Most pressure calculations are accurate inside drill string but not so accurate inside annulus, why?
Ans. Most pressure loss calculations are accurate inside drill string and through the bit. However inside annulus there are many factors which effect the behavior of mud flow pattern such as rugosity in hole wall, variation in hole diameter and temperature and pressure. Specially under HPHT conditions huge errors may enter into our pressure loss calculations.
Q. What are different flow regimes that exist in hole during circulation?
Q. What are different flow regimes that exist in hole during circulation?
Ans. In the circulating system three distinct flow regimes can be identified: laminar, transitional and
turbulent.
Laminar flow – fluid flows in smooth layers with minimal mixing between layers. Velocity increases towards the center of the flow.
Transitional flow – the flow pattern is between laminar and turbulent. (Most hydraulic calculation software do not identify transitional flow)
Turbulent flow – fluid particles flow in random directions and the velocity is almost constant across the flow area.
Laminar flow is desirable in the annulus (space between drill pipe and formation) to prevent erosion. Turbulent flow may be desirable in high angle holes to break up cuttings beds.
The regimes are identified by Reynolds numbers. If the number is greater than 2000, the flow is likely turbulen
Q. What are the disadvantages in keeping high hydrostatic pressure over formation pressure?
Ans. It is always desirable and safe to keep hydrostatic pressure above formation pressure, but there are some disadvantages in consistently keeping HP very high over formation pressure. What are they?
1. Reduced ROP
2. Poor expression of gasses from permeable formations, due to drilling fluid flushing of formation
3. Poor electric log response, due to drilling fluid flushing of formation
4. Reservoir damage, from injection of drilling solids into formation pores
5. Possible lost circulation from opening of existing formation fractures.
Q. If I ask you to calculate flow rate; what information will you need from me?
Ans. The flow rate (Q) depends on the pump output per stroke, the pump efficiency, and the number of strokes per minute:
Flow Rate Q = (vol / stk) x (Efficiency) x (stks / min)
Q. What is Booster Pump?
Ans. Offshore wells drilled with riser sometimes require a booster pump to increase the flow rate in the riser annulus. Often the riser annulus is much larger in diameter than the annular sections below it. The larger diameter results in a lower fluid velocity in that section; the lower fluid velocity may result in the settling out of cuttings at the bottom of the riser, eventually blocking the annulus and possible causing stuck pipe. The booster pump increases the flow rate (and fluid velocity) to prevent this from happening. Mud Loggers may need to consider the effects of a booster pump on lag times, when working offshore. See section 4.3 for further details.
Q. Apart from carbide or rice and pulses etc. how else can you check the accuracy of lag time?
Ans. We can approximately check lag time by looking at positive or negative drill break and correlating the lithology and their appearance on shaker. Similarly we can use connection gas, pump off gas and coal gas peaks against ROP on mudlog. There should be consistency and good match among these parameters.
Q. What is ECD? What parameters affect ECD?
Ans. Equivalent Circulating Density is an apparent mud density when the circulation is going on. Static mud density is the density when mud is not in circulation. On surface we measure only static mud density. ECD cannot be measured directly. It is either calculated or derived from bottom hole pressure as measured by MWD.
Size of annular cross-sections, mud properties like density, PV, YP, and accumulation of cuttings in the annulus increase the ECD.
Q60. While drilling, how will you know that Bottom Hole Circulating Pressure is close to Formation Pressure?
Ans. In such case we will see increasing trend of ROP and background gas and a good expression of all types of gas peaks including connection gas, short trip gas, trip gas pump off gas etc.
Q. How does nozzle selection effect drilling efficiency? What is the effect of nozzle size on ROP?
Ans: Nozzle sizes effect jet velocity which in turn effect ROP or drilling efficiency
If we are drilling hard formation we must employ maximum hydraulic horse power at the bit by selecting nozzles in such a way that we lose 65% pressure across the bit. If we are drilling soft formation then ROP will be naturally fast. Therefore we must ensure to spend more hydraulic energy in the annulus to efficiently remove the cuttings and avoid cutting build in the hole. To achieve this we must select large nozzle sizes so that only 48% energy is spent across the bit nozzles.
Q. How does a mud cake form and why do we monitor it?
Ans. A mud cake is formed usually against porous and permeable formation where the liquid phase of mud goes into formation leaving a deposit of mud solids at the bore hole wall.
Cake is formed during circulation as well as non-circulation period. A thin cake is preferred to safe guard hole wall but thicker mud cake may cause drilling related problems like:
Tight hole, causing excessive drag.
Increased pressure surges due to reduced hole diameter.
Differential sticking due to an increased area of pipe contact in filter cake.
Excessive formation damage and evaluation problems.