Author Archives: Amit Kanda

Introduction

In addition to extremely high purity requirements for BTX products, there are other stringent impurity specifications that must be met before they can be sold as finished products or sent to downstream units for processing. 

BTX Product Specifications

Typical specifications for BTX products include purity, non-aromatic content, bromine index, acid wash color, total distillation range, specific gravity, Color Pt-Co, copper corrosion, solidification point, Sulfur content, Thiophene, Nitrogen, etc.

For the purpose of this blog, we will focus on two key specs – the bromine Index (BI) and acid wash color (AWC) since they are both related to the presence of olefins in BTX products.

Typical BI and AWC specs for BTX products are given below:

ParameterUnitBenzeneTolueneMixed XylenesBromine Index (BI)max10.0——Acid Wash Color (AWC)max1.02.06.0

These specifications are typical and may vary from manufacturer-to-manufacturer and/or as required by the end user.

Source of impurities

The two main feed sources for Aromatic Extraction Units (AEUs) are light reformate from the reformate splitter and raw pygas (RPG) stream from steam crackers. Light reformate is usually free of sulfur compounds and has low levels of olefins content. However, the RPG feed not only has sulfur compounds like thiophene and mercaptans, but also multitude of olefins, di-olefins and cyclo-olefins present in it. These impurities and olefins, if not removed or treated, will make their way into the final product. Hence, it is imperative to remove them to meet the final product specifications.

Bromine Index

Bromine Index is a broad indicator of the olefin content in an aromatic product. It is defined as milligrams of bromine consumed per 100 gram of sample under given conditions.

Acid Wash Color

Acid wash color is one the most common parameter for Benzene and Toluene product. A high AWC value also implies the presence of olefins & di-olefins, but it may also indicate the presence of other color causing contaminants – like rust. AWC value is most sensitive to di-olefins, followed by straight chain, cylco-olefins and branched-chain olefins.  

Removal of Olefins and other trace impurities

Due to the high levels of olefinic and sulfur species present in raw pygas (RPG), it is typically hydrotreated in a two-stage pygas hydrotreater. In the first stage, all di-olefins are converted to olefins, and in the second stage, most of the olefins are saturated to paraffins. Hydrotreating also removes majority of the sulfur and nitrogen compounds down to the desired levels. However, small amounts of olefins are left after hydrotreating, which must be removed by additional means.  

Most of the remaining left-over olefins are further rejected in the solvent extraction section, where they are removed as ‘raffinate’ product. Some close-boiling olefins are still carried into the extracted aromatics, these are finally removed by clay treatment prior to product fractionation.

Clay treatment

The last traces of olefins present in the BTX products are removed by means of clay treatment. In clay treatment, the BTX product is heated to high temperature (150-200 ºC) and passed through a fixed bed reactor (called clay treaters) containing acid-activated clay. Operating pressure is kept sufficiently high to keep the heaviest of product fraction in the liquid phase.

Acid-activated clays (bentonite clay treated with mineral acids to increase its surface area and acidity enhancing its adsorptive and catalytic properties) help remove the olefins from BTX products in two possible ways:

1. by polymerizing the olefins into heavier boiling compounds (oligomers), and

2. By alkylation of the olefins with aromatic compounds.

The final product of clay treatment is a high-boiling compound which is removed in the product-fractionation section along with the heaviest fraction (C8 aromatics).

GK Process Engineering Offering

Clay treatment is a non-regenerative process and spent clays are usually sent to locally approved landfills. This is an additional operating cost, that can be minimized by removing as much olefins as possible in the upstream pygas hydrotreaters and extractive distillation sections.

GK Process Engineering LLC can help its clients save capital and operating costs by optimizing and de-bottlenecking their aromatic extraction units to maximize olefin removal/rejection and minimize the size of clay treaters.

Amit Kanda

GK Process Engineering LLC

Introduction

Aromatic hydrocarbons (Benzene, Toluene, Xylenes or BTX) are some of the most important intermediate products in the petrochemical industry. They are high value by-products of refinery and petrochemical processes and significant financial incentives exist for them to be extracted, purified and sold as finished petrochemical products rather than be sold as fuel. The demand for high purity BTX products has been steadily increasing over the past several decades and is projected to grow even more in the near future. A process unit designed to extract aromatic compounds from a mixture of hydrocarbons is called an Aromatics Extraction Unit (AEU).

Sources of aromatic hydrocarbons

Aromatic rich streams are formed in a variety of refinery and petrochemical processes as by-products, but the most common sources are catalytic reformers units and steam crackers. The feed streams obtained from these sources are called reformate and pygas (short for pyrolysis gasoline) respectively. Other aromatic rich streams are coke oven light oil (COLO) from coke oven plants. The BTX content of these streams can range from low to high (15% to over 90%).  A typical AEU feed stream consists of C5-C10 hydrocarbon compounds with a mixture of paraffins (P), olefins (O), naphthenes (N) and aromatics (A). Of course, C6-C8 aromatics compounds form the biggest fraction in the feed stream.

What is extractive distillation?

Under normal conditions, the boiling points of different aromatic and non-aromatic hydrocarbons are so close that they cannot be separated by simple distillation alone, or the required product purity levels cannot be achieved simply by distillation. Extractive distillation is the technique of separating the aromatics hydrocarbons (C6-C8 A) from non-aromatic hydrocarbons (C5-C10 paraffins, olefins and naphthenes) via the use of a solvent. By introducing a solvent, the relative volatility of the components in the mixture is altered enough that they can be separated by simple distillation. The high boiling solvent preferentially ‘dissolves’ the aromatics hydrocarbons in itself and the non-aromatic hydrocarbons are easily separated by distillation. The ‘extracted’ aromatic compounds are then recovered from the solvent by steam stripping. The non-aromatic product stream is called the ‘raffinate’ has extremely low aromatic content (less than 1%) and can either be routed back to olefin block (for pygas feed) or sent for fuel blending (for refineries).

Product specifications

Benzene’s product purity requirements are usually very high – 99.9% min. Toluene has a product purity requirement of 99.5% min. although, nitration grade Toluene can have lower purity requirements of 98.5% min. C8 aromatics are usually as a mixture of ortho, meta & para-xylenes (called mixed xylenes) and Ethyl benzene (EB). Their product purity requirements can range from 96.5 – 98% min depending on feed composition.

Solvent Characteristics

The solvent used in aromatic extraction, therefore, must have the following characteristics:

1. High boiling point (to be thermally stable at operating temperatures)
2. Miscible with the mixture
3. Easily separable from the dissolved components
4. Should not form an azeotrope with any component in the feed mixture

Technologies and Licensors for aromatic extraction

Many commercial processes are available for extracting aromatic compounds, depending on type of technology or solvent. Typical examples of technology are Liquid-liquid extraction (LLE) and extractive distillation (ED). Types of solvents include Sulfolane, N-Methyl Pyrrolidone (NMP), Ethylene Glycol & other glycol based solvents (DEG, DGA, TEG and Carom), N-Formylmorpholine (NFM), etc. The most widely solvent used is Sulfolane.

These technologies, along with their respective solvents, have been successfully marketed and implemented worldwide by licensors like UOP (UOP ED Sulfolane), Uhde (Morphylane), Sulzer GTC (GT-BTX) and a large number of their units are in operation worldwide. These technologies differ primarily by the CAPEX requirements (total number of equipment), operating cost (energy consumption), solvent selectivity, stability and degradation, corrosion issues faced by operators, and aromatic recovery guaranteed by the licensors.

GKPE’s offering

Aromatic Extraction Units are rarely stand-alone units and are typically part of a larger complex in refinery or petrochemical plants. No two AEUs are the same due to wide range of feeds used in upstream units (for example liquid or gas or mixed feed for steam crackers) and their different modes of operation (for example, ethylene mode or propylene mode ). This results in wide variations in flowrate, aromatic content and even contaminants in AEU feed streams. This sometimes necessitates the pre-treatment of feed before it can be fed to the extractive distillation section. Examples include pygas hydrotreating and clay treatment of benzene. All these factors contribute to the overall cost of building and operating an Aromatic Extraction Unit.

GK Process Engineering LLC can help its customers understand the pros and cons of all available technologies and select the best one suited for their specific purposes – in both technical and commercial terms.

Amit Kanda

GK Process Engineering LLC

Centrifugal pumps are the most widely used pump type in the oil and gas industry. They are the workhorse of refineries and petrochemical plants, with arguably millions of centrifugal pumps in operation worldwide. Operators rely heavily on their smooth and uninterrupted operation to meet daily production targets. Hence, it is absolutely necessary to accurately size a centrifugal pump for proper and reliable plant operations.

Following are some of the best practices that can be followed for properly sizing a centrifugal pump:

• Gather the essential Information: The basic information required for sizing a centrifugal pump is, but not limited to, the following documents: Process Design Basis, Project Design Basis, Process Flow Diagram (PFD), Piping & Instrumentation Diagram (P&ID), Material Balance tables, Preliminary Plot Plan, Equipment Datasheets, etc.

The above documents will provide different pieces of information that will be required for pump sizing calculations. For example, the Process/Project Design Basis document will provide information like over-design margins for specific equipment, turndown ratio, and battery limit conditions for product and utility lines, etc.

Process Flow diagrams will show the number and sequence of equipment in the pump circuit as well as the locations of control valves. P&IDs will show details of valves, fittings, instrumentations (FE’s) and equipment elevations, etc. Material balance tables will provide flowrates and physical properties like density, viscosity, vapor pressure, etc. of the service fluid for different operating scenarios and will help decide on the design case and rating case.

Equipment datasheets will provide allowable pressure drops through different equipment. A preliminary plot plan will provide distances and elevations of the various equipment involved in the pump circuit.

• Draw the pump circuit: A well-drawn and accurate sketch of the pump circuit is a good starting point in pump calcs.  Such a sketch would show all the major equipment on the pump suction and discharge sides, and if applicable, all the different destinations where the service fluid needs to be pumped. For example, an overhead product pump of a distillation column may normally be pumping liquid back to the tower as reflux, and to product OSBL storage tanks, but will be in total recycle mode during start-up time. Hence the pump needs to be sized to operate under all scenarios

• Design case and rating case: Selecting the right design case is critical for proper pump sizing. Usually a centrifugal pump has multiple operating cases with different flowrates and operating conditions (T&P), thereby resulting in different fluid physical properties for each scenario. In some cases, the difference between the max and min operating flowrates can be huge. As an example, the max flow case can be 120% of the case with highest normal operating flowrate and min case can be 50% (turndown case) of the case with lowest normal operating flowrate. In such scenarios, the final pump design must be checked for lowest flowrate case to ensure the pump does not operate too high or low on the curve. Otherwise, multiple pump (2+1) operating options should be considered.

• Importance of pipe fittings: For a grass-roots project, information related to pipe lengths, number of valves & fittings and equipment elevation may not be available early on, these must be generously assumed to avoid under sizing the pump. It can be argued that the pump suction side requires extra careful assessment as it directly impacts the NPSHa calculations. A process engineer must consider any temporary or permanent strainer, isolation valves, tees, elbows, and reducers in the suction line pressure drop calcs. The discharge side should include any equipment, fittings or instruments that can contribute to pressure loss.  

• Assumptions: All assumptions related to calculations must be made carefully and noted in the calculation file. These include number of fittings, valves, size of reducers, equipment and piperack elevations, equipment pressure drops, liquid levels, plot plan locations, etc. These must be revisited and verified along the way, for example after 3D model is developed by the piping group, or after receiving actual information from the pump vendor.

• Remember the phase change: In many pump circuits, the liquid being pumped is heated in a heat exchanger or a fired heater before reaching the final destination – which can be a distillation column or a reactor/pressure vessel. In such cases, it must be remembered that the pressure drop of a two-phase line in much higher than the pressure drop of a liquid-only line. Therefore, the extra pressure drop encountered by the pump after the phase change must be added to the pump discharge pressure calculations. The equipment layout on the plot plan can be ‘tweaked’ to minimize the length of the two-phase line while trying to keep the fluid in the liquid phase for as much of its circuit as possible. This greatly simplifies process design as well as subsequent plant operation.

• Casing design pressure: Some clients like to calculate the pump casing design pressure based on max. operating pressure in the suction vessel PLUS liquid static head at high Liquid level (HLL) in the suction vessel. While other clients prefer the worst case scenarios of pump suction vessel at PSV set pressure (relieving conditions) PLUS high liquid level (HLL) in the suction vessel. This is matter of project guidelines and must be discussed and agreed with the client beforehand.

The above mentioned are some of the few best practices that can be followed to ensure an accurate pump design. Of course this does not cover all scenarios and sound judgement must  made on case-by-case basis.

Amit Kanda

GK Process Engineerig LLC