Category: Blogs

Blogs, Mud logging

The Job of A Mudlogger

Mudlogging is one of the many important activities during drilling, especially in exploration drilling. Third-party service providers make up about half of the workforce on an offshore rig. With so many hi-tech and specialized operations being performed at all stages of the drilling operations it’s imperative that experts in their field perform these tasks.

The job of the “mudloggers” is to monitor the drilling operations from the time the well is spudded to the time the well is safely drilled, tested and secured for either production or abandonment.

“Mudlogger” is the generic term used to describe the field specialists who monitor the well and also collect samples for the geologist. The career progression for a mudlogger is to generally start as a sample catcher while they learn about the drilling operations, then progress to a mudlogger and with further experience, become a data engineer.

Sample Catchers

Dedicated sample catchers aren’t always part of the team but they often get “thrown in” as a complementary part of the mudlogging services. They don’t need to have any prior experience in working offshore or as a mudlogger, so it’s a very good entry-level job and is generally the starting position for a graduate geologist (or anyone else) who wishes to work offshore. Although you don’t need to be a geologist to be a sample catcher, most of them will be and will go on to get trained as a mudlogger.

Sample catching is without a doubt the least glamorous and lowest paid of all jobs on the rig…but you have to start somewhere! The role of a sample catcher is to provide the most basic geological data acquisition on the rig and to assist with all general activities when possible. The main duties of the sample catcher are:

  • Ensuring that representative geologic samples are caught throughout the drilling or reaming phases of the well program. This is done by collecting cuttings (drilled rock) samples, from the proper “lagged” (explained below) depths and at the proper intervals as required for evaluation. These samples are collected off the shale shakers, screened and washed, divided into correct portions, and packed into sets for the Client, partners, and government agencies. They may also have to assist in core recovery and packaging as required.
  • Preparing a clean “cuttings” sample on a sample tray for the wellsite geologist and mudlogger, who will then examine it under the microscope and describe the lithology of the drilled formation.
  • Assisting mudloggers and data engineers to perform regular and frequent calibration checks of instruments, perform normal routine maintenance of sensors and other equipment and also assist logging crew with rig-up/rig-down procedures.

 

Shaleshaker-Amanda
A shale shaker

 

The sample catcher reports directly to the mudlogging crew who will ensure his duties are performed correctly. This may include on-the-job training as required. They work out of the mudlogging unit, which is always close to the shale shakers and these are generally one or two levels below the drill floor.

The shale shakers are vibrating screens that separate the drilling fluid from the drilled rock cuttings. The “shaker house” is a very noisy place and double hearing protection must always be worn. There will be multiple shakers to accommodate the large volume of cuttings that can be produced when the drilling rate of penetration is high (i.e. they are drilling fast!). It’s a very “dirty” job and multiple layers of personal protective equipment need to be worn to prevent skin contact with the drilling mud, which can cause serious skin inflammation.

 

Mudloggers and Data Engineers (DE)

Mudloggers and data engineers are responsible for gathering, processing and monitoring information pertaining to drilling operations. They don’t only collect data using specialist data acquisition techniques – they also collect oil samples and detect gases using state-of-the-art equipment.

The information amassed by these guys is analyzed, logged and then communicated to the team that is responsible for the physical drilling of the well. Without the help of the mudlogger, the drilling operations would be less efficient, less cost-effective and much more dangerous. The mudlogger is vital for preventing hazardous situations, such as well blowouts.

They also provide vital assistance to wellsite geologists and write detailed reports based on the data that is collected. Being an entry-level position, employees will be given a mixture of ‘on-the-job’ training and expert in-house training courses, which cover different aspects of drilling operations. A major part of the training will focus on the use of specialist computer software.

Typically, you will need a degree in geology to start a career as a mudlogger. However, candidates with degrees in physics, geochemistry, chemistry, environmental geoscience, maths or engineering may also be accepted.

Along with the sample catchers and data engineers, the mudloggers work out of the mudlogging unit, which is a pressurized sea container-type of office, which is positioned close to the drill floor and shaker house.

The unit will have an air-lock compartment when you first enter it so as to maintain the positive pressure within the unit whenever somebody leaves or enters the unit.

This is the main control room for monitoring the drilling operations and is full of sophisticated and delicate equipment and computer systems. Positive pressure needs to be maintained to ensure the air pressure inside the container is higher than that of the outside area to prevent contamination of sensitive monitoring equipment – and also to ensure the safety of the crew working inside the unit should the outside air become contaminated through uncontrolled releases of hydrocarbons from the well.

 

mudloggingunit-amanda
A mudlogging unit

 

One of the most important tasks of the mudlogger is to oversee the collection of not only geological samples but also mud and gas samples from the well during drilling operations. To be able to do this accurately they have to know the exact “lag time” (or “bottoms-up time”) that it will take for the drilled cuttings or mud and gas to arrive at the surface after being drilled and circulated up the outside of the drill hole (annulus) while suspended in the drilling mud. The lag time maybe a few minutes in a shallow hole or as much as several hours in deep wells with low mud flow rates. To be able to work this time out accurately there are many factors that have to be taken into consideration. The lag time depends on:

  • the annular volume fluid
  • flow rate, which in turn requires knowledge of:
  • dimensions (internal diameter (ID) and outside diameter (OD)) of surface equipment, drill string tubular, casing and riser.
  • mud pump output per stroke, pumping rate, and efficiency.

While the computer’s software will work this out automatically, the calculated value may be incorrect if the operator has entered erroneous or incomplete values for the pipe or hole dimensions, or if the hole is badly washed out. This has to be monitored very carefully to avoid catching mud, gas and cuttings samples at incorrect depths.

Sensors

The mudloggers and DE’s monitor the drilling operations via a series of sensors that are placed at various locations around the drill floor, pit room, and shaker house.

The main drilling and mud parameters that are recorded are: hook movement, weight on hook, standpipe pressure, wellhead pressure, rotary torque, pump strokes, RPM, mud pit levels, mud density, mud temperature, mud resistivity, and mudflow.

These parameters are monitored in real-time and any deviances from the expected normal values must be immediately reported to the driller. The DE will view and monitor all the drilling parameters on a screen as shown below.

drilling parameters-amanda
A drilling parameter screen

 

The five most important monitoring tasks that the mudlogger and DE must watch out for are:

  • Rate of penetration increase, which could indicate they have drilled into a reservoir formation
  • Mud pit volume gain or loss, which could indicate the well is taking a kick, or losing fluid into the formation
  • Mudflow rate change
  • Mud density variation
  • Indication of oil or gas.

The mudlogging unit is a very confined workplace and there may be up to several people working in there at any one time, especially if it’s a “combo” unit, which houses the mudloggers, MWD engineers and possibly also the directional drillers.

Generally (but not always), the same service provider company performs all of these roles so it is quite common for data engineers to progress into a role as an LWD/MWD engineer. Other common career progressions for mudloggers/data engineers are as a wellsite geologist or drilling fluids engineer (mud engineer).

inside a mudlogging unit - amanda
Inside a mudlogging unit

The complete list of responsibilities of the mudloggers is too exhaustive to detail in this article but the above-mentioned roles are the main ones. Like most jobs on the rig, daily reports are a big part of the data engineer’s responsibilities.

The mudloggers report directly to the wellsite geologist, who are generally working in the mudlogging unit alongside them. Because the mudloggers are required to monitor the drilling operations from the commencement of drilling they will always be employed on a permanent rotating roster, which is generally 4-weeks on, 4-weeks off.

This article was written by Amanda Barlow, a wellsite geologist and published author of “Offshore Oil and Gas PEOPLE – Overview of Offshore Drilling Operations” for a beginner guide to working in offshore drilling operations, and “An Inconvenient Life – My Unconventional Career as a Wellsite Geologist”

Another great book you may want to read if you like to get an overview of oil exploration, drilling and production is “The Story of Oil and Gas”: How Oil and Gas Are Explored, Drilled and Produced”.

 

 

Blogs

The Job of a Wellsite Geologist

The wellsite geologist (WSG) is the source of operational geological information on the rig and is responsible for all geology-related administrative wellsite activity. They are the operating company’s eyes and ears on the rig and as such, have to make sure that all possible geological and drilling information is gathered in a concise and timely manner.

While the wellsite geologist works in close cooperation with the company man on the rig he is not actually under his authority. Instead, the WSG reports directly to the “Operations Geologist” who is the “shore-based” intermediary between the geologist on the rig and the geology team in town who will be analyzing all the data. The unusual chain of command for disseminating key official geological data from the wellsite geologist follows this line of reporting:

WSG (rig) => Operations Geologist (town) => Drilling Superintendent (town) => Company Man (rig)

While the wellsite geologist is required to immediately notify the company man of any pertinent drilling and geological information, the company man generally cannot act on the information until the town-based drilling superintendent has officially confirmed it.

The wellsite geologist will report all key geological and drilling data to the operations geologist immediately as it comes to hand. It is then the responsibility of the “ops geo” to disseminate this information to all members of the onshore geology and drilling teams who need to know the information for decision-making.

All key drilling decisions are made in collaboration with every department involved in the drilling of the well to ensure that well control barrier criteria are met and any decisions made will not compromise the integrity of the well or process safety systems.

At the commencement of drilling, when the well will be drilled “riserless” with no cuttings coming to surface, there will often only be one wellsite geologist on the rig. There may be two or even three casing strings run before the riser is finally run and drilled cuttings are brought to the surface.

The wellsite geologist will be needed during these stages of drilling to confirm that suitable geological formations have been intersected in order to successfully set casing. This task is commonly referred to as “calling casing point”. It is critical that the casing shoe for the conductor and surface casing is set deep enough to withstand pressure from a “kicking” formation further down.

Surface casing is run to prevent caving of weak formations that are encountered at shallow depths. The wellsite geologist needs to identify when a competent formation is intersected to ensure that the formation at the casing shoe will not fracture at high hydrostatic pressure, which may be encountered later in the drilling of the well.

Because there are no drilled cuttings coming to surface all geological data is interpreted from one, or a combination of both, of the following sources:

  • Drilling parameters such as ROP (rate of penetration) and torque when there are no LWD (Logging While Drilling) tools in the BHA (Bottom Hole Assembly).
  • Real-time Gamma Ray and/or Resistivity data from downhole LWD tools.

Once the surface casing has been set and the BOP (blow out preventer) and riser are run to the seabed, all drilled cuttings will then be circulated to the surface, which means the days get a whole lot busier for the wellsite geologist. From this stage on there will generally be two wellsite geologists operating back-to-back 12-hour shifts.

Responsibilities

As the acting representative for the operating company’s geology team, the wellsite geologist will have the following responsibilities:

  • Evaluating offset data before the start of drilling
  • Analyzing, evaluating and describing formations while drilling, using cuttings, gas, formation evaluation measurement while drilling (FEMWD) and wireline data
  • Comparing data gathered during drilling with predictions made at the exploration stage;
  • Advising on drilling hazards and drilling bit optimization
  • Making decisions about suspending or continuing drilling. Ultimately, it’s the wellsite geologist’s responsibility to decide when drilling should be suspended or stopped.
  • Advising operations personnel both on the rig and in the onshore operations office about any pertinent geological or drilling information as it arises.
  • Supervising mudlogging, MWD (Measurement while drilling)/LWD (logging while drilling) and wireline services personnel and monitoring quality control in relation to these services.
  • Keeping detailed records, writing reports, completing daily, weekly and post-well reporting logs and sending these to appropriate departments.
  • Maintaining up-to-date knowledge of LWD and MWD tools and status of all equipment onboard and in transit to make sure the equipment is available and in working order when it is needed.

In expected HPHT (high-pressure high temperature) wells it is critical the wellsite geologist can identify (and immediately communicate) any identifying signs of increases in pore pressure. These can include the following telltale signs:

  • Changes in flow rate and active mud system volumes. If the formation pressure becomes higher than the hydrostatic pressure being exerted by the circulating drilling fluid then the mud will become “underbalanced” and the well will “kick”. If this kick isn’t detected early enough then a catastrophic blowout could occur.
  • Presence of “cavings” coming over the shakers. When drilling over-pressured shales, it is common for the formation to undergo stress relief causing chips of rocks to cave from the borehole wall. These overpressure “cavings” tend to be larger than normal cuttings and maybe concave or propeller-shaped.
  • Increase in ROP (rate of penetration) and volume of cuttings. A pressure transition zone will make drilling easier because of the trapped water-reducing compaction and the increase in pore pressure reducing differential pressure, allowing cuttings to be released more easily into the mud stream.
  • Changes in LWD data, in particular, resistivity and sonic, density and neutron.
  • Changes in drilling parameters, especially torque, drag, and overpull. This can be due to deterioration of borehole integrity causing an increase in the volume of cuttings and cavings in the circulating mud.
  • The rise in background gas level, changes in the composition of the gas, or presence of “connection” gas, which is a result of swabbing downhole hole when the pumps are turned off to make a connection (add another stand of drill pipe).
  • Changes in pump pressure. An influx of gas into a well may reduce the density of the drilling fluid and therefore it will require less pressure to circulate the drilling fluid.
  • Change in properties of mud.
  • Changes in downhole temperature. Generally, there will be a slight decrease in temperature immediately above the over-pressured zone and then a steady increase with depth at a higher rate than in the normally pressured zone above.

If the wellsite geologist identifies any potentially hazardous changes in the drilling, the driller and company man must be notified immediately, and then the operations geologist will be notified.

If a potentially dangerous situation is recognized then the drilling will be stopped immediately while the company man either makes a decision on what to do next or waits for official instructions from the drilling superintendent in town on how to proceed.

The wellsite geologists spend most of their time working in the mudlogging unit (like the hardworking one in the photo above J), which is where all the monitoring equipment for the rig is located and also where the mudloggers/sample catchers will deliver the cuttings samples for them to inspect and describe.

All rock cuttings are inspected under a microscope and a detailed description is written for every sample that is generally collected in composite 5, 10 or 20 m intervals.

Cuttings Descriptions

cuttings-Amanda

The cuttings descriptions need to be very detailed and follow an industry-standard format that includes (but is not restricted to) the following observations:

  • Rock types and percentage of each found in the sample
  • Color
  • Texture
  • Grain or crystal size
  • Sphericity, roundness, and sorting of sandstone grains
  • Type of cement and/or matrix
  • Any fossils or accessory minerals
  • Presence of hydrocarbon indications, such as fluorescence or “show”
  • Estimate of porosity

A detailed well log is created combining all the cuttings information, LWD, and MWD data and drilling parameter data, and submitted along with a daily report every 24 hours. When the wellsite geologist finishes the shift and hands over to the next shift they have to have all of the reporting and samples descriptions up-to-date at the time of them handing over.

To become a wellsite geologist, you’ll need a degree in geology or possibly even chemistry, geochemistry or geophysics. There is no formal wellsite geologist qualification, but you would need to obtain knowledge in areas such as wellsite and offshore safety management, wellsite operations, formation evaluation of wireline, FEWD logs, and risk assessment before starting as a wellsite geologist.

Most wellsite geologists start their offshore career working as a mudlogger, MWD engineer or mud engineer and gain knowledge in the fields that a WSG is responsible for. They also need to possess supervisory skills, the ability to work well under pressure and the ability to quickly make decisions.

As most wellsite geologists work as independent consultants and are employed on a contracting basis, it’s up to them to handle their own career progression. Any wellsite geologists who progress beyond this position will generally move into an operations geologist role, with a few even moving up into company man positions.

While a wellsite geologist might earn a lot per day there is little job security, and quite often no permanent rotation. They may only get flown onto the rig the day before drilling operations begin and flown off again immediately after the well is completed or wireline logging is completed. The date of your arrival and departure is quite often only known within days of it occurring so long-term social commitments are impossible to plan. You can either expect to have to fly out to the rig at very short notice or have unplanned months without any work…or even years when the industry is going through a downturn.

Like with many oil and gas roles, being a wellsite geologist can be a very demanding job but the rewards can certainly outweigh the risks if a sensible approach is taken to managing your time and finances. If unpredictability is not your thing then wellsite geology is not for you! Being away from home for several months of the year is part and parcel of the job so people with young families may find this job too demanding on their family life. This will always be the first and foremost decision you will have to make if considering to become a wellsite geologist.

This article is written by Amanda Barlow. Amanda Barlow is a wellsite geologist and published author of “Offshore Oil and Gas PEOPLE – Overview of Offshore Drilling Operations” and “An Inconvenient Life – My Unconventional Career as a Wellsite Geologist”.

Amanda Barlow
Ms. Amanda Barlow

Another great book you may want to read if you like to get an overview of oil exploration, drilling and production is “The Story of Oil and Gas”: How Oil and Gas Are Explored, Drilled and Produced”.

 

Blogs, Course Instructors, Dr. Roland N. Horne, Oil and gas courses, Reservoir Engineering

About Dr. Roland N. Horne

 

Roland Horne 2018_03-1
Dr. Roland N. Horne

Dr. Roland N. Horne is the Thomas Davies Barrow Professor of Earth Sciences at Stanford University, and Senior Fellow in the Precourt Institute for Energy. He was also formerly Chairman of the Petroleum Engineering Department from 1995 to 2006.

He holds BE, Ph.D. and DSc degrees from the University of Auckland, New Zealand, all in Engineering Science.

Roland Horne is well recognized as an expert in geothermal resources. He received Geothermal Special Achievement Award from Geothermal Resources Council in 2015. He is the Technical Programme Chair of World Geothermal Congress 2020 in Reykjavik and a member of the Geothermal Resources Council (GRC) Board of Directors.

Dr. Horne is also well known for his work in well test interpretation, production optimization, and analysis of fractured reservoirs.

He is an internationally-recognized expert in the area of well test analysis and has twice been an SPE Distinguished Lecturer on well-testing subjects.

Under him, more than 50 people have obtained Ph.D. degrees at Stanford University.  Currently, Stanford University is recognized as one of the top schools in the world for the study of well test interpretation.

Prof. Roland Horne has written more than 90 technical papers, is the author of the book Modern Well Test Analysis and co-author of the book Discrete Fracture Network Modeling of Hydraulic Stimulation. He is an SPE Honorary Member, and a member of the National Academy of Engineering in the USA.

Prof. Horne will conduct a 4-day webinar – Geothermal Reservoir Engineering– in October 6-9, 2020. If you want more information about this course, please contact LDI Training at lditrain@singnet.com.sg.

He also conducts a 5-day Modern Well Test Analysis course. This highly regarded course has been attended by thousands of oil and gas, as well as geothermal professionals in many countries for more than 20 years. If you want more information about the course, please contact LDI Training at lditrain@singnet.com.sg.

Blogs

The Top Ten Oil Refineries in Southeast Asia

1.    Exxon Singapore Refinery – 592,000 BPD – Singapore

With a design capacity of about 592,000 barrels a day, the Exxon Singapore Refinery in Singapore is the largest refinery in South East Asia. It is also ExxonMobil’s largest in the world.

Located in Jurong Island of Singapore, the refinery became the largest as it is made up of the former Mobil and Esso refineries which operate as one facility, following the merger of Exxon and Mobil in 1999.

ExxonMobil recently completed the refinery expansion to upgrade of the production of its proprietary EHC Group II base stocks.

It also has an ongoing multibillion-dollar expansion to enable the refinery to convert fuel oil and other bottom-of-the-barrel crude products into higher-value lube base stocks and distillates.

2.    Shell Pulau Bukom Refinery – 458,000 BPD – Singapore

Royal Dutch Shell’s refinery at Pulau Bukom in Singapore has the capacity to process 458,000 barrels of crude oil per day.

It recently completed the expansion to increase the storage capacity by nearly 1.3 million barrels by building two large crude oil tanks.

The refinery is the company’s largest wholly-owned Shell refinery globally in terms of crude distillation capacity.

3.    Pertamina Cilacap Refinery – 348,000 BPD – Indonesia

With a total combined capacity to process 348,000 barrels of oil per day, the Pertamina Cilacap refinery consisting of Oil Refinery I and Oil Refinery II is Indonesia’s largest refinery. It is located in Cilacap in Central Jawa of Indonesia.

Oil Refinery I was constructed in 1974 with a design capacity of 100,000 barrels of oil per day. In 1998, to meet the growing demand for fuels and lube oil, the refinery underwent a Debottlenecking Project which increased its crude oil processing capacity to 218,000 BOP. The refinery was designed to process crude oil from the Middle East.

Oil Refinery II was built in 1981 with a design capacity of 220,000 BOPD. It is capable to process the crude oil from Indonesia and The Middle East.

4.    Singapore Refining Corporation Jurong Island Refinery – 285,000 BPD – Singapore

Located in Jurong Island of Singapore, the Singapore Refining Corporation Refinery was originally constructed in 1979 to process 70,000 BOPD. It was later expanded to increase its capacity to 285,000 BPD.

Singapore Refining Corporation is currently owned by Chevron and PetroChina. PetroChina became a co-owner of the refinery following its purchase of Keppel Corporation’s stake in the refinery in 2009.

5.    PTT Rayong Refinery – 280,000 BPD – Thailand

PTT Rayong Refinery started in 1996, is owned by PTT Aromatics and Refining Public Company. Currently, the refinery has a design capacity of 280,000 BPD following the completion of an expansion of its condensate splitting capacity and connected units in 2009.

The refinery is located in Sriracha, Thailand. PTT Group became the sole owner of the refinery when Shell International sold its 64 percent stake in the refinery to state giant PTT Plc.

6.    Thai Oil Refinery – 275,000 BPD – Thailand

The Thai Oil Refinery is a large high complexity refinery capable of processing 275,000 barrels per day. Located at Sriracha, Thailand, the refinery was originally commissioned in 1961 with a capacity of 35,000 BPD. It underwent several expansions subsequently to increase its processing capacity to its current level.

Currently, the refinery is being further expanded and upgraded. The expansion project will increase daily crude throughput from 275,000 barrels to 400,000 barrels.

7.    Pertamina Balikpapan Refinery – 260,000 BPD – Indonesia

The Pertamina Balikpapan Refinery has a very interesting and long history. It was built by Shell Transport and Trading Ltd in 1922, during the Dutch colonial times, following the discovery of oil in Balikpapan in East Kalimantan in 1897. The discovery was named Mathilda as it was drilled by Mathilda Corporation.

Pertamina acquired the refinery from Shell in 1966 and subsequently expanded the capacity of the refinery to its current level.

The refinery is currently being expanded further to increase its capacity from 260,000 to 360,000 BPD.

8.    IRPC Rayong Refinery – 215,000 BPD – Thailand

Located at Rayong, Thailand, the IRPC Rayong Refinery has a capacity to process 215,000 barrels of oil per day. It is a large refinery and integrated petrochemical complex and is designed to handle condensate and crude oil.

9.    Petron Bataan Refinery – 180,000 BPD – The Philippines

Located at Bataan in the Philippines, Petron Bataan Refinery has a designed capacity of 180,000 barrels per day. The refinery started in 1961 and is owned by Petron Corporation.

10.  Petronas/Phillips66 Melaka II Refinery – 170,000 BPD – Malaysia

Located in Melaka, Malaysia, the Petronas/Phillips66 Melaka II Refinery has an installed capacity of 170,000 barrels of oil per day.

The refinery was commissioned in 1999 with an initial capacity of 100,000 BPD. Its crude oil processing capacity increased to 170,000 BPD after it underwent a debottlenecking project in 2007.

PETRONAS became the sole owner of the refinery in 2014 when it acquired the 47% stake of Phillips 66 in the refinery.

This article was written by Jamin Djuang, a published author of “The Story of Oil and Gas: How Oil and Gas Are Explored, Drilled and Produced” for readers who have not seen an oil field.

Blogs, Pipelines

Pertamina Dumai Refinery reduces its fuel costs by 40%

IMG20180924180432-cropped.jpg
The PLN power plant at Muara Karang, Jakarta.

Pertamina has completed the construction of the 67 km gas pipeline supplying gas to its Unit II Refinery in Dumai. With the commissioning of the 24-inch pipeline on 14 April 2019, the fuel needed to operate the refinery is now supplied by the gas produced from the nearby gas fields.

The gas comes from the following three blocks:

  1. The prolific Grissik field located in the Corridor Block which is operated by ConocoPhillips. The Grissik field produced more than 900 MMSCF of gas per day in 2018. With an area of 2258 square kilometers, the Corridor Block is one of the largest gas blocks in Indonesia. Other very large gas blocks are the Tangguh and the Mahakam blocks.
  2. The fields located in the Bentu Block which is managed by PT Mega Energi Persada (PT EMP). The Bentu Block is located near the city of Pekanbaru. PT EMP also supplies its gas to Indonesia’s state power company (PLN) and Riau Andalan Pulp and Paper (RAPP).
  3. The oil and gas fields located in the Jambi Merang Block which is now operated by Pertamina Hulu Energi Jambi Merang (PHE Jambi Merang). PHE Jambi Merang acquired the block from the Joint Operating Body Pertamina-Talisman Jambi Merang on 9 February 2019.

In the past, the refinery used the fuel oil, Naptha and fuel gas it produced internally to meet the fuel needs of the refinery.

The project has brought significant economic benefits to both the gas producers and the refinery. In using the gas, the refinery is able to reduce its fuel costs by 40%.

This article was written by Jamin Djuang, a published author of “The Story of Oil and Gas: How Oil and Gas Are Explored, Drilled and Produced” for readers who have not seen an oil field.

Blogs, oilfields in Indonesia

The Top 10 Crude Oil Producing Companies in Indonesia in 2018

westseno
The photo showed the drilling activity at the West Seno field, the first deepwater field in Indonesia. The photo was taken by Dr. Tony Tirta.

The average crude oil production in Indonesia in 2018 is 803,000 barrels per day according to SKK Migas of Indonesia.

Here are the top ten crude oil-producing companies in Indonesia in 2018.

Chevron Pacific Indonesia – 209,000 BOPD

Chevron is the biggest oil producer in Indonesia in 2018 and has been a leading oil producer in Indonesia for more than 90 years. It started operating in Indonesia in 1924 under Standard Oil Company of California (SOCAL).

Chevron operated oilfields in Sumatera and East Kalimantan. It’s East Kalimantan assets came from the acquisition of Unocal in 2005. Chevron handed back all the assets in East Kalimantan to the Indonesia government on October 24, 2018, after 50 years of operation under Unocal and Chevron.

Currently, Chevron’s oil production comes mainly from the oil fields located in Riau, Sumatera under the Rokan Production Sharing Contract. The biggest oil field in the Rokan PSC is the Duri field which has been under steam-flood since 1985 and is one of the largest steam flood projects in the world. Minas is another giant oil field that Chevron discovered and operated in the Rokan Block.

ExxonMobil Cepu Ltd – 208,000 BOPD

ExxonMobil Cepu Ltd is the operator of the Cepu block located in Central Java and East Java. The Cepu Cooperation Contract (KKS) was signed on 17 September 2005 and will continue until 2035. ExxonMobil holds a 45% interest in the Cepu block.

ExxonMobil started exploration in 1999, and the oil from the Banyu Urip field started to flow in December 2008.

Pertamina EP – 79,000 BOPD

Pertamina EP operated 21 oil and gas fields located in various parts of Indonesia. These oilfields are managed under five asset groups based on their geographical locations.

Located in North Sumatera and some parts of South Sumatera, the Asset One oilfields include Rantau Field, Pangkalan Susu Field, Lirik Field, Jambi Field, dan Ramba Field.

Located in South Sumatera, the Asset Two oilfields include Prabumulih Field, Pendopo Field, Limau Field dan Adera Field.

Located in West Jawa, the oilfields included in Asset Three are Subang Field, Jatibarang Field dan Tambun Field.

Located in Central and East Jawa, the Asset Four oilfields include Cepu Field, Poleng Field dan Matindok Field.

Located in the eastern part of Indonesia, the oilfields in Asset Five are Sangatta Field, Bunyu Field, Tanjung Field, Sangasanga Field, Tarakan Field dan Papua Field.

Pertamina Hulu Mahakam – 42,000 BOPD

Pertamina Hulu Mahakam became the operator of the oil and gas fields located in the Mahakam Block on 1 January 2018. The fields were previously discovered and operated by Total along with Inpex as its partner. They acquired the block in 1966.

Several giant oil and gas fields are located in this block such as the Handil field, the Tunu field, and the Peciko field.

Pertamina Hulu Energi OSES (Offshore South East Sumatera) – 30,000 BOPD

Pertamina Hulu Energi OSES became the operator of the oil fields in Block South East Sumatera on September 6, 2018. The fields were previously operated by CNOOC, China National Offshore Oil Company.

Pertamina Hulu Energi ONWJ – 29,000 BOPD

Pertamina Hulu Energi ONWJ (PHE ONWJ) is currently the operator of the  Offshore North West Java (ONWJ) production sharing contract following the change of company ownership from BP to Pertamina in July 2009.

The contract area, located in the Java Sea, covers an area of approximately 8,300 square kilometers – stretching from the North of Cirebon to Kepulauan Seribu.

The giant Ardjuna field is located in this Production Sharing Contract area. It was discovered by ARCO – Atlantic Richfield Company –  in 1969 and operated by ARCO until BP – British Petroleum – acquired ARCO in 2000.

The production facilities consist of 670 wells, 170 shallow water platforms, 40 processing and service facilities and some 1,600 kilometers of sub-sea pipeline.

Medco EP Natuna – 16,000 BOPD

Medco EP Natuna, a subsidiary of Medco Energi, is the operator of the South Natuna Sea Block B. The field was initially operated by ConocoPhillips until Medco Energi acquired it in 2016.

Besides producing oil, Medco EP Natuna also supplies gas to Singapore using a 656 KM long 28” subsea pipeline.

Petronas Carigali (Ketapang) – 15,000 BOPD

Petronas Carigali Ketapang operates the Bukit Tua Field located in the Ketapang Block in East Java. Bukit Tua is an oil field but with a significant amount of associated gas. The offshore field is situated at a water depth of about 57 m.

The production facilities consist of wellhead platforms, an FPSO – Floating Production, Storage and Offloading – and onshore receiving facilities (ORF) in Gresik.

PetroChina International Jabung – 14,000 BOPD

PetroChina International Jabung operates the prolific Jabung Block located in Jambi in Central Sumatera.

The company produces crude oil, condensate, LPG and gas. PetroChina supplies gas to Singapore using a 450 KM long subsea pipeline.

An interesting aspect of the block is that PetroChina discovered the fractured basement rock contains a significant quantity of gas that can flow at significant rates.

Pertamina Hulu Kalimantan Timur – 13,000 BOPD

Pertamina Hulu Kalimantan Timur operates the East Kalimantan-Attaka Work Area. Chevron was the previous operator of the work area until it handed over the operatorship to Pertamina on October 25, 2018.

Attaka, the famous giant oil field is located in this block. The Attaka field was discovered and operated by Unocal until Chevron acquired it in 2005.

The oil fields in this work area are in the late declining phase. Around one billion barrels of oil and 3 TCF of gas have been produced from this work area.

This article was written by Jamin Djuang, a published author of “The Story of Oil and Gas: How Oil and Gas Are Explored, Drilled and Produced” for readers who have not seen an oil field.

Blogs, Reservoir Engineering

Key Concepts and Methodologies for Effective Reservoir Simulation

 

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Here are the key concepts and methodologies which a reservoir engineer should understand to simulate a reservoir effectively, according to Emeritus Professor Val Pinczewski of the University of New South Wales.

  • The internal structure of reservoir simulators – single, two and three phase reservoir simulators, black oil and modified black oil simulators, compositional simulators.
  • Limitations of numerical solution methods – truncation errors, numerical dispersion and stability, grid orientation effects.
  • Rock properties and saturation functions – design of effective SCAL programs and reservoir wettability, two and three-point saturation end-point scaling, rock-typing and hydraulic flow units, Leverett J-Function and Corey based models for relative permeability and capillary pressure, averaging saturation dependent property data, limitation of three-phase relative permeability and capillary pressure models.
  • Upscaling and relative permeability pseudo-functions – dynamic pseudo-functions, vertical equilibrium, and viscous dominated pseudo-functions.
  • Grid selection – advantages and disadvantages of structured, unstructured and hybrid gridding systems, corner-point geometry grids, PEBI grids, locally orthogonal grids, vertical heterogeneity and layering, guidelines for grid design.
  • Model initialization – Capillary-gravity equilibrium, initialization with zero capillary pressure, initialization using an average capillary pressure curve, initialization using the Leverett J-Function and a reference capillary pressure curve, initialization using Eclipse SWATINIT method. Effect of different options for run-time capillary pressure.
  • Aquifer modeling and history matching – unsteady-state water influx, Hurst and van Everdingen model, Carter-Tracy and Fetkovich models, material balance and aquifer history matching, guides for effective aquifer model history matching.
  • Well models and gas condensate reservoir modeling – condensate blockage and the two-phase pseudo-pressure method, implementation of the method in commercial reservoir simulators, gas condensate inflow relationships, PVT and fluid flow relationships for gas-oil relative permeability ratios, gas relative permeability ratio as a function of gas-oil relative permeability ratio, high velocity effects, positive and negative coupling, velocity dependent relative permeability and capillary number, guidelines for running gas condensate reservoir simulations using commercial reservoir simulators.

These are the topics Professor Val Pinczewski will discuss in the 5-day Advanced Reservoir Simulation course to be held on June 24-28, 2019 in Singapore.

Blogs, Oil and gas production

The World Top 10 Oil Producers

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Offshore oil and gas production and processing platforms and facility.

 

In 2018, daily world oil production amounts to around 92 million barrels per day, increasing slightly 0.7% from previous year.

Here are the world top ten oil producers according to the US Energy Information Administration (EIA) in 2017:

  1. USA – 15.6 Million barrels of oil per day
  2. Saudi Arabia – 12.1 Million BOPD
  3. Russia – 11.2 Million BOPD
  4. Canada – 5.0 Million BOPD
  5. China – 4.8 Million BOPD
  6. Iran – 4.7 Million BOPD
  7. Iraq – 4.5 Million BOPD
  8. UAE – 3.7 Million BOPD
  9. Brazil – 3.4 Million BOPD
  10. Kuwait – 2.9 Million BOPD

The USA is the largest oil producer in the world in 2017. The production of crude oil in the USA is expected to increase into 2019. The USA is also the world’s largest consumer of oil. Its daily oil consumption in 2019 is projected to increase by 340,000 barrels to 20.65 million barrels, according to EIA.

EIA reported on 21 December 2018 United States produced a total of 16.3 million barrels per day of crude oil and natural gas liquids in November 2018.  This total production consists of 11.7 million BPD of crude oil and 4.6 BPD of natural gas liquids or NGL.

Saudi Arabia, on the other hand, is the largest oil exporting country. As the most well-known and influential oil producer, it has 260 billion barrels of oil reserves, which is about 22% of the world’s oil reserves.

Blogs, Unconventional oil and gas resources

The Top Three Unconventional Oil and Gas Resources

Unconventional oil and gas resources are resources where the oil and gas are difficult to recover or produce due to either the very low permeability of the formation or the very low mobility of the hydrocarbons. Special techniques and processes are required to recover these types of resources.

The three common types of unconventional hydrocarbon resources are:

  1. Oil sands.
  2. Shale oil and shale gas.
  3. Coal-bed Methane.

Oil Sands

The world’s largest oil sand deposit is the Athabasca oil sands located in Alberta, Canada. Oil sands are a mixture of semi-solid bitumen or asphalt and sand, and they are buried not far from the earth’s surface. Commercial production of the Athabasca oil sands began in 1967 and the current production is at around two million BOPD. Many major oil companies are involved in the production of these oil sands.

Two methods are used to recover the oil from the oil sands. They are open-pit mining and the SAGD method.

The open-pit mining method is commonly used to extract the oil from oil sands located near the earth’s surface. After the tar sand is mined, it is mixed with hot water and agitated to form a slurry. The released bitumen droplets will float to the surface with the help of the tiny air bubbles which attach to the bitumen droplets. The bitumen will then be skimmed off and further processed to remove the remaining water and solids. Lastly, the bitumen will be upgraded to synthetic crude oil. About 75% of the bitumen can be extracted from the tar sands.

For tar sands located at a deeper depth, in-situ production methods are used, such as steam injection, fire flooding, and chemical injection. A popular steam injection method is the SAGD method. In SAGD, steam-assisted gravity drainage, a pair of horizontal wells are drilled into the oil sand, one at the bottom of the formation and another about 5 meters above it. High-pressure steam is injected into the sand from the upper well to heat the heavy oil and thus reduce its viscosity. With the increase in mobility, the oil drains into the lower well where it is pumped to the surface. SAGD is the preferred method for extracting the oil sands due to environmental concerns.

Shale Oil and Shale Gas

Another currently popular unconventional hydrocarbon resource is shale oil and shale gas. Shale oil is oil that is trapped inside the tight shale. Shale is a hard sedimentary rock

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An oil field and sucker Rod pumps

composed of clay that is rich in organic materials. Since tight shale has very low permeability, the hydraulic fracturing method is used to extract the oil. In hydraulic fracturing, a large quantity of viscous fluid-carrying sand is pumped into the well under high pressure to fracture the shale, creating pathways and highways for the oil to flow out of the shale and into the wellbore.

Most shale oil production takes place in the US and the daily production of shale oil reaches six million BOPD in 2017. A large quantity of gas is also produced from shale. According to the US Energy Information Agency (EIA), gas production from shale in the US in 2016 was 15.8 trillion cubic feet (TCF).

The most well-known and top shale oil plays in the US are the Permian Basin and Eagle Ford Shale in Texas, and Bakken Shale in North Dakota.

Coal Bed Methane

Coalbed methane (CBM) is an unconventional resource of methane gas. It is being produced successfully in some parts of the world, notably in Australia and Canada. Since coal is formed from organic materials, methane gas (CH4) is generated during the formation of coal. The generated methane is adsorbed in the coal matrix, fractures and coal seams called cleats. Cleats are horizontal and vertical fractures formed naturally in coal.  

Wells are needed to produce the trapped methane gas. Since underground coal is usually saturated with water, methane is extracted by first removing the water from the coal by pumping out the water. As the water is pumped out from the well, the coal pore pressure will decrease causing the adsorbed gas to be liberated from the coal and then flow to the wellbore. Due to the low permeability of the coal matrix, the coal must have a sufficient network of fractures and cleats to produce the methane gas at economic production rates.

This article was written by Jamin Djuang, a published author of “The Story of Oil and Gas: How Oil and Gas Are Explored, Drilled and Produced” for readers who have not seen an oil field.

 

Blogs

The largest tidal power plant in the world

Indonesia will build the largest tidal power plant in the world in the straits of Larantuka at the Island of Flores. The power plant is designed to provide electricity to more than 100,000 residents in that area.

This Larantuka power plant project aligns with Indonesia’s commitment to increase the share of renewable energy in the total energy supply to 25% by 2025. It also commits to reduce the emission of CO2 by 300 million tonnes by 2030.

The tapping of ocean energy, consisting of wave and tidal energy to produce clean and cheaper power will grow significantly.  According to Market Research Future, the annual growth rate of the global wave and tidal market is expected to be more than 17% till 2023.

Please read this great article on “Larantuka Straits, Indonesia will be home to the largest tidal power plant in the world” written by Novrida Masli.

You can learn how to tap the energy from the ocean in this video.

Blogs

Lava Laze of Kilauea

 

Watch this spectacular USGS video showing lava laze formed by the lava of Kilauea volcano flowing into ocean at Kapoho bay on June 4, 2018.

The lava is from Kilauea Volcano’s lower east Rift Zone entering the ocean. The ocean entry is about a half-mile wide. The flow sends a large laze plume into the air along the coast.

 

What is lava laze?

When the lava flow goes into the ocean water, it boils the water and creates a white acidic plume. That’s laze.

“It’s a complex chemical reaction that occurs between the lava flow and seawater,” said Wendy Stovall, a volcanologist with the U.S. Geological Survey. “It creates a mixture of condensed acidic steam, hydrochloric acid gas and tiny shards of volcanic glass.”

From the air, the plume looks like exhaust from a factory or the white smoke released during a forest fire.

If you’re underneath the plume, a light sprinkle of rain as corrosive as battery acid can fall on you. The acid can burn your skin, irritate your eyes and make it difficult to breathe. In rare cases, the damage can be permanent.

Source: LA Times article by Heidi Chang

Blogs

Geothermal Plants near a Volcano

Geothermal plants can be safely situated near a volcano, says Dr. Roland Horne, Thomas Davies Barrow Professor in the School of Earth Sciences and Senior Fellow at the Precourt Institute for Energy at Standord University.

You can read the outstanding article from Stanford University titled Geothermal at the foot of Kilauea on this and on the recent volcano eruption of Mt. Kilauea in Hawaii at https://earth.stanford.edu/news/geothermal-foot-kilauea?linkId=52195066.

In this article, Dr. Roland Horne discusses geothermal energy in the face of natural hazards and a way to tap the earth’s heat far from volcanoes in the future.

I highly recommend you read the article that I mention above. In this article you can also watch the awesome lava flow from a fissure of Mt. Kilauea on May 19, 2018 and learn about Stanford University’s School of Earth, Energy & Environmental Sciences.

Blogs, New Technology

Digital Rock Physics – Core Analysis Using Digital Technology

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Offshore oil and gas processing platform,

In the last decade, there has been an important breakthrough in how petroleum engineers and geoscientists obtained oil and gas reservoir rock properties.

Traditionally, reservoir rock properties or petrophysical properties such as porosity, pore size distribution, effective and relative permeability, capillary pressure, water saturation and other reservoir parameters are determined from Special Core Analysis (SCAL), electric logs and well pressure transient tests. In recent years, a new method in determining rock properties using Digital Rock Physics (DRP) has gained serious attention from petroleum engineers, petro-physicists and geoscientists.

What is digital rock physics? Digital rock physics is also referred to as digital core analysis. In this measurement method, high-resolution digital images of the rock pores and mineral grains of selected reservoir core samples are made and analyzed. These images are usually 3D digital X-ray micro-tomographic images. The rock properties are then determined using numerical simulation at the pore scale.

The significant benefit of this new DRP technology is now a large number of complex reservoir parameters can be determined faster and more accurately than the traditional laboratory measurements or well testing methods.

Using the DRP technology to determine the rock properties, oil and gas companies can now analyze their reservoir capacity and performance more accurately and sooner during the field evaluation and development phase. This, in turn, allows them to develop and manage their reservoirs more efficiently and economically.

Source – Digital Rock Physics for Fast and Accurate Special Core Analysis in Carbonates – A Chapter in New Technologies in the Oil and Gas Industry – By  Mohammed Zubair Kalam

Blogs, Course Description, Oil and gas facilities

Gas Handling, Conditioning and Processing

This gas handling, conditioning and processing course is designed and presented by Dr Maurice Stewart to teach you how to design, select, specify, install, test and trouble-shoot your gas processing facilities.

This gas handling, conditioning and processing course has been attended by thousands of oil and gas professionals since Dr Maurice Stewart began teaching it more than 20 years ago. Dr Stewart is a co-author of a widely acclaimed “Surface Production Operations: Design of Gas Handling Facilities” along with Ken Arnold.

By attending this course, participants will:

1. Know the important parameters in designing, selecting, installing, operating and trouble-shooting gas handling, conditioning and processing facilities.
2. Understand the uncertainties and assumptions inherent in designing and operating the equipment in these systems and the limitations, advantages and disadvantages associated with their use.
3. Learn how to size, select, specify, operate, maintain, test and trouble-shoot surface equipment used with the handling, conditioning and processing of natural gas and associated liquids such as separators, heat exchangers, absorption and fractionation systems, dehydration systems, refrigeration, low temperature separation units, JT plants and compression systems.
4. Know how to evaluate and choose the correct process for a given situation.

Course Content

In this 5-day course, Dr Maurice Stewart will cover the following topics:
• Fluid properties, basic gas laws and phase behaviour
• Well Configurations, surface safety systems (SSS) and emergency support systems (ESS)
• Gas Processing systems, selection and planning
• Water-hydrocarbon phase behaviour, hydrate formation prevention and inhibition
• Heat transfer theory and process heat duty
• Heat exchangers: configurations, selection and sizing
• Gas-liquid separation and factors affecting separation
• Types of separators and scrubbers, and their construction
• Gas-liquid separators and sizing
• Liquid-liquid separators and sizing
• Three phase separator sizing
• Pressure vessels: the internals, mechanical design and safety factors
• Separator operating problems and practical solutions
• Gas compression theory, compression ratio and number of stages
• Compressor selection: centrifugal compressors vs. reciprocating compressors
• Vapor recovery units, screw compressors and vane compressors
• Compression station design and safety systems
• Performance curves for reciprocating compressors
• Absorption process and absorbers
• Adsorption process and adsorbers
• Glycol gas dehydration unit design and operation
• Glycol unit operating variables and trouble shooting
• Glycol selection and glycol regeneration
• Acid gas sweetening processes and selection
• Fractionation, refrigeration plants, expander plants and J-T plants
• Process control and safety systems

Course Materials

Participants will receive the following course materials:
1. The 3rd Edition of Volume 2 of the widely acclaimed “Surface Production Operations: Design of Gas Handling Facilities” written by Ken Arnold and Dr Maurice Stewart. This textbook continues to be the standard for industry and has been used by thousands since its first printing over fifteen years ago.
2. A comprehensive set of lecture notes for after course reading and reference
3. An extensive set of practical in-class “case study” exercises developed by Dr Stewart that will be used to emphasize the design and “trouble-shooting” pitfalls often encountered in the industry.

Who Should Attend

• Facility engineers, production engineers, design and construction engineers, team leaders, operations engineers, maintenance team leaders/engineers and other personnel who are or will be responsible for the designing, selecting, sizing, specifying, installing, testing, operating and maintaining gas handling facilities, gas plant facilities and gas pipelines.
• Experienced professionals who want to review or broaden their understanding of gas handling, conditioning and processing facilities and gas pipeline operation and maintenance.
• Professionals with little to moderate experience with the handling or processing of natural gas and associated liquids.

If you like to receive a pdf file of this course outline, please contact us.

Registration Information

Course date: November 25-29, 2019
Location: Singapore
Tuition: US$4500

Registration Form

If you or your people want to attend this course, please register HERE.

Contact information
Email: lditrain@singnet.com.sg
Website: https://oilandgascourses.org

Blogs, Course Instructors, Oil and gas facilities

About Dr. Maurice Stewart

Maurice Stewart - LDI Training Dr. Maurice Stewart, PE, CSP, is a Registered Professional Engineer and Certified Safety Professional with over 40 years of experience in international consulting, trouble-shooting oil, water and gas processing facilities; and leading safety audits, hazards reviews and risk assessments.

He is internationally respected for his teaching excellence and series of widely acclaimed textbooks in the areas of designing, selecting, specifying, installing, operating and troubleshooting:

  • Oil and water handling facilities
  • Gas handling, conditioning and processing facilities
  • Facility piping and pipeline systems
  • Gas dehydration and sweetening facilities
  • Pumps, compressors and drivers
  • Instrumentation, process control and safety systems
  • Oil and gas measuring and metering systems

Dr. Stewart is the author of several new textbooks related to oil and gas processing facilities; and he is one of the co-authors of the SPE Petroleum Engineering Handbook.  He has authored and co-authored over 90 technical papers and contributed to numerous conferences as a keynote speaker. Dr. Stewart has taught over 60,000 professionals from more than 100 oil and gas related companies in 90 countries.

Dr. Stewart serves on numerous international committees responsible for developing or revising industry Codes, Standards and Recommended Practices for such organizations as ANSI, API, ASME, ISA, NACE and SPE. He is currently serving on the following American Petroleum Institute (API) committees: API RP 14C, RP 14E, RP 14F, RP 14G, RP 14J, RP 500 and RP 75. He has developed and taught worldwide short courses for API related to Surface Production Operations. In 1985, he received the National Society of Professional Engineers “Engineer-of-the-year” award.

Dr. Maurice Stewart holds a BS in Mechanical Engineering from Louisiana State University and MS degrees in Mechanical, Civil (Structural Option) and Petroleum Engineering from Tulane University and a PhD in Petroleum Engineering from Tulane University.  Dr. Stewart served as a Professor of Petroleum Engineering at Tulane University and Louisiana State University.

Here are the most frequently requested Dr. Maurice Stewart courses:

  • Oil and water handling facilities
  • Gas handling, conditioning and processing
  • Production safety systems
  • The new API RP 14C and API RP 17V
  • Plant piping and pipeline systems
  • Oil and gas project management
  • Pumps, compressors and drivers

Here are his upcoming courses – Featured Oil and Geothermal Courses

If you are interested in having an inhouse course with Dr. Maurice Stewart, please contact LDI Training at LDITrain@singnet.com.sg.

Blogs, Course Description, Oil and gas facilities, Production Safety in Oil and gas

Production Safety Systems

A 5-day course by Dr. Maurice Stewart incorporating the new 2017 8th Edition of API RP 14C, the new API RP 17V 1st Edition, API RP 14J, API RP 500/505, API RP 520/521/2000, IEC 61508-2 and IEC 61508-3.

This intense Production Safety Systems course presents a systematization of proven practices for providing a safety system for onshore and offshore production facilities. Thousands of oil and gas professionals have attended this course since it was offered by Dr. Maurice Stewart more than 20 years ago.

This production safety systems course has been updated to reflect the changes provided in the new API RP 14C and the API RP 17V. In this course, you will learn the latest concepts, methods and practices that will make your facility operationally safe.

What You’ll Learn

• Provisions for designing, installing and testing both safety and non-marine emergency support systems (ESSs) on both onshore and offshore production facilities.
• Concepts of a facility safety system and outline production methods and requirements of the system.
• Guidance on how safety analysis methods can be used to determine safety requirements to protect common process components from the surface wellhead and/or topside boarding valve and for subsea systems including all process components from the wellhead and surface controlled subsurface safety valve (SCSSV) to upstream of the boarding shutdown valve. (Note: The shutdown valve is within the scope of API RP 17V for gas injection, water injection, gas lift systems and chemical injections.)
• The importance of “Safety Concept,” “Safety Reviews,” and “EB-HAZOPs.”
• A method to document and verify process safety system functions, i.e., safety analysis function evaluation (SAFE chart).
• Design guidance for ancillary systems such as pneumatic supply systems and liquid containment systems.
• A uniform method of identifying and symbolizing safety devices.
• Procedures for testing common safety devices with recommendations for test data and acceptable test tolerances.
• The Principles of Safe Facility Design and Operation, specifically, how to Contain Hydrocarbons, Prevent Ignition, Prevent Fire Escalation and Provide Personnel Protection and Escape.
• The Principles of Plant Layout Partitioning and how to partition a plant into Fire Zones, Restricted Areas and Impacted Areas thereby minimizing the Risk to Radiation, Explosion, Noise and Toxicity.
• How to determine Electrical Hazardous (Classified) Locations and determine what Electrical Equipment should be installed in these locations,
• The purpose of Surface Safety Systems, specifically, the Emergency Shut-down System, Emergency Depressurization System, Fire and Gas Detection Systems and High Integrity Protection Systems,
• The Objectives, Types, Location and Placement of Fire and Gas Detection Systems.
• The Objectives, Types and Performance of Active and Passive Fire Protection Systems.
• The Function, Types, Selection and layout of Vent, Flare and Relief Systems to minimize the effects of Radiation, Flammable Gas Dispersion and Toxic Gas Dispersion.
• The function and design considerations of Liquid Drainage Systems
• How to determine piping “spec breaks”.
• How to evaluate workplace and operating/maintenance procedures for “hidden” hazards.
• How to effectively design facilities and work areas to reduce human errors and improve performance.

Course Content

• Principles of safe facility design
• Ignition prevention
• Fire escalation prevention
• Personnel protection and escape
• Installation layout
• Electrical installations in hazardous (classified) areas
• Safety systems
• Pressure ratings and Specification breaks
• High Integrity Pressure Protection Systems (HIPPS)
• Safety system and ESS bypassing
• Onshore gathering station safety systems
• Fire and gas detection systems
• Active and passive fire protection
• Relief, vent and flare systems
• Liquid drainage systems
• Electrical Area Classification

Who Should Attend

This workshop is specifically targeted for professionals and engineers who are involved in safety or production operations and who want to:

1. Develop a better understanding of the effectiveness of existing Production Safety System initiatives at existing oil and gas facilities.
2. Appreciate the main steps contemplated in the Safe Design of a plant or facility,
3. Better understand the scope and functioning of the various safety related equipment installed onshore, offshore and subsea.
4. Review or broaden their understanding of how to conduct a safety analysis, Experience-Based HAZOP and how to install electrical equipment in hazardous (Classified) locations.
5. Other professionals who want to develop a better understanding of how to conduct a Safety Analysis, EB-HAZOPs and install electrical equipment in hazardous (Classified) locations.

Course Materials

• Each participant will receive a comprehensive set of worksheets and checklists to aid them in conducting a safety analysis
• Each participant will receive a comprehensive set of lecture notes for after course reading and reference
• An extensive set of practical in-class “case study” exercises specially designed by Dr. Maurice Stewart that emphasizes the design and “trouble-shooting” pitfalls often encountered in the industry.

If you like to receive a pdf file of this course outline, please contact us.

Registration Information

Course date : December 10-14, 2018
Location : Singapore
Tuition : US$4500

Registration Form

If you or your people want to attend this course, please register HERE.

Contact information

LDI Training Pte Ltd
369 Holland Road #02-04
Singapore 278640

Email : lditrain@singnet.com.sg
Website : https://oilandgascourses.org

Blogs, Oil and gas facilities, Production Safety in Oil and gas

The New API 2017 RP 14C and API RP 17V

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In 2017, API published the new 8th Edition of API RP 14C and created the new 1st Edition of API 17V for subsea applications.

Here are the major modifications of API RP 14C and the new guidelines provided in API RP 17V:

1. The API RP 14C, new 8th Edition “Analysis, Design, Installation, and Testing of Safety Systems for Offshore Production Facilities” was developed in coordination with the new First Edition of API RP 17V “Recommended Practice for Analysis, Design, Installation, and Testing of Safety Systems for Subsea Applications”.

2. Changes in safety system technology.

3. Additional guidance for facility safety systems as they have become larger, more complex and moved into deeper water.

4. Added requirements include an extensive emphasis on the performing of hazards analysis due to increased flow rates, pressures, temperatures, and water depth.

5. Better alignment with API Standard 521, “Pressure-relieving and Depressuring Systems”.

6. Additional requirements for pumps and compressors greater than 1000 HP and reference to API 670.

7. Additional requirements to protect against backflow and settle-out pressures.

8. New address on low-temperature hazards.

9. Enhancements on open deck Fire and Gas detection placement and sensor type.

10. Extensive emphasis on performing hazards analysis to include the introduction of the Prevention vs. Mitigation concepts.

11. Additional annex to cover topside High-Intensity Pressure Protection Systems (HIPPS).

12. Additional annex to cover Safety System By-passing.

13. Additional annex to cover Logic Solvers.

14. Additional annex to cover Remote Operation.

Since the API RP 14C and API RP 17V are critically important for the safety of your offshore and subsea facilities, please share this information with your company’s managers, supervisors, engineers and safety personnel who need to:

1. Develop a better understanding of the modifications of the 2017 edition of API RP 14C and the newly created API RP 17V

2. Appreciate the main steps contemplated in the Safe Design of onshore, offshore and subsea applications

3. Better understand the scope and functioning of the various safety-related equipment installed onshore, offshore and subsea.

If you want to understand the new API RP 14C and API RP17V to keep your production facilities safe, Dr. Maurice Stewart conducts a 5-day course – Production Safety Systems – that incorporates the new API RP 14C and API RP 17V.

This article is written by Dr. Maurice Stewart.

For more information about the course, please contact LDITrain@singnet.com.sg

Blogs

What Profession Is Best For You or Your Children?

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Robert Kiyosaki said A students become professionals such as engineers, accountants, lawyers, scientists, consultants, doctors, IT specialists etc.

He then said B students work for government and C students become entrepreneurs.

Let’s analyse the characteristics of each of these three categories of profession.

In category A, as a professional, you have very good income and decent job security. This is a low- risk yet high income profession.

In category B, as a government worker, you have adequate income but excellent job security. This is also a low- risk profession providing sufficient income.

In category C, as a business entrepreneur, you can become very rich but you have low job security. This is a high-risk profession. As a business person, you may suffer losses or have negative income. This is a high reward and high-risk profession. The positive correlations of high rewards with high risks is a proven economic theory.

So then, what profession is best for you?

Since I have been a professional and an entrepreneur, I like to share with you my thoughts and suggestions. There is no such a thing as the best profession in the world; but for everyone, there is one profession which is best just for him or her. To determine the best profession for you, you should consider these factors:

  1. What are your dreams?
  2. What are your objectives in life?
  3. What profession will fulfil your dreams and life objectives?
  4. What are you good at?
  5. What do other people say you are good at?
  6. How well do you handle stress?
  7. How important is job stability to you?
  8. How healthy are you?
  9. Are you good at problem solving?
  10. Are you a multi-tasking person?
  11. Are you good in handling rejections?
  12. Are you a generalist or a specialist?
  13. Are you a people person or a task person?
  14. Are you a risk-taker of risk avoider?
  15. Are you good in managing money?
  16. Are you the sole breadwinner, the only person who supports the family financially?
  17. Can you afford to fail or lose money?

After you have considered these factors and you still have not found the answer, you should follow your heart. Your body and soul will tell you what is best for you.

You shouldn’t be afraid to fail if you can afford to fail. You will have challenges and failures in your journey to reach your dream; but with each failure you face, you are closer to where you want to be.

Finally, since nowadays most people will change job 3-5 times in their working life you shouldn’t worry too much which profession you choose. Every profession you are in is a bridge or a stepping stone to a better profession. Very often as you go forward in your career, the path leading to your dream will appear in front of you.

Jamin Djuang

23-10-2017

 

 

 

Blogs

8 Power Phrases To Get The Best Out In People

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How to get the best out in your people? You give them affirmations. To be an effective leader, it is important you give verbal affirmations regularly to people who work around you. An affirmation is any form of feedback communicated primarily through language.  Timely affirmations can provide the emotional support and encouragement that people need to perform at the highest level.

You can win the hearts and minds of your people by giving them your sincere affirmations. It can be based on your hope and expectation. It can also be made based on his or her accomplishments, efforts, performance results or progress. Even when someone fails to achieve the desired result, positive affirmations can be given based on the special efforts he or she has put into the task or project.

Here are the power phrases you can use to affirm the people around you:

“Thank you!”

“I believe in you.”

“I know you can do it.”

“I know we can depend on you.”

“I can see you always give your best.”

“I am pleased to see the progress you are making.”

“I thank you for your contributions in making this project a success!”

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Gas Handling, Conditioning and Processing – A Course by Dr. Maurice Stewart

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If you want to learn:

  • The processes of gas-liquid separation, gas dehydration, glycol regeneration, acid gas sweetening, gas compression and expansion, and other gas conditioning methods
  • How to select and operate gas processing equipment such as separators, heat exchangers, absorption and fractionation systems, gas dehydration systems, refrigeration, low temperature separation units, JT plants and compression systems
  • Different type of gas liquid separators and scrubbers
  • Hydrate formation and how to prevent it

Here is the course information:

Title: Gas Handling, Conditioning and Processing

Instructor: Dr. Maurice Stewart PE, CSP

                       Author of Surface Production Operations: Design of Gas

                       Handling Facilities      

 Date: November 19-23, 2018

Location: Singapore

For enrollment and more information please contact LDI Training.

Email: LDITrain@singnet.com.sg

Website: https://oilandgascourses.org