In 2018, daily world oil production amounts to around 92 million barrels per day, increasing slightly 0.7% from previous year.
Here are the world top ten oil producers according to the US Energy Information Administration (EIA):
USA – 15.6 Million barrels of oil per day
Saudi Arabia – 12.1 Million BOPD
Russia – 11.2 Million BOPD
Canada – 5.0 Million BOPD
China – 4.8 Million BOPD
Iran – 4.7 Million BOPD
Iraq – 4.5 Million BOPD
UAE – 3.7 Million BOPD
Brazil – 3.4 Million BOPD
Kuwait – 2.9 Million BOPD
The USA is the largest oil producer in the world in 2017. The production of crude oil in the USA is expected to increase into 2019. The USA is also the world’s largest consumer of oil. Its daily oil consumption in 2019 is projected to increase by 340,000 barrels to 20.65 million barrels, according to EIA.
Saudi Arabia, on the other hand, is the largest oil exporting country. As the most well-known and influential oil producer, it has 260 billion barrels of oil reserves, which is about 22% of the world’s oil reserves.
Unconventional oil and gas resources are resources where the oil and gas are difficult to recover or produce due to either the very low permeability of the formation or the very low mobility of the hydrocarbons. Special techniques and processes are required to recover these types of resources.
The three common types of unconventional hydrocarbon resources are:
Shale oil and shale gas.
The world’s largest oil sand deposit is the Athabasca oil sands located in Alberta, Canada. Oil sands are a mixture of semi-solid bitumen or asphalt and sand, and they are buried not far from the earth surface. Commercial production of the Athabasca oil sands began in 1967 and the current production is at around two million BOPD. Many major oil companies are involved in the production of these oil sands.
Two methods are used to recover the oil from the oil sands. They are open-pit mining and the SAGD method.
Open-pit mining method is commonly used to extract the oil from oil sands located near the earth surface. After the tar sand is mined, it is mixed with hot water and agitated to form a slurry. The released bitumen droplets will float to the surface with the help of the tiny air bubbles which attach to the bitumen droplets. The bitumen will then be skimmed off and further processed to remove the remaining water and solids. Lastly, the bitumen will be upgraded to synthetic crude oil. About 75% of the bitumen can be extracted from the tar sands.
For tar sands located at a deeper depth, in-situ production methods are used, such as steam injection, fire flooding, and chemical injection. A popular steam injection method is the SAGD method. In SAGD, steam-assisted gravity drainage, a pair of horizontal wells are drilled into the oil sand, one at the bottom of the formation and another about 5 meters above it. High-pressure steam is injected into the sand from the upper well to heat the heavy oil and thus reduce its viscosity. With the increase in mobility, the oil drains into the lower well where it is pumped to the surface. SAGD is the preferred method for extracting the oil sands due to environmental concerns.
Shale Oil and Shale Gas
Another currently popular unconventional hydrocarbon resource is shale oil and shale gas. Shale oil is oil that is trapped inside the tight shale. Shale is a hard sedimentary rock
composed of clay that is rich in organic materials. Since tight shale has very low permeability, hydraulic fracturing method is used to extract the oil. In hydraulic fracturing, a large quantity of viscous fluid carrying sand is pumped into the well under high pressure to fracture the shale, creating pathways and highways for the oil to flow out of the shale and into the wellbore.
Most shale oil production takes place in the US and the daily production of shale oil reaches six million BOPD in 2017. A large quantity of gas is also produced from shale. According to the US Energy Information Agency (EIA), gas production from shale in the US in 2016 was 15.8 trillion cubic feet (TCF).
The most well-known and top shale oil plays in the US are The Permian Basin and Eagle Ford Shale in Texas, and Bakken Shale in North Dakota.
Coal Bed Methane
Coalbed methane (CBM) is an unconventional resource of methane gas. It is being produced successfully in some parts of the world, notably in Australia and Canada. Since coal is formed from organic materials, methane gas (CH4) is generated during the formation of coal. The generated methane is adsorbed in the coal matrix, fractures and coal seams called cleats. Cleats are horizontal and vertical fractures formed naturally in coal.
Wells are needed to produce the methane gas. Since underground coal is usually saturated with water, methane is extracted by first removing the water from the coal by pumping out the water. As the water is pumped out from the well, the coal pore pressure will decrease causing the adsorbed gas to be liberated from the coal and then flow to the wellbore. Due to the low permeability of the coal matrix, the coal must have a sufficient network of fractures and cleats to produce the methane gas at economic production rates.
Since 1966 when Indonesia began offering production sharing contracts (PSC) for international companies to explore and produce oil and gas in Indonesia, many giant and super-giant oil and gas fields were discovered.
Giant fields are those with estimated ultimate recoverable reserves (EUR) of 500 million barrels of oil or gas equivalent (MMBOE) and super giant oil fields are those holding an equivalent of 5.5 billion barrels of oil reserves.
Here are the ten giant offshore oil and gas fields in Indonesia discovered between 1966 and 2000.
1. Abadi Field
Abadi is a giant gas field discovered by Inpex in 2000 in the Masela contract area in the Arafura Sea. The Abadi field has an estimated ultimate recovery (EUR) of 768 MMBOE and it is located 93 miles offshore from the province of Maluku in the eastern part of Indonesia.
Originally the field would be developed using subsea production system and a floating LNG (FLNG) facility. The plan now is to develop the field based on an onshore LNG development concept.
Inpex in partnership with Royal Dutch Shell is currently conducting preliminary front-end engineering design (Pre-FEED) studies for the Abadi field development based on an onshore concept. The LNG project will produce 9.5 MM tons of LNG annually.
When developed, the Abadi field may become the biggest deepwater gas project in Indonesia. It is expected to produce more than 1 billion SCF of gas per day and 20,000 barrels of condensate per day for 24 years.
2. Gula Field
The Gula field is an offshore gas field discovered by Unocal in its Ganal production sharing contract area located in the Kalimantan strait in 2000. With an EUR of 545 MMBOE, it is a giant gas field.
The Gula field, along with the Gendalo discovery and the Gada discovery, is one of the many discoveries made by Unocal in the deep-water area between Kalimantan and Sulawesi. These discoveries confirm that the Central Delta play contains world-class gas resources.
The Gula field is currently an undeveloped discovered resource.
3. Ubadari Field
Ubadari is a giant offshore gas field discovered in 1997. The Ubadari field has an EUR of 500 MMBOE and it is located at Bintuni Bay in West Irian province.
The Ubadari field will supply its gas to Tangguh LNG plant when the Tangguh LNG Train-3 project is completed in 2020. The Tangguh expansion aims at meeting the ever-increasing demand for energy in Indonesia and accelerating the development of West Irian.
PLN, Indonesia’s electricity company, has signed a sales and purchase agreement to buy up to 1.5 million tons of LNG produced by Tangguh LNG plant annually.
Tangguh LNG plant is scheduled to process the gas produced from the six gas fields located at Bintuni Bay: Vorwata, Wiriagar Deep, Ofaweri, Roabiba, Ubadari, and Wos.
4. Vorwata Field
Vorwata is an offshore giant gas field located in Bintuni Bay in West Irian Province. The Vorwata field, with EUR of 1833 MMBOE, was discovered by ARCO in the Berau block in 1997. BP became the operator of Vorwata field after it acquired ARCO.
Gas production from Vorwata field started in 2009. The field is capable of producing more than 1 BCF of gas per day and the gas is processed into LNG by the Tangguh LNG plant.
5. West Seno Field
The West Seno field is a deepwater oil field discovered by Unocal in 1996. Having an EUR of 553 MMBOE, it is a giant oil field and is currently operated by Chevron.
Lying in water depths of 2,400 to 3,400 feet, the West Seno field is Indonesia’s first deepwater development. It lies in the Makassar Strait PSC off Kalimantan on the continental slope of the northern Mahakam Delta.
The oil is produced using two tension leg platforms and a floating production unit, tied back by two export pipelines to onshore infrastructure.
6. Peciko Field
Peciko is a gas field located offshore in the Mahakam Delta in East Kalimantan. The field was discovered by Total with INPEX as its partner in 1991. The Peciko is a giant gas field having EUR of 1180 MMBOE.
Of all the producing fields in the Mahakam River delta, the Peciko field is unique in that its reservoir trap is both structural and stratigraphic.
The Peciko wells are highly productive having an average well productivity of 80 MMSCF of gas per day. Total daily gas production exceeded 1 BSCF during its peak. A substantial quantity of condensate is being produced along with the gas.
7. Tunu Field
The Tunu field is a supergiant gas field discovered by Total along with Inpex as its partner in 1977. It is located at the shallow waters along the outer limits of the delta offshore Mahakam Block in East Kalimantan. It has an EUR of 4378 MMBOE.
Started in 1978, the Tunu field produces gas and condensate having negligible CO2 or H2S, with the main productive reservoirs lying at depths from 2,200 to 4,900 meters.
Developing the large Tunu field is challenging and producing the gas requires drilling a large number of wells. The field has a large surface area of 20 Km wide and 75 Km long and it is located at the wetland of Mahakam swamp.
8. East Natuna Field
The offshore East Natuna gas field was discovered by AGIP in 1970. It is located 140 miles northeast of the Natuna Islands, Indonesia’s northernmost territory. It is a super-giant gas field with estimated recoverable reserves of 46 trillion cubic feet (TCF) of gas.
There were serious studies done and attempts made by Exxon-Mobil and Pertamina to develop this field.
The field is currently undeveloped due to its very high CO2 content of 71%. To produce the gas will require removing the CO2 from the gas and injecting it back into the reservoir. Production can be commercially viable when the price of oil is above $100 per barrel.
9. Attaka Field
The Attaka field is a giant oil and gas field discovered by Unocal in partnership with Inpex in 1970. Chevron became the field operator after it acquired Unocal in 2005. Having an EUR of 1000 MMBOE, the Attaka field is located 12 miles from the shore of East Kalimantan.
The huge Attaka reservoir, formed in the very prolific Kutei basin, has an areal closure of 8000 acres. Due to its large areal extent, originally the oil and gas were produced from more than 100 wells located in 6 remote wellhead platforms.
Ten years later, five subsea wells were completed in 1981-1984 to produce the untapped oil accumulation in areas out of reach of the existing remote platforms. These are the first subsea completions in Indonesia.
Attaka field daily oil production was 110,000 BOPD at its peak and gas production was 150 MMSCFPD. Now the Attaka field is quite depleted.
10. Ardjuna Field
The Ardjuna Field is a giant oil field having an EUR of 698 MMBOE. This is the first offshore giant field discovered since the birth of the Indonesian PSC system in 1966.
The Ardjuna field was discovered by ARCO in the Offshore North West Java (ONWJ) production sharing contract area in 1969. Subsequently, it was operated by BP when it acquired ARCO in 2000. Now the field is operated by Pertamina Hulu Energy ONWJ Ltd.
Interesting facts about the Ardjuna field include the drilling of the first horizontal well in Indonesia in 1985 and supplying gas to PLN’s power plant in Muara Karang in Jakarta in 1993.
Pertamina’s refinery in Cilacap began using crude oil from Ardjuna field in 1986.
In the last decade, there has been an important breakthrough in how petroleum engineers and geoscientists obtained oil and gas reservoir rock properties.
Traditionally, reservoir rock properties or petrophysical properties such as porosity, pore size distribution, effective and relative permeability, capillary pressure, water saturation and other reservoir parameters are determined from Special Core Analysis (SCAL), electric logs and well pressure transient tests. In recent years, a new method in determining rock properties using Digital Rock Physics (DRP) has gained serious attention from petroleum engineers, petro-physicists and geoscientists.
What is digital rock physics? Digital rock physics is also referred to as digital core analysis. In this measurement method, high-resolution digital images of the rock pores and mineral grains of selected reservoir core samples are made and analyzed. These images are usually 3D digital X-ray micro-tomographic images. The rock properties are then determined using numerical simulation at the pore scale.
The significant benefit of this new DRP technology is now a large number of complex reservoir parameters can be determined faster and more accurately than the traditional laboratory measurements or well testing methods.
Using the DRP technology to determine the rock properties, oil and gas companies can now analyze their reservoir capacity and performance more accurately and sooner during the field evaluation and development phase. This, in turn, allows them to develop and manage their reservoirs more efficiently and economically.
Source – Digital Rock Physics for Fast and Accurate Special Core Analysis in Carbonates – A Chapter in New Technologies in the Oil and Gas Industry – By Mohammed Zubair Kalam
This gas handling, conditioning and processing course is designed and presented by Dr Maurice Stewart to teach you how to design, select, specify, install, test and trouble-shoot your gas processing facilities.
This gas handling, conditioning and processing course has been attended by thousands of oil and gas professionals since Dr Maurice Stewart began teaching it more than 20 years ago. Dr Stewart is a co-author of a widely acclaimed “Surface Production Operations: Design of Gas Handling Facilities” along with Ken Arnold.
By attending this course, participants will:
1. Know the important parameters in designing, selecting, installing, operating and trouble-shooting gas handling, conditioning and processing facilities.
2. Understand the uncertainties and assumptions inherent in designing and operating the equipment in these systems and the limitations, advantages and disadvantages associated with their use.
3. Learn how to size, select, specify, operate, maintain, test and trouble-shoot surface equipment used with the handling, conditioning and processing of natural gas and associated liquids such as separators, heat exchangers, absorption and fractionation systems, dehydration systems, refrigeration, low temperature separation units, JT plants and compression systems.
4. Know how to evaluate and choose the correct process for a given situation.
In this 5-day course, Dr Maurice Stewart will cover the following topics:
• Fluid properties, basic gas laws and phase behaviour
• Well Configurations, surface safety systems (SSS) and emergency support systems (ESS)
• Gas Processing systems, selection and planning
• Water-hydrocarbon phase behaviour, hydrate formation prevention and inhibition
• Heat transfer theory and process heat duty
• Heat exchangers: configurations, selection and sizing
• Gas-liquid separation and factors affecting separation
• Types of separators and scrubbers, and their construction
• Gas-liquid separators and sizing
• Liquid-liquid separators and sizing
• Three phase separator sizing
• Pressure vessels: the internals, mechanical design and safety factors
• Separator operating problems and practical solutions
• Gas compression theory, compression ratio and number of stages
• Compressor selection: centrifugal compressors vs. reciprocating compressors
• Vapor recovery units, screw compressors and vane compressors
• Compression station design and safety systems
• Performance curves for reciprocating compressors
• Absorption process and absorbers
• Adsorption process and adsorbers
• Glycol gas dehydration unit design and operation
• Glycol unit operating variables and trouble shooting
• Glycol selection and glycol regeneration
• Acid gas sweetening processes and selection
• Fractionation, refrigeration plants, expander plants and J-T plants
• Process control and safety systems
Participants will receive the following course materials:
1. The 3rd Edition of Volume 2 of the widely acclaimed “Surface Production Operations: Design of Gas Handling Facilities” written by Ken Arnold and Dr Maurice Stewart. This textbook continues to be the standard for industry and has been used by thousands since its first printing over fifteen years ago.
2. A comprehensive set of lecture notes for after course reading and reference
3. An extensive set of practical in-class “case study” exercises developed by Dr Stewart that will be used to emphasize the design and “trouble-shooting” pitfalls often encountered in the industry.
Who Should Attend
• Facility engineers, production engineers, design and construction engineers, team leaders, operations engineers, maintenance team leaders/engineers and other personnel who are or will be responsible for the designing, selecting, sizing, specifying, installing, testing, operating and maintaining gas handling facilities, gas plant facilities and gas pipelines.
• Experienced professionals who want to review or broaden their understanding of gas handling, conditioning and processing facilities and gas pipeline operation and maintenance.
• Professionals with little to moderate experience with the handling or processing of natural gas and associated liquids.
If you like to receive a pdf file of this course outline, please contact us.
Course date: November 19-23, 2018
Dr Maurice Stewart, PE, CSP, is a Registered Professional Engineer and Certified Safety Professional with over 40 years of experience in international consulting, trouble-shooting oil, water and gas processing facilities; and leading safety audits, hazards reviews and risk assessments.
He is internationally respected for his teaching excellence and series of widely acclaimed textbooks in the areas of designing, selecting, specifying, installing, operating and trouble-shooting:
Oil and water handling facilities
Gas handling, conditioning and processing facilities
Facility piping and pipeline systems
Gas dehydration and sweetening facilities
Pumps, compressors and drivers
Instrumentation, process control and safety systems
Oil and gas measuring and metering systems
Dr Stewart is the author of several new textbooks related to oil and gas processing facilities; and he is one of the co-authors of the SPE Petroleum Engineering Handbook. He has authored and co-authored over 90 technical papers and contributed to numerous conferences as a keynote speaker. Dr Stewart has taught over 60,000 professionals from more than 100 oil and gas related companies in 90 countries.
Dr Stewart serves on numerous international committees responsible for developing or revising industry Codes, Standards and Recommended Practices for such organizations as ANSI, API, ASME, ISA, NACE and SPE. He is currently serving on the following American Petroleum Institute (API) committees: API RP 14C, RP 14E, RP 14F, RP 14G, RP 14J, RP 500 and RP 75. He has developed and taught worldwide short courses for API related to Surface Production Operations. In 1985, Dr Stewart received the National Society of Professional Engineers “Engineer-of-the-year” award.
Dr Stewart holds a BS in Mechanical Engineering from Louisiana State University and MS degrees in Mechanical, Civil (Structural Option) and Petroleum Engineering from Tulane University and a PhD in Petroleum Engineering from Tulane University. Dr. Stewart served as a Professor of Petroleum Engineering at Tulane University and Louisiana State University.
Here are the most frequently requested Dr Maurice Stewart courses:
Oil and water handling facilities
Gas handling, conditioning and processing
Production safety systems
The new API RP 14C and API RP 17V
Plant piping and pipeline systems
Oil and gas project management
Pumps, compressors and drivers
If you are interested in having an inhouse course with Dr Maurice Stewart, please contact LDI Training at LDITrain@singnet.com.sg.
A 5-day course by Dr. Maurice Stewart incorporating the new 2017 8th Edition of API RP 14C, the new API RP 17V 1st Edition, API RP 14J, API RP 500/505, API RP 520/521/2000, IEC 61508-2 and IEC 61508-3.
This intense Production Safety Systems course presents a systematization of proven practices for providing a safety system for onshore and offshore production facilities. Thousands of oil and gas professionals have attended this course since it was offered by Dr. Maurice Stewart more than 20 years ago.
This production safety systems course has been updated to reflect the changes provided in the new API RP 14C and the API RP 17V. In this course, you will learn the latest concepts, methods and practices that will make your facility operationally safe.
What You’ll Learn
• Provisions for designing, installing and testing both safety and non-marine emergency support systems (ESSs) on both onshore and offshore production facilities.
• Concepts of a facility safety system and outline production methods and requirements of the system.
• Guidance on how safety analysis methods can be used to determine safety requirements to protect common process components from the surface wellhead and/or topside boarding valve and for subsea systems including all process components from the wellhead and surface controlled subsurface safety valve (SCSSV) to upstream of the boarding shutdown valve. (Note: The shutdown valve is within the scope of API RP 17V for gas injection, water injection, gas lift systems and chemical injections.)
• The importance of “Safety Concept,” “Safety Reviews,” and “EB-HAZOPs.”
• A method to document and verify process safety system functions, i.e., safety analysis function evaluation (SAFE chart).
• Design guidance for ancillary systems such as pneumatic supply systems and liquid containment systems.
• A uniform method of identifying and symbolizing safety devices.
• Procedures for testing common safety devices with recommendations for test data and acceptable test tolerances.
• The Principles of Safe Facility Design and Operation, specifically, how to Contain Hydrocarbons, Prevent Ignition, Prevent Fire Escalation and Provide Personnel Protection and Escape.
• The Principles of Plant Layout Partitioning and how to partition a plant into Fire Zones, Restricted Areas and Impacted Areas thereby minimizing the Risk to Radiation, Explosion, Noise and Toxicity.
• How to determine Electrical Hazardous (Classified) Locations and determine what Electrical Equipment should be installed in these locations,
• The purpose of Surface Safety Systems, specifically, the Emergency Shut-down System, Emergency Depressurization System, Fire and Gas Detection Systems and High Integrity Protection Systems,
• The Objectives, Types, Location and Placement of Fire and Gas Detection Systems.
• The Objectives, Types and Performance of Active and Passive Fire Protection Systems.
• The Function, Types, Selection and layout of Vent, Flare and Relief Systems to minimize the effects of Radiation, Flammable Gas Dispersion and Toxic Gas Dispersion.
• The function and design considerations of Liquid Drainage Systems
• How to determine piping “spec breaks”.
• How to evaluate workplace and operating/maintenance procedures for “hidden” hazards.
• How to effectively design facilities and work areas to reduce human errors and improve performance.
• Principles of safe facility design
• Ignition prevention
• Fire escalation prevention
• Personnel protection and escape
• Installation layout
• Electrical installations in hazardous (classified) areas
• Safety systems
• Pressure ratings and Specification breaks
• High Integrity Pressure Protection Systems (HIPPS)
• Safety system and ESS bypassing
• Onshore gathering station safety systems
• Fire and gas detection systems
• Active and passive fire protection
• Relief, vent and flare systems
• Liquid drainage systems
• Electrical Area Classification
Who Should Attend
This workshop is specifically targeted for professionals and engineers who are involved in safety or production operations and who want to:
1. Develop a better understanding of the effectiveness of existing Production Safety System initiatives at existing oil and gas facilities.
2. Appreciate the main steps contemplated in the Safe Design of a plant or facility,
3. Better understand the scope and functioning of the various safety related equipment installed onshore, offshore and subsea.
4. Review or broaden their understanding of how to conduct a safety analysis, Experience-Based HAZOP and how to install electrical equipment in hazardous (Classified) locations.
5. Other professionals who want to develop a better understanding of how to conduct a Safety Analysis, EB-HAZOPs and install electrical equipment in hazardous (Classified) locations.
• Each participant will receive a comprehensive set of worksheets and checklists to aid them in conducting a safety analysis
• Each participant will receive a comprehensive set of lecture notes for after course reading and reference
• An extensive set of practical in-class “case study” exercises specially designed by Dr. Maurice Stewart that emphasizes the design and “trouble-shooting” pitfalls often encountered in the industry.
If you like to receive a pdf file of this course outline, please contact us.
Course date : December 10-14, 2018 Location : Singapore Tuition : US$4500
In 2017, API published the new 8th Edition of API RP 14C and created the new 1st Edition of API 17V for subsea applications.
Here are the major modifications of API RP 14C and the new guidelines provided in API RP 17V:
1. The API RP 14C, new 8th Edition “Analysis, Design, Installation and Testing of Safety Systems for Offshore Production Facilities” was developed in coordination with the new First Edition of API RP 17V “Recommended Practice for Analysis, Design, Installation and Testing of Safety Systems for Subsea Applications”.
2. Changes in safety system technology.
3. Additional guidance for facility safety systems as they have become larger, more complex and moved into deeper water.
4. Added requirements which include extensive emphasis on the performing of hazards analysis due to increased flow rates, pressures, temperatures and water depth.
5. Better alignment with API Standard 521, “Pressure-relieving and Depressuring Systems”.
6. Additional requirements for pumps and compressors greater than 1000 HP and reference to API 670.
7. Additional requirements to protect against backflow and settle-out pressures.
8. New address on low-temperature hazards.
9. Enhancements on open deck Fire and Gas detection placement and sensor type.
10. Extensive emphasis on performing hazards analysis to include introduction of the Prevention vs. Mitigation concepts.
11. Additional annex to cover topside High Intensity Pressure Protection Systems (HIPPS).
12. Additional annex to cover Safety System By-passing.
13. Additional annex to cover Logic Solvers.
14. Additional annex to cover Remote Operation.
If you have a need to understand these new modifications in API RP 14C and the new guidelines provided in the brand new API RP 17V for subsea applications, here is a 5-day course which you and/or your colleagues may want to attend:
Course Title: Production Safety Systems – Incorporating the New 2017 API RP 14C and API RP 17V The Instructor: Dr. Maurice Stewart, PE, CSP Course Date and Location: December 10-14, 2018 in Singapore
Since the API RP 14C and API RP 17V are critically important for the safety of your offshore and subsea facilities, please share this information with your company’s managers, supervisors, engineers and safety personnel who need to:
1. Develop a better understanding of the modifications of the 2017 edition of API RP 14C and the newly created API RP 17V
2. Appreciate the main steps contemplated in the Safe Design of onshore, offshore and subsea applications
3. Better understand the scope and functioning of the various safety related equipment installed onshore, offshore and subsea.
For more information about the course, please contact LDITrain@singnet.com.sg
This is the Attaka field, a super-giant offshore oil field located 12 miles from the shore of East Kalimantan in Indonesia. It was discovered by Unocal in August 1970. Unocal, and later on Chevron, was the operator of the Attaka unit on a 50-50 interest basis with Inpex. Attaka field is considered a super-giant oil field having 1023 MMBOE of recoverable reserves.
Here are the interesting facts about the Attaka unit:
Two years after its discovery, Attaka field started producing oil in November 1972, making it as the first offshore field in Indonesia.
It has 10 platforms, 6 of which are remote well head platforms producing oil and gas from 109 wells.
Five subsea wells were completed in 1981-1984 to produce the oil accumulation in areas out of reach of the existing remote platforms. These are the first subsea completions in Indonesia and in Asia.
Following the first discovery well, the Attaka Well 1A, seven appraisal wells were drilled to assess to size and potential of the hydrocarbon accumulation.
The huge Attaka reservoir, formed in the very prolific Kutei basin, is a faulted anticline. It has an areal closure of 8000 acres. Attaka field is one of five super-giant fields discovered in the Kutei basin.
Its oil reserves are attributed to oil found in 22 separate sands at depth between 2800 feet and 7600 feet.
Attaka sands have very high permeability. It is as high as 5 Darcy in some wells.
Attaka field daily oil production was 110,000 BOPD at its peak and gas production was 150 MMSCFPD.
A significant milestone was reached when cumulative oil production of 600 million barrels was recorded at 6:42 PM in March 7, 2001. Cumulative gas production in that same year was 1.3 trillion SCF.
Attaka field has more than 50 sands with variable oil reserves. Reservoir sand thickness ranges from 5 to 100 feet. To produce them economically, multiple zone completion method using dual tubing strings and multiple packers was selected. This method allows the engineers the flexibility to select from which of the 2 to 4 perforated zones in each well they would like to produce from.