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The Amazing Rise of Medco Energi

The Belanak FPSO

This year, Medco Energi is celebrating its forty years of continuing successes and presence as one of the leading energy companies in Indonesia and South East Asia.

Medco Energi International became a public company in 1994, and today it operates in eight countries.

It has interests in oil and gas exploration and production, geothermal power generation, gas distribution and trading, and mining.

The Beginning of Medco

Medco Energi has come a long way in a short time since it started as an oil drilling service company in 1980, Meta Epsi Pribumi Drilling Company (MEDCO).

Founded by Mr. Arifin Panigoro, Medco Energi was a visionary and a trailblazer ever since its beginning.

The Acquisition of Stanvac Indonesia

The first breaks that made Medco became big and successful were the acquisition of Stanvac’s oil and gas assets in South Sumatera in 1995, and the following discovery of the big oil fields in Kaji and Semoga in the Rimau Block, in South Sumatera.

Stanvac Indonesia, set up by Standard Oil of New Jersey in 1912, was one of the oldest and biggest oil companies in Indonesia during the Dutch colonial era.  

The Acquisition of ConocoPhillip’s Interest in West Natuna Sea Block B PSC

The Acquisition of ConocoPhillip’s Interest in West Natuna Sea Block B

Medco Energi further expanded in 2016 when it purchased ConocoPhillips’s 40% interest in the West Natuna Sea Block B and took over the operatorship of the block.

This acquisition added substantial gas and liquids reserves and increased Medco Energi’s daily production by over 35%.

The block is in approximately 300 feet of water and had 11 offshore platforms, four producing subsea fields, and one FPSO – the Belanak FPSO – in addition to two dedicated floating storage and offloading vessels.

The Belanak FPSO was described as one of the most complex FPSO in the world. It was the first offshore liquefied petroleum gas (LPG) facility on a floating vessel in the Asia Pacific region when it was commissioned in 2004.

The fields include the Belanak field, South Belut field, Hiu field, Kerisi field, North Belut field and Bawal field.

The produced natural gas is sold to Singapore and Malaysia through a 654 KM long 28 inch gas pipeline.

Medco Energi also assumed the operatorship of the Onshore Receiving Facility in Singapore following the acquisition.

Acquisition of Ophir Energy

Medco Energi Internasional continued to expand by acquiring Ophir Energy, a London-based independent in 2019.

The acquisition of Ophir Energy increased Medco Energi’s daily oil and gas production by 29% to 110,000 BOE per day.

By taking over the operatorship of Ophir Energy’s offshore Bualuang field in Thailand, Medco Energi became a leading regional oil and gas player in South East Asia.

Acquisition of Corridor PSC and Transasia Pipeline

On March 3, 2022, Medco Energi acquired the entire remaining assets of ConocoPhillips in Indonesia..

Through this acquisition, Medco Energi is now the operator of the Corridor block with 54% interest and has 35% ownership of Transasia Pipeline Company.

The Corridor PSC has two producing oil fields and seven producing gas fields located onshore South Sumatra, Indonesia, adjacent to MedcoEnergi’s existing operations in South Sumatra. The Corridor is the second-largest gas-producing block in Indonesia.

Through Transasia, MedcoEnergi now owns a minority interest in the gas pipeline network supplying Central Sumatera, Batam, and Singapore customers.

Epilogue

With this latest acquisition, Medco Energi is now one of the largest oil and gas operators in Indonesia.

Besides acquiring producing assets, Medco Energi is also active in exploring new oil and gas reserves.

Its 2020 exploration drilling campaign in the South Natuna Sea Block B was 100% successful. It tested hydrocarbon in all the four exploration wells it drilled. The wells are Bronang-2, Kaci-2, Terubuk-5, and West Belut-1.

Medco Energi is planning to develop these fields.

As Medco Energi celebrates its more than 40 years of progress, with its solid management team, it certainly will continue to march toward an even brighter future.

Top Management Team of Medco Energi

Here is the top management team of Medco Energi.

Muhammad Lutfi – President Commissioner

Hilmi Panigoro – President Director

Roberto Lorato – Chief Executive Officer

Anthony R Mathias – Chief Financial Officer

Ronald Gunawan – Chief Operating Officer

Amri Siahaan – Chief Human Capital and Business Support Officer

Myrta Sri Utami – VP Corporate Planning & IR

Siendy K Wisandana – Head of Legal Counsel and Secretary

As a final note, Dr. Arifin Panigoro, the man who started it all and the founder of Medco group of companies died on 27 February 2022 at age of 76.

Written by Jamin Djuang – Chief Learning Officer of LDI Training and author of the published book The Story of Oil and Gas: How Oil and Gas are Explored, Drilled and Produced.

The Old Dutch Oil Companies in Indonesia

The Balikpapan Refinery – Photo courtesy of Tropenmuseum

Since the early 1900s, with oil discoveries in Sumatera in 1885, Java in 1887, and Kalimantan in 1891, Indonesia has been recognized as an important oil-producing country outside America.

By 1900 there were already 18 oil companies operating in Indonesia. It is interesting to note that only companies registered in Nederland and managed by the Dutch could operate in Indonesia at that time.  The reason for this was up until World War II, Indonesia was under the administration of the Netherlands East Indies (NEI).

These old Dutch oil companies played important roles in putting Indonesia on the world map as a significant producer of crude oil and fuels. They discovered and developed many oilfields in Indonesia, and even built refineries in Sumatera, Java, and Borneo. By 1938, oil production had reached 140,000 barrels per day.

Oil well drilling in Pangkalan Susu, Sumatera, in 1916 by KNPM.

By 1945, the year when Indonesia declared its independence, due to acquisitions and mergers, the number of oil companies had reduced to just four: BPM (Bataafsche Petroleum Maatschappij), NIAM (Nederlands Indische Aardolie Maatschappij), STANVAC, and CALTEX.

Stanvac and Caltex which were owned by their American parent companies started as Dutch-registered companies.

After 1965, when Pertamina acquired BPM, all the oil companies with Dutch names no longer existed. Nevertheless, their names appeared in many old and new articles and are often cited in research papers.

Since the names of the old Dutch oil companies in Indonesia consisted of long Dutch words, they were often written in their acronyms.

Here is the glossary of the acronyms of some of the old Dutch oil companies that operated in Indonesia in the past. 

BPM – Bataafsche Petroleum Maatschappij

DPM – Doordsche Petroleum Maatschappij

KNPM – Koninklijke Nederlandsche Petroleum Maatschappij

NIAM – Nederlands Indische Aardolie Maatschappij

SPPM – Sumatera Palembang Petroleum Maatschappij

MEPM – Muara Enim Petroleum Maatschappij

NNGPM – Nederlandsche Nieuw Guinea Petroleum Maatschappij

SVPM – Standard Vacuum Petroleum Maatstchappij

SVTM – Standard Vacuum Tankvaart Maatschappij

NKPM – Nederlandsche Koloniale Petroleum Maatschappij

NPPM – Nederlandsche Pacific Petroleum Maatschappij 

SMOB – Steenkolen Maatschappij Oost Borneo

NIIHM – Nederlandch Indisch Industrie en Handel Maatschappij

If you are interested in the history of oil in Indonesia, please read The Three Big Oil Companies in Indonesia before 1945.  

This article is written by Jamin Djuang – Chief Learning Officer of LDI Training and author of The Story of Oil and Gas: How Oil and Gas Are Explored, Drilled and Produced.

The Three Big Oil Companies in Indonesia before 1945

Sungei Gerong Refinery in South Sumatera in 1926

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
  • CALTEX

Here are the amazing stories of these three big oil companies operating in Indonesia before 1945.


BPM

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

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

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.

Epilogue

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.

WRITTEN BY

Jamin Djuang – Chief Learning Officer of LDI Training and author of The Story of Oil and Gas: How Oil and Gas Are Explored, Drilled and Produced


 

Geothermal Drilling by The Government of Indonesia

The Indonesia government will drill geothermal exploration wells in 20 geothermal work areas in Indonesia beginning in 2020 until 2024, according to Ida Nuryatin Finahari, Director of Geothermal in the Ministry of Energy and Mineral Resources.

The purpose of this initiative is to gather information on the geothermal potentials in each work area and to pass this information to potential investors.

The Indonesia government hopes this four year project will stimulate the interests of investors and accelerate the development of geothermal energy in Indonesia.

Here are the twenty geothermal work area where the government of Indonesia will drill exploration wells.

  • Lokop in Aceh
  • Sipoholon Ria Ria in North Sumatera
  • Sajau in North Kalimantan
  • Bora Pulu in Central Sulawesi
  • Marana in Central Sulawesi
  • Bittuang in South Sulawesi
  • Limbong in South Sulawesi
  • Jailolo in North Maluku
  • Banda Baru in Maluku
  • Nage in NTT (Nusa Tenggara Timur)
  • Maritaing in NTT
  • Sembalun in NTB (Nusa Tenggara Barat)
  • Gunung Batur – Kintamani in Bali
  • Guci in Central Java
  • Cisolok Cisukarame in West Java
  • Gunung Galunggung in West Java
  • Gunung Tampomas in West Java
  • Gunung Ciremai in West Java
  • Gunung Papandayan in West Java
  • Gunung Endut in Banten

If you want to understand how your geothermal reservoirs work and how to optimize them, Dr. Roland N. Horne will teach an online Geothermal Reservoir Engineering course on 6-9 October 2020.

The Famous Duri Oil Field

Duri to Dumai Road Construction in 1958

Eighty years ago, CALTEX discovered the huge Duri oil field in the Rokan block in Riau, Sumatera.

Oil was found at a shallow depth of 400 feet when CALTEX began drilling its exploration wells in 1941. However, the exploration drilling was interrupted due to the onset of the World War 2. After the war ended, CALTEX managed to obtain the approval from the newly formed government of Indonesia to operate in the Rokan block under a work contract scheme. Eventually, oil production from the Duri field began in February 1954.

The giant Duri field – 10 km wide and 18 km long – is one of the many oil fields discovered in the Rokan block. Minas is another giant oil field discovered in this block.

Oil production peaked at 65,000 BOPD in the 1960s.

Due to the high viscosity of the low gravity oil, to enhance the production, the steam injection was introduced in 1985.

The Duri steam flood project was so successful that it became one of the largest and the best steam floods in the world.

Thanks to the successful steam injection, Duri oil production increased significantly to 185,000 BOPD.

After 30 years of the steam flood, the production had declined to about 50,000 BOPD by 2017.

With more than 2.6 billion barrels of cumulative oil produced, the giant Duri field is still producing today.

Chevron will hand over the operatorship of the Duri field and the Rokan block to Pertamina in August 2021.

Terms Related To Decarbonization

 

pexels-pixabay-259280

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

Carbon footprint is the amount of carbon dioxide emissions created by a person or industry.

Carbon Tax

Carbon tax is tax paid by businesses and industries that produce carbon dioxide through their operations.

Carbon Neutrality

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 Fuels

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.

DAC

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

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.

GHG

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).

Hydrogen Economy

The hydrogen economy is a situation where hydrogen is used as the major carrier of energy.  

Renewable 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.

RNG

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.

 

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

 

The West Seno Oil Field

Picture2
From top left clockwise: The tension leg platform of West Seno (TLP-A), a drilling support vessel, and the floating production unit (FPU).

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.

The field is currently operated by Chevron.

History of the Giant Attaka Oilfield

Pres. Soeharto di Santan

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.

If you like to read more about the Attaka field here is The Ten Interesting Facts About Attaka.

WRITTEN BY

Jamin Djuang – Chief Learning Officer of LDI Training and author of The Story of Oil and Gas: How Oil and Gas Are Explored, Drilled and Produced

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The New Seven SUPERMAJOR Oil Companies

The Seven SUPERMAJORS (2)

 

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:

  1. Anglo-Persian Oil Company (now BP)
  2. Royal Dutch Shell
  3. Gulf Oil (Acquired by Chevron in 1985)
  4. Standard Oil of California (now Chevron)
  5. Standard Oil of New Jersey (now ExxonMobil)
  6. Standard Oil of New York – Socony ( later became Mobil Oil and then ExxonMobil)
  7. 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

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

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 S.A.

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

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.

 

WRITTEN BY

Jamin Djuang – Chief Learning Officer of LDI Training and author of The Story of Oil and Gas: How Oil and Gas Are Explored, Drilled and Produced

 

How Are LPG and LNG Different?

Spherical tanks - shutterstock_674277817
Spherical tanks

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
  1. Both LPG and LNG are by-products of crude oil and natural gas.
  2. They are both in liquefied form making them easier for storage and transportation.
  3. They are commonly used as fuel.
  4. They are considered as clean fuel as they leave no smoke or soot.
Differences between LPG and LNG
  1. LPG consists mainly of propane and butane whereas LNG consists mainly of methane.
  2. LPG has a much higher heating value than LNG, and therefore it is also used to power cars and even buses.
  3. LPG is liquefied by increasing its pressure whereas LNG is liquefied by lowering its temperature.
  4. LPG is usually distributed to consumers in pressurized cylinders whereas LNG is gasified before it is transmitted to end-users by pipelines.
  5. 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.

The article is written by Jamin Djuang, the author of The Story Of Oil and Gas: How Oil and Gas are Explored, Drilled and Produced.

 

The First Oil Discoveries in Indonesia

Mathilda B-1 – The first oil discovery well located in Balikpapan, East Kalimantan. Photo courtesy of Chaz Tumbelaka,

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.

The article is written by Jamin Djuang, the author of The Story Of Oil and Gas: How Oil and Gas are Explored, Drilled and Produced.

 

 

Eight Largest Oil Lifting Terminals in Indonesia

oil storage tanks
Oil Storage Tanks

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.

  1. 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.

  1. 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

  1. 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.

  1. ARDJUNA 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.

  1. 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.

  1. RU PP7

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.

  1. DUMAI TERMINAL

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.

  1. 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.

This article is written by Jamin Djuang based on the information published by SKK Migas. He is the founder of LDI Training which provides oil and gas training and the published author of The Story of Oil and Gas.

 

Performance of Oil Industry of Indonesia in 2019

IMG_4902
Power Plant at North Jakarta, Indonesia

 

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:

  • ExxonMobil Cepu
  • Chevron Indonesia
  • Pertamina EP
  • 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
  • ConocoPhillips Grissik

The 15 largest natural gas producers in 2019

Here are the 15 largest gas producers in Indonesia in 2019:

  • BP Berau
  • ConocoPhillips Grissik
  • Pertamina EP
  • 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
  • Husky-CNOOC Madura
  • Mubadala Petroleum Indonesia
  • PHE Offshore North West Java

 

The SKK Migas

The SKK Migas of 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)
  • Facility Maintenance
  • Project Progress
  • 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.

 

 

The SKK Migas of Indonesia

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:

  1. SKK Migas Sumatera Bagian Utara located in Pekanbaru
  2. SKK Migas Sumatera Bagian Selatan located in Palembang
  3. SKK Migas Kalimantan and Sulawesi located in Balikpapan
  4. SKK Migas Jawa, Bali, Madura dan Nusa Tenggara located in Surabaya
  5. 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.

About Guy Allinson

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.

Here are the testimonials from delegates who have attended Petroleum Economics, Risk and Fiscal Analysis course presented by Guy Allinson.

This was a fantastic course.  I was worried that the content would be dry and boring but it was the opposite, very interesting.  The notes are great and will make a very good future reference as will the exercise spreadsheets.  Thanks very much.”

“This is an excellent short course for anyone interested in understanding the basics of petroleum economics. The presenter is highly knowledgeable of the subject and excellent in delivering the content.”

“I was very pleased with the content, delivery, pace of delivery and accessibility and style of presentation. Simple to understand, supported by working examples and solutions to work at our own pace. An invaluable course.”

Note:

Mr. Guy Allinson will conduct his flagship course – Petroleum Economics, Risk and Fiscal Analysis on August 17-19, 2020 in Singapore.

For more information about Guy Allinson’s Petroleum Economics, Risk and Fiscal Analysis course, please contact LDI Training at lditrain@singnet.com.sg.

 

The Larantuka Tidal Power Plant in Indonesia

sky-sunset-sun-twilight-46169

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:

  1. Sihwa Lake Tidal Power Station, South Korea – 254 MW
  2. La Rance Tidal Power Plant, France – 240 MW
  3.  Swansea Bay Tidal Lagoon, UK – 240 MW
  4.  MeyGen Tidal Energy Project, Scotland – 86 MW
  5.  Annapolis Royal Generating Station, Canada – 20 MW

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

 

 

The Masela LNG Plant Location – Yamdena Island

Masela LNG - 75341025_2575149926055521_9059067100873621504_n

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.

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

This information is adapted from the Facebook post of Mr. Rinto Pudyantoro.

The Giant Carcara and the Pre-Salt Basin

A semisubmersible drilling rig

 

The Giant Carcara Oil Field

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.

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

Balikpapan – The Most Interesting Oil Town of Indonesia

City of Balikpapan - Photo by Uut Minhudan
The city of Balikpapan – Photo courtesy of Uut Minhudan

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.

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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

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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.

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

The Job of a Subsea Engineer in Deepwater Drilling

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.

Subsea 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 repair components 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.

Subsea Wellhead

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.

subsea wellhead

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.
  • Low-pressure housing.
  • 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.

subsea blowout preventer - BOP

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.

Subsea BOP control panel

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.

subsea BOP control system

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:

  1. 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.
  2. 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.
  3. 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.
  4. 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.
  5. Automatic Disconnect System (ADS) closes the shear rams when the lower flex joint reaches a preset angle.
  6. 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.

Drilling riser

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.

Riser tensioner

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!

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