The Job of a Wellsite Geologist

Amanda Barlow
Ms. Amanda Barlow

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

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

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

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

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

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

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

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

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

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

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

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

Responsibilities

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

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

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

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

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

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

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

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

Cuttings Descriptions

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

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

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

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

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

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

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

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

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

 

About Dr. Roland N. Horne

 

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Dr. Roland N. Horne

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

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

He is best known for his work in well test interpretation, production optimization, and analysis of fractured reservoirs.

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

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

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

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

Dr. Horne will conduct a 5-day course – Modern Well Test Analysis – on August 26-30, 2019 in Singapore. This highly regarded course has been attended by thousands of oil and gas, as well as geothermal professionals in many countries for more than 20 years. If you want more information about the course, please contact LDI Training at lditrain@singnet.com.sg.

The Top Ten Oil Refineries in Southeast Asia

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

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

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

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

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

 

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

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

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

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

 

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

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

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

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

 

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

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

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

 

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

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

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

 

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

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

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

 

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

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

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

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

 

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

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

 

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

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

 

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

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

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

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

 

Pertamina Dumai Refinery reduces its fuel costs by 40%

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The PLN power plant at Muara Karang, Jakarta.

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

The gas comes from the following three blocks:

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

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

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

The Top 10 Crude Oil Producing Companies in Indonesia in 2018

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

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

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

Chevron Pacific Indonesia – 209,000 BOPD

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

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

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

ExxonMobil Cepu Ltd – 208,000 BOPD

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

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

Pertamina EP – 79,000 BOPD

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

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

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

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

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

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

Pertamina Hulu Mahakam – 42,000 BOPD

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

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

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

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

Pertamina Hulu Energi ONWJ – 29,000 BOPD

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

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

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

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

Medco EP Natuna – 16,000 BOPD

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

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

Petronas Carigali (Ketapang) – 15,000 BOPD

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

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

PetroChina International Jabung – 14,000 BOPD

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

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

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

Pertamina Hulu Kalimantan Timur – 13,000 BOPD

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

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

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

Key Concepts and Methodologies for Effective Reservoir Simulation

 

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

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

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

The World Top 10 Oil Producers

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Offshore oil and gas production and processing platforms and facility.

 

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

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

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

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

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

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

The Top Three Unconventional Oil and Gas Resources

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

The three common types of unconventional hydrocarbon resources are:

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

Oil Sands

The world’s largest oil sand deposit is the Athabasca oil sands located in Alberta, Canada. Oil sands are a mixture of semi-solid bitumen or asphalt and sand, and they are buried not far from the earth 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

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An oil field and sucker Rod pumps

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

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

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

Coal Bed Methane

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

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

 

The largest tidal power plant in the world

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

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

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

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

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

Lava Laze of Kilauea

 

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

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

 

What is lava laze?

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

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

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

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

Source: LA Times article by Heidi Chang