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Leading Countries and Region wise Share in the Oilfield Scale Inhibitor Market

The global oilfield scale inhibitor market was valued at USD 509.4 Million in 2014 and is expected to witness a CAGR of 5.40% between 2015 and 2020. Factors driving the market of oilfield scale inhibitor include increasing demand from the oil and gas industry, wide availability of scale inhibitors, rising demand for biodegradable and environment-compatible scale inhibitors, and so on.

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 The oilfield scale inhibitor market is experiencing strong growth and is mainly driven by regions, such as RoW, North America, Asia-Pacific, and Europe. Considerable amount of investments are made by different market players to serve the end-user applications of scale inhibitors. The global market is segmented into major geographic regions, such as North America, Europe, Asia-Pacific, and Rest of the World (RoW). The market has also been segmented on the basis of type. On the basis of type of scale inhibitors, the market is sub-divided into phosphonates, carboxylate/acrylate, sulfonates, and others. 

Carboxylate/acrylic are the most common type of oilfield scale inhibitor

Among the various types of scale inhibitors, the carboxylate/acrylate type holds the largest share in the oilfield scale inhibitor market. This large share is attributed to the increasing usage of this type of scale inhibitors compared to the other types. Carboxylate/acrylate meets the legislation requirement, abiding environmental norms due to the absence of phosphorus. Carboxylate/acrylate scale inhibitors are used in artificial cooling water systems, heat exchangers, and boilers.

RoW, which includes the Middle-East, Africa, and South America, is the most dominant region in the global oilfield scale inhibitor market

The RoW oilfield scale inhibitor market accounted for the largest share of the global oilfield scale inhibitor market, in terms of value, in 2014. This dominance is expected to continue till 2020 due to increased oil and gas activities in this region. The Middle-East, Africa, and South America have abundant proven oil and gas reserves, which will enable the rapid growth of the oilfield scale inhibitor market in these regions. Among the regions in RoW, Africa’s oilfield scale inhibitor market has the highest prospect for growth. Africa has a huge amount of proven oil reserves and is one of the leading oil producing region in the World. But political unrest coupled with lack of proper infrastructures may negatively affect oil and gas activities in this region.

Major players in this market are The Dow Chemical Company (U.S.), BASF SE (Germany), AkzoNobel Oilfield (The Netherlands), Kemira OYJ (Finland), Solvay S.A. (Belgium), Halliburton Company (U.S.), Schlumberger Limited (U.S.), Baker Hughes Incorporated (U.S.), Clariant AG (Switzerland), E. I. du Pont de Nemours and Company (U.S.), Evonik Industries AG (Germany), GE Power & Water Process Technologies (U.S.), Ashland Inc. (U.S.), and Innospec Inc. (U.S.). 

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Scope of the Report:

  • By Type:
    • Phosphonates
    • Carboxylate/Acrylate
    • Sulfonates
    • Others
      • Polymaleic Acid
      • Synthetic Polymeric Acid
      • Polyaspartate
      • Phosphinopolyacrylate
      • Carboxy Methyl Inulin
  • By Region:
    • North America
      • U.S.
      • Canada
      • Mexico
    • Europe
      • Western Europe
      • Eastern Europe
      • Southern Europe
    • Asia-Pacific
      • China
      • India
    • RoW
      • Middle-East
      • Africa
      • South America

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Your Weekly Update: 9 - 13 December 2019

Market Watch  

Headline crude prices for the week beginning 9 December 2019 – Brent: US$64/b; WTI: US$59/b

  • The recent adjustment to the OPEC+ supply deal may not have been enough to convince the market completely, but a deal is still better than no deal; with the club coordinating to formalise the existing level of production as cuts, crude prices capped off a week of gains but failed to move higher
  • The new supply quotas include a reduction of 500,000 b/d across OPEC+, though this does not remove additional barrels from the market but rather seals in the current level of production, where Saudi Arabia is overcompensating for non-compliance elsewhere; the challenge now is also to ‘equitably redistribute’ the Saudi burden among other members
  • Saudi Arabia also pledged an additional voluntary cut of 400,000 b/d, provided all OPEC+ members meet their own quotas; compliance did, however, get easier as the club agreed to remove condensate from the crude quotas, benefitting Russia
  • The new supply deal will only stay in place until March 2020 – not quite enough time to resolve the supply glut – but OPEC is also betting that the relentless rise in American crude production will slow down in 2020
  • There is a reason to believe this, given the sharp decline in American drilling activities; but debt-laden US shale drillers might actually do the opposite – accelerate drilling to produce more oil to stave off their creditors
  • There are hints that a US-China trade deal might be coming soon, as China agreed to stop the planned implementation of tariffs on US goods due to kick on December 15; a deal cannot happen soon enough, with reports that Chinese exports to the US fell by 23% y-o-y, flagging up worries about oil demand
  • OPEC’s attempt to expand its influence by courting Brazil to its membership has been rebuffed by Petrobras, with its CEO stating that he is ‘against cartels’
  • In. the US, the EIA reports that the US moved to be a net exporter of crude and petroleum products for the first time since 1973 – aided by growth in crude and refined product exports, with imports largely flat
  • The US active rig count fell below 800 for the first time in 32 months, shedding 5 oil rigs but gaining 2 gas ones for a net loss of 3; the rig count is now down 276 from 1,075 sites working a year ago
  • OPEC’s headline agreement will prop up oil prices, but since details of the new ‘distribution’ of cuts is not yet clear, there will be no appetite for the market to allow crude to break out beyond their range; Brent is expected to stay in the US$64-65/b range, while WTI will stay at the US$59-60/b range


Headlines of the week

Upstream

  • Apache’s closely watched Maka-1 oil well – adjacent to ExxonMobil’s massive Liza field– is going for a third test drill, raising suspicions that Maka-1 could prove to be a bust, dashing hopes of Suriname emulating Guyana’s success
  • Following Murphy Oil and ExxonMobil’s exit from Malaysian upstream, oilfield service provider Petrofac is also mulling an exit, selling its assets – which include a stake in the PM304 field – for US$300 million
  • Libya and Turkey have agreed to a potentially contentious maritime deal demarcating their nautical exclusive economic zones, setting both countries up for a showdown with Greece, Cyprus, and Egypt over exploration rights
  • Repsol’s upstream arm is the first oil major to align its business goals with the Paris climate change accord, aiming to eliminate all net greenhouse gas emissions from its own operations and customers by 2050 – with a change in focus away from output growth towards value generation and clean energy
  • Canadian oil sands producers in Alberta are looking at new ways to export their crude, which would involve removing condensate, light oils and other diluents from the oil sands, and shipping the heavier latter by more cost-effective rail
  • UK independent EnQuest has been awarded 85% of the offshore Block PM409 PSC in Peninsular Malaysia, with Petronas Carigali holding the remaining 15%
  • Fresh from the success of starting up the giant Johan Sverdrup oilfield ahead of schedule, Equinor now estimates that it will be able to raise recoverable reserves from the field from 2.7 billion boe to 3.2 billion boe

Midstream/Downstream

  • PDVSA has reached a deal with Curacao to operate the 335,000 Isla refinery for another year, extending a contract that was set to expire at the end of 2019, but the new arrangement has been described as a  ‘transition’ by Curacao
  • Turkey’s state sovereign wealth fund – the Turkish Wealth Fund – will be investing some US$10 billion to build a new integrated refinery and petrochemicals complex in Adana, with construction expected to begin in 2021
  • Sonangol has terminated its contract with Hong Kong-based consortium United Shine to plan to build its new 60,000 b/d Cabinda refinery in Angola but will seek new investors and partners to go ahead with the project

Natural Gas/LNG

  • First gas has begun to flow into Sempra’s Cameron LNG Train 2 in Louisiana, marking the start of the final commissioning stage of the phase that will eventually incorporate 3 trains with 12 million tpa capacity
  • The Power of Siberia natural gas pipeline – connecting Russia and China – has launched, which will deliver up to 38 bcm of natural gas annually for 30 years to CNPC and Chinese customers from the enormous gas fields in eastern Siberia
  • After years spent getting Kitimat LNG in Canada’s BC off the ground, Chevron will be selling its 50% stake in the project – part of a broader retreat from natural gas amid a bleak price outlook – adding new woes to the troubled project
  • Prior to Chevron’s decision to exit Kitimat LNG, Canada’s Energy Regulator has doubled the timeframe of the project’s export license – allowing it to export up to 18 million tpa of LNG (up from 10 million tpa previously) for 40 years
  • ExxonMobil has shelved plans to build an LNG import terminal in Australia’s Victoria state after failing to secure enough buyers for the project
  • Train 1 at the Freeport LNG export terminal in Texas has begun operations, with Train 2 and Train 3 expected next year for a full capacity of 15 mtpa
EIA analysis explores India’s projected energy consumption

In the U.S. Energy Information Administration’s (EIA) International Energy Outlook 2019 (IEO2019), India has the fastest-growing rate of energy consumption globally through 2050. By 2050, EIA projects in the IEO2019 Reference case that India will consume more energy than the United States by the mid-2040s, and its consumption will remain second only to China through 2050. EIA explored three alternative outcomes for India’s energy consumption in an Issue in Focus article released today and a corresponding webinar held at 9:00 a.m. Eastern Standard Time.

Long-term energy consumption projections in India are uncertain because of its rapid rate of change magnified by the size of its economy. The Issue in Focus article explores two aspects of uncertainty regarding India’s future energy consumption: economic composition by sector and industrial sector energy intensity. When these assumptions vary, it significantly increases estimates of future energy consumption.

In the IEO2019 Reference case, EIA projects the economy of India to surpass the economies of the European countries that are part of the Organization for Economic Cooperation and Development (OECD) and the United States by the late 2030s to become the second-largest economy in the world, behind only China. In EIA’s analysis, gross domestic product values for countries and regions are expressed in purchasing power parity terms.

The IEO2019 Reference case shows India’s gross domestic product (GDP) growing from $9 trillion in 2018 to $49 trillion in 2050, an average growth rate of more than 5% per year, which is higher than the global average annual growth rate of 3% in the IEO2019 Reference case.

gross domestic product of selected countries and regions

Source: U.S. Energy Information Administration, International Energy Outlook 2019

India’s economic growth will continue to drive India’s growing energy consumption. In the IEO2019 Reference case, India’s total energy consumption increases from 35 quadrillion British thermal units (Btu) in 2018 to 120 quadrillion Btu in 2050, growing from a 6% share of the world total to 13%. However, annually, the level of GDP in India has a lower energy consumption than some other countries and regions.

total energy consumption in selected countries and regions

Source: U.S. Energy Information Administration, International Energy Outlook 2019

In the Issue in Focus, three alternative cases explore different assumptions that affect India’s projected energy consumption:

  • Composition case: EIA assumes India’s economy shifts toward further growth in manufacturing, which increases energy consumption.
  • Technology case: EIA assumes India’s industrial technology does not advance as quickly as in the IEO2019 Reference case, resulting in greater energy use.
  • Combination case: EIA combines the assumptions in the Composition and Technology cases.

EIA’s analysis shows that the country's industrial activity has a greater effect on India’s energy consumption than technological improvements. In the IEO2019 Composition and Combination cases, where the assumption is that economic growth is more concentrated in manufacturing, energy use in India grows at a greater rate because those industries have higher energy intensities.

In the IEO2019 Combination case, India’s industrial energy consumption grows to 38 quadrillion Btu more in 2050 than in the Reference case. This difference is equal to a more than 4% increase in 2050 global energy use.

U.S. onshore wind capacity exceeds 100 gigawatts

Cumulative U.S. installed onshore wind capacity exceeded 100 gigawatts (GW) on a nameplate capacity basis as of the end of September 2019, according to the U.S. Energy Information Administration’s (EIA) Preliminary Monthly Electric Generator Inventory. More than half of that amount has been installed since the beginning of 2012. The oldest wind turbines still operating in the United States came online as early as 1975.

installed wind capacity by state

Source: U.S. Energy Information Administration, Preliminary Monthly Electric Generator Inventory

As of the third quarter of 2019, 41 states had at least one installed wind turbine. Texas had the most capacity installed, at 26.9 GW, followed by Iowa, Oklahoma, and Kansas. These four states accounted for half of the total U.S. installed wind capacity.

In the United States, wind turbines tend to come online late in the year. Based on information reported in the Preliminary Monthly Electric Generator Inventory, EIA expects that an additional 7.2 GW of capacity will come online in December 2019. EIA also expects that another 14.3 GW of wind capacity will come online in 2020. If realized, the United States would have about 122 GW of wind capacity by the end of next year.

U.S. coal production employment has fallen 42% since 2011

The U.S. Energy Information Administration’s (EIA) Annual Coal Report shows that coal mining employment has declined in the past decade as coal demand has decreased. Most U.S. coal is consumed in the electric power sector and has faced increased competition from electricity generation from natural gas and renewable technologies. U.S. coal mining employment fell from a high of 92,000 employees in 2011 to 54,000 employees in 2018, with the most dramatic decrease in the Appalachian region.

Annual U.S. coal production peaked in 2008, three years before coal mining employment reached its record high. In 2008, the United States produced 1.2 billion tons of coal from 1,458 mines. Since then, coal production has fallen and many mines have closed: in 2018, U.S. coal production was 756 million tons from 679 mines. As was the case with employment, much of coal’s production decline was concentrated in the Appalachian region. More than half of the region’s mines have closed since 2008, and production has fallen from 390 million tons in 2008 to 200 million tons in 2018.

U.S. coal production by region

Source: U.S. Energy Information Administration, Annual Coal Report

Appalachian mines tend to be smaller than mines in the Interior and Western regions and to use labor-intensive underground mining techniques, as opposed to machinery-intensive longwall mining and surface mining operations. A slight increase in coal mining employment in the Appalachia region from 2016 to 2018 corresponded to an increase in coal exports because this region is the dominant source of coal shipped overseas.

The decline in operating mines has been steeper than the changes in employment and production. EIA’s review of operating mines showed that smaller mines have had greater difficulty competing in the current market and have been the first to close.

U.S. coal mining labor productivity

Source: U.S. Energy Information Administration, Annual Coal Report

As smaller, less productive mines were idled or closed, overall coal labor productivity, measured in tons per labor hour, gradually increased from 5.2 tons per labor hour in 2011 to 6.2 tons per labor hour in 2018. The large surface mines in the Powder River Basin (PRB) in Wyoming and Montana have much higher productivity, but even PRB productivity has declined as the region’s producing coal seams become deeper and the amount of overburden, or top soil and rock above the coal seam, increases.

In contrast, the Appalachia and Interior regions both have shown improvements in labor productivity between 2011 and 2018, largely because they are increasingly relying on less labor-intensive longwall and highwall mining systems and closing or idling the least productive mines.

Data from EIA’s Annual Coal Report are available in EIA’s Coal Data Browser. In addition to data from the U.S. Mine Safety and Health Administration, EIA’s Annual Coal Report also includes mine-level data from EIA’s Survey of Coal Production and Preparation and coal exports data from the U.S. Department of Commerce.

This Week in Petroleum: With pipeline development, U.S. crude oil pipeline fill has increased by more than 60% since 2011
Crude oil held in pipelines (pipeline fill) in the United States grew from 75 million barrels in March 2011, the earliest data available, to nearly 124 million barrels in September 2019, a 64% increase, according to the U.S. Energy Information Administration’s (EIA) Working and Net Available Shell Storage Capacity report (Figure 1). The increase is due to the significant expansion of the U.S. crude oil pipeline system over that period. Almost 97% of the 48 million barrel increase in crude oil pipeline fill, which includes some volumes of crude oil in transit via water and rail, occurred in the Gulf Coast (Petroleum Administration for Defense District, or PADD, 3) and the Midwest (PADD 2).

Figure 1. . Crude oil pipeline fill

Pipelines are the primary method of transporting crude oil in the United States. The increase in U.S. crude oil production in recent years has required the construction of new pipelines and reconfiguration of existing pipelines, including the conversion of natural gas pipelines to crude oil pipelines. The Gulf Coast region, which was responsible for 70% of the growth in U.S. crude oil production between 2010 and 2018, has experienced the largest pipeline buildout during that time period. The Permian Basin, covering West Texas and southeastern New Mexico, contributed the most to crude oil production growth and supported higher crude oil inventories in the region, including increased pipeline fill.

According to EIA’s Liquid Pipeline Projects Database, more than 100 crude oil pipeline projects were completed between March 2011 and September 2019. During this time, about 90% of projects were located in either the Gulf Coast or Midwest regions (Figure 2). The most prevalent project types were pipeline expansions and new pipeline builds. The vast majority of the projects were for transporting crude oil within their respective regions.

Figure 2. Crude oil pipeline projects (2nd Quarter 2011-3rd Quarter 2019)

Many pipeline expansions increased crude oil takeaway capacity from producing regions. For example, in 2018, Enterprise Products Partners L.P.’s 418-mile Midland-to-Echo 1 Pipeline System was placed into service to transport crude oil from the Permian Basin to locations near Houston, Texas. Other Permian Basin projects completed in 2018 included Plains All American’s Sunrise Pipeline Expansion and Enterprise Products Partners L.P.’s new Loving County Pipeline. The Sunrise Pipeline Expansion transports crude oil from the Permian region to Cushing, Oklahoma, and destinations in the Gulf Coast and the Loving County Pipeline transports crude oil from Permian Basin fields in New Mexico to Midland, Texas, a crude oil supply hub.

About 64% of crude oil production, 52% of U.S. petroleum refining capacity (measured by operable distillation capacity), and 52% of crude oil storage is located in the Gulf Coast (Figure 3). Rising Permian crude oil production decreased crude oil imports, and increased demand for crude oil at petroleum refineries have coincided with several projects aimed at increasing crude oil pipeline deliveries to Gulf Coast refineries. For example, the 264-mile Kinder Morgan Crude & Condensate Pipeline (KMCC), which includes a converted 109-mile natural gas pipeline, initiated deliveries of crude oil and condensate from the Eagle Ford region to Houston in 2012. Kinder Morgan later included a 27-mile lateral to Phillips 66’s refinery in Old Ocean, Texas. In 2014, TC Energy’s Keystone Gulf Coast Expansion was placed into service to supply refineries in Port Arthur, Texas.

Figure 3. Crude oil production, distillation capacity, and crude oil storage

In the Midwest, Cushing, Oklahoma—a key crude oil storage hub—has experienced significant increases in crude oil pipeline capacity as new crude oil tank farms were built to handle rising supplies. Crude oil working storage capacity in Cushing rose 59% between March 2011 and September 2019 to reach 76 million barrels. Cushing receives large volumes of crude oil by pipeline and rail from various areas such as Canada and the Rocky Mountains (PADD 4). For example, TC Energy’s 2014 expansion of the Keystone Pipeline transports crude oil that originated in Alberta, Canada, to Gulf Coast refineries via Cushing. Several additional pipeline projects that entered service between 2014 and 2018 were designed to move crude oil from the Rocky Mountains, which includes the Bakken formation, to Cushing.

Growing crude oil exports have also supported increases in crude oil pipeline capacity. The removal of restrictions on U.S. crude oil exports at the end of 2015, combined with higher crude oil production, allowed an increase in crude oil exports in the Gulf region, which grew from 3,000 barrels per day (b/d) in 2010 to 1.8 million b/d in 2018. Petroleum terminals in the Gulf Coast that once imported large volumes of crude oil now load crude oil tankers for export to international destinations. Enterprise Products Partners L.P. recently completed an expansion to its Midland-to-Sealy Pipeline and conversion of its Seminole Red Pipeline to service the Enterprise Crude Houston (ECHO) terminal, a facility where shippers can load U.S. crude oil for export.

U.S. average regular gasoline and diesel prices fall

The U.S. average regular gasoline retail price fell more than 1 cent from the previous week to $2.56 per gallon on December 9, 14 cents higher than the same time last year. The West Coast price fell 7 cents to $3.34 per gallon, the Rocky Mountain price fell nearly 3 cents to $2.79 per gallon, and the Gulf Coast price fell more than 2 cents to $2.20 per gallon. The East Coast and Midwest prices remained unchanged at $2.48 per gallon and $2.42 per gallon, respectively.

The U.S. average diesel fuel price fell more than 2 cents from the previous week to $3.05 per gallon on December 9, 11 cents lower than a year ago. The West Coast price fell by nearly 6 cents to $3.65 per gallon, the Rocky Mountain price fell by more than 3 cents to $3.21 gallon, the Gulf Coast price fell by 2 cents to $2.76 per gallon, the Midwest price fell by nearly 2 cents to $2.97 per gallon, and the East Coast price fell by nearly 1 cent to $3.05 per gallon.

Propane/propylene inventories rise

U.S. propane/propylene stocks increased by 1.7 million barrels last week to 93.5 million barrels as of December 6, 2019, 7.4 million barrels (8.6%) greater than the five-year (2014-18) average inventory levels for this same time of year. Gulf Coast and Rocky Mountain inventories increased by 3.3 million barrels and 0.1 million barrels, respectively. Midwest and East Coast inventories decreased by 1.1 million barrels and 0.6 million barrels, respectively. Propylene non-fuel-use inventories represented 5.8% of total propane/propylene inventories.

Residential heating oil prices increase, propane prices decrease

As of December 9, 2019, residential heating oil prices averaged almost $3.02 per gallon, more than 1 cent per gallon above last week’s price but more than 18 cents per gallon below last year’s price at this time. Wholesale heating oil prices averaged nearly $2.07 per gallon, more than 2 cents per gallon higher than last week’s price and more than 7 cents per gallon higher than a year ago.

Residential propane prices averaged more than $2.02 per gallon, almost 1 cent per gallon lower than last week’s price and nearly 42 cents per gallon less than a year ago. Wholesale propane prices averaged more than $0.83 per gallon, more than 7 cents per gallon lower than last week’s price and nearly 8 cents per gallon below last year’s price.