Surface Production

Introduce

Is found in shallow reservoirs, seeps of crude oil or gas may naturally develop, and some oil could simply be collected from seepage or tar ponds. Historically, we know of tales of eternal fires where oil and gas seeps would ignite and burn. One example 1000 B.C. is the site where the famous oracle of Delphi would be built, and 500 B.C. Chinese were using natural gas to boil water.
But it was not until 1859 that "Colonel" Edwin Drake drilled the first successful oil well, for the sole purpose of finding oil.
The Drake Well was located in the middle of quiet farm country in north-western Pennsylvania, and began the international search for and industrial use of petroleum. Photo: Drake Well Museum Collection, Titusville, PA



These wells were shallow by modern standards, often less than 50 meters, but could give quite large production. In the picture from the Tarr Farm, Oil Creek Valley, the Phillips well on the right was flowing initially at 4000 barrels per day in October 1861, and the Woodford well on the left came in at 1500 barrels per day in July, 1862. The oil was collected in the wooden tank in the foreground. Note the many different sized barrels in the background. At this time, barrel size was not yet standardized, which made terms like "Oil is selling at $5 per barrel" very confusing (today a barrel is 159 liters, see units at the back). But even in those days, overproduction was an issue to be avoided. When the “Empire well” was completed in September 1861, it gave 3,000 barrels per day, flooding the market, and the price of oil plummeted to 10 cents a barrel.
Soon, oil had replaced most other fuels for mobile use. The automobile industry developed at the end of the 19th century, and quickly adopted the fuel. Gasoline engines were essential for designing successful aircraft. Ships driven by oil could move up to twice as fast as their coal fired counterparts, a vital military advantage. Gas was burned off or left in the ground. Despite attempts at gas transportation as far back as 1821, it was not until after the World War II that welding techniques, pipe rolling, and metallurgical advances allowed for the construction of reliable long distance pipelines, resulting in a natural gas industry boom. At the same time the petrochemical industry with its new plastic materials quickly increased production. Even now gas production is gaining market share as LNG provides an economical way of transporting the gas from even the remotest sites.
With oil prices of 50 dollars per barrel or more, even more difficult to access sources become economically interesting. Such sources include tar sands in Venezuela and Canada as well as oil shales. Synthetic diesel (syndiesel) from natural gas and biological sources (biodiesel, ethanol) have also become commercially viable. These sources may eventually more than triple the potential reserves of hydrocabon fuels.

Process overview

The following figure gives a simplified overview of the typical oil and gas production process




Today oil and gas is produced in almost every part of the world, from small 100 barrel a day small private wells, to large bore 4000 barrel a day wells; In shallow 20 meters deep reservoirs to 3000 meter deep wells in more than 2000 meters water depth; In 10.000 dollar onshore wells to 10 billion dollar offshore developments.
Despite this range many parts of the process is quite similar in principle. At the left side, we find the wellheads. They feed into production and test manifolds. In a distributed production system this would be called the gathering system. The remainder of the figure is the actual process, often called the Gas Oil Separation Plant (GOSP). While there are oil or gas only installations, more often the wellstream will consist of a full range of hydrocarbons from gas (methane, butane, propane etc.), condensates (medium density hydro-carbons) to crude oil. With this well flow we will also get a variety of non wanted components such as water, carbon dioxide, salts, sulfur and sand. The purpose of the GOSP is to process the well flow into clean marketable products: oil, natural gas or condensates. Also included are a number of utility systems, not part of the actual process, but providing energy, water, air or some other utility to the plant.


Facilities



Onshore

Onshore production is economically viable from a few tens of barrels a day upwards. Oil and gas is produced from several million wells world-wide. In particular, a gas gathering network can become very large, with production from hundreds of wells, several hundred kilometers/miles apart, feeding through a gathering network into a processing plant. The picture shows a well equipped with a sucker rod pump (donkey pump) often associated with onshore oil production. However, as we shall see later, there are many other ways of extracting oil from a non-free flowing well For the smallest reservoirs, oil is simply collected in a holding tank and collected at regular intervals by tanker truck or railcar to be processed at a refinery.
But onshore wells in oil rich areas are also high capacity wells with thousands of barrels per day, connected to a 1.000.000 barrel a day gas oil separation plant (GOSP). Product is sent from the plant by pipeline or tankers. The production may come from many different license owners. Metering and logging of individual wellstreams into the gathering network are important tasks.
Recently, very heavy crude, tar sands and oil shales have become economically extractible with higher prices and new technology. Heavy crude may need heating and diluent to be extracted, sands have lost their volatile compounds and are strip mined or could be extracted with steam. It must be further processed to


separate bitumen from the sand. These unconventional of reserves may contain more than double the hydrocarbons found in conventional reservoirs.


Offshore

Offshore, depending on size and water depth, a whole range of different structures are used. In the last few years, we have seen pure sea bottom installations with multiphase piping to shore and no offshore topside structure at all. Replacing outlying wellhead towers, deviation drilling is used to reach different parts of the reservoir from a few wellhead cluster locations. Some of the common offshore structures are:
Shallow water complex, characterized by a several independent platformsw with different parts of the process and utilities linked with gangway bridges. Individual platforms will be described as Wellhead Platform, Riser Platform, Processing Platform, Accommodations Platform and Power Generation Platform. The picture shows the Ekofisk Field Centre by Phillips petroleum. Typically found in water depths up to 100 meters. Photo: Conoco Phillips Gravity Base. Enormous concrete fixed structures placed on the bottom, typically with oil storage cells in the “skirt” that rests on the sea bottom. The large deck receives all parts of the process and utilities in large modules. Typical for 80s and 90s large fields in 100 to 500 water depth. The concrete was poured at an at shore location, with enough air in the storage cells to keep the structure floating until tow out and lowering onto the seabed. The picture shows the world’s largest GBS platform, the Troll A during construction



Compliant towers are much like fixed platforms. They consist of a narrow tower, attached to a foundation on the seafloor and extending up to the platform. This tower is flexible, as opposed to the relatively rigid legs of a fixed platform. This flexibility allows it to operate in much deeper water, as it can 'absorb' much of the pressure exerted on it by the wind and sea. Compliant towers are used between 500 and 1000 meters water depth.
Floating production, where all topside systems are located on a floating structure with dry or subsea wells. Some floaters are:
FPSO: Floating Production, Storage and Offloading.
Typically a tanker type hull or barge with wellheads on a turret that the ship can rotate freely around (to point into wind, waves or current). The turret has wire rope and chain connections to several anchors (position mooring - POSMOR), or it can be dynamically positioned using thrusters (dynamic positioning – DYNPOS). Water depths 200 to 2000 meters. Common with subsea wells. The main process is placed on the deck, while the hull is used for storage and offloading to a shuttle tanker. May also be used with pipeline transport.
A Tension Leg Platform (TLP) consists of a structure held in place by vertical tendons connected to the sea floor by pile-secured templates. The structure is held in a fixed position by tensioned tendons, which provide for use of the TLP in a broad water depth range up to about 2000m. Limited vertical motion. The tendons are constructed as hollow high tensile strength steel pipes that carry the spare buoyancy of the structure and ensure limited vertical motion. A variant is Seastar platforms which are



miniature floating tension leg platforms, much like the semi submersible type, with tensioned tendons. SPAR: The SPAR consists of a single tall floating cylinder hull, supporting a fixed deck. The cylinder however does not extend all the way to the seafloor, but instead is tethered to the bottom by a series of cables and lines. The large cylinder serves to stabilize the platform in the water, and allows for movement to absorb the force of potential hurricanes. Spars can be quite large and are used for water depths from 300 and up to 3000 meters. SPAR is not an acronym, but refers to its likeness with a ship’s spar. Spars can support dry completion wells, but is more often used with subsea wells.
Subsea production systems are wells located on the sea floor, as opposed to at the surface. Like in a floating production system, the petroleum is extracted at the seafloor, and then can be 'tied-back' to an already existing production platform or even an onshore facility, limited by horizontal distance or “offset”. The well is drilled by a moveable rig and the extracted oil and natural gas is transported by
undersea pipeline and riser to a processing facility. This allows one strategically placed production platform to service many wells over a reasonably large area.
Subsea systems are typically in use at depths of 7,000 feet or more, and do not have the ability to drill, only to extract and transport. Drilling and completeion is performed from a surface rig. Horizontal offsets up to 250 kilometers, 150 miles are currently possible.




Main Process Sections

We will go through each section in detail in the following chapters. The summary below is an introductory short overview of each section


Wellheads

The wellhead sits on top of the actual oil or gas well leading down to the reservoir. A wellhead may also be an injection well, used to inject water or gas back into the reservoir to maintain pressure and levels to maximize production. Once a natural gas or oil well is drilled, and it has been verified that commercially viable quantities of natural gas are present for extraction, the well must be 'completed' to allow for the flow of petroleum or natural gas out of the formation and up to the surface. This process includes strengthening the well hole with casing, evaluating the pressure and temperature of the formation, and then installing the proper equipment to ensure an efficient flow of natural gas out of the well. The well flow is controlled with a choke.
We differentiate between dry completion with is either onshore or on the deck of an offshore structure, and Subsea completions below the surface. The wellhead structure, often called a Christmas tree, must allow for a number of operations relating to production and well workover. Well workover refers to various technologies for maintaining the well and improving its production capacity.


Manifolds/gathering
Onshore, the individual well streams are brought into the main production facilities over a network of gathering pipelines and manifold systems. The purpose of these is to allow set up of production “well sets” so that for a given production level, the best reservoir utilization, well flow composition (gas, oil, waster) etc. can be selected from the available wells. For gas gathering systems, it is common to meter the individual gathering lines into the manifold as shown on the illustration. For multiphase (combination of gas, oil and water) flows, the high cost of multiphase flow meters often lead to the use of software flow rate estimators that use well test data to calculate the actual flow.
Offshore, the dry completion wells on the main field centre feed directly into production manifolds, while outlying wellhead towers and subsea installations feed via multiphase pipelines back to the production risers. Risers are the system that allow a pipeline to “rise” up to the topside structure. For floating or structures, this involves a way to take up weight and movement. For heavy crude and in arctic areas, diluents and heating may be needed to reduce viscosity and allow flow.






Separation

Some wells have pure gas production which can be taken directly to gas treatment and/or compression. More often, the well gives a combination of gas, oil and water and various contaminants which must be separated and processed. The production separators come in many forms and designs, with the classical variant being the gravity separator.






In gravity separation the well flow is fed into a horizontal vessel. The retention period is typically 5 minutes, allowing the gas to bubble out, water to settle at the bottom and oil to be taken out in the middle. The pressure is often reduced in several stages (high pressure separator, low pressure separator etc.) to allow controlled separation of volatile components. A sudden pressure reduction might allow flash vaporization leading to instabilities and safety hazards. Photo: JL Bryan Oilfield Equipment

Gas compression

Gas from a pure natural gas wellhead might have sufficient pressure to feed directly into a pipeline transport system. Gas from separators has generally lost so much pressure that it must be recompressed to be transported. Turbine compressors gain their energy by using up a small proportion of the natural gas that they compress. The turbine itself serves to operate a centrifugal compressor, which contains a type of fan that compresses and pumps the natural gas through the pipeline.
Some compressor stations are operated by using an electric motor to turn the same type of centrifugal compressor. This type of compression does not require the use of any of the natural gas from the pipe; however it does require a reliable source of electricity nearby. The compression includes a large section of associated equipment such as scrubbers (removing liquid droplets) and heat exchangers, lube oil treatment etc.
Whatever the source of the natural gas, once separated from crude oil (if present) it commonly exists in mixtures with other hydrocarbons; principally ethane, propane, butane, and pentanes. In addition, raw natural gas contains water vapor, hydrogen sulfide (H2S), carbon dioxide, helium, nitrogen, and other compounds. Natural gas processing consists of separating all of the various hydrocarbons and
fluids from the pure natural gas, to produce what is known as 'pipeline quality' dry natural gas. Major transportation pipelines usually impose restrictions on the make






up of the natural gas that is allowed into the pipeline. That means that before the natural gas can be transported it must be purified. Associated hydrocarbons, known as 'natural gas liquids' (NGL) ar used as raw materials for oil refineries or petrochemical plants, and as sources of energy.


Metering, storage and export
Most plants do not allow local gas storage, but oil is often stored before loading on a vessel, such as a shuttle tanker taking the oil to a larger tanker terminal, or direct to crude carrier. Offshore production facilities without a direct pipeline connection generally rely on crude storage in the base or hull, to allow a shuttle tanker to offload about once a week. A larger production complex generally has an associated tank farm terminal allowing the storage of different grades of crude to take up changes in demand, delays in transport etc.
Metering stations allow operators to monitor and manage the natural gas and oil exported from the production installation. These metering stations employ specialized meters to measure the natural gas or oil as it flows through the pipeline, without impeding its movement.
This metered volume represents a transfer of ownership from a producer to a customer

(or another division within the company) and is therefore called Custody Transfer Metering. It forms the basis for invoicing sold product and also for production taxes and revenue sharing between partners and accuracy requirements are often set by governmental authorities.
Typically the metering installation consists of a number of meter runs so that one meter will not have to handle the full capacity range, and associated prover loops so that the meter accuracy can be tested and calibrated at regular intervals. Pipelines can measure anywhere from 6 to 48 inches in diameter. In order to ensure the efficient and safe operation of the pipelines, operators routinely inspect their pipelines for corrosion and defects. This is done through the use of sophisticated pieces of equipment known as pigs. Pigs are intelligent robotic devices that are propelled down pipelines to evaluate the interior of the pipe. Pigs can test pipe thickness, and roundness, check for signs of corrosion, detect minute leaks, and any other defect along the interior of the pipeline that may either impede the flow of gas, or pose a potential safety risk for the operation of the pipeline. Sending a pig down a pipeline is fittingly known as 'pigging' the pipeline.

The export facility must contain equipment to safely insert and retrieve pigs form the pipeline as well as depressurization, referred to as pig launchers and pig receivers Loading on tankers involve loading systems, ranging from tanker jetties to sophisticated single point mooring and loading systems that allow the tanker to dock and load product even in bad weather.

Utility systems
Utility systems are systems which does not handle the hydrocarbon process flow, but provides some utility to the main process safety or residents. Depending on the location of the installation, many such functions may be available from nearby infrastructure (e.g. electricity). But many remote installations must be fully self sustainable and thus must generate their own power, water etc.

Source :

Håvard Devold

© 2006 ABB ATPA Oil and Gas

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Introduction Valve (Jenis-jenis Valve)

VALVE

1.1 The Valve
1.1.1 Definition of a Valve

By definition, valves are mechanical devices specifically designed to direct, start, stop, mix, or  regulate the flow, pressure, or temperature of a process fluid. Valves can be designed to handle either liquid or gas applications.
By nature of their design, function, and application, valves come in a wide variety of styles, sizes, and pressure classes. The smallest industrial valves can weigh as little as 1 lb (0.45 kg) and fit comfortably in the human hand, while the largest can weigh up to 10 tons (9070 kg) and extend in height to over 24 ft (6.1 m). Industrial process valves can be used in pipeline sizes from 0.5 in [nominal diameter (DN) 15] to beyond 48 in (DN 1200), although over 90 percent of the valves used in process systems are installed in piping that is 4 in (DN 100) and smaller in size. Valves can be used in pressures from vacuum to over 13,000 psi (897 bar). An example of how process valves can vary in size is shown in Fig. 1.1.
Today’s spectrum of available valves extends from simple water faucets to control valves equipped with microprocessors, which provide single-loop control of the process. The most common types in use today are gate, plug, ball, butterfly, check, pressure-relief, and globe
valves.
Valves can be manufactured from a number of materials, with most valves made from steel, iron, plastic, brass, bronze, or a number of special alloys.

1.2 Valve Classification According to Function
1.2.1 Introduction to Function Classifications

By the nature of their design and function in handling process fluids, valves can be categorized into three areas: on–off valves, which handle the function of blocking the flow or allowing it to pass; nonreturn valves, which only allow flow to travel in one direction; and throttling valves, which allow for regulation of the flow at any point between fully open to fully closed. One confusing aspect of defining valves by function is that specific valve-body designs—such as globe, gate, plug, ball, butterfly, and pinch styles—may fit into one, two, or all three classifications.

For example, a plug valve may be used for on–off service, or with the addition of actuation, may be used as a throttling control valve. Another example is the globe-style body, which, depending on its internal design, may be an on–off, nonreturn, or throttling valve. Therefore, the user should be careful when equating a particular valve-body style with a particular classification.


1.2.2 On–Off Valves

Sometimes referred to as block valves, on–off valves are used to start or stop the flow of the medium through the process. Common on–off valves include gate, plug, ball, pressure-relief, and tank-bottom valves (Fig. 1.2). A majority of on–off valves are hand-operated, although they can be automated with the addition of an actuator (Fig. 1.3). On–off valves are commonly used in applications where the flow must be diverted around an area in which maintenance is being performed or where workers must be protected from potential safety hazards.

They are also helpful in mixing applications where a number of fluids are combined for a predetermined amount of time and when exact measurements are not required. Safety management systems also require automated on–off valves to immediately shut off the system when an emergency situation occurs. Pressure-relief valves are self-actuated on–off valves that open only when a preset pressure is surpassed (Fig. 1.4). Such valves are divided into two families: relief valves and safety valves. Relief valves are used to guard against overpressurization of a liquid service. On the other hand, safety valves are applied in gas applications where overpressurization of the system presents a safety or process hazard and must be vented.





1.2.3 Nonreturn Valves

Nonreturn valves allow the fluid to flow only in the desired direction. The design is such that any flow or pressure in the opposite direction is mechanically restricted from occurring. All check valves are non return valves (Fig. 1.5).Nonreturn valves are used to prevent backflow of fluid, which could damage equipment or upset the process. Such valves are especially useful in protecting a pump in liquid applications or a compressor in gas applications from backflow when the pump or compressor is shut down. Nonreturn valves are also applied in process systems that have varying pressures, which must be kept separate.

1.2.4 Throttling Valves

Throttling valves are used to regulate the flow, temperature, or pressure of the service. These valves can move to any position within the stroke of the valve and hold that position, including the full-open or fullclosed positions. Therefore, they can act as on–off valves also. Although many throttling valve designs are provided with a hand-operated


Manual handwheel or lever, some are equipped with actuators or actuation systems, which provide greater thrust and positioning capability, as well as automatic control (Fig. 1.6). Pressure regulators are throttling valves that vary the valve’s position to maintain constant pressure downstream (Fig. 1.7). If the pressure builds downstream, the regulator closes slightly to decrease the pressure. If the pressure decreases downstream, the regulator opens to build pressure. As part of the family of throttling valves, automatic control valves, sometimes referred to simply as control valves, is a term commonly used to describe valves that are capable of varying flow conditions to match the process requirements. To achieve automatic control, these valves are always equipped with actuators. Actuators are designed to receive a command signal and convert it into a specific valve position.


Figure 1.6 Globe control valve with extended bonnet (left) with quarter- turn blocking ball valves (right and bottom) in refining service. (Courtesy of Valtek International)



Figure 1.7 Preassure Regulator(Courtesy of Valtek International)

Using an outside power source (air, electric, or hydraulic), which matches the performance needed for that specific moment.

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ISO, Quality Assurance & Requirements

ISO 9000

Quality Assurance

Requirements

As we move into the next century, the terms quality assurance, quality management, and total quality control are becoming the new buzz words. Actually they are more than buzz words; they are reality for many American companies as well as foreign ones. The concept of total quality control (TQC) has been widely practiced in Japan for over a decade and is a way of life for Korean companies as well. With the collapse of the Berlin Wall, the unification of Germany, the European Common Market, the dismantling of the Communist party, and Asian communities beginning to band together, one international quality assurance standard for all nations seems to be most practical.
This chapter will discuss the latest requirements for these international
standards.

Introduction to ISO 9000 Standards

The International Organization for Standardization (ISO) is a worldwide federation of national standards bodies (ISO member bodies) that is headquartered in Geneva, Switzerland. The American National Standards Institute (ANSI) is the representative organization for the United States within the International Organization for Standardization federation. The purpose of the International Organization for Standardization is to develop internationally recognized standards to facilitate commerce worldwide and to enhance product safety.
The work of preparing international standards is normally carried out through ISO technical committees. Each member body or country interested in a subject for which a technical committee has been established has the right to be represented on the committee. In 1979, Technical Committee 176, Quality Assurance, was formed and in 1985 the ISO 9000 Series of Standards was circulated in draft form to the member bodies for approval. In 1987, following approval by a majority of the member bodies, the ISO 9000 Series of Standards became an international standard recognized worldwide.
Since the United States is a member of the International Organization for Standardization, the ISO 9000 series was concurrently adopted as an ANSI standard, the Q90 Series of Standards. ISO 9000
series standards and the ANSI Q90 series are identical in content. The ISO 9000–Q90 series consists of five standards:



The first document is ISO 9000, which is essentially an overview and guide for the series. This standard is entitled “Quality Management and Quality Assurance Standards—Guidelines for Selection and Use.”This document lists the reference standards applicable to the other standards, definitions useful for the establishment of an ISO quality assurance system, and characteristics of quality systems and gives generic quality assurance and control requirements regarding quality management, quality assurance, and quality control.
The next three documents (9001, 9002, 9003) provide three levels of generic quality system requirements that must be addressed within an ISO 9000 quality assurance program. The most stringent, ISO 9001, entitled “Quality Systems—Model for Quality Assurance in Design/ Development; Production, Installation, and Servicing,” establishes a model or guide for the manufacturer of pressure vessels to use in establishing a quality assurance program for design and/or development of their product. This ISO 9001 program includes 20 different quality
 points. Table 12.1 lists the 20 attributes and compares the requirements of ISO 9001 quality assurance requirements with those of ASME Code Section III, Nuclear Quality Assurance, requirements. There are close similarities. Note that the nuclear quality assurance program does not list statistical process control (SPC) nor does it address service (after service). Generally speaking, a holder of an ASME Code Section III Code symbol stamp already has many facets of an ISO 9001 program in place

Table. Comparison of Quality Assurance Requirements between ISO 9001

and ASME NQA-1

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PENGERTIAN GAS ALAM

Gas alam terbentuk dari berbagai macam hewan, tumbuhan dan mikroorganisme yang telah mati dan tertimbun di dalam lapisan tanah dengan rentan waktu yang cukup lama, ditambah dengan adanya tekanan dan temperatur yang tinggi di dalam lapisan bumi membuat ikatan karbon pada timbunan organik tersebut terlepas, sehingga berubah menjadi gelembung-gelembung gas.

Sering juga ditemui kandungan gas dan minyak bumi terdapat dalam satu ladang pengeboran yang sama, itu disebabkan semakin dalambya deposit tertimbun, maka semakin tinggi juga temperatunrya dalam lapisan bumi, biasanya pada temperatur yang tidak terlalu tinggi, akan mengandung minyak bumi yang relatif lebih banyak dibandingkan dengan gas bumi, begitupun dengan sebaliknya, kandungan gasnya akan lebih banyak jika temperatur lapisannya lebih tinggi.

Pengertian Gas Alam

Gas alam merupakan bahan bakar fosil yang terbentuk secara alami, gas alam merupakan campuran yang mudah terbakar serta tersusun dari gas-gas hidrokarbon yang dalam kondisi temperatur dan tekanan atmosfir akan berbentuk fase gas. Komposisi utama pada gas bumi ialah gas metana (CH₄) yang merupakan molekul hidrokarbon dengan rantai terpendek dan teringan, selain metana, terdapat juga kandungan hidrokarbon yang lebih berat seperti propana (C₃H₈), butana (C₄H₁₀), etana (C₂H₆), serta gas-gas yang mengandung sulfur. Gas alam biasanya ditemukan pada lokasi tempat pengeboran minyak bumi, tambang batu bara serta ladang gas itu sendiri.

Pemanfaatan Gas Alam

Pemanfaatan gas bumi sebagai sumber energi pada zaman sekarang, sudah banyak digunakan oleh berbagi macam sektor, dikarenakan karakteristiknya yang aman, bersih dan efisien. Pada keadaan murni, karakteristik lain dari minyak bumi yaitu tidak berbau, tidak berbentuk dan tidak berwarna sehingga lebih efisien dibandingkan dengan bahan bakar fosil lainnya, misalnya saja minyak bumi dan batu bara, karena gas bumi menghasilkan pembakaran yang sempurna (clean burning) sehingga hampir tidak menghasilkan emisi buangan yang dapat merusak lingkungan. 

Terdapat berbagi macam sektor yang memanfaatkan gas bumi seperti bahan bakar pembangkit listrik, bahan bakar industri dan tentunya bahan bakar untuk kendaraan bermotor. Selain sebagai bahan bakar, gas alam juga digunakan sebagai bahan baku produksi, misalnya bahan baku methanol, petrokimia, pabrik pupuk dan bahan baku plastik serta sebagai komuditas expor untuk pendapatan negara contohnya saja LNG (Liquid Natural Gas).

Karena gas alam terbentuk secara alami dan memerlukan waktu yang lama, maka gas alam digolongkan dalam sumber daya yang tidak dapat diperbaharui.

Sumber : Buku Pintar Migas

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PENGERTIAN CRUED OIL (MINYAK MENTAH)

Minyak mentah atau crude oil adalah cairan coklat kehijauan sampai hitam yang terutama terdiri dari karbon dan hidrogen. Teori yang paling umum digunakan untuk menjelaskan asal-usul minyak bumi adalah “organic source materials”. Teori ini menyatakan bahwa minyak bumi merupakan produk perubahan secara alami dari zat-zat organik yang berasal dari sisa-sisa tumbuhan dan hewan yang mengendap selama ribuan sampai jutaan tahun. Akibat dari pengaruh tekanan, temperatur, kehadiran senyawa logam dan mineral serta letak geologis selama proses perubahan tersebut, maka minyak bumi akan mempunyai komposisi yang berbeda di tempat yang berbeda.

Komposisi Minyak Bumi

Minyak bumi memiliki campuran senyawa hidrokarbon sebanyak 50-98% berat, sisanya terdiri atas zat-zat organik yang mengandung belerang, oksigen, dan nitrogen serta senyawa-senyawa anorganik seperti vanadium, nikel, natrium, besi, aluminium, kalsium, dan magnesium. Secara umum, komposisi minyak bumi terdiri dari Karbon (C) 84 – 87%, Hidrogen (H) 11 – 14%, Sulfur (S) 0 – 3%, Nitrogen (N) 0 – 1%, Oksigen (O) 0 – 2%.

Berdasarkan kandungan senyawanya, minyak bumi dapat dibagi menjadi golongan hidrokarbon dan non-hidrokarbon serta senyawa-senyawa logam.

1. Hidrokarbon

Golongan hidrokarbon-hidrokarbon yang utama adalah parafin, olefin, naften, dan aromatik.

1.1. Parafin

adalah kelompok senyawa hidrokarbon jenuh berantai lurus (alkana), CnH2n+2. Contohnya adalah metana (CH4), etana (C2H6), n-butana (C4H10), isobutana (2-metil propana, C4H10), isopentana (2-metilbutana, C5H12), dan isooktana (2,2,4-trimetil pentana, C8H18). Jumlah senyawa yang tergolong ke dalam senyawa isoparafin jauh lebih banyak daripada senyawa yang tergolong n-parafin. Tetapi, di dalam minyak bumi mentah, kadar senyawa isoparafin biasanya lebih kecil daripada n-parafin.

1.2. Olefin

Olefin adalah kelompok senyawa hidrokarbon tidak jenuh, CnH2n. Contohnya etilena (C2H4), propena (C3H6), dan butena (C4H8).

1.3. Naften

Naften adalah senyawa hidrokarbon jenuh yang membentuk struktur cincin dengan rumus molekul CnH2n. Senyawa-senyawa kelompok naften yang banyak ditemukan adalah senyawa yang struktur cincinnya tersusun dari 5 atau 6 atom karbon. Contohnya adalah siklopentana (C5H10), metilsiklopentana (C6H12) dan sikloheksana (C6H12). Umumnya, di dalam minyak bumi mentah, naftena merupakan kelompok senyawa hidrokarbon yang memiliki kadar terbanyak kedua setelah n-parafin.

1.4. Aromatik

Aromatik adalah hidrokarbon-hidrokarbon tak jenuh yang berintikan atom-atom karbon yang membentuk cincin benzen (C6H6). Contohnya benzen (C6H6), metilbenzen (C7H8), dan naftalena (C10H8). Minyak bumi dari Sumatera dan Kalimantan umumnya memiliki kadar aromat yang relatif besar.

2. Non Hidrokarbon

Selain senyawa-senyawa yang tersusun dari atom-atom karbon dan hidrogen, di dalam minyak bumi ditemukan juga senyawa non hidrokarbon seperti belerang, nitrogen, oksigen, vanadium, nikel dan natrium yang terikat pada rantai atau cincin hidrokarbon. Unsur-unsur tersebut umumnya tidak dikehendaki berada di dalam produk-produk pengilangan minyak bumi, sehingga keberadaannya akan sangat mempengaruhi langkah-langkah pengolahan yang dilakukan terhadap suatu minyak bumi.

2.1. Belerang

Belerang terdapat dalam bentuk hidrogen sulfida (H2S), belerang bebas (S), merkaptan (R-SH, dengan R=gugus alkil), sulfida (R-S-R’), disulfida (R-S-S-R’) dan tiofen (sulfida siklik). Senyawa-senyawa belerang tidak dikehendaki karena :

a. menimbulkan bau tidak sedap dan sifat korosif pada produk pengolahan.

b. mengurangi efektivitas zat-zat bubuhan pada produk pengolahan.

c. meracuni katalis-katalis perengkahan.

d. menyebabkan pencemaran udara (pada pembakaran bahan bakar minyak, senyawa belerang teroksidasi menjadi zat-zat korosif yang membahayakan lingkungan, yaitu SO2 dan SO3).

2.2. Nitrogen

Senyawa-senyawa nitrogen dibagi menjadi zat-zat yang bersifat basa seperti 3-metilpiridin (C6H7N) dan kuinolin (C9H7N) serta zat-zat yang tidak bersifat basa seperti pirol (C4H5N), indol (C8H7N) dan karbazol (C12H9N). Senyawa-senyawa nitrogen dapat mengganggu kelancaran pemrosesan katalitik yang jika sampai terbawa ke dalam produk, berpengaruh buruk terhadap bau, kestabilan warna, serta sifat penuaan produk tersebut.

2.3. Oksigen

Oksigen biasanya terikat dalam gugus karboksilat dalam asam-asam naftenat (2,2,6-trimetilsikloheksankarboksilat, C10H18O2) dan asam-asam lemak (alkanoat), gugus hidroksi fenolik dan gugus keton. Senyawa oksigen tidak menyebabkan masalah serius seperti halnya senyawa belerang dan senyawa nitrogen pada proses-proses katalitik.

3. Senyawa logam

Minyak bumi biasanya mengandung 0,001-0,05% berat logam. Kandungan logam yang biasanya paling tinggi adalah vanadium, nikel dan natrium. Logam-logam ini terdapat bentuk garam terlarut dalam air yang tersuspensi dalam minyak atau dalam bentuk senyawa organometal yang larut dalam minyak. Vanadium dan nikel merupakan racun bagi katalis-katalis pengolahan minyak bumi dan dapat menimbulkan masalah jika terbawa ke dalam produk pengolahan.

Sumber : Buku Pintar Migas

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CENTRIFULGAL PUMP

HEAD, FLOW, AND PRESSURE

Centrifugal Pumps:

Fundamentals

of Operation

HEAD

Centrifugal pumps are dynamic machines, which means that they convert velocity into feet of head. To explain this concept of converting speed or velocity into feet of head, let’s look at Fig. 29.1. This is the water intake section of the Chicago Water Treatment Plant. Water flows from Lake Michigan into a large concrete sump. The top of this sump is well above the level of Lake Michigan. The line feeding the sump extends three miles (3 mi) out into the lake. 

The long line is needed to draw water into the plant, away from the pollution along the Chicago lakefront. The pipeline diameter is 12 ft. Water flows in this line at a velocity of 8 ft/s. Six pumps, stationed atop the concrete sump, pump water into the water treatment plant holding tanks. One day, the plant experiences a partial power failure. Three of the six pumps shown in Fig. 1 shut down. A few moments later, the manhole covers on top of the sump blow off. Geysers of water spurt out of the manholes. What has happened?

FIGURE 1 Converting momentum into feet of head.

HYDRAULIC HAMMER

This is an example of water, or hydraulic, hammer. But what causes water hammer? Let’s consider the change in the water velocity in the 3-mi pipeline when half the pumps failed. The velocity in the pipeline dropped from 8 down to 4 ft/s. Velocity is a form of energy, called kinetic energy.

Energy can take several different forms:

• Heat (Btus)
• Elevation or potential energy
• Kinetic energy (miles per hour)
• Pressure (psig)
• Electrical power (amperes)
• Work (horsepower)
• Acceleration
• Chemical (heat of reaction)

About 250 years ago, Daniel Bernoulli first noticed two important things about energy:

• Energy in one form can be converted to energy in another form.
• While energy can be changed from one form to another, it cannot be created or destroyed.

This idea of the conservation of energy is at the heart of any process plant. In the case of the Chicago Water Treatment Plant, the reduced velocity of the water was converted into feet of head. That is,

the elevation of the water in the sump suddenly increased and blew

the manhole covers off the top of the sump.

MOMENTUM

If the length of the pipeline had been a few hundred feet, this incident would not have happened. It is not only the sudden reduction of the velocity of the water that caused an increase of the water level in the sump. It is also the mass of water in the 3-mi pipeline that contributed to the increased height of water in the sump. The combined effect of mass times velocity is called momentum.

The mass of water in our pipeline weighed 160 × 106 lb. This much water, moving at 8 ft/s, represents a tremendous amount of energy (about 500 million Btu per hour). If the flow of water is cut in half, then the momentum of the water flowing in the pipeline is also cut in half. This energy cannot simply disappear. It has to go somewhere. The energy is converted to an increase of feet of head in the sump; that is, the water level in the sump jumps up and blows the manhole covers off the top of the sump. Incidentally, this is a true story. Can you imagine what would have happened if all six pumps failed simultaneously due to an electric power failure? The result would be a dramatic lesson in the meaning of water hammer.

MY WASHING MACHINE

Figure 2 is a picture of our washing machine as it was originally installed. Whenever the shutoff valve on the water supply line closed, water hammer, or hydraulic shock, would shake the water piping. The momentum of the water flowing in the piping would be suddenly converted to pressure. If the end of a piping system is open (as into a sump), then the momentum of the water is converted to feet of head. But if the end of the piping system is closed, then the momentum of the water is converted to pressure. 

To fix this problem, I installed the riser tube shown in Fig. 3. The top of the riser tube is left full of air. Now when the water flow in the supply pipe is shut, the momentum of the water is converted to compression energy. That is, the air in the riser tube is slightly compressed, as indicated by the pressure gauge I installed at the top of the riser tube.

FIGURE 2 ConHydrolic Hammer Hits Home

FIGURE .3 Riser tube stops hydraulic hammer.

ACCELERATION

Let us imagine that the six pumps in Fig. 1 have not run for a few days. The water level in the sump and the level of Lake Michigan will be the same. I now start all six pumps at the same time. An hour later, the water level in the sump is 12 ft below the water level in the lake. This 12 ft is called “feet of head loss.” If the pipeline is 3 mi long, we say we have “lost 4 ft of head per mile of pipeline.” If we look down into the sump, what would we see happening to the water level during this hour? Figure 4 is a graph of what we would observe. The water level in the sump would drop gradually to 15 ft below the level in the lake. Then the water level in the sump would come partly back up to its equilibrium level of 12 ft below the lake level. Why?

FIGURE 4 Effect of acceleration.

The loss of 12 ft of head as the water flows through the pipeline is due to friction; that is, 12 ft of head are converted to heat. But why do we have a temporary loss of an extra 3 ft? The answer lies in the concept of acceleration. Let’s say you are driving your car onto the expressway. To increase the speed of your car from 30 to 65 miles per hour, you press down on the accelerator pedal. Having reached a velocity of 65 miles per hour, you ease off the accelerator pedal to maintain a constant speed. 

Why? Well, according to Newton’s second law of motion, it takes more energy to accelerate your car than to keep it in motion. Referring again to Fig. 1, the water in the 3-mi pipeline is initially stagnant. Its velocity is zero. An hour later, the water has accelerated to 8 ft/s. When you accelerate your car, the extra energy required comes from the engine. But when we accelerate the water in the pipeline, where does the extra energy come from? Does this extra energy come from the pumps? Absolutely not! The pumps are downstream of the pipeline and the sump. 

They cannot contribute any energy to an upstream pipeline. No, dear reader, the energy to accelerate the water in the pipeline must come from Lake Michigan. But what is the only source of energy that the lake possesses? Answer—elevation or potential energy. To accelerate the water in the pipeline to 8 ft/s requires more energy than to keep the water flowing at that same velocity. And this extra energy comes from the 3 ft of elevation difference between the water level in the sump and the water level in the lake. Once the water has reached its steady-state velocity of 8 ft/s, the need for this extra conversion of feet of head to acceleration disappears, and the water level in the sump rises to within 12 ft of the lake’s level

STARTING NPSH REQUIREMENT

The need to accelerate the fluid in the suction of a pump is called the starting net positive suction head (NPSH) requirement. To calculate this starting NPSH requirement, let’s assume:

• Suction line = 100 ft
• Eight-in line
• Fluid = water @ 62 lbs/ft3
• Initial velocity is zero
• Final velocity is 10 ft/s Then proceed as follows:
• Mass in line is 2170 lb

PRESSURE

Loss of Suction Pressure The need to accelerate liquid in the suction line of a pump leads to a difficult operating problem, which occurs on start-up. Just before the pump shown in Fig. 5 is put on line, the velocity in the suction line is zero. The energy to increase the velocity (i.e., accelerate) the liquid in the suction line must come from the pressure of the liquid at the pump’s suction. As the pump’s discharge valve is opened, the velocity

FIGURE 29.5 Loss of suction pressure causes cavitation

In the suction line increases, reducing the pressure at the suction of the pump. The faster the discharge valve is opened, the greater the acceleration in the suction line, and the greater the loss in the pump’s suction pressure. If the pressure at the suction of the pump falls to its bubble or boiling point, the liquid will start to vaporize. This is called cavitation. A cavitating pump will have an erratically low discharge pressure and an erratically low flow. As shown in Fig. 5, the bubble-point pressure of the liquid is the pressure in the vessel.

We usually assume that the liquid in a drum is in equilibrium with the vapor. The vapor is then said to be at its dew point, while the liquid is said to be at its bubble point. To avoid pump cavitation on start-up, the experienced operator opens the pump discharge valve slowly. Slowly opening the discharge valve results in reduced acceleration of the liquid in the suction line and a slower rate of the conversion of suction pressure to velocity. Try this test. To illustrate what I have just explained, try this

experiment:

1. Open the suction valve to a pump completely.
2. Crack open the case vent to fill the case with liquid. This is called “priming the pump.”
3. Open the pump discharge valve completely.
4. Push the motor START button.
5. Observe the pump suction pressure.

You will see that the pump suction pressure will drop and then come partly back up. If the pump suction pressure were 15 psig to start with, it might drop to 12 psig and then come up to 14 psig. The permanent difference in the suction pressure between 15 and 14 psig is due to a 1-psig piping friction pressure loss. The temporary difference in the suction pressure between 14 and 12 psig is due to a 2-psig conversion of pressure to velocity or kinetic energy. 

To review—all the energy needed to accelerate the liquid to the suction of a pump comes from the pump’s suction pressure. None of this energy comes from the pump itself. Or, as one clever operator at the Unocal Refinery in San Francisco explained to me, “Pumps push, but they do not suck.”

Pump Discharge Pressure

Figure 6 illustrates the internal components of an “overhung, single-stage” centrifugal pump. The term “overhung” refers to the feature that the pump has only an inboard, but no outboard, bearing. The inboard side of a pump means the end closest to the driver. The term “single-stage” means that there is only one impeller. Multistage pumps can have five or six impellers

FIGURE 6 A centrifugal pump.

The main components of the pump shown in Fig. 6 are

• Shaft—used to spin the impeller
• Coupling—attaches the shaft to the turbine or motor driver
• Bearings—support the shaft
• Seal—prevents the liquid inside the pump from leaking out around the shaft
• Impeller wear ring—minimizes internal liquid leakage, from
• the pump discharge, back to the pump suction
• Impeller—accelerates the liquid
• Volute—converts the velocity imparted to the liquid by the impeller to feet of head The impeller is the working part of a centrifugal pump. 

The function of the impeller is to increase the velocity or kinetic energy of the liquid. The liquid flows into the impeller and leaves the impeller at the same pressure. The location of the oval dot

shown at the top of the impeller in Fig. 6 is called the “vane tip.” The pressure at the vane tip is the same as the pump’s suction pressure. However, as the high-velocity liquid escapes from the impeller and flows into the volute, its velocity decreases. The volute (which is also called the diffuser) is shaped like a cone. It widens out in the manner illustrated in Fig. 7. As the liquid flows into the wider section of the volute, its velocity is reduced, and the lost velocity is converted—well, not into pressure, but into feet of head.

FIGURE 7 A volute or diffuser converts velocity into feet of head.

FEET OF HEAD

A centrifugal pump develops the same feet of head regardless of the density of the liquid pumped, as long as the flow is constant. This statement is valid as long as the viscosity of the liquid is below 50 to 100 cP or 200 to 400 SSU (Saybolt Seconds Universal). But, as process operators or engineers, we are not interested in feet of head. We are interested only in pressure. Differential pressure is related to

differential feet of head as follows:

The increase in pressure ΔP is also called head pressure. For example, if I have 231 ft of water in the glass cylinder shown in Fig. 29.8, it would exert a head pressure of 100 psig on the pressure gauge at the bottom of the cylinder. The head pressure would be

FIGURE 8 Head pressure compared to feet of head.

proportionally reduced as the liquid becomes less dense. For example, 231 ft of kerosene (which has 0.75 s.g.) would exert a head pressure of only 75 psig, because it is lighter than water.

EFFECT OF SPECIFIC GRAVITY

Figure 9 shows a centrifugal pump that may pump water through valve B or naphtha through valve A. Question: When water is pumped, the pump’s discharge pressure is 110.4 psig. The pump’s suction pressure is 10.4 psig. When naphtha is pumped, what is the pump’s discharge pressure?

Answer: The head pressure developed by the pump is

and the pump discharge pressure = 10.4 + 60 = 70.4 psig Next question: The pump is driven by an ordinary alternatingcurrent electric motor. It is running at 3600 rpm. When we switch from pumping water to naphtha, what happens to the speed of the pump?

Answer: Nothing. An AC motor is a fixed-speed machine. It will continue to spin at 3600 rpm. Next question: The pump is pulling 100 amps of electrical power. The flow rate is 100 GPM. If we now close valve B and open valve A, what happens to the amp load on the motor driver?

FIGURE 9 Effect of specifi c gravity on pump performance.

Answer: The power demand will go down to 60 amp. Amp(ere)s are a form of electrical work. The units of work are foot-pounds. The feet of head developed by the pump is not affected by the specific gravity of the liquid. But the weight of liquid pumped is proportional to the specific gravity. If the specific gravity drops by 40 percent, and the liquid volume (GPM) stays constant, then the pounds lifted by the pump drops by 40 percent and so does the electrical work.

Last question: Water is being pumped to a tank on a hill at 100 GPM. If we now switch to pumping a lighter fluid at the same rate, can we pump the lighter fluid to a higher elevation, only to a lower elevation, or the same elevation?

Answer: The same elevation. Centrifugal pumps develop the same feet of head at a given volumetric flow rate regardless of the specific gravity of the liquid pumped. This means the ability of the pump to push liquid uphill is the same even if the density of the liquid changes

PUMP CURVE

The feet of head developed by a pump is affected by the volume of liquid pumped. Figure 10 is a typical pump curve. As the flow of liquid from a centrifugal pump increases, the feet of head developed by the pump goes down, as does the pump discharge pressure. A pump curve has two general areas. These are the flat portion of the curve and the steep portion of the curve. We normally design and operate a pump to run toward the end of the flat portion of its curve. A centrifugal pump operating on the flat portion of its curve loses only a small portion of its discharge pressure when flow is increased. 

This is a desirable operating characteristic. A centrifugal pump operating on the steep portion of its curve loses a large portion of its discharge pressure when flow is increased. Pumps operating quite far out on their curve will have an erratic discharge pressure, as the flow through the pump varies. For one such pump, I have seen the discharge pressure drop from 210 to 90 psig as the flow increased by 40 percent. The flow through this pump was regulated by a downstream level-control valve. The discharge pressure varied so erratically that the operators thought the pump was cavitating.

DEVIATION FROM PUMP

Pumps always perform on their performance curve. It is just that they do not always perform on the manufacturer’s performance curve

FIGURE 29.10 Centrifugal pump curve.

The dotted line in Fig. 7 compares an actual performance curve to the manufacturer’s performance curve. Why the deviation?

• The manufacturer’s curve was generated using water. We are pumping some other fluid, perhaps with a much higher viscosity.
• The clearance between the impeller and the impeller wear ring (Fig. 6) may have increased as a result of wear.
• The impeller itself may be worn, or the vane tips at the edge of the impeller might be improperly machined.
• If the pump is driven by a steam turbine, the pump speed could be lower than in the design.
• Available NPSH may be marginal.

DRIVER HORSEPOWER

Normally, increasing the flow from a centrifugal pump increases the amperage load on the motor driver, as shown in Fig. 11. Driver horsepower is proportional to GPM times feet of head. As shown in Fig. 10, as the flow increases the feet of head developed by the pump decreases. On the flat part of the pump curve, the flow increases rapidly, while the head slips down slowly. Hence the product of GPM times feet of head increase. On the steep part of the pump curve, the flow increases slowly, while the head drops off rapidly. Hence, the product of GPM times feet of head remains the same, or goes down.

FIGURE 11 Horsepower requirement for a centrifugal pump.

The response of the amp load on the motor driver is an indication of pump performance. A pump operating on the proper, flat portion of its curve will pull more motor amps as flow increases. A pump operating on the poor, steep portion of its curve will not pull more amps. If the manufacturer’s horsepower/flow curve indicates that more horsepower is required as flow is increased, but the motor amp load is not increasing, then something is wrong with the pump. The amp meter for a pump is best located right on the start-stop box next to the motor. Unfortunately, more often, the only amp meter is located on the electrical breaker box, which is at a remote location.

PUMP IMPELLER

Impeller Diameter

The pump impeller resembles a hollow wheel with radial vanes. The diameter of this wheel can be trimmed down on a lathe. If an impeller with a 10-in diameter is trimmed down to 9 in, it will have a new performance curve below its former performance curve. Both the flow and head of the pump will be reduced. Also, the amp load on the motor driver will decrease. As a rough rule of thumb, reducing a pump’s impeller diameter by 10 percent will reduce the amp load by 25 percent. Not only will this save electricity, but the motor will run much cooler. 

Unloading the motor by 25 percent may increase the life of the motor windings by 10 years. When the control valve downstream of a pump is operating in a mostly closed position, the pump is a good candidate to have its impeller trimmed. Sometimes, the pressure drop across a control valve is so huge (≥100 psi) that it makes a roaring sound. The energy represented by this wasteful ΔP is coming from the electricity supplied to the pump’s motor. 

Hence, trimming the impeller also reduces wear because of erosion in downstream control valves. We frequently increase the size of impellers to increase pump capacity and discharge pressure. However, many chemical plants break the law when they do so. State boiler codes require that vessels and heat exchangers downstream of pumps be rated for the

• Maximum pump discharge pressure
• At the maximum specific gravity that can reasonably be expected
• Unless the equipment is protected by a relief valve

Increasing the size of an impeller always increases its maximum discharge pressure. Hence, increasing the impeller diameter may be unlawful, depending on the maximum allowable working

pressure (MAWP) of downstream heat exchangers. The MAWP is shown on the exchanger name plate. Increasing the size of the impeller by 10 percent will increase the amperage load on the motor driver by 30 percent. For many process pumps, this would require a new motor and breaker to support the larger impeller.

Trimming the pump impeller on a lathe also requires the reshaping of the tips of the impeller vanes. Most often, this requirement is ignored, and the revamped pump operates below its expected curve.

Rather than worry about these fine points, it is best to order new impellers directly from the manufacturer. Installing a larger impeller may require an upgrade in the pump bearings and the mechanical seal. While it is good practice to purchase a pump with a seal and bearings rated for the

maximum impeller size, some pumps can have bearings and seals rated only for their purchased impeller size. 

For process people, the only practical method to check that a pump’s seal and bearings are suitable for the larger impeller is to check with the manufacturer. Drilling pressure balancing holes in the hub of the impeller helps to reduce the extra strain on the bearings of a larger impeller. Sometimes installing a full-sized impeller causes the pump to vibrate. This happens because of a disturbance to the liquid as the vanes spin past the volute or diffuser (i.e., the case outlet opening).

Exxon had, at one time, a standard of keeping impeller sizes at not more than 92 percent of the full impeller diameter. This seems a conservative practice to me. I have usually kept impeller sizes in my

revamp designs 0.25 to 0.5 in below maximum. I don’t recall any of my clients complaining that such pumps vibrated as a result of the enlarged impeller. On the other hand, for a new installation, now that I’ve learned of the Exxon standard, I plan to follow it in my process design work.

IMPELLER ROTATION

Motor-driven pumps often are found running backward. If the motor is wired up backward (this is called reversing the polarity of the leads), the pump will run with the impeller spinning backward. This will reduce the pump’s discharge pressure, sometimes by a little (10 percent) and sometimes by a lot (90 percent). It depends on the design of the impeller. You cannot see the direction of rotation of a pump, but if you touch a pencil to the spinning shaft, you can feel the direction of rotation. The correct direction of rotation is indicated by an arrow stamped on the top of the pump case. There are right- and left-handed pumps. So two otherwise identical pumps may have opposite directions of rotation.

Capacity EFFECT OF TEMPERATURE ON PUMP CAPACITY

We wish to increase the capacity of a centrifugal pump. Should we make the liquid hotter or colder? Let’s make a few assumptions:

• Cooling the liquid will not increase its viscosity above 30 or 40 cSt.
• We are pumping hydrocarbons. Cooling many hydrocarbons by 100°F increases their density by 5 percent.
• The pump’s motor is somewhat oversized.

On this basis, cooling the liquid by 100°F will raise the pump’s discharge pressure by 5 percent. If the pump is developing 1000 psig of differential pressure, cooling the liquid by 200°F will increase its discharge pressure to 1100 psig. If the discharge control valve is now opened, the pump’s discharge pressure will drop back to 1000 psig as the flow increases. The discharge pressure drops because the pump develops less feet of head at a higher flow rate.

Source : Digital Engineering Library @ McGraw-Hill

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