To reduce the impacts of climate change due to greenhouse gases, many countries and businesses are moving towards carbon-neutrality.
One of these moves is decarbonization and the other is the use of clean energy such as hydrogen and renewable energy.
Microsoft recently announced its commitment to become carbon negative by 2030. Microsoft also said that it will remove more carbon from the environment than it has ever emitted in the past by 2050
Here are some of the technical terms related to decarbonization and clean energy.
Carbon footprint is the amount of carbon dioxide emissions created by a person or industry.
Carbon tax is tax paid by businesses and industries that produce carbon dioxide through their operations.
Carbon neutrality is a term used to describe the action of organizations, businesses, and individuals taking action to remove as much carbon dioxide from the atmosphere as each put into it.
The overall goal of carbon neutrality is to achieve a zero-carbon footprint. For example, a business may plant trees in different places around the world to offset the electricity the business uses. This practice is often called carbon offset or offsetting.
Carbon Capture and Storage (CCS)
CCS is the process of capturing waste carbon dioxide usually from large sources such as a factory or power plant, transporting it to a storage site, and depositing it where it will not enter the atmosphere, usually a subsurface rock formation.
Currently, there are less than 20 coal plants that use CCS technology to capture the produced carbon dioxide.
Carbon-neutral fuel is a fuel that has no net greenhouse gas emissions or carbon footprint. An example is a synthetic fuel produced by hydrogenating the carbon dioxide captured directly from the air.
Carbon Negative Fuels
Carbon negative fuels are fuels that take more carbon out of the environment than it generates.
Direct air capture is the process of capturing carbon dioxide directly from the air to produce a concentrated stream of CO2 for sequestration or utilization. In terms of utilization, as an example, the CO2 is being used to drive out reservoir oil in many CO2 miscible EOR projects around the world. The captured CO2 can also be used to produce carbon-neutral fuels by hydrogenating it with hydrogen.
Fuel cells are devices that convert the chemical energy of a fuel directly into electricity by electrochemical reactions. For example, hydrogen cars use fuel cells to convert the energy stored in the hydrogen into electrical energy for powering the car.
Greenhouse gases are gases that cause the greenhouse effect on our planet. The most common types of greenhouse gases are CO2, carbon monoxide (CO), methane (CH4), water vapor (H2O), Nitrous oxide (N2O), and ozone (O3).
The hydrogen economy is a situation where hydrogen is used as the major carrier of energy.
Renewable energy is any naturally occurring, theoretically inexhaustible source of energy, as biomass, solar, wind, tidal, wave, and hydroelectric power, that is not derived from fossil or nuclear fuel.
Renewable Natural Gas is produced by capturing methane emitted from the breakdown of organic wastes in landfills, wastewater and farms, and processing it into natural gas.
Net Zero Carbon Emission
Net zero carbon emission is a balance achieved when the amount of carbon that we emit is offset by the amount of carbon we remove from the atmosphere.
Discovered by Unocal in 1998, the West Seno field, lying in water depths of about 3200 feet, is the first deepwater oil field in Indonesia.
Located in the Strait of Makassar, the West Seno field is about 50 km away from the giant Attaka field and 60 km from the Santan terminal in East Kalimantan.
The oil and gas are produced through a tension leg platform (TLP) which is also the first of its kind in Indonesia.
The floating topside of the tension leg platform is attached to the seafloor by four 3200 feet long tendons having a diameter of 26 inches and a wall thickness of 1.036 inches.
Currently, all the subsea wells are produced from platform TLP-A which can accommodate 28 wells. Unocal originally had planned to build two tension leg platforms.
Oil production from the West Seno wells began in 2003 and currently, they are producing about 1200 BOPD. The fluids from the subsea wells are initially separated into oil and gas on the FPU (Floating Production Unit).
The separated oil and gas are then transmitted via two 12-inch diameter and 60 km long pipelines to the onshore facilities at Santan for final handling and storage.
One of the oil production challenges of West Seno is handling the difficult-to-break emulsions. The emulsions are hard to break due to the presence of certain chemicals in the fluid, the decreasing fluid temperature as it rises to the surface, and the motion of the floating platform.
The West Seno offshore production facilities also handle the production from the nearby Bangka field. Bangka field produces about 1000 barrels of condensate daily and 40 MMSCF of gas per day.
The development of the West Seno field was made possible by having a favorable PSC profit splits of 35 percent instead of the regular 15 percent for shelf developments.
Fifty years ago, Union Oil of California (UNOCAL) along with its partner, INPEX, discovered the giant offshore oil field Attaka in East Kalimantan.
General Soeharto, the president of Indonesia at that time, then inaugurated the Attaka field and the Santan terminal on 22 January 1973.
In the early days of Attaka and the Santan terminal, there were many workers from the US and UK. Over time, they were gradually replaced by Indonesian workers.
Unocal operated the oil field for 25 years from its East Kalimantan headquarters located in Balikpapan. The Attaka field was subsequently acquired and operated by Chevron, and then by Pertamina Hulu Kalimantan Timur beginning on 25 October 2018.
At 50 years old, the field is still producing today.
Thousands of oil people – expatriates from many nations and Indonesians from every region – have visited and worked in the offshore facilities and the onshore Santan terminal including me.
I worked in the Attaka field as “Production Foreman” in 1980. I hope you like this snippet of the history of Attaka and the Santan terminal.
Before there was OPEC, there were the “SEVEN SISTERS”.
The Seven Sisters, a consortium of seven world’s largest oil companies, was formed in the 1950s.
Here are the original members of the Seven Sisters:
Anglo-Persian Oil Company (now BP)
Royal Dutch Shell
Gulf Oil (Acquired by Chevron in 1985)
Standard Oil of California (now Chevron)
Standard Oil of New Jersey (now ExxonMobil)
Standard Oil of New York – Socony ( later became Mobil Oil and then ExxonMobil)
Texaco (Acquired by Chevron in 2001)
Although the term “The Seven Sisters” was used for the first time in 1951, these seven companies had been dominating the oil industry since the 1940s. The Seven Sisters were so powerful that at one time, they controlled about 85% of the global oil and gas reserves.
Due to company mergers and acquisitions that took place in the oil industry in the last 40 years, the composition of the seven largest oil companies in the world had changed significantly.
The original Seven Sisters consisted of two European and five American oil companies whereas currently, the seven largest international oil companies in the world consist of four European and three American companies.
Here are the new seven largest international oil companies in the world which are now commonly referred to as the seven SUPERMAJORS.
BP (British Petroleum)
British Petroleum is a British oil company that started as Anglo-Persian Oil Company in 1908 as a subsidiary of Burmah Oil Company. BP grew bigger and bigger by acquiring SOHIO (Standard Oil of Ohio) in 1978, then Amoco in 1998 and ARCO (Atlantic Richfield Company) in 2000.
BP operates in 79 countries with 70,000 employees. The London-based company produces 3.8 million BOEPD of oil and gas.
Chevron began as Standard Oil of California as one of the successors of the original Standard Oil company, the company founded by Mr. John D. Rockefeller after it was broken up into several companies in 1911 under the Sherman Antitrust Act in the US.
Chevron became a huge oil company after acquiring Gulf Oil in 1985, then Texaco in 2001, and Unocal Corporation in 2005.
With headquarters in San Ramon, California, Chevron operates in 180 countries and employs more than 48,000 people. Its daily oil and gas production is about 3.1 million BOEPD.
ExxonMobil that began as Standard Oil of New Jersey is also another descendant of the original Standard Oil company. Standard Oil of New Jersey changed its name to Exxon in 1972, and later on, Exxon became ExxonMobil after it merged with Mobil Oil in 1999.
Operating in 58 countries, ExxonMobil has about 71,000 employees. It produces about 2.3 million BOE of oil and gas daily. The company is based in Irving, Texas.
ROYAL DUTCH SHELL
The formation of the Royal Dutch Shell group came from the merger of Royal Dutch Petroleum Company of the Netherlands and Shell Transport and Trading Company Limited of the United Kingdom in 1907. The Anglo-Dutch company was formed to compete against the powerful American oil company – The Standard Oil.
The Royal Dutch Petroleum Company, known as Koninklijke Nederlandse Petroleum Maatschappij in Dutch, had its root in Indonesia when it was formed in 1890 to produce the oil it discovered in Pangkalan Brandan in North Sumatera and later on in Balikpapan in East Kalimantan.
Royal Dutch Shell became a big player in LNG when it acquired BG Group in 2016.
From its headquarters in the Netherland, Shell operates in 70 countries and has 81,000 employees. The company’s daily oil and gas production is about 3.7 BOE.
Total, a French supermajor oil company, started in 1924 as Compagnie Française des Pétroles ( CFP). It later changed its name to Total CFP in 1985 and finally to Total in 1991.
The company grew even bigger after it acquired the Petrofina of Belgium in 1999 and then ELF Aquitaine in 2000.
Based in France, Total has operations in 130 countries and it employs more than 100,000 employees. It produces 3 million BOEPD of oil and gas.
ConocoPhillips started as Conoco 1875 in the US. Conoco merged with Phillips Petroleum Company to form ConocoPhillips in 2002.
Based in Houston, ConocoPhillips involving only in the upstream part of the oil industry is the world’s largest independent oil company. With about 10,400 employees, its daily oil and gas production in 17 countries is around 1.3 million BOE.
ENI (Ente Nazionale Indrocarburi)
ENI, a supermajor oil company from Italy was formed in 1953, and then it acquired AGIP, another Italian oil company, in 2003.
From its headquarters in Rome, ENI operates in 79 countries. The company employs more than 30 thousand people and it produces a combined 1.7 million BOE of oil and gas daily.
LPG and LNG are by-products of petroleum and they are increasingly used for fuel as countries are increasingly concerned about their environment.
So what are LPG and LNG, and how are they different?
LPG – Liquefied Petroleum Gas
LPG is liquefied petroleum gas which consists mainly of propane and butane.
LPG is commonly used as fuel in heating appliances, cooking equipment, and vehicles. It is also increasingly used as an aerosol propellant and refrigerant, replacing chlorofluorocarbons to reduce damage to the ozone layer.
As a clean fuel, LPG is also increasingly used to power cars and buses. For this application, LPG is referred to as autogas or CNG (compressed natural gas).
At the normal condition, 15 degrees C and 14.7 PSI, the mixture of propane and butane is in the gaseous state. However, when its pressure is increased to above 120 PSI, the gaseous mixture turns into liquid. The liquefaction of the LPG makes it easier to store and transport.
In the liquid state, the volume of the mixture is only 1/270th of its volume in gaseous form. So, when LPG is released to the atmosphere, it will expand 270 times as it turns into vapor.
LPG is produced by extracting the propane and butane from the gas and condensate produced from oil reservoirs and gas reservoirs. This extraction process usually takes place in a gas processing plant located at an oil or gas field.
LPG is also produced from crude oil as one of the distillates from the refining process in a refinery.
LNG – Liquefied Natural Gas
LNG is liquefied natural gas. In remote places where a large quantity of natural gas is discovered and no gas pipeline is available, the produced natural gas is often turned into a liquid allowing it to be transported in bulk by LNG carriers. At its destination, the LNG is offloaded from the tanker and stored in insulated tanks. The LNG will be processed back into a gas, and the gas will be put into the pipeline for further distribution.
To produce LNG, natural gas consisting mainly of methane is super-cooled to -162 degrees C to turn it into a liquid. This decreases the gas volume 600 times making it easier to store and transport. It also plays a very important and useful role in meeting peak demands for gas, which the normal pipeline infrastructure cannot do. LNG is finding many new applications, and its demand is increasing. According to a Shell report, the global demand for LNG is expected to increase 4 to 5 % per year until 2030 while the demand for natural gas will increase at 2% per year.
In places where demand for natural gas cannot be met locally, the use of FSRU is gaining popularity. FSRU is a floating, storage and regasification unit. An FSRU can be constructed and installed quite quickly and economically to receive LNG from an LNG carrier and deliver the gas to the end-users as needed.
In summary, LPG and LNG have similarities and differences.
Similarities of LPG and LNG
Both LPG and LNG are by-products of crude oil and natural gas.
They are both in liquefied form making them easier for storage and transportation.
They are commonly used as fuel.
They are considered as clean fuel as they leave no smoke or soot.
Differences between LPG and LNG
LPG consists mainly of propane and butane whereas LNG consists mainly of methane.
LPG has a much higher heating value than LNG, and therefore it is also used to power cars and even buses.
LPG is liquefied by increasing its pressure whereas LNG is liquefied by lowering its temperature.
LPG is usually distributed to consumers in pressurized cylinders whereas LNG is gasified before it is transmitted to end-users by pipelines.
Finally, as their names imply, petroleum – the crude oil, condensate, and natural gas – is the source of the propane and the butane contained in the LPG, whereas natural gas is the main source of the methane contained in the LNG.
In North America, the first oil well was drilled in 1858 by James Miller Williams in Oil Springs, Ontario, Canada.
In the United States, the petroleum industry began in 1859 when Edwin Drake found oil near Titusville, Pennsylvania.
How about in Indonesia?
Indonesia also has a very interesting history of early oil drilling, and it was not too far behind North America in finding its first oil wells in the 19th century.
In Indonesia, Dutch officials noted there were 53 oil seepage locations across Indonesia in 1869. The first oil well drilling in Indonesia began in 1871 in West Java. Several years later, oil was discovered in Pangkalan Brandan in Sumatera in 1885 and Sanga-Sanga in East Kalimantan in 1892.
The First Oil Discovery in Java
“Knowledge of oil on Java and Sumatra was reported as early as the year 954 and in 1596 a Dutch voyage reported a well in Sumatra producing a balm used for treating rheumatism and for lighting purposes (Van Bemmelen, 1949).”
“In 1869, Von Baumhauer recorded 44 oil seeps in Java, drilling for oil started in West Java in 1872 and the first oil company started operations in East Java in 1887 (Van Bemmelen, 1949).”
“Early exploration wells in West Java onshore were drilled by Jon Reesink who was a storekeeper in Cirebon (Courteney and others, 1989). He visited the United States, collected drilling equipment and skills, and began drilling at Cibodas in 1871 with the financial backing of Nederlandsche Handel Maatschappij (the predecessor of Royal Dutch Shell) (Courteney and others, 1989).”
“Sub-commercial oil was found in two of his first four wells, which were drilled using water buffalo for power. He resumed drilling in 1874 with steam equipment, but the next 5 wells were unsuccessful, which discouraged his backers. However, other drilling ventures were conducted with encouraging shows, and the first commercial oil field was discovered at Randegan in 1939 (Courteney and others, 1989).”
The First Oil Discovery in Sumatera
In 1883, tobacco planter A.J. Zijkler obtained the first petroleum exploration rights in North West Sumatera from the Sultan of Langkat. He then discovered the first commercial oil well in Indonesia in 1885.
The discovery well – Telaga Tunggal 1 – was discovered in Langkat near Pangkalan Brandan. Oil was found at a depth of 121 meters and the field produced more than 7 million barrels of crude oil for more than 50 years.
The First Oil Discovery In Kalimantan
Oil was discovered in Balikpapan, Kalimantan in 1897 when Jacobus Hubertus Menten, a Dutch mining engineer observed oil seepages in the area.
With the help from Sir Marcus Samuel from Shell Transport and Trading Ltd, they drilled the famous Well Mathilda B-1 on 10 February 1897. The well was drilled to 222 Meter and it flowed initially at 184 barrels per day. This oil discovery in Balikpapan took place 38 years after Sir Edwin Drake drilled the world’s first oil well in America.
With the discovery, Jacobus Hubertus Menten and Sir Marcus Samuel formed Nederlandsch Indisch Industrie en Handel Maatschappij (NIIHM), and it continued to discover other oil fields away from Balikpapan. 10 February 1897 is considered the birth date of Balikpapan.
This article consists of excerpts from the article “Petroleum Systems of the Northwest Java Province, Java, and Offshore Southeast Sumatra, Indonesia” written by Michelle Bishop published by USGS in 2000 and information from several other sources.
In 2019, the average daily crude oil production in Indonesia was 746,000 barrels.
Here are the eight largest crude oil lifting terminals in Indonesia in 2019 according to SKK Migas of Indonesia.
WIDURI MARINE TERMINAL
Widuri Marine Terminal is operated by Pertamina Hulu Energi OSES which operates the oil fields located in the Offshore South East Sumatera contract area.
The South East Sumatera contract area was initially awarded to IIAPCO in 1968. Many big oil fields were discovered in this block such as Banuwati, Cinta, Intan, Widuri and Zelda.
Crude oil produced from these fields were stored in the Lentera Bangsa FSO – a floating, storage, and offloading vessel – and then offloaded into oil tankers.
The operatorship of this contract area changed hands many times during its 50 years of operation. Previous operators include IIAPCO, Maxus, Repsol, and CNOOC.
The average daily crude oil lifting volume of the Widuri Marine Terminal was 8501 BOPD.
SENORO MARINE TERMINAL
Senoro Marine Terminal is operated by JOB Pertamina Medco Tomori Sulawesi which is a joint operating body consisting of Pertamina Hulu Energi, Medco E&P and Tomori E&P.
JOB Pertamina Medco Tomori Sulawesi operating in the Tomori-Toili Block located in Central Sulawesi produces gas and condensate from the Senoro gas field and crude oil from the Tiaka oil field.
The gas from the Senoro field is processed into LNG by the Donggi-Senoro LNG plant which started operation in August 2015.
The average daily lifting volume at Senoro Marine Terminal was 14,857 BOPD
TUBAN MARINE TERMINAL
Tuban Marine Terminal located in East Java is operated by PT Pertamina EP. The terminal handles the lifting of crude oil that Pertamina EP produces from the Tuban block. Before 29 February 2018, the Tuban block was operated under Joint Operating Body (JOB) Pertamina Petrochina East Java.
PT Pertamina EP, established on 17 September 2005, came under the supervision of BPMIGAS on 17 September 2005. BPMIGAS became SKK Migas on 13 November 2012.
On average, 16358 BOPD was lifted at the Tuban Marine Terminal.
The Ardjuna oil terminal is operated by Pertamina Hulu Energi ONWJ which operates the oil and gas fields located in the Offshore North West Java work area.
The huge Ardjuna oil field was initially discovered by ARCO after it signed the PSC contract in 1971. ARCO later became BP West Java. Pertamina Hulu Energi ONWJ became the operator of the Ardjuna field in July 2009.
The average crude oil lifting volume from the Ardjuna terminal was 25626 BOPD.
SENIPAH MARINE TERMINAL
Senipah Marine terminal is operated by Pertamina Hulu Mahakam. The terminal was previously operated by Total Indonesie who discovered several big oil and gas fields – Bekapai, Handil, Tunu, Peciko, Sisi, Tunu – in the Offshore Mahakam block.
On average, 31539 BOPD was lifted at The Senipah Marine terminal.
The RU PP7 terminal is located in the Riau province in Sumatera and operated by Chevron Pacific Indonesia.
The average daily lifting volume at RU PP7 Terminal was 62,337 BOPD.
The Dumai terminal is located in the Riau province in Sumatera and operated by Chevron Pacific Indonesia who holds the operatorship of the prolific Rokan PSC which will soon expire in 2021.
Chevron Pacific Indonesia, also known as CPI, discovered two super-giant oilfields: the Duri field in 1941 and Minas in 1944. Subsequently, CPI continued to discover many smaller oil fields in the Rokan work area.
Due to its low gravity oil, the Duri field underwent steam flooding in 1985 to enhance the recovery of its heavy oil. The Duri field steam flood project is one of the largest in the world.
The average daily lifting volume at the Dumai Terminal was 116,555 BOPD.
BANYU URIP MARINE TERMINAL
At an average daily crude oil lifting volume of 200, 937 barrels, the Banyu Urip Marine Terminal is currently the top crude oil lifting terminal in Indonesia. It handles the lifting of the crude oil produced by Mobil Cepu from the onshore Banyu Urip field located in the Cepu Block contract area.
After the crude is processed in the central processing facilities (CPF) located at the center of the oil field, the oil is transported through a 72 KM long pipeline to the coast of Tuban, and then through a 23 KM long subsea pipeline to the FSO (Floating, Storage and Offloading) vessel. The FSO is named FSO Gagak Rimang.
The crude oil from the Banyu Urip field is lifted by oil tankers from FSO Gagak Rimang for transport to domestic and international refineries. The FSO has storage capacity for 2 million barrels of crude oil.
Oil companies in Indonesia and SKK Migas were buzzing with activities and excitement in 2019.
Exploration and Production Results
First, here are the combined performance results of the exploration and production activities of all the oil and gas production sharing contractors in Indonesia operating under the supervision of SKK Migas in 2019:
Total number of active work areas: 201
Average daily crude oil production: 746,000 BOPD
Average daily gas production: 5934 MMSCFD
Combined total daily oil and gas production: 1,806,000 BOEPD
The total value of the investment: 11.49 Billion USD
Number of development wells completed: 322
Number of exploration wells drilled: 36
The volume of oil and gas in place discovered: 113 BBOE
2-D seismic surveys completed: 12169 KM
3-D seismic survey completed: 6837 KM2
On the oil and gas discovery front, it is nice to note that REPSOL and partners PETRONAS and MOECO discovered a giant gas field in February 2019 in the Sakakemang block in South Sumatera. With 2 trillion cubic feet of recoverable gas reserves, it is one of the largest gas discoveries in the world in 2019 and also the most significant gas discovery in Indonesia in the last 18 years.
On new field development, Inpex Indonesia and SKK Migas made significant progress in developing the huge Abadi gas field and constructing the LNG plant. It was decided the LNG plant will be built in the Yamdena Island in the Maluku province of Indonesia.
The 15 Largest Oil Producers in Indonesia
Here are the 15 largest oil producers operating under the production sharing system in Indonesia in 2019:
Pertamina Hulu Mahakam
Pertamina Hulu Energi Offshore North West Java (PHE ONWJ)
Pertamina Hulu Energi Offshore South East Sumatera (PHE OSES)
PetroChina International Jabung
Medco E&P Natuna
Petronas Carigali Ketapang
Pertamina Hulu Kalimantan Timur
BOB Bumi Siak Pusako Pertamina Hulu
Pertamina Hulu Sanga Sanga
Medco E&P Rimau
JOB Pertamina Medco Tomori Sulawesi
The 15 largest natural gas producers in 2019
Here are the 15 largest gas producers in Indonesia in 2019:
Pertamina Hulu Mahakam
ENI Muara Bakau
JOB Pertamina Medco Tomori Sulawesi
Premier Oil Indonesia
PetroChina International Jabung
Medco EP Natuna
Kangean Energy Indonesia
PHE West Madura Offshore
Pertamina Hulu Energi Jambi Merang
Mubadala Petroleum Indonesia
PHE Offshore North West Java
The SKK Migas
The SKK Migasof Indonesia has also been very proactive in its roles as the supervisor of the production sharing contractors to facilitate their exploration and production activities.
With the vision to increase the oil production in Indonesia to one million barrels per day by 2030, SKK Migas instituted the Integrated Operation Center (IOC) and the One Door Service Policy (ODSP) in 2019.
The Integrated Operation Center (IOC)
SKK Migas launched the Integrated Operation Center (IOC) in 2019. With the IOC, SKK Migas now has online and realtime access to information and data related to the exploration, drilling and production activities of the production sharing contractors in all work areas.
The IOC allows SKK Migas to monitor the daily field activities of all operators, understand the field situations and make prompt recommendations.
The objectives of SKK Migas in establishing the OIC are to keep the oil and gas operations go smoothly and achieve the production targets.
Currently here is the information that is being monitored by the Integrated Operation Center:
Oil and gas production (Production Dashboard)
Oil and gas lifting (Oil and Gas Lifting Dashboard)
Stock Management (Stock Management Dashboard)
Plant Operation (Plant Information Management System – PIMS)
Vessel tracking (Vessel Tracking Information System – VTIS)
Real-Time Drilling Operation
Emergency responses (Emergency Response Center – ERC)
The One Door Service Policy (ODSP)
SKK Migas also introduced One Door Service Policy (ODSP) in 2019. Through ODSP, the applications of all the permits related to exploration, drilling, field development, and production can be processed in one place.
SKK Migas will work with and support all the production sharing contractors in preparing the required documents and submitting the applications to obtain the various permits they need.
This is a very significant service because of the various types of permits that oil operators must apply. With this one-door policy, SKK Migas is hopeful that the various permits can be obtained promptly, and the oil and gas exploration and production targets can be achieved.
The One Door Service Policy consists of four work-groups that will help the production sharing contractors deal with the following type of permits:
Permits related to land acquisition and use
Permits related to the environment, safety and security
Permits related to the use of resources and infrastructure
Permits related to the use of materials and human resources from outside Indonesia.
Several exploration and production targets were exceeded in 2019 and SKK Migas is hopeful the new 2020 targets can be achieved also by the end of the year.
This article is adapted from the information posted by SKK Migas.
SKK Migas – Satuan Kerja Khusus Pelaksana Kegiatan Usaha Hulu Minyak dan Gas Bumi – is a special task force that implements the production sharing contracts, develops the oil and gas upstream business and supervises the activities of the production sharing contractors in Indonesia.
SKK Migas is an institution created by the government of Indonesia based on the presidential regulation “Perpres Nomor 9 Tahun 2013 on the development and management of upstream oil and gas activities”.
SKK Migas is tasked to manage and supervise the upstream oil and gas activities – exploration, drilling, field development, and production – based on the production sharing contract system. It is established with the mission to ensure the exploration and production of the oil and gas will benefit the country and the people of Indonesia.
Here are the functions of SKK Migas:
Give considerations and recommendations to the Minister of Energy and Mineral Resources of Indonesia regarding the preparations and tenders of oil and gas work areas
Sign production sharing contracts
Study the development plan of a new oil and gas field in a work area, and submit the development proposal of the production sharing contractor for approval by the Minister of Energy and Mineral Resources
Give approval on the field development plan submitted by production sharing contractors
Approve the work program and budget of production sharing contractors
Monitor the operation and progress made by production sharing contractors and submit reports to the Minister of Energy and Mineral Resources
Appoint sellers of the produced oil and gas that will benefit the country.
These functions were originally carried out by BPPKA, a department under Pertamina, when the production sharing contract system was introduced in 1966. BPPKA (Badan Pembinaan Pengusahaan Kontraktor Asing) was later replaced by BP Migas. BP Migas later became SKK Migas in 2013.
To best serve and support the activities of oil operators around the country, SKK Migas has five field offices. They are:
SKK Migas Sumatera Bagian Utara located in Pekanbaru
SKK Migas Sumatera Bagian Selatan located in Palembang
SKK Migas Kalimantan and Sulawesi located in Balikpapan
SKK Migas Jawa, Bali, Madura dan Nusa Tenggara located in Surabaya
SKK Migas Wilayah Papua dan Maluku located in Sorong
The current head of SKK Migas is Mr. Dwi Soetjipto. Its head office is located at Wisma Mulia, Jalan Gatot Subroto Kav. 42, Jakarta, Indonesia.
Guy Allinson is an experienced upstream oil and gas industry consultant and a lecturer at the School of Petroleum Engineering, University of New South Wales (“UNSW”).
Guy Allinson has held a range of petroleum economics and commercial positions in the oil and gas industry in Europe and the Asia / Pacific regions. He has advised companies and governments in the Asia / Pacific region on petroleum PSC and fiscal terms. He has valued many petroleum properties and companies for acquisition and sale, prepared economics research reports on the oil and gas industry and has provided commercial support for oil field operations and investments worldwide.
Guy has presented courses in petroleum economic analysis for more than 30 years and has presented these courses over 230 times to oil industry professionals in many countries including USA, UK, Denmark, Switzerland, Australia, New Zealand, Indonesia, India, Iran, Malaysia, Thailand, Vietnam, Brunei, Egypt, Libya, and South Africa.
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Indonesia will have a large tidal power plant in the straits of Larantuka at the Island of Flores. The Larantuka tidal power plant is designed to provide electricity to more than 100,000 residents in that area.
Witteveen+Bos and Bita Bina Semesta had started the Environmental and Social Impact Assessment (EISA) and Indonesian Environmental Impact Assessment (AMDAL) for the Larantuka Tidal Power Plant. These environmental assessments will be completed on September 1, 2020.
The Larantuka tidal power plant is commissioned by Tidal Bridge BV. The project consists of building and operating a 30-megawatt tidal power plant which will be the largest in the world! The turbines will be integrated into a bridge between Flores and Adonara island. The bridge will replace the dangerous ferry crossings at the Larantuka Strait. This is an interesting project where connectivity and renewable energy are integrated in an innovative way.
A tidal power plant converts the energy provided from tides into electricity. Tidal power is one of the most reliable sources of renewable energy. Tides are a more predictable power source than the wind or the sun. It is interesting to note that the moon is the source of the energy provided by the tides.
This Larantuka tidal 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% until 2023.
Here are the current top five tidal power plants around the world:
Sihwa Lake Tidal Power Station, South Korea – 254 MW
La Rance Tidal Power Plant, France – 240 MW
Swansea Bay Tidal Lagoon, UK – 240 MW
MeyGen Tidal Energy Project, Scotland – 86 MW
Annapolis Royal Generating Station, Canada – 20 MW
The Inpex Abadi Masela LNG plant in Indonesia will be built on Yamdena Island in Kabupaten Kepulauan Tanimbar of the Province of Maluku. Yamdena island is the biggest island among the Tanimbar Islands.
The head of SKK Migas of Indonesia, Bapak Dwi Sutjipto, handed the documents related to the plant location plan to the governor of Maluku, Bapak Murad Ismail on November 4, 2019, in Ambon. The event was attended by Mr. Akihiro Watanabe from Inpex and Mr. Lucki Wattimury.
(Note: SKK Migas is an Indonesian government institution that is tasked to manage all upstream oil and gas activities of companies who operate in Indonesia under a Cooperation Contract.)
This is a significant positive step to accelerate the construction of the Abadi Masela LNG plant. The LNG plant is designed to produce 9.5 million tons of LNG annually.
In this event, the governor of Maluku stated that the local government of Maluku welcomes the project and will give their full support in the land acquisition and construction of the LNG plant.
The total investment of the huge Abadi Masela project estimated at around US$20 billion will be the biggest project in Indonesia. During the development phase, the project will employ around 30,000 workers.
The natural gas to feed the LNG plant will come from the giant offshore Abadi gas field which was discovered by Inpex in 2000. The Abadi field has the capacity to produce more than 1 billion SCF of gas per day and 20,000 barrels of condensate per day for 24 years.
Inpex Indonesia has a 65 percent share of the Abadi Masela project and Shell has the remaining 35 percent. Inpex will operate the field until 2055.
The giant Carcara is a pre-salt oil and gas field located in the Santos basin offshore Brazil. It lies in water depths of 2027 meters and is one of the biggest discoveries in the world. It was discovered by Petrobras in 2012.
The oil reservoir lies in the pre-salt layer and its total thickness is more than 400 meters. It is estimated to contain recoverable reserves of more than one billion barrels of oil.
Operated by Equinor, oil production from the Carcara field is scheduled to start in 2024. Two FPSOs will be used to produce the oil and gas.
The Interesting Pre-Salt Basins
Oil was discovered in the Pre-Salt Basin in offshore Brazil in 2005. Oil-rich formations sit deep in the water and under thick layers of rock and salt.
Pre-salt basins were formed more than 100 million years ago when the South American and African continents separated, and therefore pre-salt layers are especially common off the coast of Africa and Brazil.
The hydrocarbon sits under layers of salt formations that are 2000 meters thick. The pre-salt production rates are some of the highest in the world for deepwater fields.
In Africa, the first pre-salt oil discoveries took place in Angola in 1983. The presence of pre-salt basins in eastern offshore Brazil and western offshore of Africa is proof that the South American and African continents were connected at one time.
Balikpapan, located in East Kalimantan, is the most well known and interesting oil town in Indonesia, and possibly in the world. It is at the center of oil and gas exploration and production activities that have been taking place in East Kalimantan since 1897 when the first oil well was drilled in Balikpapan. It is also the battleground of two fierce battles during World War II. It is set to become even more well known with the announcement of the relocation of the capital city of Indonesia from Jakarta to East Kalimantan.
Here are the interesting facts about Balikpapan.
The First Oil Discovery At Balikpapan
Oil was discovered in Balikpapan in 1897 when Jacobus Hubertus Menten, a Dutch mining engineer observed oil seepages in the area. With the help from Sir Marcus Samuel from Shell Transport and Trading Ltd, they drilled the famous Well Mathilda B-1 on 10 February 1897. The well was drilled to 222 Meter and it flowed initially at 184 barrels per day. This oil discovery in Balikpapan took place 38 years after Sir Edwin Drake drilled the world’s first oil well in America.
This picture shows the Mathilda B-1, the first well drilled in Balikpapan. The picture was taken by Chaz Tumbelaka.
With the discovery, Jacobus Hubertus Menten and Sir Marcus Samuel formed Nederlandsch Indisch Industrie en Handel Maatschappij (NIIHM), and it continued to discover other oil fields away from Balikpapan. 10 February 1897 is considered the birth date of Balikpapan.
The Balikpapan Refinery
To process the crude oil from the surrounding area and to meet the needs for fuel, the oil refinery of Balikpapan was completed in 1922 by BPM (Bataafsche Petroleum Maatschappij) which was a subsidiary of Royal Dutch Shell. The Balikpapan refinery was damaged in 1942 when the Japanese army invaded Balikpapan. The refinery was controlled by the Japanese army in 1942-1945. BPM regained control of the refinery after the Allied forces ended the Japanese occupation of Balikpapan in 1945.
Several years later, Pertamina gained control of the refinery in 1949. The refinery has been expanded and upgraded several times to meet the increasing demand for fuel in the eastern part of Indonesia.
As one of the largest refineries in Indonesia, it is set to become even bigger. It is currently undergoing a large 4-billion-dollar expansion which will increase its processing capacity from 260,000 barrels per day to 360,000 barrels per day when it is completed in 2021. The refinery will have the capability to produce high-quality Euro V standard fuels.
The Discovery of Giant Oil and Gas Fields
Balikpapan experienced its biggest boom when several large international oil companies came to town after the production sharing contract scheme was introduced by Indonesia in 1966.
Balikpapan was the base of Union Oil of California (Unocal), Total and Roy M. Huffington Incorporated (Huffco) during their exploration and production operations in East Kalimantan where they discovered several giant oil and gas fields.
Pertamina has a huge presence in Balikpapan since 1949 when it took over the oilfields and the refinery which were previously operated by BPM (Bataafsche Petroleum Maatschappij), a subsidiary of Royal Dutch Shell.
Operated from Balikpapan, Unocal in partnership with Japex discovered the giant offshore oil field of Attaka in 1970. It also discovered the offshore Sepinggan field and the Yakin field both of which are clearly visible from the hills at Balikpapan. In 1996, Unocal discovered and developed the West Seno field which is the first deepwater oil field in Indonesia.
Total with its partner, Inpex, acquired the Mahakam Block in 1966. They discovered several giant offshore oil and gas fields: Handil, Peciko, Tambora, Bekapai, South Mahakam, Sisi-Nubi, and Tunu.
Huffco discovered the giant onshore Badak gas field in 1970 in East Kalimantan. The discovery of the giant Badak gas field had a huge influence on the course of oil and gas development in East Kalimantan. It prompted Huffco and Pertamina of Indonesia to build an LNG plant making it possible to export the gas.
Besides the Badak field, Huffco subsequently discovered the Nilam, Pamaguan, Semberah, Mutiara, Beras, and Lempake fields.
Huffco later became known as VICO Indonesia (Virginia Indonesia Company) in 1990 after Mr. Roy M. Huffinton sold the company.
After the introduction of the production sharing contract scheme (PSC) in 1966, and with the discovery of several giant oil and fields in East Kalimantan and in other parts of Indonesia, crude oil production in Indonesia increased from 500,000 BOPD to 1,650,000 BOPD at its peak in 1977.
The Badak LNG Plant in Bontang
The LNG plant known as the Badak LNG was completed in 1977. Located in Bontang, besides processing the gas produced by Huffco from the Badak field, the Badak LNG plant also processes gas produced from the fields operated by Unocal and Total located in East Kalimantan. Up until the completion of the LNG plant, most of the associated gas produced by Unocal and Total were flared.
The Badak LNG plant initially comprised of two trains. Over the years, with new field discoveries, six additional trains were constructed. With 22.5 million tons per year LNG production capacity, it is one of the largest LNG plants in the world.
As of 16 September 2019, Badak LNG has delivered 9445 LNG cargoes to countries such as Japan, Taiwan, Korea, China, the USA, Russia, and India.
The Fierce Battlefield during World War II Twice
Being rich in oil and having a refinery, Balikpapan was so vital that it became a battlefield twice during World War II.
The Battle of Balikpapan in 1942
During World War II, in order to control the supply of fuel, Japan invaded Balikpapan in 1942. The Dutch garrison resisted the invasion but eventually was defeated by the much bigger Japanese forces. The refinery was partially destroyed during the invasion. Japanese forces took control of Balikpapan, oil production and the refinery from 1942 to 1945.
The Battle of Balikpapan in 1945
To regain control of Balikpapan and the oil supply, the Allied forces directed by General Douglas McArthur and spearheaded by the Australian 7th Division invaded Balikpapan on 25 June 1945. After 3 weeks of fierce fighting and heavy bombing, the Japanese soldiers in Balikpapan finally surrendered on 21 July 1945. Many Japanese soldiers fought to the end in the battle. There is a Japanese cemetery hidden among the hills in Balikpapan.
The Coal Boom of Balikpapan in the 1990s
Balikpapan experienced another economic boom when it became the center of the booming coal production in East Kalimantan beginning in the 1990s.
The Balikpapan Coal Terminal completed in 1995 is one of the biggest coal terminals in Indonesia. It has a throughput capacity of 15 million tons of coal annually.
Will Balikpapan continue to boom?
Since the discovery of the first oil well in Balikpapan in 1897, Balikpapan has seen several booms in the last 120 years. It has grown from a small fishing village to become a city with a population of 850,000 today.
On 26 August 2019, the President of Indonesia, Joko Widodo, announced that Indonesia will relocate its capital city from Jakarta to East Kalimantan. As the main gateway to East Kalimantan, Balikpapan will be the center of activities during the construction of a new capital of Indonesia. So, Balikpapan will likely continue to boom.
Finally, Balikpapan indeed is a very interesting town. As an oil and coal mining town, it has been voted several times as the most liveable city in Indonesia. Thousands of oil people from around the world have worked and lived here. Many children of international expatriates and Indonesian oil professionals from Java, Sumatera and other parts of Indonesia grew up in Balikpapan. Most of them have fond memories of Balikpapan.
Many sons and daughters of the first-generation Indonesian oil professionals follow the footsteps of their parents to work for oil companies in Balikpapan. There is a saying in Balikpapan whoever has drunk the water of Balikpapan will surely return. The writer of this article lived and worked for Unocal in Balikpapan from 1976 to 1980, and he has returned to visit this interesting place many times.
Subsea engineers are the crew that works with all the equipment and operations that are performed between the drill-floor and the seabed on floating offshore drilling rigs. The “SUBSEA” crew is employed by the drilling contractor and is an integral part of the offshore operations.
The subsea crew is responsible for implementing and maintaining the structures, tools, and equipment used in the underwater components of offshore oil and gas drilling and production operations.
The underwater environment presents unique challenges to subsea engineers, particularly deepwater operations where temperature, pressure, and corrosion test the durability of submerged equipment and tools. Most subsea engineering operations depend on automation and remote procedures to construct, maintain and repaircomponents beneath the surface of the water.
To understand what tasks the subsea team is required to undertake we first need to explore the key structures between the seabed and the drill-floor that connect the drilling unit to the wellbore. There’s also a lot of technology hiding beneath the surface of the water. Starting from the seabed and working our way up to the drill-floor we’ll look at the subsea components that help us bring drill cuttings and potentially trapped hydrocarbons safely to surface.
With the deepest-water offshore well ever to be drilled lying in 3,400 m (11,155 ft) of water, it’s easy to see why a team of specialists needs to be employed to oversee the operations that happen beneath the waves.
The subsea wellhead system is a pressure-containing vessel that provides a means to hang off and seal off casing used in drilling the well. The wellhead also provides a profile to latch the subsea blowout preventer (BOP) stack and drilling riser back to the floating drilling rig. In this way, access to the wellbore is secure in a pressure-controlled environment. The subsea wellhead system is located on the ocean floor and must be installed remotely with running tools and drill-pipe.
Figure 1 – Subsea wellhead
The subsea wellhead inside diameter (ID) is designed with a landing shoulder located in the bottom section of the wellhead body. Subsequent casing hangers land on the previous casing hanger installed. The casing is suspended from each casing-hanger top and accumulates on the primary landing shoulder located in the ID of the subsea wellhead. Each casing hanger is sealed off against the ID of the wellhead housing and the outside diameter (OD) of the hanger itself with a seal assembly that incorporates a true metal-to-metal seal. This seal assembly provides a pressure barrier between casing strings, which are suspended in the wellhead.
A standard subsea wellhead system will typically consist of the following:
Drilling guide base.
High-pressure wellhead housing.
Casing hangers (various sizes, depending on casing program).
Metal-to-metal annulus sealing assembly.
Bore protectors and wear bushings.
Running and test tools.
The drilling guide base provides a means for guiding and aligning the BOP onto the wellhead. Guidewires from the rig are attached to the guideposts of the base, and the wires are run subsea with the base to provide guidance from the rig down to the wellhead system.
Subsea Blowout Preventer (BOP)
There are two means to prevent an escape of high-pressure fluids or gases from the well when drilling for oil and gas.
The primary means is the hydrostatic pressure from the weighted up drilling mud and the second means is the blowout preventer. The BOP is literally the last line of defense in preventing a catastrophic event on the rig.
The BOP is an arrangement of valves, rams preventers, annular preventers, connectors, and control system that can be controlled from the surface to “shut-in” the well in the event of an impending blowout.
In addition to controlling the downhole pressure and the flow of oil and gas, blowout preventers are intended to prevent tubing, tools and drilling fluid from being blown out of the wellbore when a blowout threatens. Blowout preventers are critical to the safety of the crew, rig, and environment, and to the monitoring and maintenance of well integrity.
Figure 2 – A Subsea BOP
With the wellhead just above the mudline on the seafloor, there are four primary ways by which a BOP can be controlled. The possible means are:
Electrical Control Signal: sent from the surface through a control cable;
Acoustical Control Signal: sent from the surface based on a modulated/encoded pulse of sound transmitted by an underwater transducer;
ROV Intervention: remotely operated vehicles (ROVs) mechanically control valves and provide hydraulic pressure to the stack (via “hot stab” panels);
Deadman Switch / Auto Shear: fail-safe activation of selected BOPs during an emergency, and if the control, power and hydraulic lines have been severed.
Two control pods are provided on the BOP for redundancy. Electrical signal control of the pods is primary. Acoustical, ROV intervention and dead-man controls are secondary.
An emergency disconnect system, or EDS, disconnects the rig from the well in case of an emergency. The EDS is also intended to automatically trigger the deadman switch, which closes the BOP, kill and choke valves. The EDS may be a subsystem of the BOP stack’s control pods or separate.
Pumps on the rig normally deliver pressure to the blowout preventer stack through hydraulic lines. Hydraulic accumulators on the BOP stack enable closure of blowout preventers even if the BOP stack is disconnected from the rig. It is also possible to trigger the closing of BOPs automatically based on too high pressure or excessive flow.
The subsea team
The subsea team is responsible for all maintenance and testing of the BOP and its ancillary equipment. Function tests are carried out frequently throughout the drilling program, especially prior to running “the stack” from the surface, and also prior to drilling through expected reservoir formations.
The drilling crew and subsea team run coordinated tests from both the drill-floor and the backup system’s control panel within the accommodation unit. Every rig must have a BOP control panel at the driller’s station as well as one in a safe location away from the drill floor.
Figure 3 – A BOP control panel
The members of a subsea team are generally recruited with an electrical or mechanical trade base or engineering degree and they then go through extensive training programs to familiarize themselves with the subsea operations. Because of the skills required to be able to competently do their job these crew members don’t start working offshore as an unskilled laborer like many of the drilling crew members generally do. Subsea operations are a highly specialized field and as such, highly specialized teams are required to perform the tasks involved.
It is also one of the most highly regulated areas in the offshore drilling industry due to the fact that failures in the system can result in catastrophic events, such as the Deepwater Horizon disaster. Being the last line of defense in the event of a blowout, it is critical that all the subsea equipment can be reliably called upon to shut the well in during a well control emergency situation.
Because the BOP is such a critical part of the process safety systems offshore, since the Macondo blowout there have been strict regulatory requirements imposed on the industry to ensure the operators have clear programs in place to identify potential hazards when they drill, clear protocol for addressing those hazards, and strong procedures and risk-reduction strategies for all phases of activity, from well design and construction to operation, maintenance, and decommissioning.
Adhering to these regulations requires certification of all subsea equipment from an independent third party regarding the condition, operability, and suitability of the BOP equipment for the intended use and the operator must have all casing designs and cementing program/procedures certified by a professional engineer, verifying the casing design is appropriate for the purpose for which it is intended under expected wellbore conditions.
Third-party verification and inspection organizations work with subsea equipment, specifically BOP and regulatory compliance audits, well-control, and drilling equipment inspections, to ensure the highest levels of integrity within the subsea well control system prior to it being deployed.
Adjoining the top of the BOP and connecting with the bottom of the marine riser is the lower marine riser package.
Lower Marine Riser Package (LMRP)
The LMRP – Lower Marine Riser Package – is the upper section of a two-section subsea BOP stack consisting of the hydraulic connector, annular BOP, ball/flex joint, riser adapter, jumper hoses for the choke, kill and auxiliary lines and subsea control modules. The LMRP interfaces with the BOP stack.
Figure 4 – Subsea BOP control system
Blowout preventers must have completely redundant control systems on the BOP. These control systems are called pods and are designated Blue Pod and Yellow Pod in all systems, no matter which manufacturer. They can be found on the lower marine riser package and are extensively function tested prior to the deployment of the BOP.
There can be as many as six emergency systems in a BOP to operate critical functions in the case of the loss of the primary control system:
Emergency Disconnect Sequence (EDS) – In a case where a dynamically positioned rig has lost the station-keeping ability, the EDS is a one-button system that allows the wellbore to be secured by closing the shear rams. The hydraulic functions to the lower BOP are then vented and the LMRP is separated from the lower BOP by unlatching the connector. An over‐pull is preset on the riser tensioners and the LMRP lifts from the lower BOP. A riser recoil system prevents a slingshot effect. After the EDS button is activated, the sequence takes about 55 seconds maximum.
Acoustic systems – A limited number of emergency functions (typically shear rams and LMRP connector) can be operated from the rig using a hydrophone transmitting to transducers on the BOP. It is uncertain if these systems will work in a well-control situation where considerable noise is generated from flow in the wellbore.
Remote operated vehicles (ROVs) have pumps which can operate functions through a ‘hot stab’ plugged into a dedicated receptacle in the panel. The limitation of an ROV is the time to deploy from the rig to the seabed and the limited flow rate of their pumps.
Deadman systems will close the shear rams in the event all hydraulic and electric control is lost on the BOP. This would typically only happen if the riser string parted. In deepwater if the riser is lost, then the hydrostatic pressure of the drilling mud, which is needed to contain wellbore pressure, would be reduced as it is replaced by seawater. Closing the shear rams secures the well.
Automatic Disconnect System (ADS) closes the shear rams when the lower flex joint reaches a preset angle.
Autoshear closes the shear rams in the event the LMRP is unintentionally disconnected.
The BOP and LMRP are run subsea using the “marine drilling riser” after the top part of the well has been drilled, the conductor casing has been cemented and the wellhead has been landed.
Marine Drilling Riser and Marine Riser Tensioner
A marine drilling riser is a conduit that provides a temporary extension of the subsea oil well to the drilling rig. The “riser” has a large diameter, low-pressure main tube with external auxiliary lines that include high-pressure choke and kill lines for circulating fluids to the subsea blowout preventer (BOP), and usually power and control lines for the BOP.
Figure 5 – A drilling riser
When used in water depths greater than about 20 meters, the marine drilling riser has to be tensioned to maintain stability.
A marine riser tensioner located on the drilling platform provides a near-constant tension force adequate to maintain the stability of the riser in the offshore environment. The level of tension required is related to the weight of the riser equipment, the buoyancy of the riser, the forces from waves and currents, the weight of the internal fluids, and an adequate allowance for equipment failures.
The marine riser is kept in tension with large pistons operated with an air/oil system at pressures up to 3,000 psi. The riser may be connected via a tensioning ring to wire rope, which is reeved over sheaves on the pistons, or the pistons may be connected directly to the riser tensioner ring.
Figure 6 – Riser Tensioner
Once the BOP stack has been successfully run to the seabed with the marine riser and latched onto the wellhead, it will undergo another series of function tests to determine its operability under water-depth conditions.
The density of water can cause problems that can increase dramatically with depth. The hydrostatic pressure at the surface is 14.6 psi (pounds per square inch) but this increases by this amount for every 10 meters of water depth. For a deepwater well that has the wellhead on the seabed in 2,000 meters of water, you would expect to find the hydrostatic pressure acting on the BOP to be around 3,000 psi.
When you also consider the water temperature to be close to 0° Celsius then you can imagine the type of hostile environment these safety-critical components have to function under. Making equipment that can operate under these conditions is the job of the manufacturer’s design engineers, and making sure they work and keeping them well maintained is the responsibility of the subsea engineers onboard the rig.
Troubleshooting difficult BOP issues generally require collaboration between the design engineers onshore and the subsea engineers and the maintenance crew involved in the offshore operations. When subsea function tests fail then the entire BOP stack and riser string has to be pulled up to the surface so physical examination of the unit can take place.
This is a very time-consuming and costly exercise and therefore making sure everything is functioning 100% before running it down to the seabed is imperative. As anyone who has ever worked offshore knows, it’s all-too-common for BOP’s to fail function tests and this is why such strict regulatory conditions have been placed on the subsea components used for the drilling of offshore wells, especially in deepwater and ultra-deepwater wells. Once the BOP has been successfully tested it’s time to drill ahead!
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.
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.
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.
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
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.
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 email@example.com.
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 firstname.lastname@example.org.
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.
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.
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:
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.
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).
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%.