SLICKLINE

Slickline refers to a single strand wire which is used to run tools into wellbore for several purposes. It is used in the oil and gas industry, but also describes that niche of the industry that involves using a slickline truck or doing a slickline job.
Slickline looks like a long, smooth, unbraided wire, often shiny, silver/chrome in appearance. It comes in varying lengths, according to the depth of wells in the area it is used (it can be ordered to specification) up to 35,000 feet in length. It is used to lower and raise downhole tools used in oil and gas well maintenance to the appropriate depth of the drilled well. In use and appearance it is connected by the drum it is spooled off of in the back of the slickline truck to the wireline sheave a round wheel grooved and sized to accept a specified line and positioned to redirect the line to another sheave that will allow the slickline to enter the wellbore.^[1] Slickline is used to lower downhole tools into an oil or gas well to perform a specified maintenance job downhole. Downhole refers to the area in the pipe below surface, the pipe being either the casing cemented in the hole by the drilling rig (which keeps the drilled hole from caving in and pressure from the various oil or gas zones downhole from feeding into one another) or the tubing, a smaller diameter pipe hung inside the casing.

Slickline is more commonly used in production tubing. The wireline operator monitors at surface the slickline tension via a weight indicator gauge and the depth via a depth counter 'zeroed' from surface, lowers the downhole tool to the proper depth, completes the job by manipulating the downhole tool mechanically, checks to make sure it worked if possible, and pulls the tool back out by winding the slickline back onto the drum it was spooled from. The slickline drum is controlled by a hydraulic pump, which in turn is controlled by the 'slickline operator'.

Slickline comes in different sizes and grades. The larger the size, and higher the grade, generally means the higher line tension can be pulled before the line snaps at the weakest spot and causes a costly 'fishing' job. Due to downhole tools getting stuck because of malfunctions or 'downhole conditions' including sand, scale, salt, asphaltenes, and other well byproducts settling or loosening off the pipe walls because of agitation either by the downhole tools or a change in downhole inflow, sometimes it is necessary to pull hard on the tools to bring them back uphole to surface. If the tools are stuck, and the operator pulls too hard, the line will snap or pull apart at the weakest spot, which is generally closer to surface as the further uphole the weak point in the line is, the more weight it has to support (the weight of the line).

Weak spots in the line can be caused by making the circle around the counter wheel, making a bend around a sheave, a kink in a line from normal use (when rigging up the equipment extra line must be pulled out from the truck to give enough slack when the pressure control lubricator is picked up - this leaves line coiled on the often rutted ground, and sometimes it snags and kinks the line).
When the slickline parts, this can create an expensive 'fishing' job. It is called fishing because you often have to try different 'fishing' tools until you get a 'bite', then you have to work the original tools downhole free, or cut off the slickline where they join the tools downhole so that you can pull the broken slickline back to surface and out of the way, in order to fish the stuck toolstring. Because of the downtime involved in 'fishing', meaning not being able to flow the oil/gas well, the client is losing money by lack of production and also the cost of the slickline unit to fish, and the cost of what is left in the hole if it is not fished out (in the oil/gas industry, if the cause of the fishing job was not the fault of the slickline company, the oil/gas company is usually responsible to pay for it, and it can be very expensive).

Slickline was originally called measuring line, because the line was flat like a tape measure, and marked with depth increments so the operators would know how deep in the hole they were. This probably changed because the flat measuring line wasn't as strong as the modern slickline, and separate depth counters were developed. It is advantageous to keep the diameter of the wire as small as possible for the following reasons:

• It reduces the load of its own weight.
• It can be run over smaller diameter sheaves, and wound on smaller diameter spools or reels without overstressing by bending (where the wire bends makes it weaker. Where it makes a complete circle, such as a counter wheel, makes it weaker yet).
• It keeps the reel drum size to a minimum (which reduces the area needed in the back of the slickline unit to house the drum and hydraulic pump, reducing weight and leaving more room for the other specialized equipment needed for slickline operations).
• It provides a small cross-section area for operation under pressure.

The disadvantage of a smaller diameter slickline is the lower strength. Depth and the nature of the job (a tool that must be pulled hard or might be stuck) will affect what slickline truck (different trucks specialize in different sizes of line) used.
The sizes of solid wireline in most common uses are: 0.092", 0.108", 0.125", 0.140", 0.150", and 0.160" in diameter, and are obtainable from the wire-drawing mills in one-piece standard lengths of 18,000, 20,000, 25,000 and 30,000 foot lengths. Other diameters and lengths are usually available on request from the suppliers, with the largest size currently available at 0.188".

Mechanical and Hydraulic Jars

Slickline tools operate with a mechanical action, controlled from surface in the wireline trucks operators compartment. Typically, this mechanical action is accomplished by the operation of jars. There are generally two types of jars; mechanical and hydraulic.
Mechanical jars look like a long, tubular piece of machined metal that slides longer or shorter approximately 75% to 90% of its total length. They give the effect of hammering on the downhole tools. The weight or hit of the 'hammer' depends on how much sinker bar is added above the jars. Generally, a slickline operator controls the downhole tools with taps and hits from the sinker bar via the mechanical jars, controlled at surface by lowering or raising the toolstring and monitoring weight, depth, and pressure. Mechanical jars for slickline can hit up or down the hole, making them a versatile form of jarring.
Hydraulic jars for slickline are generally meant to jar up only, because not enough sinker bar is able to feasibly be lubricated in to jar down on the downhole tools. Hydraulic jars work by the operator pulling up on the line, which puts an upward force on the top of the hydraulic jars. The bottom of the hydraulic jars is usually attached by threaded connection to the mechanical jars, which are attached to the downhole tools. Depending on how hard the operator pulls on the hydraulic jars will affect how fast they hit, and how hard they hit. When the top is pulled on, the inner mandrel begins to slide upwards. It has a restriction in it that hydraulic fluid has to bypass as it is pulled upwards, until it reaches an area of no restriction, allowing it to slide rapidly. The reason for the initial tighter restriction is to allow the operator to pull his line to the desired hitting range.
Generally once he hits that range on his weight indicator, he waits while the jars open to the less restricted point, whereupon the sinker bar travels upwards rapidly, providing an upwards hit on the downhole tools. The jars can then be 'reset' by lowering the line until the weight of the sinker bar closes, or pushes the inner mandrel of the hydraulic jars back to the starting position. Because the hydraulic jars are designed to provide a wait time to allow the operator to get up to the desired line tension, they can provide a very effective upwards hit.
Mechanical jar and hydraulic jar hitting power is affected by the length of the jars (the longer the length, they faster they can travel before they stop), the mass of the weight above them (the more the mass, the harder they will hit), and the tension of the line pulling on them.
Some completion components may be deployed and retrieved on slickline such as wireline retrievable safety valves, battery powered downhole gauges, perforating, placing explosively set bridge plugs, and placing or retrieving gas lift valves. Slickline can also be used for fishing, the process of trying to retrieve other equipment and wire, which has been dropped down the hole.

Applications

The most common applications for slickline are:

• Tagging T.D. (Total Depth, which is the furthest depth possible down the wellbore)
• Gauge Ring runs (which is running a special sized downhole tool called a gauge ring, which comes in various pre-machined diameters, designed to ensure the pipe is clear to a certain point)
• Tubing Broach / Plunger Installations (a tubing broach looks like an aggressive, tubular file, available in different diameters, used for removing burrs and crimps in the inside of tubing and casing in oil and gas wells)
  
  

  

  Tubing Broach

  
  
• Bailing sand and debris (removing formation sand/rock and other such debris left over from the drilling and completion of the well, using a specialized tool called a bailer. This tool uses either a Chinese water pump type stroke action or a hydrostatic vacuum action to suction up the downhole debris, allowing it to be conveyed back to surface via the wireline)
• Shifting sleeves (formations downhole can be isolated behind sliding metal 'windows' called sliding sleeves. They are shifted open or closed by means of a specialized shifting tool locating the sleeve and it being jarred up or down, providing access or closing off that formation or section of casing)
• Setting / Pulling plugs and chokes (specialized downhole tools which either lock into pre-machined restrictions in the tubing, or which lock into the tubing itself, sealing pressure from below or above the plug)
• Setting / Pulling gas lift valves
• Running tailpipes (tubing extensions where the tubing is not landed close enough to the formation perforations in the casing)
• Bottom hole pressure and temperature surveys (specialized electronic and mechanical tools designed to measure the pressure and temperature at predetermined depths in the wellbore. This data can be used to determine reservoir life)
• Spinner Surveys (to determine which formation perforations have the best inflow / which perforations make the most water / liquids)
• Kinley perforator, sandline cutter, and caliper
• Running production logging tools
• Fishing operations (fishing usually refers to attempting to retrieve lost tools or wire, or other debris that was not intended to restrict the flow / disrupt the well operations. Fishing can be difficult, due the fish being downhole, and other affecting conditions such as high pressure, the fish being jammed in the tubing / casing)
• Paraffin cutting (making a hole through and removing a wax buildup, which is a byproduct of oil cooling too much to reach surface)
• Chipping ice / salt (restrictions and plugs which can be formed as by products of a flowing well)
• Lubricating long assemblies in and out of the hole (lubricating is done via a larger than tool overall diameter pipe, joined at surface on top of the wellhead, which houses the valve that shuts the pressure in downhole. The lubricator should be long enough to be able to swallow the toolstring and downhole tools that are to be run or pulled)

Braided line

Braided line is generally used when the strength of slickline is insufficient for the task. Most commonly, this is for heavy fishing such as retrieving broken drill pipe. The most common use for braided line is fishing electric line tools.

Slickline Tools

Jar

This type of tool can be extended and closed rapidly to induce a mechanical shock to the tool string. This shock can induce certain components such as plugs to lock into place and then unlock for retrieving. Jars are commonly used to shear small brass or steel pins that are put in place to function certain down-hole tools at a certain moment. The operator can use the jars to shear the pins at a predetermined depth. Spang jars are manually operated by the wireline operator who either lifts or lowers wire rapidly, requiring a great deal of expertise. Power jars use springs or built-in hydraulics to give an upward jarring motion where greater force is required.

Stem

Stem essentially just serves to add weight to the toolstring. The weight may be necessary to overcome the pressure of the well. Some variations of stem, called roller stem, may have wheels built into the tool to allow the tool string to glide more easily down moderately deviated wells. Stem give the hammering action to the tool string which in turn allows the jars to transmit the force given by the movement of the stems bars. Depending on well conditions extra small OD stems are use or extra large. The range can be from .75" to 3.50" OD and the stems normally come in 2 ft, 3 ft or 5 ft lengths. The connection to the rope socket or other tools can be a threaded connection or a QLS system (quick connect).

Pulling tools

These are tools designed for fishing other wireline components which have been dropped down hole. All wireline tools are designed with 'fishing necks' on their top side, intended to be easily grabbed by pulling tools. Pulling tools are also used for retrieving seated components such as plugs.

Gauge Cutter (Gauge Ring)

A gauge cutter is a tool with a round, open-ended bottom which is milled to an accurate size. Large openings above the bottom of the tool allow for fluid bypass while running in the hole. Most often a gauge ring will be the first tool ran on a slickline operation. A gauge ring that is just undersized will allow the operator to ensure clear tubing down to the deepest projected working depth; for example 2 7/8" tubing containing 2.313" profiles would call for a gauge ring between 2.25" - 2.30". A gauge ring can also be used to remove light paraffin that may have built up in the tubing. Often a variety of different sized gauges and/or scratchers will be run to remove parafin little by little.Gauge cutter can be used for drift runs also.

Lead impression block

If an obstruction is found downhole, a lead impression block can be run to help determine its nature. The LIB has a malleable lead base in which the obstruction can leave an impression when they meet. The LIB is called Wireline Camera because of its function to mark any object downhole. They are also sometimes called "confusion" blocks because they only give a two-dimensional view of the down-hole object, making it hard for an inexperienced person to determine what three-dimensional object is in the hole

Downhole bailer

Bailers are downhole tools that are generally long and tubular shaped, and are used for both getting samples of downhole solids (sand, scale, asphaltines, rust, rubber and debris from well servicing operations) and for 'bailing' the unwanted downhole solids from the well. Bailers are attached either via threaded connection or releasable downhole tool to the wireline toolstring, and are manipulated from surface by the wireline operator. Bailers usually have an interchangeable bottom (the shoe) which also houses a check to keep the solids from falling or washing out of the bottom.

Sample bailer

A sample bailer is generally around a meter long, and has a hollow tube (the barrel) usually around 40 mm in diameter, with a 'ball check' on the bottom and an opening at the top. This tool is beat downwards into the as yet unknown obstruction using the mechanical jars and weight above of the wireline toolstring. Generally, after a predetermined amount of 'hits', hopefully allowing a usable sample of solids to fill the barrel. When the tool is pulled upwards, the solids usually (hopefully) settle the ball check onto its 'seat', which will keep the solids in the barrel during the return trip to surface, where the solids can be inspected to determine what the downhole obstruction was. This procedure can be 'hit and miss', the success depending on how readily the solid was accepted into the barrel, and if the ball check was properly seated on the return trip to surface. If the ball check is not seated (sometimes a large, hard piece of solid will sit in between the ball and seat) downhole fluids tend to 'wash' the sample out of the bottom of the sample bailer, leaving the inspectors at surface wondering if the tool actually collected a sample. Persistence is generally a good rule of thumb with this tool.

Stroke bailer

A stroke bailer functions like a 'Chinese water pump', and is used to collect unwanted solids from the wellbore. A stroke bailer is long and tubular looking, with a smaller rod that extends from the top, a hole in the bottom, and is generally around 7 meters long, but the length depends on how much barrel section is added to the bailer. The barrel 'free floats' on the stroke rod, which is attached to the wireline toolstring. The tool is usually 'spudded' into the downhole solid, then the wireline toolstring is pulled upwards, which in turn pulls the stroke up through the barrel. Ideally, this draws the downhole solid in through the bottom 'shoe' of the tool, past the check and into the barrel for collection. The tool is usually stroked either a predetermined number of times, or until it appears the tool is not stroking, which can mean either it is full, or stuck.

Hydrostatic bailer

A hydrostatic bailer functions like a 'vacuum', and is used to suck up unwanted solids from the wellbore. A hydrostatic bailer is generally around 2.5 meters long and is tubular looking, with two 10 mm holes on opposing sides at the top of the tool, and a hole in the bottom. A hydrostatic bailer uses a pinned plug with o-ring seals at the bottom, and a plug at the top to maintain the surface pressure that it was assembled at (nominally around 100 kPa) all the way to the bottom of the well, whereupon it is spudded into the downhole solids, which ideally pushes the shoe into the bottom plug, which shears the pin on the bottom plug. An oil or gas well's pressure downhole is always more than atmospheric pressure at surface, due to the formation pressure, and a combination of depth and hydrostatic weight of wellbore fluids. Sometimes fluid will be added to the wellbore to assist in bailing by bringing up the pressure, and also lubricating the downhole solid. Because the pressure inside the bailer is much less than the downhole wellbore pressure, any solids that are loose enough are 'sucked up' by the vacuum formed when the bottom plug is sheared and travels upwards through the barrel, followed by the solids. At the same time, due to the changed from negative pressure to positive pressure, the top plug pops out (and is caught by the top part of the tool), and excess flow is directed out through the 10 mm ports on the sides of the top of the tool. These ports allow the barrel to fill more readily. Then the bailer is returned to surface where it is taken apart, the solids are emptied, and it is cleaned and serviced with new o-ring seals. Care must be taken when disassembling at surface as the tool is potentially charged with the downhole pressure (possibly many tens of thousands of kpa) and may 'blow apart' when being unthreaded if not bled off first.

Running Tools

These tools are primarily used to 'set' plugs into locking profiles (nipples) located in the tubing; however, the term 'running tool' refers to a downhole tool attached to the wireline toolstring that is used to 'run' another tool that is meant to be left downhole when the toolstring returns to surface. In general, a running tool is attached to a downhole 'locking tool' that locates and locks into the selected downhole profile (nipple). The 'locking tool', or 'lock' for short, can be attached via threaded connection to the top of a variety of different tools, including but not limited to, downhole chokes (flow rate restrictors sized according to a pre-determined calculation), one-way check valves (TKX style plugs), instrument hangers, and most commonly, tubing plugs. The lock is fitted onto the running tool and attached using shear pins made of brass or steel. When the target profile is reached the lock can be set by seating the lock into the profile using mechanical jars (spangs) until the locking keys have locked the lock into the profile, whereupon the operator usually 'pull tests' the lock to give an indication it is properly 'set', then shears off the shear pins with his mechanical or hydraulic jars to allow the 'toolstring' to return to surface. There are many different types of running tools, some are mechanically complex and able to be made 'selective' in order to pass through profiles in order to reach one of the same size but a different depth; some are relatively simple, such as an 'F' collarstop running tool, which is essentially a metal rod which fits inside the collarstop downhole tool which is pinned in place

Source : Wikipedia

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SUBSEA PROCESSING

Subsea processing benefits

As oil and gas production moves into deeper water, the cost of surface production platforms becomes prohibitively high. The industry has found that surface facilities must be kept to a minimum and shared by satellite fields to be commercial. Subsea processing is a key toward a cost-effective, “hub-and-spoke” development (Fig. 1), allowing the industry to operate successfully in deeper water.

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  Fig. 1—Spar hub-and-spoke concept.

Visit other topic : Risk of Oil and Gas

Advantages of subsea processing

Subsea processing refers to the separation of produced fluids into gas and liquid—or gas, oil, and water—for individual phase transport and disposal (in the case of water). The liquid stream can be pumped to a central facility for final processing. The gas stream can be transported under natural pressure or pressure boosted (compressed) to the host facility.

The current practice is to flow produced fluids from subsea wells directly back to a central surface processing facility in multiphase (gas, oil, and water) pipelines, known as a “subsea tieback” field development. Because reservoir pressure is the only source of energy to overcome all the impediments to flow [e.g., pressure drop through the formation, wellbore, tubing (friction and static head), tree, flowline, and so on] well productivity for normally pressured reservoirs tends to be low, and the “tieback” distance is typically limited to less than 25 miles. In addition, multiphase pipelines potentially have many flow-assurance problems, like:

• fluid slugging
• hydrate formation
• wax deposition
• solids dropout

Subsea processing offers a technical solution to many of these problems. It can accomplish the following:

• Improve well productivity with greater pressure drawdown.
• Increase ultimate recovery by extending economic life.
• Eliminate fluid surges by use of single-phase pipelines.
• Avoid gas hydrates with no inhibition or with reduced inhibitor dosage.
• Prevent solids dropout by allowing higher liquid-flow velocities.
• Allow online pigging to control wax deposition in oil pipelines.
• Reduce capital and operating costs by reducing surface processing needs.

Improved reservoir productivity

A key benefit of subsea processing (separation and liquid pumping) is greater pressure drawdown, which results in higher production rates and greater oil and gas recovery. Separating the produced fluids on the seabed allows the liquid to be pressure-boosted with an efficient conventional mechanical pump. Single-phase pumping overcomes the static backpressure of the fluid column from the seafloor to the surface, and it avoids the excessive pressure drop and surges of multiphase flow.

As illustrated in Figs. 2 (left) and 2 (right), for a typical deepwater development in 6,000 ft of water, flowing tubing pressure at the seabed may be 1,800 psi, even with a separator inlet pressure of only 200 psi on the platform. Much of the 1,600-psi pressure drop takes place because of hydrostatic head of the fluid (gas and liquid) column. If the separator can be located at the seabed, a significant portion of the 1,600 psi can be used as additional reservoir pressure drawdown. Assuming a modest productivity index (PI) of 5 bbl/psi, a production increase of 8,000 B/D per well may be realized. As reservoir pressure declines, reduced backpressure may extend the productive life of the field and increase ultimate hydrocarbon recovery. Because productivity and reserves recovered per well are key to field economics, use of subsea processing can greatly enhance the value of some deepwater developments.

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  Fig. 2—Subsea separation and pumping application in typical deepwater developments.

Deepwater and long-distance tiebacks

Subsea processing moves the productivity limiting influences to the seabed and decouples the reservoir development from water depth. The source of flowing tubing pressure drop is only between the wellbore and seabed, rather than all the way up to the platform elevation. This has greater impact as production advances into deeper water, especially for shallow, low-pressure reservoirs in deep water. Similarly, the pressure-boosting benefits of subsea processing will enable longer distances from the subsea tieback to a host platform. Most direct subsea tiebacks are limited to approximately 25 miles because of available flow energy from the reservoir.

With subsea separation and liquid pumping, most of the energy required to transport the produced fluid is supplied by mechanical means rather than totally by reservoir pressure. Subsea liquid pumps are currently available for most applications. Separator gas can flow long distances under natural pressure. As advances are made into large-capacity subsea power supply and compressor systems, subsea gas compression will become another viable option, enabling smaller pipeline size and even longer transport distances.

Flow assurance

Flow-assurance problems such as multiphase flow, hydrate formation, and wax deposition are detrimental to deepwater and long-distance subsea tieback projects. In a direct tieback, major operational difficulties can be caused by:

• fluid slugging
• excessive pipeline pressure drop
• startup dynamics

Such issues can require large investments in topside facilities. Gas hydrate formation is difficult to avoid in the high-pressure, cold deepwater environment. Using insulated and heated bundles and large quantities of chemical inhibitors are costly and not effective under all circumstances. With waxy crude production, pipeline plugs are a constant challenge. Because there is no universal inhibitor for wax, finding an effective chemical for a particular crude is always uncertain and sometimes not possible. Regular round-trip pigging (in a dual pipeline system, sending a pig from the host platform to the subsea well manifold and returning it by a crossover into the other pipeline) is the only reliable solution. But this method of pigging requires production shutdown that can be lengthy because of difficulties in restarting the wells and re-establishing flow.

Subsea processing can be a cost-effective solution to flow-assurance problems. In a subsea system depicted in Fig. 3, wellstreams are separated and transported in separate pipelines, which eliminates multiphase flow and associated problems. Separator gas entering the pipeline is saturated with water; therefore, hydrate formation is still a concern. However, the amount of water that must be inhibited to prevent hydrates is relatively small and very predictable. This eliminates the need for overinjection of inhibitor to combat water slugs and allows the use of the more environmentally friendly inhibitor, glycol, which can be easily recovered and regenerated at the host platform. Unlike methanol, glycol has a very low vapor pressure and is less prone to vaporization losses.

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  Fig. 3—Subsea separation and pumping system.

With waxy crude pipelines, regular and frequent pigging is the only sure way to guard against wax plugs. An automatic subsea pig launcher, working in conjunction with a subsea separation and pumping system, may solve the problem. Because the system downstream of the separator is decoupled from the flowing wells and the reservoir, it is possible to pig online without production interruption. Any additional frictional pressure drop because of pigging can be overcome by the pump. Similarly, flow velocity in the pipeline can be kept high (at the expense of horsepower) to avoid produced-solids dropout, if that is a problem. With a replaceable multipig cartridge, pigs can be launched on a regular basis at a time frequency matched to the estimated rate of wax or solids deposition.

Topside facilities limitations

With subsea processing, produced fluids arrive at the host platform already separated into their respective phases, so the need for large slug catchers and separators is reduced or eliminated. Degassed oil and water may be further separated at the seabed, and the produced water reinjected back into subsea wells. Seabed separation and water reinjection increase oil pipeline capacity, reduce pipeline internal corrosion and water treatment on the surface, and reduce overall power demand. This is the natural progression from two-phase (gas-liquid) separation as the field matures and water production increases.

Unmanned and minimum facilities developments

One way to reduce field development costs and improve project economics is to increase well productivity and reduce facility costs. As discussed earlier, subsea processing can improve well productivity and increase ultimate recovery. It can also enable unmanned minimum production facilities developments that do not need costly pipelines. An illustration of such an infrastructure independent system is shown in Fig. 4.

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  Fig. 4—Infrastructure independent subsea oil/gas development concept.

An infrastructure independent development for a remote deepwater field is built around subsea processing. Fluids produced by subsea wells are separated in a subsea separation system. The gas is routed to the surface for conversion to liquefied natural gas (LNG) or compressed natural gas (CNG) and tanker transport. Separated oil is routed to a seabed-grounded tank, where it is stored until sufficient volume has accumulated for tanker offtake. A local unmanned buoy can provide power and control functions. Most of these technologies either are being, or have been, deployed in some form. Subsea wells are well accepted and commonly used. Subsea processing technologies are beginning to be employed with the advent of deepwater developments.

Source : Petrowiki

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RISK OF OIL AND GAS INDUSTRIES

Whenever an investor approaches a new industry, it is good to know what the risks are that a company in that sector must face to be successful. General risks apply to every stock, such as management risk, but there are also more concentrated risks that affect that specific industry. In this article, we'll look at the biggest risks that oil and gas companies face.

Political Risk
The primary way that politics can affect oil is in the regulatory sense, but it's not necessarily the only way. Typically, an oil and gas company is covered by a range of regulations that limit where, when and how extraction is done. This interpretation of laws and regulations can also differ from state to state. That said, political risk generally increases when oil and gas companies are working on deposits abroad.
Oil and gas companies tend to prefer countries with stable political systems and a history of granting and enforcing long-term leases. However, some companies simply go where the oil and gas is, even if a particular country doesn't quite match their preferences. Numerous issues may arise from this, including sudden nationalization and/or shifting political winds that change the regulatory environment. Depending on what country the oil is being extracted from, the deal a company starts with is not always the deal it ends up with, as the government may change its mind after the capital is invested, in order to take more profit for itself.

Political risk can be obvious, such as developing in countries with an unstable dictatorship and a history of sudden nationalization - or more subtle - as found in nations that adjust foreign ownership rules to guarantee that domestic corporations gain an interest. An important approach that a company takes in mitigating this risk is careful analysis and building sustainable relationships with its international oil and gas partners, if it hopes to remain in there for the long run.

Geological Risk
Many of the easy-to-get oil and gas is already tapped out, or in the process of being tapped out. Exploration has moved on to areas that involve drilling in less friendly environments - like on a platform in the middle of an undulating ocean. There is a wide variety of unconventional oil and gas extraction techniques that have helped squeeze out resources in areas where it would have otherwise been impossible.
Geological risk refers to both the difficulty of extraction and the possibility that the accessible reserves in any deposit will be smaller than estimated. Oil and gas geologists work hard to minimize geological risk by testing frequently, so it is rare that estimates are way off. In fact, they use the terms "proven," "probable" and "possible" before reserve estimates, to express their level of confidence in the findings.

Price Risk
Beyond the geological risk, the price of oil and gas is the primary factor in deciding whether a reserve is economically feasible. Basically, the higher the geological barriers to easy extraction, the more price risk a given project faces. This is because unconventional extraction usually costs more than a vertical drill down to a deposit. This doesn't mean that oil and gas companies automatically mothball a project that becomes unprofitable due to a price dip. Often, these projects can't be quickly shut down and then restarted. Instead, O&G companies attempt to forecast the likely prices over the term of the project in order to decide whether to begin. Once a project has begun, price risk is a constant companion.

Supply and Demand Risks
Supply and demand shocks are a very real risk for oil and gas companies. As mentioned, operations take a lot of capital and time to get going, and they are not easy to mothball when prices go south, or ramp up when they go north. The uneven nature of production is part of what makes the price of oil and gas so volatile. Other economic factors also play into this, as financial crises and macroeconomic factors can dry up capital or otherwise affect the industry independently of the usual price risks.

Cost Risks
All of these preceding risks feed into the biggest of them all - operational costs. The more onerous the regulation and the more difficult the drill, the more expensive a project becomes. Couple this with uncertain prices due to worldwide production beyond any one company's control, and you have some real cost concerns. This is not the end, however, as many oil and gas companies struggle to find and retain the qualified workers that they need during boom times, so payroll can quickly rise to add another cost to the overall picture. These costs, in turn, have made oil and gas a very capital-intensive industry, with fewer and fewer players all the time.

The Bottom Line
Oil and gas investing isn't going anywhere. Despite the risks, there is still a very real demand for energy, and oil and gas fills part of that demand. Investors can still find rewards in oil and gas, but it helps to know the potential risks that go along with those potential rewards.

Source : Investorpedia

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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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