Here is the monthly summary of oil and gas exploration and production activities in Indonesia in May 2022, according to SKK Migas.
· Daily crude oil production: 616,800 BOPD · Daily gas production: 5321 MMSCFD · Daily oil and gas production: 1,567,000 BOEPD · Exploration wells drilled YTD: 11 · Development wells drilled YTD: 291 · 2-D seismic survey completed YTD: 559 KM · 3-D seismic survey completed YTD: 269 KM2 · Amount of investment YTD: USD 3.9 billion · Number of Work Areas: 170
Here are other recent happenings in the oil patch of Indonesia.
· Pertamina recorded $2.046 billion corporate profit in 2021. This almost doubles the profit it made in 2020. · Pertamina EP has completed the construction of the Beringin A gathering station in Muara Enim in South Sumatera. The gathering station is designed to increase the capacity of the Prabumulih field to handle an additional 15 million MMSCFD of gas and 382 BPD of condensate. · Pertamina Hulu Energy has made hydrocarbon discovery from its exploration well GQX-1 in the Offshore North West Java (ONWJ) work area. · Gas production from the newly completed JML1 platform in the Jumelai field operated by Pertamina Hulu Mahakam had come on stream. The gas is piped to the production facility of the Senipah-Peciko-South Mahakam field. The Jumelai project is expected to produce 45 MMSCFD of gas and 710 BPD of condensate. · PT BSP (Bumi Siak Pusako) has started drilling its exploration well Nuri-1X in the CPP (Corridor Plain and Pekanbaru) Block in Riau. The company plans to drill 15 development wells and two exploration wells in 2022. · Pertamina Hulu Energy has started drilling the exploration well NSO-R2 in the North Sumatera Offshore work area. · Gas production from the new platform WPS-3 of Pertamina Hulu Mahakam came on stream on 10 June 2022. The installation of the WPS-3 platform and the subsequent drilling of the development wells are part of the JSN (Jumelai, North Sisi, and North Nubi) project. This platform is designed to handle 45 MMSCFD of gas.
This article is curated by Jamin Djuang, Chief Learning Officer of LDI Training.
Do you want to be a “high potential individual”? The secret lies in having a good education.
Education is a great social equalizer. A good education can level the playing field for everyone, especially disadvantaged people. Education can open more and better opportunities for them in the future and provide the chance for them to work and live in the places of their dream.
Indeed, the UK government has just announced it is inviting “high potential individuals” to apply to work and live in the UK.
You are considered a “high potential individual” by the UK Government if you are a recent graduate from the world’s top 37 universities outside of the UK. These are universities outside the UK that appeared at least twice in the Top 50 rankings in 2021.
So, you are a “high potential individual” if you are a recent graduate from the following 37 universities located outside the UK:
California Institute of Technology (Caltech) — U.S.
Chinese University of Hong Kong (CUHK) — Hong Kong
Columbia University — U.S.
Cornell University — U.S.
Duke University — U.S.
Ecole Polytechnique Fédérale de Lausanne (EPFL Switzerland) — Switzerland
ETH Zurich (Swiss Federal Institute of Technology) — Switzerland
Harvard University — U.S.
Johns Hopkins University — U.S.
Karolinska Institute — Sweden
Kyoto University — Japan
Massachusetts Institute of Technology (MIT) — U.S.
McGill University — Canada
Nanyang Technological University (NTU) — Singapore
National University of Singapore — Singapore
New York University (NYU) — U.S.
Northwestern University — USA
Paris Sciences et Lettres – PSL Research University — France
Peking University — China
Princeton University — U.S.
Stanford University — U.S.
Tsinghua University — China
University of British Columbia — Canada
University of California, Berkeley — U.S.
The University of California, Los Angeles (UCLA) — U.S.
University of California, San Diego — U.S.
University of Chicago US — U.S.
University of Hong Kong — Hong Kong
University of Melbourne — Australia
University of Michigan-Ann Arbor — U.S.
University of Munich (LMU Munich) — Germany
University of Pennsylvania — U.S.
The University of Texas at Austin — U.S.
University of Tokyo — Japan
University of Toronto — Canada
University of Washington — U.S.
Yale University — U.S.
Now we know why everyone wants to go to the best universities in the world.
In 2022, the Bekapai oil field, located offshore of the Mahakam Delta in East Kalimantan in Indonesia, celebrates its 50th anniversary.
The Bekapai field was discovered in April 1972 by Total along with its partner, Japex.
The field was almost undiscovered had Total’s exploration team given up its exploration drilling campaign after drilling six dry wells.
With the discovery of the Bekapai field, Total Indonesie went on to discover many big oil and gas fields in the Mahakam block – Tunu, Sisi-Nubi, Tambora, Handil, and Peciko.
Although the Bekapai is not as big as the other fields in the Mahakam block, the Bekapai field is the most well-known field in the Mahakam block being the first oil field that was discovered by Total Indonesie in East Kalimantan. A nice park in Balikpapan is named after Bekapai – Bekapai Park.
FIELD DEVELOPMENT AND PRODUCTION
The reservoirs of the Bekapai field are described as complex multi-layered reservoirs.
Total Indonesie constructed ten platforms and drilled 74 development wells between 1974 and 1996.
The Bekapai field began as an oil field. Oil production started in 1974 with peak production at around 60,000 BOPD in 1978. Then its oil production declined slowly until it reached around 1,000 BOPD in 2007.
As its oil production reached its lowest level, to rejuvenate its oil and gas production the field underwent several redevelopment and transformation projects.
FIELD EXPANSION AND TRANSFORMATION
Phase 1 Expansion
Total Indonesie initiated the Phase 1 field expansion project in 2008. The company drilled 9 development wells and production increased to 10,000 BOPD and 46 MMSCFD of gas by 2013.
With the success achieved in Phase 1 Expansion, the company conducted a 3D seismic survey to assess the potential of the Bekapai field for further development.
Phase 2A Expansion
Based on the encouraging seismic results, the company embarked on the Phase 2A expansion project to further develop the Bekapai Field.
The company drilled two development wells in 2014 and its oil production increased to 11,500 BOPD. This is a record oil production rate of the Bekapai field in its first 25 years of production.
Phase 2B Expansion
As the oil reserves of the Bekapai are depleted, Total’s engineers turn their attention to producing its gas.
The objective of Phase 2B Expansion is to produce the so-far untapped gas accumulation in the Bekapai reservoirs. The plan is to increase the capacity of the field to produce 100 MMSCFD of gas.
Here were what was involved in the Phase 2B Expansion Project.
Produced the gas remaining in the gas caps.
Increased the capacity of the offshore production facilities to produce 100 MMSCFD of gas.
Constructing a 12,6 km long submarine 12-inch pipeline from the Bekapai field to the Peciko field.
Phase 2B Expansion transformed the Bekapai field from an oil field to a gas field. The project increased the gas production of the Bekapai field from around 40 MMSCFD to 92 MMSCFD in 2015, making it a significant gas contributor to LNG production.
Phase 3 Expansion
Pertamina Hulu Mahakam as the new operator continues to further tap the gas potentials of the Bekapai field under the Phase 3 Expansion.
This ongoing expansion project involves modifying the manifold wellhead platforms BH and BE to accommodate 5 new development wells.
This project is expected to produce an additional 27 MMSCFD of gas when it is completed in November 2022.
On January 2, 2018, Pertamina Hulu Mahakam became the operator of the Bekapai field and all the fields in the Mahakam block.
Pertamina Hulu Mahakam maintains the spirit of innovation and continues to develop the remaining potential of the 50-year-old oil field.
Pertamina Hulu Mahakam managed to reach ten years without LTI (Lost Time Injury) on August 27, 2021.
And finally, with the saying “An old oil field never dies”, may the Bekapai field continues to find a new life.
The first oil exploration in Indonesia started not long after Colonel Drake successfully drilled the first oil discovery well in Pennsylvania in the United States in 1859.
By 1869, Dutch businessmen in Indonesia, known as the Netherlands East Indies at that time, had noticed and recorded 53 oil seepage locations in Sumatera, Java, and Kalimantan.
Then the first oil well drilling in Indonesia took place in 1871 in West Java.
However, commercial discoveries were made only several years later when a Dutch businessman drilled successful exploration wells in Pangkalan Brandan in North Sumatera in 1885 and Sanga-Sanga in East Kalimantan in 1892.
These two discoveries caught the attention of the world and put Indonesia on the map as one of the countries with interesting oil potentials.
By 1900 there were already 18 oil companies searching for oil in the Netherlands East Indies (NEI). All these companies were either Dutch companies or non-Dutch companies registered in Nederland. The high level of activities resulted in significant oil discoveries in the early 1900s.
Following the oil discoveries, refineries were built in Pangkalan Brandan in North Sumatera in 1892, Sungei Gerong in South Sumatera in 1926, Balikpapan in East Kalimantan in 1922. By 1940, there were already seven refineries in NEI: three in Sumatera, three in Java, and one in Kalimantan.
In 1938, the daily crude oil production was about 140,000 BOPD and in 1953 it was about 190,000 BOPD.
The high level of oil production and refining activities from 1900 to 1940 made Indonesia well-known as one of the world’s significant crude oil producers and refined product suppliers at that time. In fact, Indonesia was so well-known for its oil it became involved in World War II.
Recognized as a significant oil producer, Indonesia was invited to become a member of OPEC 1962.
The three oil companies that produced about 90% of all the petroleum in Indonesia during the Dutch colonial period are:
BPM – Bataafsche Petroleum Maatschappij
STANVAC – Standard Vacuum Oil Company
Here are the amazing stories of these three big oil companies operating in Indonesia before 1945.
BPM is Bataafsche Petroleum Maatschappij, also called the Batavian Oil Company. Batavia, which is Jakarta today, was the center of the NEI government.
BPM was established in 1907 by KNPM (Koninklijke Nederlandsche Petroleum Maatschappij) also known as Royal Dutch Petroleum Company and Shell Trading and Transport Company to explore and produce oil in the Netherlands East Indies.
Royal Dutch Petroleum Company owned 60% and Shell owned 40% of BPM.
Before BPM was set up, there were already as many as 18 oil companies operating in the Netherlands East Indies (NEI) from North Sumatera, Java, Borneo, and all the way to Papua.
BPM quickly took over almost all of these companies and dominated the oil industry in Indonesia. By 1920, it had controlled more than 95% of crude oil production in Indonesia.
In 1921, as the government of the Netherlands East Indies wanted to take part in the booming oil business in Indonesia, NEI and BPM formed another company called NIAM (Nederlands Indische Aardolie Maatschappij).
Many big changes took place in the oil industry after Indonesia declared its independence in 1945. The first big change was the takeover by the government of Indonesia the NEI’s 50% ownership in NIAM.
This marked the beginning of an Indonesian government-owned oil company. It also started a working relationship between BPM and the government of Indonesia. With this relationship, BPM managed to extend its activities in Indonesia until 1965.
In 1965, BPM sold all its assets in Indonesia to the Indonesian state-owned company PN Permina for US$110 Million. Permina later became Pertamina.
BPM operations in Indonesia were extensive. They stretched from the western part of Indonesia to the eastern part of Indonesia.
Here are the operations of BPM in various parts of Indonesia.
BPM In Borneo
In 1907, right after it was formed, BPM acquired the oil fields and refinery in Balikpapan from Mathilda company. It also acquired the oil fields in Sanga Sanga and Tarakan which had been discovered previously by KNPM (Koninklijke Nederlandsche Petroleum Maatschappij).
BPM expanded its exploration and production aggressively in East Borneo and continued to discover several other fields in these areas.
On the small island of Tarakan, BPM drilled 700 oil wells and built a refinery.
Production continued to increase and in the 1920s the Tarakan wells produced about 18,000 BOPD, a third of the total oil production in the whole Dutch East Indies.
BPM in North Sumatera
BPM acquired from KNPM the oil fields and the refinery located at Pangkalan Brandan. BPM also took over the operations of the oil tanking and the oil export facilities at Pangkalan Susu. Pangkalan Susu was the first oil-exporting port in Indonesia.
BPM in Java
In Java, BPM acquired the oil assets of DPM (Doordsche Petroleum Maatschappij), a Dutch oil company established by Adriaan Stoop in 1887.
DPM had discovered and operated the Kruka Field and the Djabakota Field near Surabaya in East Java. DPM also had built the oil refinery in Wonokromo. Completed in 1893, this was the first oil refinery in Indonesia.
By acquiring DPM, BPM also became the owner of some thirty oil fields in East Java including another refinery located in Cepu which was built in 1894.
BPM In South Sumatera
In South Sumatera, BPM took over SPPM (Sumatera Palembang Petroleum Maatschappij). SPPM had been operating the oil fields in its concessions in Banyuasin and Jambi.
BPM also acquired the oil assets of MEPM (Muara Enim Petroleum Maatschappij). MEPM had discovered the Muara Enim field and built the Plaju Refinery.
BPM In Irian Jaya
In 1935 BPM expanded its search for oil into Irian Jaya. For this venture, along with other partners, BPM formed a joint venture company named NNGPM (Nederlandsche Nieuw Guinea Petroleum Maatschappij) with exploration rights for 25 years.
By 1938 they had discovered the Klamono oil field. followed by Wasian, Mogoi, and Sele fields.
However, for commercial reasons, these fields were not developed.
STANVAC – Standard Vacuum Oil Company – started as NKPM (Nederlandsche Koloniale Petroleum Maatschappij) in 1912. NKPM was set up in Nederland by the American company Standard Oil of New Jersey so it could explore for oil in Indonesia.
Since Indonesia was under the control of the Netherlands East Indies at that time, Jersey Standards had to set up NKPM as a Dutch-registered and Dutch-managed company with headquarters located in The Hague.
NKPM began to make exploration in Java and South Sumatera in 1914.
It was in South Sumatera NKPM found its liquid gold. Operating from the city of Palembang, it discovered the Petak field in 1914, the Trembule field, and the huge Talang Akar field in 1921. These discoveries prompted NKPM to construct the famous Sungai Gerong oil refinery.
In 1922 NKPM changed its name to SVPM (Standard-Vacuum Petroleum Maatschappij).
It also constructed the 130 Km long pipeline from Pendopo area to Sungai Gerong to bring the crude oil from the prolific Talang Akar field to the refinery.
The Sungai Gerong refinery began operating in 1926 and became the largest and important oil refinery in South East Asia.
It was so important that the refinery was occupied by Japanese forces from 1942 to 1945 during World War II.
To meet the increasing demands for petroleum products in Africa and the Asia Pacific, Standard Oil Company of New Jersey and SOCONY (Standard Oil Company of New York) jointly created STANVAC (Standard Vacuum Oil Company) in 1933.
This was a synergistic partnership as Standard Oil Company of New Jersey had the oil production capacity and SONONY had the marketing facility.
The newly created Stanvac in the Netherlands East Indies consisted of three companies: Standard Vacuum Petroleum Maatschappij (SVPM), the Standard Vacuum Sales Company (SVSC), and the Standard Vacuum Tankvaart Maatschappij (SVTM).
Stanvac took over all the assets of SVPM in Indonesia and became a full-fledged oil company involved in oil exploration and production, refining, transportation, and distribution in more than 50 countries.
However, Stanvac continued to operate under its Dutch company name – SVPM – in the NEI.
Stanvac produced oil from many fields in South Sumatera. The notable ones were Talang Akar, Djirak, Benakat, Radja fields.
In 1934, Stanvac expanded its operations to Central Sumatera. Here it discovered and developed the well-known Lirik field and later the Binio field.
Things began to change after World War II and the declaration of independence of Indonesia.
It was after the declaration of independence by Indonesia in 1945, to distance itself from its Dutch connection, Stanvac began calling itself Stanvac Indonesia as its company name to show its American origin.
In so doing, Stanvac was able to keep its assets and continue to operate in the newly independent Indonesia.
In 1960, as Indonesia wanted to have more control of the oil operation and business, it introduced the 1960 Oil Law which stated that all foreign oil companies must operate as a contractor for the Indonesian government.
On 24 September 1963, Stanvac signed the “Contract of Work” agreement with Indonesia’s Pertambangan Minjak Nasional (Permina).
The contract allowed Stanvac to continue to have full control of its oil exploration and production operations in Indonesia. Under this agreement, Stanvac must sell its refinery within ten to fifteen years.
However, Stanvac had to sell its Sungai Gerong refinery to Pertamina in 1969.
Stanvac Indonesia continued to operate its oil fields until finally in 1995 it sold all its assets to Medco Energi for 88 million USD.
While Stanvac was operating in Indonesia, one of its parent companies, Mobil Oil, assumed the Arun block in Aceh in 1968. It went on to discover the super giant Arun gas field in 1971.
Interestingly, the two parent companies of Stanvac, Exxon and Mobil, merged in 1999 to become Exxon Mobil Corporation.
CALTEX was established in 1936 by Standard of California and Texaco to explore and produce oil in Indonesia and to expand its oil business in the Asia Pacific.
Earlier in 1924, The Standard of California had sent its team of geologists to Indonesia.
To operate in the Netherlands East Indies at that time, Caltex must obtain oil concessions from the government of NEI (Nederlands East India) who was the ruler of Indonesia at that time. To do so, in 1930, Caltex established NPPM (Nederlandsche Pacific Petroleum Maatschappij), a Nederland registered company with its headquarters located in The Hague. Also, the company must be run by Dutch nationals.
In the same year, Caltex received its first oil concession in the Rimba area which is now known as the Rokan Block in Central Sumatera.
Soon after that Caltex began to find oil, but it was in 1941 that Caltex discovered the huge Duri field. Due to the high pour point of its low gravity crude oil, it was necessary to use steam-flood to drive out the oil. Due to the success of the steam flood method, the Duri field became known as one of the largest steam-flood projects in the world. In spite of the huge challenges to produce the field, it has produced more than 2.64 billion barrels of oil so far.
Several years later Caltex went on to discover another giant oil field, The Minas field.
The story of the Minas field discovery is very interesting. In 1940, at the beginning of World War II, Caltex had started the drilling of its exploration well in the Minas area. However, before the drilling was completed, Caltex had to abandon the drilling as the Japanese army was coming to occupy the area and to take over the oil facilities.
The Japanese army engineers resumed the drilling of the well in 1943 and discovered oil when it drilled down to 2600 feet deep.
At the end of the war, Caltex regained control of its oil assets and continued to investigate the Minas field. After drilling several additional wells, Caltex confirmed the discovery of the huge Minas oil field.
Caltex went on to discover many smaller oil fields in its concession area.
By the late 1950s, Caltex became one of the largest oil producers in Indonesia. At its peak in 1973, Caltex produced about 1 million BOPD from the Duri, the Minas, and about 80 smaller oil fields. Caltex holds the record of having the highest daily crude oil production rate in Indonesia.
Caltex completed the construction of a crude oil export terminal in Dumai in 1958.
Caltex signed a work contract agreement with Indonesia in 1961 giving it the right to continue to operate the Rokan block until 2001. Later on, Caltex managed to obtain a work contract extension to operate the block for another 20 years until 2021.
The two owners of CALTEX, Chevron, and Texaco merged in 2001 to become ChevronTexaco Corporation. Later on, in 2005, ChevronTexaco Corporation dropped the name Texaco and renamed the company as Chevron Corporation.
Following the name change of its parent company, Caltex in Indonesia which was initially incorporated as PT Caltex Pacific Indonesia changed its name to PT Chevron Pacific Indonesia.
By 2008, Chevron Pacific Indonesia had produced 11 billion barrels of crude oil from the extremely prolific Rokan block.
Although the Rokan block has been producing oil for more than 80 years, it still has 2 billion barrels of estimated producible reserves. It is considered as an important block in Indonesia’s ambition to increase the daily oil production in Indonesia to one million barrels by 2030.
Although the name Caltex disappeared in Indonesia after the name change, the Caltex petroleum brand is still alive in many countries in the Asia Pacific.
These three companies of the past were great companies to work for. Since most of their oilfields were located in the middle of a jungle, the companies provided good and well-rounded facilities – schools, clinics, cafeterias, places for worship, sports, and entertainment – to their employees and their families.
Many people and children of those who had worked for these companies have fond and colorful memories of the companies.
To me, the one that is the most interesting is BPM.
The joint venture of Royal Dutch Petroleum Company and Shell Trading and Transport Company that formed BPM – Bataafsche Petroleum Maatschappij – in Indonesia in 1907 sowed the seed that eventually grew into the current giant Shell Oil Company.
Also, BPM had a role in the rise of Pertamina when Pertamina took over all the assets of BPM in 1965.
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.
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.
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.
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.
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.
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).
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.
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.
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.
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
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.
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
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.
Course date: November 25-29, 2019
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:
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.
• 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.
• 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.
Course date : December 10-14, 2018 Location : Singapore Tuition : US$4500
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.