Mudlogging Interview
Questions and Answers
About 200 questions and answers are covered under the following headings:
About 200 questions and answers are covered under the following headings:
- Questions on Oil Industry
- Questions on Logging
- Questions on Mudlogging
- Questions on Geology
- Questions on Cuttings Description
- Questions on Hydrocarbon Evaluations
- Questions on Gas Chromatography
- Questions on Mudlog
- Questions on Drilling Parameters
- Questions on Coring Operations
- Questions on Rigging Up
- Questions on Drilling Related Problems
- Questions on Additional Points
- Questions on Safety
Oil Industry
Q1. How do oil and gas form?
Oil and gas are a complex mixture of hydrocarbons and other substances like nitrogen, sulfur, oxygen etc. They are formed through conversion of organic matter (remains of micro-organisms, both plants and animals), under critical range of pressure and temperature conditions, into kerogen and then to oil and gas. This process of oil and gas formation takes tens of millions of years. The rocks in which oil and gas are formed are called source rocks. Examples of source rocks are shale and limestone. These then get migrated to a porous and permeable rock, called reservoir. Example of reservoir rocks are sandstone and limestone, which form 90% of World reservoirs. Other rocks in the vicinity of source rock if fractured or porous can also act as reservoirs.
Q2. What do you know about Oil Industry?
Oil industry is a global industry that deals with hydrocarbon exploration, production, refining and marketing. It is counted as one of the world’s largest and important industry that plays a vital role in the global economy.
Q3. How will you describe the setup of oil industry worldwide?
The oil industry is typically divided into three main segments:
Upstream: The upstream segment focuses on exploration and production activities. This includes performing various types of surveys, drilling wells and testing the oil and gas reservoirs to establish commercial viability and finally producing hydrocarbons.
Midstream: The midstream segment deals with the transportation and storage of crude oil and natural gas. This includes building and operating pipelines, storage facilities, tankers and terminals.
Downstream: The downstream segment focuses on the refining and processing of crude oil and natural gas into usable products, such as petrol, diesel, gasoline, jet fuel, LNG, PNG and various types of petrochemicals. It also deals with establishing the fuel stations and marketing the products.
Q4. Who owns oil companies?
Oil companies can be either government-owned or privately owned. Government-owned oil companies, also known as National Oil Companies (NOCs), are controlled by the government of the country in which they operate. Examples of NOCs include ONGC (India), Saudi Aramco (Saudi Arabia), Petrobras (Brazil), and Gazprom (Russia). Private oil companies, on the other hand, are owned by private investors or shareholders. Examples of private oil companies include ExxonMobil (USA), Chevron (USA), and Royal Dutch Shell (Netherlands).
Q5. How do national oil companies differ from private oil companies?
There are several key differences between government-owned and private oil companies. NOCs typically have a greater focus on national interests and social responsibility, while private oil companies are primarily driven by profit maximization. NOCs also often have more access to government resources and support, while private oil companies must operate on a more competitive basis.
Additional Note:
The operating styles of government-owned and private oil companies can also vary depending on the specific company and its operating environment. NOCs may be more bureaucratic and less responsive to market changes, while private oil companies are often more nimble and adaptable. However, there are also many NOCs that are efficient and well-run, and many private oil companies that are conservative and avoid taking risk.
Q6. What is difference between an Oil Company and a Service Company?
An Oil company (also called client or operator) have multidisciplinary teams, have lot of funds and an area on lease to explore and exploit hydrocarbons. Once a decision is taken to drill wells, Oil Company hires number of service companies who literally do everything from picking up the well location to completing the well and making it ready for production. But all decisions are made by oil company’s geologists and engineers.
Additional Note:
Service companies play an important role in the oil industry by providing a wide range of specialized services to oil and gas operators. As they are deeply involved in research and development, they bring cutting edge technologies to drill site. This helps them stay ahead of competition and in their global reach. Client’s representatives on the rig coordinate seamlessly between these service companies to drill a well safely and economically. Also services companies offer bigger employment opportunities than oil companies for engineers and geologists. Some of the major services and their companies are described below:
1. Geophysical Surveys: Imagine an oil rig drilling offshore where you see nothing but water all around or in desert where you see nothing but sand or in jungle where you see only foliage. These scenarios can make us wonder, how do they decide where to drill? Selecting a drill site in a favourable geological territory is done with the help of geophysical surveys. Geophysical surveys are done using non-invasive techniques to prepare maps of subsurface geology and structure that can point to most likely areas for oil accumulations. Many different types of geophysical surveys are performed prior to drilling but seismic surveys play crucial and decisive role. Other geophysical surveys are Gravity Survey and Magnetic survey. Shearwater and TGS are among many service companies who perform geophysical surveys. Sometime geochemical surveys are also conducted on soil, surface sediments and rocks to enhance our understanding of hydrocarbon potential of the area.
2. Well Engineering Services: Specialized well engineering companies provide technical expertise in well design, directional drilling, drilling fluid selection, and casing and cementing programs. Most oil companies however do this type of planning in-house.
3. Rig Contractor: The rig contractor provides the drilling rig on offshore or onshore as the requirement may be. They also provide the drilling crew, which operates the rig equipment. Schlumberger, Halliburton and Baker Hughes are logging companies that also own large fleet of rigs.
4. Mud Engineering: This company provides chemicals used to make drilling fluid (Mud) and an expert who mixes the chemicals and maintain the properties of drilling mud.
5. Mud Logging: Mud logging companies monitor and analyse the drill cuttings and hydrocarbon gases as they come to surface from the wellbore. This provides real-time information about the formations being drilled through and presence or absence of hydrocarbon in them. Also mudlogging crew closely monitor drilling parameters and alert the driller and client’s supervisor should any parameter goes into abnormal range, thus ensuring the safety of drilling operation. Mudlogging companies provide maximum jobs to geologists.
6. MWD/LWD: MWD (Measurement While Drilling) and LWD (Logging While Drilling) companies provide tools and engineers to gather formation data in real time (while drilling is in progress). This data is used for geosteering, formation evaluation, and hydrocarbon identification.
7. Wireline Logging: This company records many different types electrical, electromagnetic, sonic and nuclear logs. The company sends a logging unit and crew to do the job. After a section of hole has been drilled the wireline engineer runs their tools on wireline and records formation properties such as , formation radiation, resistivity, density and porosity to name a few.
8. Casing and Cementing: Casing and cementing companies (Two different comapanies) provide specialized equipment and engineers to run and set casing to the bottom of hole in each section. Cementing engineer then mix cement slurry and pump it around the casing. Cemented casing ensures well stability and prevents hole collapse and fluid migration.
9. Production Testing Company: After drilling a well. If geologists observations and studies show there is hydrocarbon potential in the well; then production testing company’s services are hired. The company sends specialised tools and engineers who perforate certain zones to flow oil and gas to confirm the commercial productivity of the well. So that plans can be made to put well on completion and production.
10. Completion Engineers: Completion engineers design and implement the completion strategy, which involves selecting and installing the necessary equipment to allow oil and gas production from the well.
11. Production Services Companies: Production services companies provide specialized services, such as artificial lift, well monitoring, and reservoir management, to optimize the production of oil and gas from the well.
12. Transport Companies: Three different companies are hired to transport crew and equipment to and from rig. These are: Helicopter company, Shipping company and surface transport company.
Above are the major service companies. Besides many other companies are hired on need basis such as directional drilling company, Coring company, Fishing company to name a few. In short 15 to 20 service companies get together to drill and complete a well.
Throughout the operation, the effective communication and coordination among the client representatives and various service companies remains a crucial aspect to ensure successful drilling, testing, and completion of a well.
Logging
Q7. How will you explain well logging to a layman?
As we drill an oil well we encounter different formations with change with depth. Logging means recording formation characteristics and related technical data against depth. Three different types of logging companies (Mudlogging, MWD/LWD and Wireline logging) are hired under separate contracts. These collect geotechnical data during the course of drilling a well.
Q8. How do we drill and complete an oil well starting from spud time?
We spud and drill, log and case hole in successive stages. After drilling the well to predetermined TD and logging, we go for production testing and completion if hydrocarbons have been found..
Q9. What are the objectives of mudlogging?
Mudlogging also called surface logging, performs two major tasks:
1. Evaluates formations, as they are drilled, for hydrocarbon potential
2. Closely monitors drilling, mud and gas parameters for the safety of operations.
Q10. What is difference between MWD and LWD?
Measurement While Drilling and Logging While Drilling tools and sensors are embedded in drillcollars, positioned just above the bit. So, as we drill MWD tools record and send directional and drilling data to the surface computer using mud telemetry system. While LWD tools record natural radiation of formation (GR) and resistivity, density, porosity and sonic transit time of formation.
Q11. What do you know about wireline logging?
Wireline logs often called electric logs are recorded by lowering a logging tool or a set of tools on an electric wireline to the bottom of hole and recoding logs while pulling it up to the surface. These logs are recorded at the each drilling phase prior to running casing.
Electric logs are same as recorded by LWD. Now days LWD logging has developed advantage over wireline logging as it’s logs quality is similar to wireline, is less expensive than wireline and it provides logs in real-time to help take quick decisions.
Mudlogging
Q12. How has mudlogging technology evolved with time?
Mudlogging started in early 1900 alongside the commercial exploitation of oil. In the beginning a mudlogger would stand and look at the drilling fluid ( commonly called mud on oil rigs) coming out of hole, visually analysing cuttings and recording any spot of oil in the mud stream (hence the name mudlogging). Mudlogging took formal shape of a service company in mid-1930s when depth recorder and gas detectors were introduced. Since then constant improvement of sensors and recorders and then introduction of computers have revolutionized mudlogging industry to the point where a mudlogging unit has become an integral part of all oil rigs.
Additional Note:
In recent years, the introduction of Gas Mass Spectrometry (GMS), X-Ray Fluorescence (XRF), and X-Ray Diffraction (XRD) has further enhanced mudlogging’s role in oilfield exploration and development. Additionally, the integration of artificial intelligence (AI) and data analysis algorithms has opened up new frontiers in interpretational capabilities of mudlogging data.
Q13. How does a mudlogging company gets a job?
Once an oil company decides to explore or develop a field. It invites tenders from all service companies including mudlogging companies. These tenders are evaluated based on technical specifications and commercial value. Once a mudlogging company gets a contract, it sends a mudlogging unit along with mudlogging crew. Who upon arriving on the rig sets up the unit, runs cables and installs sensors. This process is called ‘Rig Up’. When a well has been drilled, the unit is ‘rigged down’ and taken to next drill site.
Q14. What is the composition of mudlogging crew?
The standard composition of a mudlogging crew is: two sample catchers + two mudloggers + two data engineers. However this combination may vary depending upon job requirement and the contract. Followings are the other possibilities depending upon the complexity of operations (from complex to simple):
1. One Data Engineer + Two mudloggers + Two sample catchers
2. Two Mudloggers + Two Sample catchers
3. Two mudloggers only
Additional Note:
A common career path for career progression of mudlogging crew is from trainee Mudlogger (sample catcher) to mudlogger to data engineer. Some data engineers are then promoted to gas specialist or overpressure specialist or wellsite geologist and then operations geologist.
To some people oil crew designation may sound strange. However please know that oil industry has been spearheaded by Americans from its inception. In earlier days uneducated labours used to run a rig. Hence they devised the terms. Example: The man on the highest position on the rig from drilling contractor side is called “Tool Pusher”. His office on rig floor is called doghouse. Once you join the industry you will get used to these terms.
Q15. What are the responsibilities of a Sample Catcher?
1. He must always wear PPE while working on the rig
2. When drilling is going on, for every sample interval, he goes to shale shaker, collects rock cuttings (called sample), wash them, pack them and label them as per instructions. He also helps mudlogger in troubleshooting sensors.
3. During non-drilling time he cleans the unit inside out. Helps mudlogger service sensors and calibrate sensors.
4. He is also a useful hand during rig up and rig down operation.
Note: A sample catcher is usually 10th or 12th pass. Sometimes a graduate or post graduate geologist after his initial training in the office (as Mudlogger) is sent to the rig for further practical training, where he also works as sample catcher.
Q16. What are job responsibilities of a mudlogger during drilling?
The main responsibilities of a mudlogger during the course of drilling are:
1. Describe rock cutting and evaluate them for hydrocarbon shows
2. Closely monitor drilling and gas data
3. Keep the alarm closely set on critical parameters such as Mud Rturn (Flow Rate), Total Gas, Active Pits etc.
4. Prepare mudlog
5. Trouble shoot sensors, clean and service degasser
6. Clean and maintain unit in good condition.
Q17. What are job responsibilities of a mudlogger during trip?
The main responsibility of a mudlogger is to closely monitor hole-fill while pulling out of hole (POOH) and mud displacement during running in hole (RIH). Ensuring proper mud displacement and a keeping a record of it is a critical responsibility of a mudlogger. In case of any suspicion, he must consult data engineer, driller or company man.
Q18. What are job responsibilities of a mudlogger during casing and cementing operation.
1. He should ensure that all pits are accurately calibrated prior to casing job
2. Maintain a good tally of casing joints being RIH
3. Ensure good mud displacement is taking place for each joint of casing. Maintain a meticulous record of it. Poor mud displacement could mean loss of mud down hole and should immediately be reported to company man
4. While cementing ensure that proper amount of mud is being displaced. If not let the company man know about it.
5. At the end of cement displacement when the plug is bumped, ensure that Stand Pipe Pressure (SPP) is increasing sharply and is being held their more or less constantly. If it drops quickly or does not build up then company man must be informed about it
Q19. What other data does a mudlogger collect apart from the data that he records inside mudlogging unit?
There are many other types of data, that is collected from various sources and is integrated with mudlogging data to make it more comprehensive. Examples of such data are: deviation data, mud data, bit data, BHA, Casing tally etc. etc.
Q20. What are Job responsibilities of a mudlogger during wireline logging?
Wireline logging may take one day to as many as 4 or 5 days. During this operation mudlogger should keep an eye on all pit levels and trip tank. And keep close alarms on these parameters. This is a quite time for mudloggers, which should be utilized in servicing the sensors, cleaning degasser, troubleshooting any pending fault. Update and QC mudlog. Clean and wash unit from outside and outside. Audit spares and consumables and request town if anything is needed.
Q21. What are Job responsibilities of Data Engineers?
A data engineer is the most experienced mudlogging personnel in mudlogging team and is regarded as the manager of mudlogging unit. Some of his job roles and responsibilities are as follows:
1. His first and foremost responsibility is to keep the mudlogging unit functional at all time
2. Provide technical support to mudloggers and sample catchers as well as QC their jobs
3. Ensure all data is being recorded and displayed as per client’s requirement. As well as all data is being checked for its quality on constant basis.
4. His job includes preparing various reports on daily and weekly basis, including final well reports. It is his duty to thoroughly cross check all data, all reports and all logs before submitting these to client.
5. It is his responsibility to make sure unit is kept clean and tidy as well as free from hazards.
6. It is also part of his job to rig up and rig down mudlogging units, trouble shoot sensors and keep all equipment calibrated.
7. Being the captain of the unit, he has to frequently interact and communicate with various personnel on the rig such as company man (client’s representative) wellsite geologist (client’s representative), tool pusher, driller, mud engineer etc. Therefore, it is a requirement that he should have good communication skills to conduct mudlogging operation smoothly.
8. Last but not least he has to ensure the personnel safety and that all safety rules are being complied. He should always keep an eye on safety. For example, he must ensure that unit’s emergency exit is clear of all hurdles from inside and outside, all PPEs are present in the unit and are being used properly by the personnel, all chemicals are stored safely and MSDS sheet is pasted nearby. That his team members are participating in all safety meetings and safety drills. These are but a few points from lists of do and donts.
Additional Note:
Hiring Process for Mudloggers
The oil and gas industry relies on mudloggers to collect and interpret crucial drilling and geological data. With over two dozen active mudlogging companies in Asia, there’s a constant demand for qualified mudloggers. In some regions, like the Middle East, many companies opt to hire mudloggers and data engineers through third-party providers to streamline operations and reduce costs.
The standard hiring process for mudloggers typically involves an interview. While experience is highly valued, even entry-level candidates with a bachelor’s degree in geology can secure a position. However, postgraduate qualifications in geology are generally preferred.
Beyond academic qualification, mudlogging companies prefer those candidates who have good communication skills and problem solving skills, who would like to work in rough and tough environment as a good team player and who show respect to safety protocols.
Q22. What equipment do you need to collect rock cutting samples?
First the sample catcher should be equipped with PPE, then he should have a spatula and a set of three sieves with different mesh sizes. Further he should have a wooden plank set just in front of the screens; on to which cuttings of all sizes can accumulate.
Additional Note:
The typical mesh sizes for sieves used to wash rock cutting samples are 8 mesh, 80 mesh, and 170 mesh. The reason for this is that 8 mesh sieve will help remove shale cavings which are unusually large shale pieces as well as large size coal pieces both of which are fallen off from the wall of the hole. The medium sieve will retains the normal cuttings (cuttings generated by bit action and truly represent the formation), while the bottom sieve will have clay, silts and fine to very fine grained sand.
Concept of mesh is simple: Mesh numbers represent number of apertures or holes a sieve has per square inch. 8 mesh mean sieve has 8 holes in one sq. inch area, they would be naturally large in size compare to if you have 80 apertures in one sq. inch.
Q23. How do you collect cutting samples on the rig?
Samples are collected at the shakers. Shakers are used to separate cuttings from the mud. The mud drops down into a settling tank and cuttings fall off from the front of the shaker and a portion of these get accumulated on a wooden plank. These accumulated cuttings represent the full section of formation drilled between the sample interval. For example, sample interval in a particular section is decided to be 20 ft by the wellsite geologist. Therefore a sample collected at 2120 ft is the representative of downhole formation from 2100 ft to 2120 ft.
Q24. What precautions one must take in order to collect a good sample?
A few points should be kept in mind to collect representative samples: 1. Collect samples at correct lag time 2. Ensure that cuttings being accumulated are falling on wooden plank from all three shaker screens. After each collection of sample, wipe clean the wooden plank. 3. Ensure hole is not severely washed out. This can be checked with rice test. 4. When drilling top section containing soft sticky clay, the sample should be washed very lightly or else clay will wash away leaving non-representative lithologies.
Q25. What are different types of samples collected on the rig?
There are many types of samples collected and packed on the rig by sample catchers. Client decides sample interval, types of samples, size of samples and number of sets for each type of samples:
1. Unwashed samples usually two sets each about 400 gms
2. Washed and wet usually 2 sets each about 300 gms. Washed and wet in steel tray for mudlogger and geologist about 30 gms
3. Washed and dry in two or three or four sets, about 50 gms each. Packed in paper bags
4. Geochemical sample one set in a tin box about 600 gms. (Not very common)
• Most samples are collected at exploratory wells, very few on development wells.
Q26. What is the use of wet and unwashed samples?
These samples are sent for paleontological and palynological studies in order to estimate the stratigraphic age, identify formation and understand its paleo-environment.
Q27. What precautions will you take while drying the washed samples?
These samples are mostly collected from 80 mesh sieve. Many companies prefer to air dry the samples if we are using oil base mud. If using oven, one must ensure that samples are not burned or over-dry because it can lead to staining which may be confused to oil staining. Ensure oven is venting fumes to outside the mudlogging unit. Also one should wear gloves while taking out sample plates to avoid burning the fingers.
Q28. How do we preserve geochemical sample?
We normally preserve geochemical sample (wet and unwashed) in an air-tight tin jar, which is 60% full of sample, 20% water and 20% air. Also, we put a few drops of bactericide (Zepharin Chloride) to avoid the growth of fungus. Once sealed, they are stored upside down.
Q29. What are some of the contaminants that you can identify in the samples?
Some of the contaminants commonly seen in the samples are: shale cavings, barite, cement, LCM, pipe dope etc.
Q30. Can you name some of the accessory minerals often seen in the cuttings under microscope? What is significance of accessory minerals?
Siderite, pyrite and glauconite are some accessory minerals formed in-situ at the time of deposition or post deposition. They indicate depositional environments. For example presence of siderite (FeCO3) a pale-yellow to brown mineral, indicates oxygen depleted environment as seen in stagnant lagoons and deep marine settings. Pyrite also indicates oxygen depleted but sulfur rich environment, associated with decomposition of organic matter. While glauconite is formed in and indicates a warm, shallow marine environment.
Q31. What is a spot sample? When do we take it?
A spot sample is a small washed and wet sample collected directly from shale shaker either at the instruction of wellsite geologist or on certain occasions like when we get a big gas peak, or a drill break or when ROP becomes extremely slow, and if possible, when circulating out a kick. Also when new formation top is expected or a casing point or coring point is to be picked. Please bear in mind that spot sample should be collected from all three shaker screens to collect fine to very fine sand as well.
Q32. How does the technique differ in taking a spot sample from that of regular sample.
Regular sample is representative of entire sample interval while spot sample represents only the lag depth it was collected. A spot sample is not bagged and kept. While a regular sample is bagged and labeled.
Q33. How do you label sample bags and sample boxes?
Ans. We write oil company name, well name, depth interval on bags. Same information goes on boxes with an addition of sample type e.g. wet& unwashed or wet & washed.
Geology
Q34. Why don’t we find oil in igneous and metamorphic rocks?
Oil is formed from the organic matter deposited with sediments in a body of water at relatively low temperatures. Where as igneous and metamorphic rocks are devoid of organic matter more-over they are formed at extremely high temperatures, where organic matter or oil cannot exist. However, if the igneous and metamorphic rocks happen to be porous and permeable and in the vicinity of source rock. The oil may get trapped in them and can be exploited.
Q35. What are important sedimentary rocks, from the point of view of oil exploitation?
Sandstone and shale in clastic group and limestone and dolomite in carbonate group are important sedimentary rocks. Shales and limestones are good source rocks and sandstones and fractured or porous and permeable limestones and dolomites form good reservoir rocks. More over shales and evaporites are also important rocks as they provide seal in effective trapping mechanism.
Q36. What is difference between shale oil and oil shale?
Shale oil is a crude oil produced from shale by fracking. Oil shale is a type of shale rich in kerogen (organic matter) Kerogen can be extracted and processed into oil by unconventional methods.
Q37. If we encounter halite while drilling with fresh water mud; How will you identify it?
Halite being salt will dissolve in mud, therefore the cuttings volume on shaker will reduce. At the same time mud salinity and viscosity will increase. A few colorless cuttings of halite may be seen and some of it may be attached to other rock cuttings. When we see halite, it is usually colorless and rarely white in color, has cubic cleavages. Halite tastes salty. Also, halite beds are drilled smoothly at fast ROP.
Q38. How do you differentiate between gypsum and anhydrite?
Gypsum is usually translucent to white in color and frequently fibrous in structure, whereas anhydrite is fine grained, massive and usually amorphous. Gypsum is soft, its hardness varies from 1.5 to 2 on Mhos scale. It can be scratched by finger nail. While anhydrite is comparatively harder, 3.0 to 3.5 on Mohs scale. Density of gypsum is only 2.35 where as that of anhydrite is about 3 sg. (Also, this may be mentioned here that limestone reacts to HCl but anhydrite and gypsums do not).
Q39. How will you differentiate between lignite and coal in cuttings?
Lignite gives brown to reddish streak where as coal gives black streak.
Q40. How will you differentiate between limestone and dolomite if you have run out of hydrochloric acid?
1. If we do not have Hcl, we can differentiate based on density using variable density solution. The average density of limestone is 2.6 sg and average density of dolomite is around 2.78 sg.
2. We can perform Alizarin test. Staining the grain with Alizarin turns limestone red or pink, where as dolomite does not change its colour.
Notes: In order to perform staining test, we need Alizarin solution (1% of Alizarin mixed in 10% of acetic acid). The grain must be thoroughly washed with distilled water (very lightly with dilute Hcl if available). Put the grain in Alizarin solution for 1 to 2 minutes. After that wash off the solution with distilled water. Upon washing, if the grain turns red or pink it is limestone otherwise dolomite.
Q41. There are three important rocks that are required to form commercial hydrocarbon accumulations; first is the source rock, second is the reservoir rock, name the third one?
The cap rock.
Q42. There are two types of binding material in sandstone: one is cement and the other is argillaceous matrix. How is argillaceous matrix formed?
Argillaceous matrix (Authigenic Clay) is formed “in-place” by the degradation of other minerals, typically feldspars. These often form the matrix around the sand grains, binding them together into consolidated sandstone.
Q43. Name the rocks which are frequently deposited in deltaic environment.
Thick beds of clay, claystone, shale, siltstone, sand, sandstone, occasional beds of lignite and minor beds of limestone and dolomite.
Notes: Limestones are mostly deposited in shallow marine environment, where coral reef and marine organism thrive. Shallow marine lagoons with abundant micro-organisms and with right conditions of precipitation of calcium carbonate also provide suitable environment for limestone deposition.
Q44. What are drilling related problems associated with clay, claystone and shale?
Gumbo or clay often blocks flow line, possum belly and shale shaker while drilling shallower section.
Claystone being very plastic formation creates hole ballooning affect if mud weight is too high. It can also swell and create tight hole condition
Shale can excessively cave in and can make hole unstable
Q45. What is hole bridge? What causes it? What problems are associated with hole bridge?
A hole bridge is an obstruction in the open hole section caused by local collapse of hole against a friable formation like coal or in deviated hole section against highly fissile shale. Severe hole bridges may result in drill pipe and wireline tool getting held up or even stuck. Sometime we may have to snap wireline or drill string and go for fishing job. All this causes delay and cost money.
Q46. What is the significance of study of shale cavings?
Here’s a breakdown of the different types of shale cavings and the information they reveal:
1. Splintered Cavings:
• Shape: Thin, elongated, and roughly rectangular with sharp edges.
• Size: Typically centimetre-long size, but can range from 1mm to 10cm.
• Information: Indicate shear failure, often caused by drilling too fast through low-permeability shale or underbalanced drilling. They suggest the presence of pre-existing planes of weakness in the rock.
2. Platy Cavings:
• Shape: Flat and plate-like with smooth, planar surfaces.
• Size: Can vary significantly, from centimeter- long size to large slabs.
• Information: Suggest tensile failure, often due to rapid pressure changes or stress concentrations around the wellbore. They may indicate the presence of bedding planes or natural fractures in the shale. Platy Shale Cavings.
3. Blocky Cavings:
• Shape: Irregular, angular chunks with no distinct faces.
• Size: Highly variable, ranging from small fragments to large blocks.
• Information: Indicate mechanical failure, often caused by the direct impact of the drill bit or poor hole cleaning practices. They suggest the presence of weak or fractured zones in the shale.
4. Coffee-Ground Cavings:
• Shape: Fine, granular particles resembling coffee grounds.
• Size: Millimeter-sized or smaller.
• Information: Represent the breakdown of larger cavings, typically shale with high water sensitivity. They indicate ongoing instability and potential drilling fluid contamination.
Extra points:
• Surface texture: Smooth surfaces point towards pre-existing planes of weakness, while rough surfaces suggest mechanical failure.
• Presence of drilling fluid: Cavings coated in drilling fluid indicate active caving, while dry cavings may represent past instability events.
Cuttings Description
Q47. How do you describe color of a rock grain?
Color of cutting is best described using the ‘Rock Color Chart’ for the purpose of accuracy and consistency. Same rock type may show Variations in color. This variation is described starting from most dominant colour to least dominant color.
Q48. What imparts colour to lithologies and what is the significance of colour of rocks?
The color to the sedimentary rock is imparted by three main factors:
1. Oxidation state of iron
2. Amount of carbonaceous matter
3. Abundance of colored mineral
Remarks:
Minerals and depositional environments are the major factors that give colors to a sedimentary rock. Presence of manganese will give black or dark grey color to the rock. Similarly, carbonaceous matter and organic matter will give dark grey to grey colors to rocks. Iron minerals may give red or green color depending upon whether it is ferric or ferrous oxide.
Colours may often tell us the depositional environments for example a red colour may indicate presence of ferric oxide which originates in oxidising depositional environment. Reducing environments usually give green colour to iron minerals which in turn give greenish colour to the rocks. Sometimes, greenish colour imparted to sandstone or shale could be due to abundant glauconite; which is formed in warm shallow marine waters.
Q49. What is difference between hardness and induration?
Hardness of a sedimentary rock indicates its resistance to abrasion or penetration. Whereas induration is a process whereby sediments are converted into a solid rock. Induration involves compaction, cementation and recrystallization. More the compaction, more the cementation and more the recrystallization, harder will be rock and slower will it be drilled. This is the reason why ROP slows down with depth.
Q50. Can you arrange common sedimentary rocks according to their hardness?
Here are the sedimentary rocks with increasing hardness: Clay & unconsolidated sandstone followed by coal and claystone followed by shale and sandstone followed by limestone then dolomite. This is a general arrangement but there may be exceptions specially when it comes to sandstone.
Q51. How do you classify sand grains based on size? Why do we study and record grain sizes?
For the purpose cutting description, sand grains are classified as very coarse, coarse, medium, fine and very fine grained. The size of grains indicates the reservoir potential as coarse and very coarse-grained sandstones show better porosity and permeability compare to fine and very fine-grained sandstone. Coarse and very coarse-grained sands indicate high energy environments such as revers, deltas. Fine and very fine-grained sandstones usually do not form very potential reservoirs as the porosity and permeability are comparatively low. They are deposited in low energy environments like lake, deep marine basins.
Q52. How do you classify the grains shapes? What insight does the study of grain morphology gives us?
Grains’ shape is classified as well rounded, rounded, subrounded, subangular, angular. Like grain sizes grain shapes also tell us the reservoir potential, depositional energy and to some extent the source of sediments. Well-rounded and well sorted grains show good reservoir potential and high energy environment. Conversely dominance of angular and poorly sorted grains indicate poor reservoir potential, short distance of transport and nearby source of sediments.
Q53. What is difference between cement and matrix?
Cement develops by the crystallization of calcite or silica around the grain boundaries in void spaces. It binds sediments into hard compact rock. Cementation is a post depositional phenomenon. Whereas matrix is formed by deposition of clay and silt size particles (usually weathering product of feldspar). It does bind sediments but does not give the same strength to rock as cement. Both cement and matrix reduce porosity and permeability
Notes:
Usually cement whether siliceous or calcareous are of light colour and amorphous in nature whereas matrix is usually greyish or brownish in colour and is argillaceous in texture. Usually cement is secondary in nature (formed after deposition of sandstone) while most argillaceous matrix is primary in nature. Both cement and argillaceous matrix have negative effect on reservoir quality.
Quartz Cements: At the wellsite, the presence of quartz cement is often inferred from a negative reaction to 10% HCL. If sandstone grain shows very slow reaction to dilute HCl, that can be taken as the evedence of calcareous cement.
Q54. What are some of the structures you can identify on a limestone conventional core? What is their significance?
Some of the important structures that can be visually identified on a limestone conventional core are: fractures, fissures, joints, vugs, stylolites Evidence of partial infilling in the form of mineralization and crystal growth may sometime be seen. While these structures usually enhance permeability to extreme level, they can some time cause hindrance to flow of oil if the fractures are not interconnected and or are sealed with infills.
Q55. How do you describe the porosity in limestone cuttings?
On the rig we use simplest classification and describe porosity in terms of primary and secondary. Primary porosity is one that develops in between the grains (intergranular) at the time of deposition and gets modified during compaction. For description purpose it is further classified as nil, poor, fair, good and excellent.
Secondary porosity develops post deposition and may be intragranular in nature. Examples of secondary porosity are vugs, fractures, fissures. This type of porosity though may not be seen in smaller cuttings yet it may be present in abundance.
Q56. What are the common accessory minerals that you frequently see in the cuttings and make record of?
Commonly seen accessories are glauconite, pyrite, carbonaceous matter, microfossils, etc etc.
Hydrocarbon Evaluations
Q57. What are the major steps involved in evaluating oil shows?
Usually, 5 steps are involved to describe oil shows:
1. Odor
2. Visible oil stains
3. Direct fluorescence
4. Cut fluorescence.
5. Residual ring
Additional Notes:
If petroliferous odor is present describe its intensity as faint, moderate or strong. Look at the sample in natural light and see if oil stains are visible. If you are unable to see the oil on cuttings in natural light; mention ‘no visible oil stains. However, if oil stains are present describe the colour and sheen as well as its distribution. Traces, spotty, streaky, patchy or uniform.
In order to observe the direct oil fluorescence, put the sample tray inside UV Box. Roughly estimate the percentage of grains showing direct fluorescence (traces, <5% or >5% or >10% etc.) also mention the distribution (pinpoint, streaky, patchy, uniform). Next, record intensity of fluorescence eg. Pale, dull, bright.
Cut fluorescence is observed when an oil-bearing grain is emersed in solvent. Solvent dissolves the oil from inside the pore spaces and make it leach out, which under fluorescent light is seen as streaming out in various shades of colors from milky white to dark brown in color. Speed of cut is also noted and recorded apart from the color of residual ring.
Q58. What is the significance of color of fluorescence?
Observation of color of fluorescence gives a very early idea about the quality of oil. Lighter colors and brighter intensity are associated with lighter or good quality oil (oil with high API gravity) and dull and darker colors of fluorescence are associated with heavy oils (Low API gravity).
Q59. Why do we record color of residual ring?
Color of residual ring is the natural color of oil. A very light brown film indicates good quality light oil. Conversely a dark brown heavy film indicates heavy oil.
Q60. How do you define the speed of cut fluorescence? What is its significance?
When solvent is applied to the grain in a dimple tray, the oil reacts with solvent and leaches out of the grain. The speed with which the oil cuts can be described as no cut, slow cut, moderate cut, fast cut or instant cut. Fast to instant cut is indicative of excellent porosity permeability of the reservoir. It also shows oil saturation is good and that oil is not heavy. While a slow cut will indicate a heavy oil or poor porosity and permeability.
Q61. If you have run out of solvent, how will you evaluate oil shows?
We can still see direct fluorescence. If the grains showing direct fluorescence are not the minerals known for mineral fluorescence, then it can safely be assumed that the direct fluorescence is due to presence of oil in the cuttings. Additionally, we can pick those grains showing direct fluorescence and lightly squeeze between the blotting paper. After sometime it will leave a greasy mark on the paper. Another technique to see the presence of oil could be to take mud sample in a watch glass and see it under microscope you may see minute bubbles of oil popping up on the surface. Under fluoroscope you may see oil film on the surface showing direct fluorescence. Bear in mind these techniques will have limited efficacy if OBM is in use.
Q62. If you have solvent but the fluoroscope is broken i.e., no fluorescent light tube is available on the rig? How will you evaluate oil show in this situation?
If fluoroscope is broken, we may try putting the cuttings in hot water. Hot water to a great extent helps oil come out of grain and float on the surface where a sheen of oil can be seen. Holding the suspected grains in blotting paper may also leave greasy mark further confirming the presence of oil. However, these techniques will not work if we are using oil base mud.
Q63. What are the pitfalls that a mudlogger should be aware of during evaluating oil shows?
There are many pitfalls that a mudlogger should be aware of. Some of them are:
1. Use of OBM may give false indication of fluorescence to an inexperienced mudlogger. Also, the background fluorescence of the sample due to OBM may cause to miss the low intensity shows of the same color.
2. Certain contaminations in the mud like pipe dop, minerals like calcium carbonate, barite etc. may give false indication of positive fluorescence.
3. Very large size cuttings and hot cuttings may show low intensity, weaker fluorescence.
4. Improper selection of UV light tube and poor quality of solvent may also adversely affect the fluorescence description.
Gas Chromatography
Q64. How is hydrocarbon gas detected while drilling an oil well?
While drilling an oil well, gas is detected in mudlogging unit by first extracting it from drilling fluid that is coming out of hole. For this purpose, a gas trap is installed in a small ditch called possum belly. The gas is then transported to mudlogging unit through a plastic tubing; where it is analyzed by two different machines. One called Total Gas Detector that tells you the total amount of hydrocarbon gases in the air gas mixture, being sucked from gas trap. The other called Chromatograph separates the individual hydrocarbon gases like methane, ethane…pentane and analyzes to tell us the amount of individual gases present.
Q65. What is difference between Total Gas Detector and Chromatograph?
Total gas detector analysis the mixture of all hydrocarbon gases and tells us total amount of hydrocarbon gases put together. Total gas levels and various peaks indicate the down hole condition specially the balance between hydrostatic pressure and formation pressure. Which help in taking corrective measure for the safety of drilling operation. Whereas, a chromatograph analyse each hydrocarbon gas component and shows its identity and quantity. This information tells us the hydrocarbon potential of various beds and formations. This helps a geologist in identifying a possible hydrocarbon reservoir at an early stage.
Q66. What in your opinion is a better unit to record total gas? Percentage or unit?
Unit system in my opinion is a better option. Percentage gives an erroneous perception to many engineers on the rig. 20% gas to some on the rig may mean that there is 20% gas and 80% mud in the annulus. Which is wrong. It actually means that the air gas mixture that we are sucking from the gas trap contains 20% gas and rest is air.
Q67. If we are drilling target reservoir but our gas machines are not showing any significant increase in gas level. What will you do to check your gas system?
We can check the followings in priority order:
1. Check degasser: level and mud coming out of it is OK. No water or mud in the alti glass tube
2. Check gas line: to make sure line is not blocked with mud or water. If line is clean check for hole or cut in the line. To do this ask sample catcher to take the gas line off the degasser and close it with the thumb. If the ball on the suction meter on total gas detector falls to zero; line is good. If the ball does not fall to zero that means the line has got a small hole or a cut somewhere. Change the line and see the results. If the gas readings remain low
3. Give an injection of gas mixture directly into the gas line from degasser end. If you see the readings of all gasses your system is working.
4. Next, check the calibration of total gas detector and chromatograph. If calibration is good. Your gas system is good. Absence of gas may due to geological reasons, such as a fault, or intersecting the reservoir at structurally lower level.
Q68. What are the parameters that can affect the amount of total gas?
There are many parameters that can affect the gas readings. Some of them are:
1. Gas saturation in the formation: more the saturation more the readings
2. Porosity and permeability: as porosity and permeability of rock increase so do the gas.
3. Rate of Penetration: Gas readings increase with increasing ROP
4. Mud Density: As MW increases (with formation pressure staying normal) gas goes down
5. Flow Rate: With increasing FR gas increases
6. Formation Pressure: An increasing formation pressure will show up higher background gas and gas peaks.
7. Degasser inefficiency and fluctuations in mud level
Q69. What are different types of gas traps (degassers) you are aware of?
Basically, there are two types of gas traps: 1. Pneumatic motor gas traps and 2. Electric motor gas traps. Further electric motor gas traps are of two types: 1. Conventional (non-volumetric) Gas Traps and 2. Volumetric Gas Traps.
Nonvolumetric gas traps degas large amount of mud for a very short period of time as a result they do not efficiently extract heavier hydrocarbon gases like C3, iC4, nC4, iC5 and nC5. Therefore, chromatographic analysis does not truly represent the gas composition in the reservoir; hence it is generally not used for gas ratio analysis.
On the other hand, volumetric degasser takes a small amount of mud and degas it for sufficient amount of time to be able to extract all heavier components of gas from mud. As the chromatographic analysis with volumetric degasser gives quite reliable results it is used with caution to perform gas ratio analysis for predicting nature of reservoir fluid.
Q70. What gas detection principles are usually used by total gas detectors and chromatographs for mudlogging purpose?
Usually, two types of detection principles are used to analyze hydrocarbon gases: 1. FID or Flame Ionization Detection and 2. TCD or Thermal Conductivity Detection. TCD chromatographs perform nondestructive analysis, meaning that they do not burn the gases in order to analyze them. Therefore, subsequent to analysis, these gases should be provided safe exit out of machine and out of unit to avoid build up of hydrocarbon gases inside the mudlogging unit to the point where an explosion may take place.
FID chromatographs perform destructive gas analysis, meaning, hydrocarbon gases get burned during the processes of analysis.
FID based chromatographs have now replaced almost all other types of chromatographs because they provide base-line stability and maintain calibration for a longer period of time. Also, the analysis is more accurate and efficient. These chromatographs have very high sensitivity to organic (hydrocarbon) gases and zero sensitivity to inorganic gases like nitrogen, and carbon dioxide.
Q71. Explain the detection principle of FID Chromatographs.
The FID detection chamber has an electrode and a flame. The burning flame is maintained by hydrogen and air supply. When a gas sample form gas column enters the detection cell it gets burned. As the organic compounds (hydrocarbon gases) burn they produce cations (When carbon atoms in a molecule subjected to combustion, they lose electrons and rlease positively charged ions called cat ions). These cations are attracted and deposited on to electrode. The deposition of cations on electrode generates current. The more the hydrocarbon gas mor will be the carbon atoms, more cations will be deposited on electrode and more current will be generated that current or voltage is converted to amount of gas by the computer according to calibration.
Q72. Explain the detection principle of TCD Chromatographs.
Inside the chromatograph, there is a TCD detection cell, that contains tungsten filaments at constant current and temperature. When a gas sample passes over the heated tungsten filament it has a cooling effect on filament and that changes its voltage. More the gas more will be effect on the temperature of filament, that will create a high voltage difference. This voltage difference is converted to amount of gas by the computer software according to calibration.
Q73. Why FID technology has replaced TCD technology in present day chromatographs?
FID is more accurate even at traces level, baseline is more stable and so is calibration over a long period of time. More over FID provides destructive gas analysis where as TCD performs non-destructive analysis. If TCD chromatograph is in use, one has to ensure that the used hydrocarbon gases are released outside the unit. For any reason if gases start building up inside the unit, they may reach to a saturation point where an explosion may take place inside the unit. Many mudlogging units have experienced this incident.
Q74. What is difference between True Zero Gas and Background Zero Gas?
These are not commonly used terms; nevertheless, some companies use these terms. True zero gas level is achieved by passing air through the gas detector. True gas zero is ensured prior to performing calibration at the beginning of drilling. Background zero gas is observed when we circulate off-bottom in a clean and balanced. This the gas release either from the contaminations in the mud and or from recycling of gas. This level is considered as the baseline for the background gas.
Q75. What is background gas?
It is a consistent level of gas recorded while drilling a thick formation. In clastic formation it is the gas that is recorded against a thick shale section, while in carbonate area it could be the consistent low level of gas from limestone. Any significant positive deviation from the background may be considered as gas show.
Q76. How will you define a gas show?
A gas show is any significant positive deviation of total gas from background level but not all gas peaks can be taken as gas show. However, on chromatograph a gas show can be confidently recognized by manyfold increase in gas levels and appearance of heavier gases.
Q77. What is a connection gas? What is its significance?
A connection gas peak is produced in the bottom of hole at the time of connection when we have near-balanced or underbalanced condition in the hole. While drilling abnormally high-pressure zone, if formation pressure increases near to or equal to hydrostatic pressure, then drop of ECD to static MW (caused by stopping circulation) and swabbing action of bit during connection produce connection gas peak. (Both ECD becoming equal to static MW and swabbing action tend to reduce hydrostatic pressure). Connection gas peak appears on the screen after one lag time from connection. Consistent appearance of connection gas peaks on two or more connections is an indication of underbalanced condition (overpressure zone) in the hole.
Pump off gas has a similar origin and significance.
Q78. What is trip gas?
A trip gas peak shows up after a trip. when circulation has been stopped for long period of time. Its origin is not very clearly understood. A general perception is that while POOH some minor swabbing takes place that reduces the hydrostatic pressure at the bottom and allow gas to percolate into the bottom of hole. (Bottom part, probably being freshly drilled is not sealed with mud cake) Trip gas peak appears one lag time after the start of circulation on the bottom. Unusually high trip gas may also indicate underbalance condition or overpressure zone.
Wiper trip gas or short trip gas has same origin and significance.
Notes:
There are many different mechanisms by which formation gas can enter into borehole. Knowing these mechanisms are important for a mudlogger in order to correctly interpret gas shows and critical down hole conditions. Many terms are assigned to gas peaks and are widely used on oil rigs, like, trip gas, connection gas, pump-off gas, SIT or LCT, recycled gas etc. etc. A clear understanding of these is crucial for all mudloggers.
Gas released by the action of bit, in other words by crushing the rock during drilling is called Liberated Gas. This is the formation gas that tells us hydrocarbon shows. All other gas peaks are Produced Gas, for example trip gas and connection gas. These gasses usually enter from the wall of open hole, although a small amount may be contributed from the bottom as well. The size and presence or absence of these peaks depend upon differential pressure (difference between hydrostatic pressure and formation pressure).
A recycled gas peak on the other hand has nothing to do with formation potential or pressure differential. It is produced when mud properties are less than optimum, specially, when the viscosity of mud is very high. So, some of the gas in mud is retained and is not separated on surface. It can easily be identified as it appears only after one complete cycle (lag time +surface to bottom time).
Q79. What are the two most important functions that a gas chromatograph performs?
Two main functions of a chromatograph are:
1. Separating individual hydrocarbon gases from the gas mixture
2. Quantitatively analyzing individual hydrocarbon gases
Q80. Where does the separation of individual gases from gas mixture take place inside chromatograph?
The separation of individual gases takes place inside the spring shaped, aluminum/steel tubes called gas columns.
Q81. What is the use of solenoid valve in chromatograph?
Solenoid valve in a chromatograph plays crucial roles:
1. It controls the flow of carrier gas (nitrogen or helium). Carrier gas pushes the sample gas in the gas column tube. The valve also back flushes the column to get rid of the leftover heavier gases.
2. A dedicated solenoid valve controls the injection of sample into the gas column. Precise timings and size of sample is necessary for consistency of results.
Q82. What do you understand by gas normalization? Why do we do it?
Gas readings may fluctuate due to variations in certain drilling parameters such as ROP, hole diameter, Flow rate etc. The effect of these parameters on gas, can mathematically be removed to a great extent. This process is called gas normalization. It improves the accuracy in gas quantification and in correlating gas data across the wells.
Q83. Can you explain the basic concept of gas ratio analyses?
Gas ratio analysis deals with study of amount of various gases in relation to one another (C1 to C5). Gas ratio analysis gives us the first approximate idea whether the reservoir is dry or gas bearing or oil bearing. The basic premise is that the potential of hydrocarbon increases with the appearance of increasingly heavier gases in the chromatogram. Roughly speaking presence of C1 alone may indicate a dry gas of biogenic origin and that reservoir is uncommercial. Presence of abundant C1 along with some C2 and C3 gases may indicate a possible gas reservoir. While presence of all gases including C4 and C5 in certain ratios may indicate as oil reservoir. Many studies have produced many types of gas ratio analyses. One needs to identify which type of ratio plot works better in one’s field.
Q84. What are some potential sources of error in gas detection?
There are many things that can affect the accuracy of gas data, like
1. Calibration: Calibration can sometime get contaminated or the baseline gets drifted without any warning. Therefore, it should be checked occasionally and specially prior to drilling reservoirs.
2. Degasser (gas trap) in the possum belly should be at optimum level. Any starvation or flooding of degasser will give erroneous gas readings.
3. Water or vapor in gas line may affect gas readings. Hence line should be physically inspected frequently and flushed out if needed. Also ensure gas passes through clean and dry calcium chloride (drying agent). It should be changed if it becomes wet or watery.
▪ Sometime gas line may develop a hole or get cut, thereby lowering the gas level and diluting the gas-shows.
▪ Air-inlet and gas outlet on degasser (gas trap) may sometime get blocked with mud, thereby blocking the gas readings. Same may happen when mud or water gets accumulated in alti-glass tube.
Q85. What are the latest technologies and innovations being introduced to gas chromatography?
Continued research and development in the field of gas chromatography are leading to incorporation of many innovations, such as:
o High resolution chromatograms. With reduced analysis time, we can pick thinly bedded reservoirs
o Now technology is available to provide on-site analysis of stable isotopes. Isotopic ratios can, among many things, establish connectivity between the reservoirs. Understanding compartmentalization of reservoirs may help design a better production strategy
o Machine learning algorithms are being trained to interpret wholistic data, potentially identifying formation changes and gas shows even before traditional gas analyses are complete.
Mudlog
Q86. What is the significance of mudlog?
Mudlog, also called masterlog is one of the most important documents of well record. It is a record of many parameters against depth such as ROP, lithology, gas, hydrocarbon evaluation, and technical observations made during the course of drilling the well. It plays an important role in evaluating the current well and planning and drilling future wells safely. Under certain circumstances, where electric logs could not be recorded, major decisions like whether to test or plug and abandon are taken based on mudlog data
Q87. If you are asked to QC a mudlog, how will you proceed?
In order to QC a mudlog, I will check the followings:
1. Correctness of information on heading
2. Correctness of all scales
3. Consistency between ROP, Total Gas and lithology interpretation.
4. Technical comments, including mud data, deviation data, bit data etc.
Q88. What does MW on an offset mudlog tells you?
It gives a very crucial information about formation pressure encountered in the well. For example, if the maximum MW in offset well used was 15 ppg (1.8 sg) it means the area probably has an overpressure zone of about 14.7ppg (1.76 sg). However, if a well was successfully drilled using 9 to 10 ppg / (1.1 to 1.2 sg) mud it simply means the formation pressure in that well is absolutely normal.
Q89. What is missing in the following comment on a mudlog: “Increased Mud weight from 11.2 ppg to 11.7 ppg at 9810’MD / 8220’TVD”?
Why the MW was increased is not mentioned. It is a crucial information as MW was increased in a significant amount. There has to be a significant reason for this substantial increase. Was it increased to control a kick or to control poor hole condition or because the hole was showing signs of collapse. Comments sometime need to have context. Complete comments are very helpful during planning and drilling future wells. (I have used mudlogs as old as 30 years in order to plan and drill new wells as operations geologist.)
Q90. What is the importance of technical comments on mud log?
Good technical comments not only help you understand lack of drilling progress but also play a crucial role in handling problems, while drilling future offset wells in the area. Knowing the problems encountered will help us in planning the future wells in a way that will avoid or mitigate the problem.
Also, the comments on offset mudlogs fore-warn the problem to be expected in the zone being drilled eg. gumbo problem, mudlosses, presence of dolomite or chert streak, that might damage the bit.
Notes:
Increase MW. Why? Give reason. Over pressure / high gas readings, Connection gas etc./ Poor hole condition
Document any geology related problem eg. Gumbo, dolomite/chert streaks, lost circulation zones.
Depleted reservoirs (depleted reservoirs may cause DP or wireline tool to get stuck)
Overpressured indicators such as connection gas, SIT/LCT results, cavings
Down hole related problems such as tight hole, Cavings, Pipe stuck,
Kick: SHIDPP, SICPP, Mud gain. Current MW , Kill MW
Any Unusual Observations: like key seat, stuck pipe, hole bridge
In case Oil seen on shaker. Try to collect a sample (If possible) and document your observations.
Presence of H2S, CO2, etc.
Drilling Parameters
Q91. How do we install a mudlogging unit on a rig?
In a nutshell, we place the unit at an optimum and agreed-upon location, arrange power supply, install sensors, run cables and calibrate the sensors.
Q92. What are, the mudlogging related problems that a Mudlogger may encounter on the rig?
A Mudlogger may occasionally face different types of problems such as, related to sensors (sensor failure or dislocation/damage or calibration contamination), Equipment related problems inside the unit such as flame not burning inside chromatograph, pressurization of unit not functioning or run out of some of the consumables or spares. Occasionally one encounters interpersonal issues as well
Q93. Apart from gas, what in your opinion are the two most important sensors that you would want to keep in the unit as spares?
Depth and SPM sensors.
Q94. There are about two dozen parameters recorded in a mudlogging unit, which single parameter in your opinion is most important and why?
Depth is the most important parameter, since all other parameters are recorded against depth. Without depth, no parameter including gas and cutting description will make any sense. (Next is SPM as strokes are converted to mud flow and flow rate is converted to lag time and lag depth…Gas and lithologies are recorded against lag depth).
Q95. What is the name of depth sensor? How does it work?
Depth sensors, currently in use are called Drawworks sensors. It is a disk-shaped sensor fitted on the shaft of drawworks. Simply speaking this sensor has a fixed source of light and opposite to it a light sensor is fitted. Now in between the light source and sensor a metal disk is fitted that rotates on ball bearing with the shaft of drawworks. This disk has holes or small windows cut around it at the same level at which the light source and sensors are fitted. So that when the disk rotes and the light source, window and light sensor are aligned a pulse or a signal is generated.
The principle of drawworks operation is this: As the drum and the axis of drawworks rotate, it in turn rotates the disk inside the depth sensor, which generates the pulses or signals. These signals are then converted into vertical movement and speed of the travelling block and drill string) by computer in accordance to calibration.
Q96. What are the Causes of depth discrepancy? What are its effects? How to pick and resolve a depth discrepancy issue?
Depth is probably the most important parameter we record as all other parameters and data are recorded against it. If it is not correct there will be inaccurate correlation with offset logs and chances of missing the reservoirs (in highly deviated and horizontal wells). This may cause inaccuracies to creep into planning of upcoming wells as well as in targeting the objectives. Mudloggers and MWD Engineers normally follow the driller’s depth. Depth inaccuracy may come either from a typo in driller’s pipe tally or due to wrong measurement of BHA or missing out a part of BHA or LWD tool. Although these errors are rather rare but when they are observed they are usually observed at the beginning of new drilling phase. On rare occasions these mistakes are picked at very advanced stage of drilling phase. Say 400 to 500m have been drilled. In that case applying corrections becomes a nightmare for mudloggers and MWD engineers. Therefore one should remain alert to this possibility and pick the pipe discrepancy as soon as it happens
Q97. What is the significance of monitoring of ROP?
Monitoring rate of penetration gives us valuable information about the formation, formation change as well as an idea about formation pressure. Drill breaks (sudden fast ROP) sometime gives us a critical warning about a kick and frequently shows a change in formation. Conversely a slow ROP tells us that the bit is either drilling a hard formation or has worn out.
Q98. What are surface controlled drilling parameters that can affect ROP?
There are many drilling parameters that can affect rate of penetration: Bit type, bit size, bit nozzles, WOB, Flow Rate, RPM, MW,
Q99. What is lag depth?
Lag depth is the depth of formation at which it has been drilled and released the gas and cuttings. These cuttings and gas come to surface after one lag time.
Q100. What is Lag Time?
Lag time is the time taken by gas and cuttings to move from bottom of the hole to the surface of hole.
Q101. What are the factors that you take into consideration to calculate lag time?
Main factors are: 1. Hole geometry. 2. String OD and ID. 3. Flow rate. 4. Depth
Q102. What are the sources of errors in collecting lagged data and cutting samples?
There may be several reasons for lag samples not being representative. But most of these inadvertent errors can be checked and corrected. Some of the reasons could be as follows:
1. Wrong lag time due to mistake in calculation or wrong data input
2. A lazy sample catcher not collecting samples at proper time
3. Change in lag time due to severe hole wash-out, especially if the open hole section is log.
Q103. A lag time was checked by rice test. It showed 6 minutes more than the calculated lag time. How will you explain the difference?
This increase in lag time happens due to wash out in the open hole section and needs to be adjusted in lag time calculations.
Q104. Looking at mudlog, how will you know if there is a mismatch between lag depth and measured depth?
By looking at thin streaks of dolomite or coal or even looking at top of sand we can find out if drill break, lithology and gas peak are in alignment or not. If the three parameters are not supporting each other at the same level, it will be said that there is a mismatch between the measured depth and lag depth.
Q105. What are commonly used digital sensors in mudlogging operations?
SPM, RPM and drawworks sensors may be cited as examples of digital signals.
Q106. Where is hook-load sensor installed?
Hook-load sensor is installed at dead end of drill line on rig floor.
Q107. Why do we monitor and record hook load?
Hook-load is a crucial parameter. Some of the important information it gives is:
1. Tells us total load of drill string
2. Hook-Load off-bottom – Hook-Load on bottom = Wait on Bit (WOB is estimated from Hook-Load)
3. Thresholds set on hook-load tells us whether drill string is off-slip or on-slip. This status decides whether to ignore hook movement or count the movement to show bit depth. This is why if Hook Load sensor breaks down we cannot record ROP or bit depth. More over without looking at hook load driller cannot apply WOB to drill formation.
4. Hook-load tells us if the hole is normal or tight or if there is an accumulation of cuttings at the bottom (hole fill) or somewhere in between casing shoe and bottom of hole (hole bridge).
5. If the string gets stuck hook-load will increase by 50% or more without any significant upward or downward movement of the drill string.
5. If the hook load is suddenly reduced by half or so it could mean that string has parted.
Q108. What is working principle of Hook-Load sensor?
A hook-load sensor is a strain gauge type transducer. When pressure is applied on strain gauge it causes change in electrical resistance proportional to the applied pressure. This resistance in terms of voltage is calibrated to read in pressure in pounds /sq inch or load in Kilo pounds or tones
Q109. What are the drilling parameters that we will not be able to record if Hook-Load sensor breaks down?
We will not be able to record hook load itself, WOB, ROP, Depth and lag Depth.
Q110. How is weight on bit applied on the formation to drill?
Knowing the type and compactness of formation in the area, a range of WOB as well as bits are suggested in the drilling plan. Softer formations are drilled with lower WOB but as hardness and compactness of formation increase with depth more and more WOB is to applied to drill hole efficiently. Only a fraction of weight of BHA is applied on the formation through the bit. An optimum weight is usually decided by the driller based on his experience. WOB is equal to the WHO off bottom minus the WHO on-bottom. Applying WOB mor than required may damage or worn out the bit prematurely. Conversely applying less than optimum WOB will slow down the progress.
Q111. What do you understand by RPM? What is the name of the force that is required to rotate the bit
Rotation per minute (RPM) indicates the revolution of bit per minute. It is a crucial parameter in drilling a hole. So much so, that we cannot drill hole if we cannot rotate the bit. The force required to rotate the drill string and the bit is called Torque.
Optimum RPM is chosen according to bit type and formation hardness. In general, higher RPM helps increase ROP in softer formation but in harder formation a moderate RPM is required to avoid premature bit wearing and to avoid vibrations on drill string which can damage expensive MWD/LWD tools.
Q112. What are proximity sensors? What is their working principle?
Proximity switches of inductive type are commonly used to count strokes (SPM) and bit revolution (RPM) in mudlogging units. These sensors have a coil which generates a magnetic field around the sensor. When a metal objects comes close to the sensor it disturbs the magnetic field and induces a current in sensor’s coil, which in turn generates a signal. Mudlogging software then manages the signal count in the form of SPM or RPM as well as total counts.
Q113. What do you understand by torque? What is its significance in mudlogging?
Torque is a rotational force or twisting force that rotates drill string and bit. It is measured in Nm (Newton – Meter) or ft-lbs. (foot pounds). Newton is a force required to move one Kilogram to a distance of one meter in one second. However, in mudlogging unit we normally record torque in terms of ampere.
Torque is an important parameter that gives critical information about bit condition, hole condition and nature of formation.
Q114. How does erratic torque look on the chart? What are the possible down hole conditions it indicates?
An erratic torque shows sharp fluctuations (up and down spikes) on the chart and unusually high vibrations on drill string. It could be due to anyone or more of the following causes:
1. Alternate soft and hard thin beds
2. Broken or undergauge bit
3. Stabilizers hitting or reaming the hole wall
4. Drilling on metal junk or on casing of nearby wells.
Q115. What is you interpretation if the torque is occasionally or continuously increasing?
1. Hard formation
2. Unnecessarily high WOB
3. Unnecessarily high RPM
4. A sharp build or drop in inclination
Q116. Why do we count the strokes of mud pump?
Strokes per minute (SPM) is an important parameter that tells us the amount of mud being pumped into the hole. The flow rate or circulation rate helps us in calculating lag time and thus assigning lag depths to cuttings and gases.
Q117. What is the significance of monitoring and recording Stand Pipe Pressure (SPP )?
Standpipe pressure indicates the force required to pump mud in and out of the hole. SPP is primarily affected by the mud density, hole depth and hole geometry including the pipe IDs and ODs, bit nozzle sizes and cuttings accumulation in the annulus.
Recording and monitoring SPP is important as it can give crucial information about downhole condition. For example: a slow and continuous drop in SPP could mean a leak in the pipe, if not on surface then it could be in drill string. If the wash out in drill-string is not detected in time, it may cause parting of drill pipe. Parting of drill pipe is indicated by a sudden drop in hook load and standpipe pressure.
A sudden drop in stand pipe alone by 20% to 30% could mean a nozzle has been washed out. Conversely a sudden increase in SPP by 20% to 30% could mean that one nozzle has been blocked.
If standpipe pressure is slowly increasing beyond the normal; it could mean that hole cleaning is not efficient and that there is build up f cuttings in the annulus. This situation also leads to increase in ECD.
In case SPP quickly shoots up while trying to establish circulation it could mean either drill pipe got stuck or all three nozzles got blocked. In case hook-load remains normal, all nozzles are choked. If hook load drastically increases while trying to pull up the pipe then the pipe is stuck.
Q118. What is working principle of Standpipe Pressure sensor?
A SPP sensor same as hook-load sensor is a strain gauge type transducer. When pressure is applied on strain gauge it causes change in electrical resistance proportional to the applied pressure. This resistance in terms of voltage is calibrated to read in pressure in pounds /sq inch or kilogram per square centimeter Kg/cm2
Q119. Name various types of mud tanks and their uses.
ACTIVE MUD TANKS: are used to circulate during drilling and are closely monitored for mud loss and gain. It may be a single tank or two or more interconnected tanks.
NON-ACTIVE TANKS: are the spare tanks not connected to active tanks. They are used for keeping the extra mud in spare to meet out any emergency.
MIXING TANK: in this tank chemicals are mixed to prepare mud.
SUCCION TANK: This tank is connected to the mud pump. It feeds mud to the pump that forces it into the well and out of it.
SETELLING TANK: This tank is located underneath the shakers or adjacent to them, the heavier rock particles (called solids) are settled at the bottom of the tank while clean mud flows from the upper section of the tank.
TRIP TANK: is usually a smaller tank, it is used to fill hole while POOH and take mud returns while RIH. A smaller size of the tank makes it easy to detect minor changes in the mud volume (gains or losses)
Q120. How do mud-level sensors work?
Currently ultrasonic sensors are in use. These sensors produce high frequency (ultra sound) waves which hit the mud and are reflected back to receiver. The travel time is then converted to distance and then to mud volume.
Q121. Why do we record temperature in and temperature out data? How and for what purpose do we interpret temperature plot?
Temperature in & out gradients help in identifying over pressure zone.
Notes:
In theory, temperature data is plotted to detect any abnormality in geothermal gradient. Normally geothermal gradient increases at a constant rate with depth. However, if an over pressure zone is encountered, the gradient gets disturbed, first it reduces and then increases at fast rate indicating abnormal formation pressure zone. The higher-than-normal temperature gradient in overpressure zone is recorded due to the fact that overpressure zones are undercompacted (porous & permeable); therefore, they contain lots of water in them. Water is poor conductor of heat compare to solid rocks. Its reduces the transmission of heat to shallower depths. This trapped heat in pore water increases thermal gradient in overpressure zone. As water is poor conductor of heat, it does not transmit heat to shallower depths; that is why we record less than normal thermal gradient above the overpressure zone (called zone of starvation).
Bear in mind that temperature data by itself, is not a reliable indicator of overpressure zone as its accuracy is affected by number of factors, such as mixing new mud, adding water to the circulating mud or breaks in circulation during trip etc. may seriously disturb the trend.
Remarks:
In mudlogging, thermocouple type temperature sensors are generally used. Here is how thermocouple sensor works:
Construction: A thermocouple consists of two wires made from different metals, joined at one end to form the measuring point or “hot junction.” The other ends of the wires remain separate and form the “cold junction.”
Seebeck Effect: When the hot junction experiences a temperature change, it generates a voltage. This voltage is proportional to the temperature difference between the hot and cold junctions.
Voltage Measurement: The voltage generated by the thermocouple is measured using a special instrument called a potentiometer or a voltmeter.
Temperature Conversion: The measured voltage is then converted to a temperature value using a pre-calibrated table or equation specific to the type of thermocouple used.
Q122. Why do mudloggers record and monitor conductivity or resistivity of mud in and mud out
A comparison of conductivity in and out plots help us understand the nature of formation water and sometime formation itself:
If we drill through halite formation, the conductivity of mud will suddenly increase to very high level
In case of a water kick we can know whether the influx is of saline water or fresh water by looking at conductivity data.
If we are drilling with sea water-based mud. A slow decrease in conductivity may indicate that we are drilling through fresh water formation and vice versa.
Conductivity and resistivity are inversely proportional to each other. If one increases the other decreases. Unit of resistivity is ohm – m and that of conductivity is S/m.
Q123. What type of conductivity sensor is usual used by mudlogging companies?
There are many types of conductivity and resistivity sensors but the one we use for mudlogging purpose is Elecromagnetic Induction type. These sensors have a sealed magnetic coil that induces current in the mud. The strength of induced current is proportional to mud’s conductivity which is then measured in voltages and converted to a readout.
Q124. What types of flow out sensors usually used in mudlogging?
Usually, two types of flow out sensors are used in mudlogging:
1. Pedal type with a potentiometer 2. Electromagnetic.
Pedal sensors are most commonly used type. Easy to install and maintain as well as cost effective. It has pedal immersed in mud that gets lifted up by the force of flowing mud. Pedal is connected with a potentiometer through a rubber belt. As the pedal moves up and down it rotates potentiometer-shaft and produce a voltage that according to calibration gets converted to mud level in the flow-line.
Magnetic sensors on the other hand employ electromagnetic impulses to gauge the volume of mud flowing through the flow-line. This sensor though accurate and volumetric, is also very expensive and complicated to install.
Q125. Why do we have to monitor mud flow out very closely?
Among various indicators of a kick and mud losses, flow out is the most important, most reliable and most immediate indicator of a kicks and mud-losses.
Q126. Apart from gas, what in your opinion are the two most important sensors that you would always keep in the unit as spares?
Depth and SPM sensors. Depth because all other parameters are recorded against depth. SPM or rate of mud flow is crucial to calculate lag depth. Without knowing lag time we cannot make sense of gas and lithologies.
Q127. What are important parameters on which you will set alarm more closely than the others?
1.ROP. 2. Mud Flow out. 3 Active pits. 4. total gas.
Q128. What are the uses of drilling fluid (Mud)?
Drilling fluid or mud plays multiple roles in oil well drilling:
1. It brings the cuttings and gas to the surface, the study of which gives us crucial information about the hydrocarbon reservoirs in the well
2. It keeps the cutting in suspension even if the mud is not in circulation; thereby avoids settling of cuttings around the bit, thus avoids pipe getting stuck
3. It keeps the bit and BHA cool and provides lubrication, thus avoiding premature failure of bit and BHA
I4. t provides sufficient hydrostatic pressure to balance formation pressure thus avoiding kicks and blow outs.
5. Mud also seals formations by forming mud-cake against pores and fractures thus preventing communication of fluids between borehole and formation
6. The hydrostatic pressure exerted by mud also helps prevent hole from collapsing specially against fractured, friable and soft formations.
Q129. Explain the units of drilling fluid (Mud).
In oil industry, density of drilling fluid (Mud Weight) is measured either in pounds per gallon (ppg) or Specific gravity (Sg)
Pounds per Gallon (Lb/gal or ppg): is the most commonly used unit by American and Canadian Oil companies. It simply means the weight of a fluid of one gallon in pounds. For example, fresh water has a density of 8.345 ppg, which means that a gallon of fresh water weighs 8.345 pounds. Similarly, 15.0 ppg MW means that one gallon of mud weighs 15 pounds.
The other unit of density that is usually used on oil rigs is Specific Gravity (Sg). It is a dimensionless unit, meaning it is a ratio of mud density to water density at 4 deg C. Therefore, for fresh water SG is taken as 1.0. 1.5 sg MW means that mud density is 50% more than the density of water.
Q130 A. What do you understand by ECD?
Ans. Equivalent Circulating Density is the effective MW (mud density) at the bottom of hole during circulation. ECD is always higher than the MW. The reason for this is the pressure applied on the mud (to circulate) compresses the mud. This compression increases the density of mud and hydrostatic pressure. This slightly increased MW is called ECD. The moment circulation is stopped ECD becomes equal to MW.
Q 131. Where do you read ECD?
ECD is not directly read in mudlogging unit, it is calculated using vertical depth, MW, hole geometry and pressure losses in Annulus. However, this is theoretical ECD. This may not be the actual ECD. To find out actual ECD we should also take into account the amount of cuttings in the annulus. There is no way to know that. However, MWD tool has a pressure sensor very close to bit which directly reads the hydrostatic pressure at the bottom during circulation and non-circulation time. From this pressure ECD is calculated and displayed regularly on the screen. If ECD becomes too high it means cuttings are building up in the annulus and that we must clean the hole properly.
Q132. What are different types of muds that you are aware of?
Simply speaking there are three types of mud systems:
Water Based (Fresh water and sea water based)
Oil Based (oil based and synthetic oil based)
Pneumatic Drilling Fluid (Air, Mist, Foam, Gas)
Which fluid system is to be used depends upon:
1. Its technical Performance
2. Cost considerations
3. Environmental considerations
Q133. How do you calculate hydrostatic pressure, given MW = 12 ppg, and vertical depth = 9000’tvd?
Using the equation, we can calculate hydrostatic pressure:
P = 0.0519 x MW x TVD
Hydrostatic Pressure = 0.0519x 12 x 9000 = 5605 psi
P = hydrostatic pressure (psi)
MW = mud density (ppg)
TVD = vertical depth (ft)
Notes:
How to calculate hydrostatic pressure gradient?
MW (ppg) x .052 = psi/ft
12 x .052 = 0.624 psi/ft
How to calculate MW, given hyd. Pressure and TVD
MW = Hyd. Press/(0.052xTVD)
5605/(0,052×9000) = 12.0 ppg
Conversions in metric system
To convert a mud weight to a pressure:
sg x 1.421 x TVDm
To convert a pressure to a mud weight (EMW)
psi / TVDm / 1.421
To convert a EMW to a gradient :
sg x 1.421
NOTE : when calculating pressures using these equations always use True Vertical Depth.
Q134. What are the operations that happen on an oil rig during no-drilling period?
There are many non-drilling operations that are conducted on the rig:
1. Tripping
2. Casing
3. Cementation
4. Wire-line logging
5. Conventional coring
6. Production testing
Coring Operations
Q135. What are two types of coring operations performed on the rig?
The two types of coring operations are:
1. Conventional core: cut and retrieved using drill pipe, coring BHA and diamond core bit.
2. Sidewall core: taken on wire line using coring gun.
Q136. What are some of the objectives of coring?
The main objectives are:
1. To perform quantitative analysis of porosity, permeability and fluid saturations
2. Identify sedimentary structures and fossils
3. Obtain uncontaminated samples for further analysis
Q137. As a mudlogger, how will you prepare for an upcoming conventional coring job?
As conventional coring is not an everyday operation and it involves logistics, it is critical to start preparing for this operation at an early stage. Mudloggers should pay special attention to the following consumable items:
1. Ensure we have large number of rags to clean core when it is on surface
2. Ensure we have enough core boxes (length of core in ft /3 + 20%)
3. Permanent markers Red/Blue/Black (one box of each)
4. Wooden pallets as per the number of core boxes
5. Measuring tapes (Two)
6. Seal peal, wax bath and wax
During drilling, mudlogger is required to help geologist in picking up coring point by closely monitoring drilling breaks, Gas, and collecting spot samples as often as required.
Q138. What are some key steps involved in the conventional coring process?
Some of the key steps involved in conventional coring process are:
Cleaning and conditioning the hole
dropping the coring ball
optimizing coring parameters and start cutting core
monitoring parameters closely
and breaking the core before retrieval
Q139. Why is it important to closely monitor drilling parameters during coring?
To detect problems, optimize recovery, and identify lithologic variations from minor drill rate changes.
Q140. How is core retrieved and handled at surface?
As the core comes out, it is broken into lengths, cleaned, depth marked, wrapped, and packed into labeled core boxes
Notes:
A lot depends on coring plan and type of core barrel. If we have aplastic or aluminum sleeve inside the barrel then the whole core in the sleeve is taken on a core cradle from rig floor and brought to core processing area where it is cleaned cut along with the sleeve into meter long pieces. Thereafter each piece is marked for depth and top and bottom and placed in the box after putting caps on either end.
If the core barrel does not have a sleeve, then core is usually cut into pieces on rig floor itself. Driller and coring engineer perform this job. Mudlogger and data engineer are there to help geologist collect the core. Important point to bear in mind is not to disturb the orientation of core. The bottom part of the core should go to the bottom side of pre-labeled core box using the correct box number. These core boxes are promptly transferred to core processing area. A core processing area is a designated area on the rig marked by company man and tool pusher to process the core. In core processing area, core is cleaned and marked for depth and top/bottom. After which the cores are placed in boxes and boxes are labeled. On core boxes we indicate well name, Core number, box number (eg. 1of 15, 2 of 15..etc) depth from – to and top and bottom.
If the core is in sleeve, we only collect small core pieces from each end and describe them in detail. However, if the core is not in sleeve, then apart from lithology and hydrocarbon show, we should also describe sedimentary structures, fractures, macrofossils etc.
If engineering data like fluid saturation is required then entire core or part of the core is sealed using wax. For this purpose mudlogging company should arrange in advance wax, wax bath and thin film (seal peal).
Rigging Up
Q141. How do you select a location for placing mudlogging unit on an onshore rig?
The location is selected in consultation with company man and drilling supervisor. The unit should neither be placed too close to rig structure nor too far away from rig structure. In the first case, there will be risk of concentration of poisonous and explosive gases. Also there is too much of movement of heavy equipment and pipes near the rig floor. In the second case sample catching which is a constant process during drilling will become difficult. Also long cables will have to be used with the risk of physical damage.
There should be sufficient empty space around the unit to place sample boxes, core boxes and a small container of spare parts.
Q142. What challenges do you face while rigging up mudlogging unit on a new rig?
We are often called on a short notice. Time allotted to complete rig up is usually limited. Needed help in the form of welder and electrician is often delayed because they are also very busy with their rig jobs.
Q143. How do we install a mudlogging unit on a rig?
In a nutshell, we place the unit at an optimum location, arrange power supply, install sensors, run cables and calibrate the sensors.
Q144. What are, the mudlogging related problems that a Mudlogger may encounter on the rig?
A Mudlogger may occasionally face different types of problems such as, related to sensors (sensor failure or dislocation or calibration contamination), Equipment related problems inside the unit such as flame not burning inside chromatograph, pressurization of unit not functioning or run out of some of the consumables or spares.
Drilling Related Problems
Q145. What are some of the drilling related problems that you have faced on the rigs?
I have encountered partial to total mudlosses, kicks and washouts in drill string. These have enriched my experience as a mudlogger.
Q146. How do you pick mudloss?
A drop in mud level in active pit coupled with reduced level of mud flow out when there is no change in SPM is a sure indication of mud loss
Q147. What causes mudloss?
Mudloss (partial or total) happens when we encounter weak and fractured formation or highly porous and permeable formation with depleted formation pressure. The other factor that often contribute to mud loss is serious imbalance between hydrostatic pressure and formation pressure. Sometime poor cement job leading to channel development behind the casing may also cause mudloss.
Q148. If mud pressure gradient is 0.9 psi/ft and fracture pressure gradient is 0.8 psi/ft; Will we get kick in this situation or not?
No. We will not get kick. Instead, we will get severe mudlosses in this situation; because MW is higher than formation strength.
Q149. What are the implications of mudloss?
Apart from delaying drilling progress and loss of expensive drilling fluid, total mudloss may also lead to a well control situation and collapse or caving-in of bore hole and long-term damage to reservoir.
Q150. What is blind drilling? Under what situation blind drilling should not be carried out?
Blind drilling is sometime conducted when we are facing total mudloss. When we do not get returns, we sometime continue drilling with water, trying to keep the annulus as full as possible. Once the returns are established, we switch back to mud system. We cannot do blind drilling if the formations are even slightly overpressured.
Q151. Looking at offset mud logs and drilling program you become aware that soon you will be entering a lost circulation zone. As a mudlogger how will you prepare to handle the situation?
Will do the followings to handle the challenge:
1. Ensure the volume of mud in both active pits and reserve pits is being indicated correctly. This can be ascertained by physically measuring the volume in each pit. Calibrate any pit that shows discrepancy.
2. Note down all the pit volumes and share with company man and mud engineer to avoid confusion in lost volume calculations at later stage.
3. Clean the mud flow out sensor to make sure it is functioning freely.
4. Set close alarms on flow out and on active pits.
Q152. What is a kick? What causes it? How do we control a kick?
A kick happens when formation fluid (water, oil or gas) enters into the borehole. This situation arises when hydrostatic pressure becomes less than formation pressure. In order to control a kick, we need to increase the hydrostatic pressure to slightly more than formation pressure.
Notes:
Hydrostatic pressure is the pressure exerted by drilling fluid (mud) in the hole. Hydrostatic pressure at any given point depends upon two things 1. Vertical depth and 2. Density of drilling fluid. Knowing these two factors we can calculate hydrostatic pressure using the formula: MWx0.52xTVD
Where, MW in ppg and depth in ft. This will give you hydrostatic pressure in psi. To increase or decrease hydrostatic pressure all we have to do is increase or decrease MW.
The only way to avoid a kick is to always keep the hydrostatic pressure slightly above the formation pressure. To do this we need to know exact hydrostatic pressure and exact formation pressure at any given depth during the course of drilling.
It is easy to find out accurate hydrostatic pressure at any given depth. However, it is extremely difficult to calculate exact formation pressure. Certain algorithms like d’exponent or sigma log or using sonic log, resistivity log or density log, are commonly used during drilling to find out formation pressure but all these give a very rough estimate. This is why we cannot always avoid kicks.
Actually, there are two operations that give us the exact formation pressure 1. Wireline pressure tests and 2. Production testing. Unfortunately, both these tests are performed after the drilling is over. So, there is no way to find out exact formation pressure at the time of drilling. Controlling kick is the third operation that tells us the exact formation pressure. Unfortunately, this knowledge of exact formation pressure comes to us after the kick has taken place. Anyway, knowing exact formation pressure even after kick is still very important as it helps us to calculate the MW required to control the kick. Also it help us to calibrate our logs that predict formation pressure.
How do we find out formation pressure from a kick? Well, as soon as the driller realizes that a kick is taking place; first thing he does is shuts in the well, using the BOP. When the well is shut in we record two pressures called SIDPP (shut in drill pipe pressure) and SICPP (shut in casing pipe pressure. SIDPP is actually the pressure exerted by formation pressure on the mud which is inside drill pipe. Also please note SIDPP is the amount of pressure by which the formation pressure exceeds hydrostatic pressure. Again, SICPP is the pressure exerted by formation pressure on the mud inside the annulus. However, we use only SIDPP to calculate formation pressure not SICPP. The reason is that annulus apart from mud also contains gases and cuttings which affects the hydrostatic pressure by an unknown amount. Whereas, inside drill pipe the mud is clean (not contaminated with gases and cuttings), therefore its hydrostatic pressure is accurately known. After the kick, we estimate formation pressure accurately by adding SIDPP to hydrostatic pressure at the bottom.
Now let’s understand this with an example: Suppose we got a kick at 2000’MD / 1800’TVD while drilling hole with 10ppg MW. SIDPP recorded is 300 psi while SCPP is 280 psi. (We ignore SCPP in our calculations for the reason mentioned above)
Let’s find out the hydrostatic pressure at bottom: 10ppgx 0.052×1800’TVD =. 936 psi (Hydrostatic pressure)
Formation pressure = SIDPP + Hydrostatic pressure
300 + 936 = 1236 psi
To find kill mud weight = formation pressure / 0.52/ Depth in TVD
1236 / 0.052 / 1800 = 13.2 ppg
In order to kill the kick, we need to increase MW from 10 ppg to 13.2 ppg.
Drilling supervisors normally increase by another .2 or .3 ppg. Or even more. This is called safety margin. Safety margin take care of swabbing effect during connection or POOH. So final kill MW would be around 13.5 ppg.
Q153. Can we get a kick even if the formation pressure is normal?
All kicks happen when formation pressure exceeds hydrostatic pressure. This situation can also be created when the formations are normally pressured.
Here are the scenarios:
1. Formation pressure is normal. We are POOH very fast, creating swabbing in the hole and not taking out time to fill the hole properly. This may lead to situation where hydrostatic pressure becomes less than formation pressure and invite the influx into the bore hole.
2. Formation pressure is normal. We RIH nozzles get blocked and mud displacement becomes many time more than it should be. Nobody notices this and no correction to situation is applied. This will create an underbalance condition in the hole and invite a kick.
3. Formation pressure is normal. We start losing mud totally and rapidly without realizing it. This will also reduce the hydrostatic head and allow the influx to take place.
Q154. Can there be a situation where we have formation pressure more than hydrostatic pressure and not get kick?
Yes. If we are drilling a thick section of shale, in which formation pressure starts increasing and becomes more than hydrostatic pressure. We will not get any influx because shale is impervious. Nothing can quickly flow out of it. In an underbalanced situation, shale will not cause a kick but it will respond by producing large amount of splintery cavings. Bear in mind in this situation as soon as we encounter a sand bed, we will get the kick.
Q155. Can you identify water kick from gas kick after the well is shut in?
When we get water kick and well is shut in, we record mild pit gain and mild shut-in pressure, where as gas kicks are violent, they show high shut in drill pipe pressure and large pit gains in short time. (This statement is based on empirical observation).
Q156. What do you understand by poor hole condition? How to identify it? What are the factors that cause it? What are the implications of poor hole condition?
Poor hole condition means instability in open hole section. Poor hole condition can be identified by excessive amount of cavings on shaker, high torque, overpull etc. This hole instability may happen due to any or combination of the following factors:
1. Presence of fractured and friable formations in the open hole section
2. Improper mud selection, hydraulics and hole cleaning
3. High angle deviation (>60 deg.)
4. Insufficient hydrostatic pressure
5. High formation pressure (creating large amount of cavings and rock chunks)
6. Excessive drilling speed and rotary speed.
Poor hole condition may delay the drilling progress and in worst condition may lead to pipe getting stuck and sidetracking the well. Therefore, it is necessary to identify the problem as early as possible and bring it to the attention of company man, mud engineer and driller.
Q157. How can you identify a wash out in drill pipe? What will happen if wash out is not picked up?
A wash out in drill pipe can be identified by slow and continuous drop in stand pipe pressure provided there is no leak on surface and mud is not being diluted. Also ensure the SPP sensor is not having oil leak or any functional problem. If we miss picking up wash out, it may soon cause drill pipe to part away. Most of the time we are successful in fishing out the dropped pipe but some time we are not and may have to leave expensive BHA, LWD and MWD tools down hole followed by plugging and abandoning the hole and the performing a side track or drilling a new well.
Q158. What are two ways in which pipe may get stuck.
Two main types of pipe sticking are:
Mechanical sticking and
Differential sticking
Notes:
There are multiple reasons for mechanical stuck pipe:
1. Packoff due to poor hole cleaning
2. Shale/claystone swelling
3. Bridging and wellbore collapse due to fractured or friable formation
4. Plastic-flowing formation (i.e., salt)
5. Keyseating
The key indicators of mechanical stuck up are:
1. Unable to establish circulation
2. Unable to rotate pipe
3. No or little reciprocation
Indications prior to mechanical stuck up:
1. Lot of cuttings and cavings on shakers
2. Occasional tight spots, overpulls and high torque
3. Occasional spikes on stand pipe pressure
4. Unusually high ECD
Differential stuck up is caused when:
Hydrostatic pressure significantly exceeds formation pressure
Formation is porous, permeable and depleted in pressure
Drill string is stationary.
Please note, differential pressure also happens when formation pressure exceeds hydrostatic pressure but this does not cause sticking instead it causes a kick.
Drilling development wells in old field where reservoirs have become depleted, could be regarded as potential site for differential sticking.
Differential sticking can be differentiated from mechanical sticking by the fact that when we are stuck mechanically we cannot circulate, where as if pipe stuck is due to differential pressure, we can still circulate at normal SPP. However if the pipe is stuck in a key seat, we will be able to circulate, rotate and partially reciprocate drill string.
Q159. What do you understand by ‘dog leg?
Any sharp turn either in inclination or azimuth or both in a hole, is called dog leg. It is often unintentional and undesirable. Some of its implication could be:
Increased wear and tear on drill string
Difficult to run casing through the key seat area. This may sometime get casing pipe stuck.
Dog leg may cause poor cement job, creating channels and patches of no cement behind the casing.
Dog leg may lead to development of key seat thus enhancing chances of pipe getting stuck.
Q160. What is gumbo in oil well drilling? What are its implications?
Gumbo is a soft and sticky clay, often encountered at shallower depth. Due its highly sticky nature it blocks annulus, flow line and possum belly. When encountered it slows down the drilling progress as we have to remove it manually from flowline and possum belly. Gumbo is the main reason behind bit balling, that further slows down ROP.
Q161. What are hydrates? where do we encounter them? What are their implications?
Hydrates are complex mixture of methane and water formed in very cold environment specially when drilling deep water wells. They look like ice crystals and are formed under specific temperature and pressure. Drilling hydrates slow down drilling and give high torque. When large amount of hydrates move up in the annulus, they may release significant amount of gas and water and may some time give false impression of a kick.
Q162. Why do we fill up casing with mud during RIH? What will happen if we do not fill up casing while RIH?
It is extremely important to fill casing with drilling fluid at regular intervals. If we do not do it, the casing may collapse and get stuck in hole. We will have to plug and abandon and move away, thus losing the hole.
Q163. What are the problems that we may encounter while running the casing pipe?
1. Casing may get stuck if hole is highly deviated and the formation is fractured or very fissile.
2. If we run casing in poor hole condition then we may encounter hole bridge due to hole collapse, stopping the casing to go any further.
3. If casing is not properly filled it may collapse and get stuck.
4. Presence of a severe dog leg in hole will create resistance to casing running.
Q164. What problems have you observed while cementing the casing?
I have observed several problems associated with cement jobs:
1. No or partial return of mud during displacement. So, most cement would go to formation rather than behind casing. This will create channels and patches behind casing. This poor cement does not does not allow casing to provide intended protection to the well.
2. Unable to displace cement full or in part from inside the casing due to failure of pumps. Ultimately drilling out cement from inside the casing.
3. Sometime top plug drops before we start displacement. This, apart from mixing the mud with cement, does not allow cement displacement from casing to annulus. Thus, cement gets hardened inside the casing. That takes days to drill out.
Additional Points
Q165. What is well prognosis? What information are provided in it?
A well prognosis is a well plan given to service companies by oil company. It tells us size and depth of various hole sections, casing sizes and shoe depths, mud type and mud weight to be used in each section, Formation to be expected, sample program for each phase, logging program etc. etc.
Q166. What are the roles of casing shoe and float collar in a casing string?
Casing shoes is placed at the bottom of casing string. It has a non-return-valve (NRV) that allows mud and cement to pass out from casing to annulus but not from annulus to casing. The other job of casing shoe is to guide casing form tight hole and minor dog legs. Float collar (placed 1 – 3 joints above the shoe) basically provides landing platform for bottom and top wiper plugs. Sometime float collar is also equipped with an NRV as a backup.
Q167. What is difference between casing and liner?
A casing is run from bottom of hole section to bottom of conductor pipe and is always cemented while a liner is usually run in the bottom part of hole. Like casings it does not go all the way to conductor but is attached to the bottom part of last casing using casing hanger.
Q 168. There are different types of bits used to drill oil well. Can you name a few types?
Different types of bits are used according to formation hardness in oil well drilling. Some of well known types are: 1. Mild tooth bit. 2. Insert Bit (button bit). 3. PDC bit (Polycrystalline Dimond Compact)
Q169. What is difference between LOT and FIT? Why do we perform these just below the shoe?
Both leak off test and formation integrity tests are performed after drilling out the shoe and 10 ft (3m) of formation. LOT is performed to find out the strength of formation to know what is the maximum MW that will fracture the formation therefore should be avoided not to cause mudloss.
To perform LO, pressure is applied until formation gets fractured and pressure starts leaking off. LOT is commonly performed on exploratory or semi-exploratory wells and in overpressure wells.
In fields where the formation pressure is known to be normal, FIT is performed instead of LOT. In FIT a formation and casing shoe is tested up to a predetermined pressure not to the point where it leaks, to avoid unnecessary damage to formation and cement around shoe.
Why do we perform LOT and FIT just after drilling few feet of formation? In each open hole section, the formation is weakest just below the shoe. This is the area where, if a kick is not handled properly may cause underground blow out.
Q170. What is the use of calcimetry in mudlogging?
Calcimeter is a valuable tool as its analyses is used for multiple purposes:
The analysis helps in finding the percentage of limestone, dolomite and marl
If calcimetry is performed consistently for each well, then the calcimetry data can be used to correlate various carbonate beds along with sonic and density logs.
High carbonate content is often associated with good secondary porosity, therefore, calcimetry data can help identify potential reservoir section in carbonate rocks.
Q171. How do we do shale density in mudlogging unit?
There are two different type of kits that are usually used by mudloggers to determine shale density. One is weighing the shale grain in water and in air then calculating out density. The other is using the graded density liquids, where in, we drop a shale grain and read the density from the graded tube where the grain stop falling.
Both these methods have challenges in maintaining the kits in good condition and picking the uncontaminated shale grains.
Q172. What is the use of shale density determined by mudloggers?
This real-time shale density data is plotted to pick overpressure zone.
Notes: Shale density increases with depth due to increasing overburden pressure and increasing compaction. Overpressure zones on the other hand are under-compacted and therefore, less dense. So, any deviation from compacting trend is considered due to overpressure
Q173. What is Shale Factor? Why do we perform it in mudlogging unit?
Shale Factor is a titration method performed to find out cation exchange capacity (CEC) of shales. CEC of shale decreases with depth as the montmorillonite mineral gets converted into illite. Shale factor is used to identify overpressure zone. In a normally pressured environment, shale factor will decrease with depth. Increase in shale factor, therefore is taken as an indication of overpressure zone.
Notes:
Shales are composed of a number of minerals, important among them are illite and montmorillonite. Montmorillonite is abundantly found in clay and claystone. However, with increasing depth (increasing pressure and temperature) montmorillonite gets converted into illite (and claystone becomes shale).
Shale factor is determined by a simple chemical titration method using methylene blue dye and dry powder of shale cuttings. Shale factor also called CEC, is a measure of shale’s ability to adsorb positively charged ions (cations) from the surrounding liquid. Montmorillonite has high CEC value (>25 meq/100gm) because it has more negatively charged surfaces than illite (CEC value <25 milliequivalents per 100 grams of dry rock)
Metodology:
Crushed and dried shale cuttings are added to a solution containing methylene blue dye.
The solution is agitated, and the dye molecules adsorb onto the negatively charged clay particles, changing the solution’s color.
The amount of dye needed to reach a specific endpoint (color change) is proportional to the CEC of the shale.
Interpretation:
High CEC values (typically >25 meq/100g) indicate the presence of highly reactive clays like montmorillonite, which is associated with potential drilling hazards (swelling, hydration) and overpressure zones.
Lower CEC values indicate less reactive clays and potentially normal pressure conditions.
Q174. How will you handle sensor problems?
Depends on how sensor is behaving.
If the sensor readings are consistently low or high: consider recalibration. Sometime extreme temperatures can affect the readings.
If the sensor readings are erratic: before suspecting sensor and replacing it, one should check if the sensor is damaged or displaced. Also need to check out connections. They are clean (no moisture) and tight. Further check if the cable has not been damaged. If possible, swap the cables and see the readings.
If no readings at all: suspect sensor is dead or cable got cut or the electronic channel has developed a fault. Isolate the fault by first replacing the sensor, then cable, then electronics.
Q175. How do you select a location for placing mudlogging unit on an onshore rig?
The location is selected in consultation with company man and drilling supervisor. The unit should neither be placed to close to rig structure nor too far away from rig it. In the first case, there will be risk of concentration of poisonous and explosive gases. Also there is too much of movement of heavy equipment and pipes near the rig floor. In the second case sample catching which is a constant process during drilling will become difficult. Also long cables will be exposed to physical damage. Also, there should be sufficient empty space around the unit to place sample boxes, core boxes and a small container of spare parts.
Q176. What challenges do you face while rigging up mudlogging unit on a new rig?
We are often called on a short notice. Time allotted to complete rig up is usually limited. Needed help in the form of welder and electrician is often delayed because they are also very busy with their rig jobs. Sometime we find a few spares missing and have to get them from town on urgent basis.
Safety
Q177. What safety trainings have you completed?
Name whatever trainings that you have completed e.g. :
Fire Fighting
H2S Training
Helicopter Underwater and Escape Training (HUET) or its equivalent
Q178. What is Work Permit? When do mudloggers need it on the rig?
A work permit is a formal authorization to carry out a potentially risky job on the rig. The permit is obtained from company man or tool pusher. It mentions the scope of work, safety procedures, possible hazards and personnel involved. For example a work permit is needed before entering a confined space like tank or pit or any rig area with limited ventilation.
Q179. What is hot permit? When is it required?
Hot permit is a formal authorization, that is to be taken before conducting any job that generates heat, flame or sparks in an area that contains hazards of fire and explosion. Common activities that make hot permit mandatory are: welding, grinding, cutting etc.
Q180. Fire has been classified into various categories like class A, class B, class C etc. What is the basis of this classification?
The basis of classification is burning material. Accordingly different types of extinguishing material is used to put out the fire:
Class A Fire: It involves burning of wood, paper, cloth, rubber and plastic. For Class A fire we use water as fire extinguisher.
Class B Fire: It involves burning of oil, alcohol and grease. For this class of fire, we use foam, CO2 or Dry Chemical Powder (DCP)
Class C Fire: It involves electrical equipment. For class C fire, we use Dry Chemical Powder.
It is advisable to identify the type of fire before attempting to extinguish it. Wrong selection of extinguisher may be ineffective or even dangerous. Also bear in mind, these extinguishers are designed to put out small fires.
Notes:
Types of Fire Extinguishers:
Water:
Material: Pressurized water.
Suitable for: Class A fires (ordinary combustibles like wood, paper, and cloth).
Not suitable for: Class B (flammable liquids), Class C (electrical), Water conducts electricity and can spread flammable liquids.
Foam:
Material: A mixture of water, surfactants, and air that forms a blanket to smother the fire.
Suitable for: Class A and B fires (including flammable liquids like gasoline and oil).
Not suitable for: Class C (electrical) or Class D (combustible metals) fires.
Carbon Dioxide (CO2):
Material: Carbon dioxide gas displaces oxygen, suffocating the fire.
Suitable for: Class B and C fires (flammable liquids and electrical equipment).
Not suitable for: Class A (ordinary combustibles). CO2 doesn’t cool the fuel, so reignition is possible.
Dry Chemical:
Material: Powdered chemicals like sodium bicarbonate or potassium chloride that smother the fire and absorb heat.
Suitable for: Class A, B, and C fires (ordinary combustibles, flammable liquids, and electrical equipment). Some types are also rated for Class D (combustible metals) fires.
Not ideal for: Enclosed spaces due to dust creation. Can leave residue that damages electronics.
Choosing the Right Extinguisher:
Identify the type of fire: Look for the fire class rating on the extinguisher label.
Match the extinguisher to the fire class: Use the right type for the specific fire you’re facing.
Consider the surroundings: Be aware of potential hazards like electrical equipment or flammable liquids.
Know your limitations: Extinguishers are for small fires. Evacuate if the fire is large or spreading.
Q181. Where do you install H2S sensors on the rig?
Normally H2S sensors are installed at or near possum belly, pit room, rig floor and on gas-line inside mudlogging unit
Q182. If you are walking towards shale shaker and smell rotten egg smell and minor irritation in your eyes; what will you do?
Rotten egg smell is a sign of H2S which is a deadly poisonous gas. One should immediately move to upwind direction. Use PPE if available nearby and raise H2S alarm.
Q183. What is the lowest concentration of H2S that is harmful for human health?
10 ppm is the lowest concentration that is considered harmful to human health.
Notes:
The severity of H2S affect depends upon the concentration and duration of exposure. Here’s a breakdown of the different levels and their potential impacts:
Below 10: Odour threshold (rotten egg smell), may not cause noticeable symptoms in healthy adults for short durations.
10-50: Eye, nose, and throat irritation, coughing, headaches, dizziness, nausea. 50-100: Difficulty breathing, chest tightness, confusion, loss of coordination, fatigue.
100-200: Severe respiratory distress, pulmonary edema (fluid in lungs), vomiting, unconsciousness.
200-500: Rapid collapse, coma, potential death.
Above 500: Near-instantaneous unconsciousness, respiratory paralysis, and death within minutes.
Important to remember:
Even low concentrations of H2S can be dangerous for people with respiratory problems or compromised health.
The sense of smell can be dulled by prolonged exposure to H2S, making it unreliable for detection.
Exposure limits are set by occupational health and safety organizations like OSHA (Occupational Safety and Health Administration) and ACGIH (American Conference of Governmental Industrial Hygienists). For H2S, the OSHA permissible exposure limit (PEL) is 10 ppm, and the ACGIH threshold limit value (TLV) is 1 ppm.
Do not attempt to rescue others without proper training and PPE.
Q184. If you are working on an offshore rig with in an H2S infected field; How many life jackets and H2S mask you should have in the mudlogging unit?
We should have one set of each for every crew working in the unit in each shift plus one set in spare for the visitor.
Q185. What is MSDS? What does it tell you?
Material safety data sheet, also known as SDS (safety data sheet) or PSDS(Product data sheet) is a brief document that provides critical information about a chemical or product, such as:
Physical and chemical properties
Health and safety hazards
Safe handling and storage procedure
Emergency responses
Q186. What are the potential risks associated with oil rig operations?
An oil rig may be described as a huge factory in a limited space with lot of heavy and moving objects, flammable material and chemicals. Naturally oil rig operations pause multiple hazards like:
1. Fire and explosions hazards from oil and gases which are ever present on an oil rig
2. Exposure to poisonous gases like H2S and volatile chemicals that can cause skin and eye irritations
3. Moving machinery and heavy objects in a limited space. Risk of getting hit by moving objects, pinch point, electric shocks
4. Slips and trips due to slippery surfaces caused by oil and rain may cay cause potential injuries.
5. Drop objects and fall from height may also cause severe injuries.
Q187. What are the potential risks associated to conventional core handling and management?
Collecting conventional core on rig floor is quite risky. The sharp and jagged core edges may cause injuries to hand. Wet surfaces and slippery core plus limited space on rig floor may cause slips and trips. Heavy weight of core, if not properly handled may cause back injury. Further, fatigue, poor lighting in core processing area and uneven surfaces may further enhance the potential risks of injuries.
Therefore to minimize the risks one should adhere to all safety protocols and proper use of PPEs. Good communication in the team is vital during core processing.
Q188. What safety procedures will you follow while making dilute hydrochloric acid?
In order to safely dilute Hcl, we should: 1. wear proper PPE 2. Perform dilution in a well ventilated place 3. Pore acid into water (not water into acid otherwise there will be splashing around and we may get burns).
Q189. What do you know about different coloured bins placed on rig?
These are meant to segregate and manage waste material:
Blue bins are used to place dry papers and clean cardboard boxes
Green bins: Here, organic materials like food waste, fruits and vegetables, flowers, plate scrapings including meat, fish and leftovers and coffee grounds are disposed of so they can be taken to a composting site and turned into fertilizer and biogas for agricultural and energy use.
Red bins: In the red bin, drinking glassware, broken crockery, cling wrap, plastic bags, packing straps, sticky tape, are dumped, so they can be taken to the landfill for disposal.
Q190. What all will you check if you have to perform safety audit of a mudlogging unit?
In order to do a safety audit of a mudlogging unit, I will check the followings:
1. Emergency exit: its functioning and useability, that is, no obstacles inside and outside of it.
2. H2S sensors and flow out sensors are properly calibrated and functioning
3. MSDS sheet is available and properly displayed
4. Crew is using proper PPEs and spare PPEs (like life jacket and H2S masks if required) are available in the unit.
5. Crew has required safety certificates e.g. Firefighting, H2S and HUET etc.
6. Unit pressurization system is in operation
7. Extinguishers are available and crew is well trained in minor firefighting.
8. Check to see if crew is following safety protocols, attending various drills and safety meeting.
Q 191. How do check the validity of solvent before performing cut fluorescence?
We take a few drops of solvent in a dimple tray and place it under UV light, if it does not show any fluorescence it is good. On the contrary if it shows milky or pale colour, the solvent is either expired or contaminated and should be replaced.
Q.192 What precaution will you take while using solvent to check cut fluorescence?
We should take following precautions:
1. Use mask
2. Keep the solvent in tightly packed glass bottles. It gets contaminated if placed in plastic bottle.
3. If possible switch on ventilation while using solvent.
4. Should wash hands thoroughly after the use of solvent and before eating anything
Q193. What are major component of a BOP?
The major components of BOP are:
1. Annular BOP
2. Pipe Ram
3. Blind Ram
4. Shear Ram
Q194. What is the role of Blind Ram?
Blind ram is used to close well in a kick situation, when drill string is out of hole.
Q195. What is gas-cut-mud? What are its implications?
When a large amount of gas enters into hole and get mixed with mud it cuts down the mud density. Gas-cut-mud should not be circulated as this may invite influx into hole. When we record large amount of total gas, we should inform mud engineer to check mud density. If gas cut is observed, the mud should be passed through rig degasser to get rid of gas.
Q196. How do you QC a mudlog?
Ans. Look at accuracy of information on log heading, accuracy of scales. Consistency between lithology, ROP and Gas peaks. And completeness of comments in remark coulmn
Q197. In your opinion what qualities a good mudlogger should have?
Ans. To be a good mudlogger one must possess good mudlogging knowledge and skills. Good observation skills and good communication skills.
Q198. What are three important rock types that are required to form commercial hydrocarbon accumulations?
A. The source rock. The reservoir rock. The cap rock.
Q199. In your opinion what are three most critical parameters that you record in mudlogging unit?
Ans. 1. Depth. 2. Gas 3. SPM. (Without SPM we cannot estimate flow rate and lag depth)
Q200. How do cavings originate?
Ans. Cavings are not generated by the cutting action of bit. But they fall off from shale beds when formation pressure approaches hydrostatic pressure and or when hole condition becomes bad due to poor mud properties.
MUDLOGGING - OIL INDUSTRY
Oil industry is a global industry that deals with hydrocarbon exploration, production, refining and marketing. It is counted as one of the world’s largest and important industry that plays a vital role in the global economy.
The oil industry is typically divided into three main segments: Upstream: The upstream segment focuses on exploration and production activities. This includes performing various types of surveys, drilling wells and testing the oil and gas reservoirs to establish commercial viability and finally producing hydrocarbons. Midstream: The midstream segment deals with the transportation and storage of crude oil and natural gas. This includes building and operating pipelines, storage facilities, tankers and terminals. Downstream: The downstream segment focuses on the refining and processing of crude oil and natural gas into usable products, such as petrol, diesel, gasoline, jet fuel, LNG, PNG and various types of petrochemicals. It also deals with establishing the fuel stations and marketing the products.