quality

With ever-increasing volumes of Permian crude oil being exported and the recent inclusion of WTI Midland in the assessment of Dated Brent prices, the issue of iron content — especially in some Permian-sourced crude — is coming to the fore. This has become such a point of emphasis for exported light sweet crude because many less complex foreign refineries do not have the ability to manage high iron content adequately. Iron content that exceeds desirable levels could have far-reaching repercussions, from sellers facing financial penalties for not meeting the quality specifications to marine terminals being excluded from the Brent assessment if they miss the mark. It’s a complicated issue, with split views on what causes the iron content in a relatively small subset of Permian oil to be concerningly high — and how best to address the matter. In today’s RBN blog, we look at iron content in crude oil, why it matters to refiners, how it affects prices, and what steps the industry is taking to deal with it.

Crude oil quality has been a hot topic lately. With the increase in waterborne activity along the Gulf Coast, a high-quality barrel is desired now more than ever. Permian WTI exports have continued to increase as production rises and refining capacity remains relatively stagnant (outside of ExxonMobil’s recent Beaumont expansion). This has resulted in more scrutiny on Permian quality and more concerns rising to the surface — both from the pockets of lower-quality WTI produced at the wellhead and from blending by market participants, as many midstream providers and traders have become efficient at capturing arbitrage opportunities. Recent WTI quality concerns have primarily been around metal content, hydrogen sulfide (H2S) and mercaptans, while nitrogen has become a major issue in the natural gas market. In today’s RBN blog, we look at the issue of mercaptans in WTI.

Crude oil prices are in free fall – the prompt U.S. benchmark WTI CME NYMEX futures contract was down 24 percent to $81.78/Bbl yesterday (October 15, 2014) from its recent high in June. International benchmark IPE Brent futures were down 27 % over the same period to $83.78/Bbl. Most analysts point to an excess of crude supply over faltering demand as the main driver behind the price collapse. The apparent willingness of OPEC leader Saudi Arabia to protect its market share at the expense of higher prices is also a bearish factor. Today we explain why Saudi Arabia is bucking the trend that has pushed out other light crude imports with a robust and unwavering flow of 330 Mb/d of Arab Light.

A study released yesterday (August 4, 2014) by the North Dakota Petroleum Council (NDPC) details the final results of work they commissioned to extensively sample and test North Dakota crude oil. The goal was to establish the quality characteristics of Bakken crude oil to determine if it is more risky to transport by rail than other crudes. The results show Bakken crude to be similar to other light sweet crudes, to be consistent across the producing region and that it meets all the current hazardous materials transportation requirements. Today we review the report’s findings.

US tight oil production from shale has surged over the past three years pushing overall domestic output up by more than 60 percent since 2011. Over that same period the quality of US crude production has gotten considerably lighter. An EIA report out last week showed that the percentage of crude production with higher than 40 degrees API of gravity (very light crude) has almost doubled between 2011 and the end of 2015. The increasingly light crude slate is challenging US refining capacity and driving the push for reform of crude export regulations. Yet the data available to inform this critical industry debate is confusing and inadequate. Today we discuss the analysis challenge.

New pipelines are coming online to deliver increasing volumes of US and Canadian production to market. Producers want to be paid full value for the quality of the crude that leaves their wellhead. Yet many pipelines blend different shippers’ crude into a common stream. To compensate for any loss of value en route, pipelines operate quality banks. These systems calculate payments or debits for each shipper based on their input crude quality versus the common stream. Today we look at crude quality banks that determine value using refined products.

The physical market for Brent, Forties, Oseberg and Ekofisk (BFOE) represents the delivery mechanism for ICE Brent Futures and is linked to crude oil contracts worldwide. This year the  trading in the BFOE forward market has been limited to just 20 cargoes a month from the Forties stream. Today we describe producer’s efforts to increase market liquidity.

This is Part 3 in our series on the physical Brent crude market. What follows will make more sense if you read Part 1 and Part 2 first. In Part 1 we explain that the Brent crude used as a benchmark for international pricing that underlies the ICE Brent futures contract – is made up of crude oil produced in dozens of different North Sea fields and delivered to market in four different streams – Brent, Forties, Oseberg and Ekofisk (BFOE). In Part 2 we explain the linkage between the small Brent physical crude market that trades in 600 MBbl parcels costing upwards of $60 MM at today’s prices and the Brent ICE futures contract that trades in 1000 Bbl lots. Prices in the two markets are linked together by a cash settlement process using a Brent Index price based on forward trades in the physical market. The Brent Index settlement is an exchange for physical  (EFP) mechanism that ensures convergence between futures and physical markets.

The convergence mechanism in futures markets used to be something taken for granted in international crude trading. Futures exchanges like ICE and the CME NYMEX were considered an add-on service for the oil industry to hedge price risks - secondary to the physical market. That was the old days. Now futures trading volumes dwarf physical market transactions (in Part 2 we showed that ICE Brent futures trades 500 times the physical BFOE crude production volumes each day). Nevertheless the futures contracts still have to relate back to underlying physical crude oil prices in order to function efficiently. That can sometimes cause unexpected results.

Natural gas processing plants are being built or expanded at a feverish pace.  At least 90 projects are in the works around the U.S., expected to add more than 15 Bcf/d of capacity according to the latest Bentek NGL Facilities Databank numbers.  How do the economics of these investments work? We know that it is a lot more complicated than a simple frac spread.  But does that mean the calculations must be exclusively the purview of engineers armed with gas plant optimization models?  Heck no.  Anybody, even an MBA with a spreadsheet, a few standard factors and a gas analysis can figure out how a gas processing plant makes money.  So to prove that point today we’ll dive one more time into natural gas processing economics to understand how the composition of an inlet gas stream is converted to outlet streams of natural gas liquids and residue gas.