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Oilfield Paraffin and Asphaltene

Paraffin-in-Crude-OilParaffin control products prevent crude oil precipitation of paraffin wax deposits in production risers, subsea tie-backs, or any other production tubular or transportation pipeline.
Paraffin – Asphaltenes and Inhibitors
Some formulation products are wax crystal modifiers that prevent paraffin formation by interfering with the bonding of aliphatic wax molecules. Composed of branched chain polymers, these modifiers bond to the wax crystal lattice at an active growing site but prevent further growth and interfere with deposition by disrupting the lattice structure.
Although the paraffins remain unstable in solution, they are prevented from growing crystals of adequate size to block production lines; hence production is not impeded even for temperatures below the wax appearance temperature (WAT).
Wax crystal modifiers are applied continuously in the production stream for uninterrupted paraffin control. In pumping wells with low to moderate fluid levels, frequent batch treatments can approximate a continuous injection treatment. Similarly, a continuous supply of chemical can be provided by feedback from a formation squeeze treatment.
Paraffin Deposition
Crude oil is a complex substance formed under high pressure and temperature from vegetable and/or animal organic materials. A broad spectrum of organic chemical components exist in light, paraffinic and heavy oils. These include wax up to C60, esters, organic acids, asphaltenes and napthalenes. Depending on the makeup of these components, the crude oil will have its own characteristics, including specific gravity, wax content, pour point, color, etc.
Crude oil can cause a series of problems:
• Wax deposition
• Viscous gels at low temperatures (from heavy oils)
• Deposition of asphaltenes

read more about Crude Oil Components

Paraffin consists of straight and branched chain hydrocarbons of varying lengths; they are part of the chemical family called alkanes. Paraffin wax molecules contain between 20 to 80 or more carbon atoms in their chain and have a definite melting point. Paraffin waxes often make up 60-90% of a wax deposit. Soft deposits are composed of molecules containing from CI, to C,5 carbon atoms, their melting points are below 150·F. The high molecular weight waxes are referred as microcrystalline waxes and are similar
in chemical structure to the normal paraffin waxes but have a much higher melting point. (150 to 212·F).

Paraffins are aliphatic hydrocarbon waxes that are present in most crude oils. They precipitate from a crude oil at the point where the temperature falls below the WAT.
These deposits reduce the internal diameter of tubulars and pipelines, restrict or block valves, and impede other production equipment to reduce capacity and, in the worst case, stop production.
Factors Influencing Paraffin Deposition:
• Paraffin wax is primarily a solid – liquid phase equilibrium phenomenon; the lowering of temperature is the significant driving force for precipitation. Crude oil is made up of many different properties and freeze points. As the temperature falls below the freeze point of a hydrocarbon, it falls out of solution. The harder waxes deposit first, followed by the softer waxes as the temperature drops.
• Hydrocarbon density – paraffin waxes are increasingly soluble in lighter gravity, low molecular weight hydrocarbons.
• Solution gas – as oil losses light ends it becomes more dense, and paraffin solubility decreases. The light end losses usually occur at pressure drops, which cause the release of the volatile hydrocarbons, which are good solvents for paraffin wax.
• Rough surfaces provide sharp edges, which promote the deposition and agglomeration of wax. Suspended solids also provide surfaces for wax to adhere to and start accumulating.
• Water cut – as the water cut increases in a system it affects the temperature, water carries and retains more heat than oil does. The water reduces the tendency for wax to deposit by increased velocity and water wetting surfaces.

Asphaltene Deposition
Asphaltenes are probably the least understood deposits occurring in the oilfield. They are a complex organic material that are thought to be arranged in stacked, multi-ring structures. They contain nitrogen, oxygen’ and sulfur atoms within the repeating unit.
Asphaltenes have a wide variety of potential structures and vary from reservoir to reservoir. Asphaltenes are not truly soluble in most crude oils. They exist as 35 to 40 micron sized platelets
and are maintained in suspension by materials called maltenes and resins. These smaller similar
suspending molecules are soluble and act in what has been described as a micelle-type
arrangement to keep the asphaltic products in suspension. When stabilizing influences are
removed the asphaltic particles coalesce into larger groups, called flocs, which separate from
the oil. Asphaltene precipitation will occur with the addition of low molecular weight alkanes,
like pentane, hexane, and heptane, and are soluble in aromatic hydrocarbons, like xylene and toluene.

Factors Influencing Asphaltene Deposition
• Rich gas flooding causes destabilization by lowering the carbon to hydrogen ratio. Stripping gas from the oil has been shown to improve the solubility of the asphaltenes.
• The lowering of pH interrupts solution equilibrium and can cause a destabilization of the asphaltene. This may be caused by CO² mineral acid or naturally occurring organic acid. This can cause asphaltene to deposit in the well bore and pumps.
• Mixing of crude and/or condensate streams can cause a shift in pH or change the ratio of light hydrocarbons. Another example is the mixing of a paraffinic oil or condensate with an asphaltenic one.
• Incompatible organic chemicals, like isopropyl alcohol, methyl alcohol, acetone, and even some glycol, alcohol or surfactant based mutual solvents that do not have an aromatic component can selectively wet or attract maltenes and resins and cause the precipitation of asphaltenes.
•The effect of pressure drop and shear on asphaltene behavior may be to shift the tendency to
precipitate asphaltene, similar to a change in equilibrium. Turbulence also has impact on increasing asphaltene precipitation. Asphaltene deposits are frequently found downstream of chokes, liner
slots, valves, and vessels.
•Temperature drop – this may have more to do with indirect destabilization of the solubility of
maltenes and resins or may cause paraffin precipitation, which traps some asphaltenes as it solidifies.
Temperature can also be affected by pressure drop.

Paraffin / Asphaltene Comparison
Paraffin
• Straight and branched chains
• Definite melting point
• Cloud point indicates crystal initiation
• Soluble in crude oil
• Pour Point – no flow of oil due to wax
• Carbon number’s C12 to C66+
Asphaltene
• Friable solids
• No definite melting point
• Swell and pop when heated
• Aromatic rings
• Decompose to coke material
• Stabilized by resins and maltenes
• Not soluble in crude oil
• Contain nitrogen, oxygen and sulphur

Impact of Paraffin / Asphaltene Deposition
The impact of paraffin/asphaltene deposition is very severe and it can increase operating costs as well as
reduce well and system productivity. Examples of the impact are as follows:
• Plugging of perforations and near well bore damage resulting in a decline in reservoir productivity.
• Increased lifting costs from down hole pump maintenance, etc.
• Pressure increases in flow lines and wells resulting in higher operating costs.

Deposition and plugging of production tanks resulting in a difficulty of meeting BS &W requirements.
• Pipeline blockage and increased transmission costs.
Wax is present in most crude oils, usually in quantities of less than 5%, but even this much can still cause problems. Wax can be detected by normal analytical methods (IP) and usually represents that fraction of the oil with a carbon number higher than 18. Wax is formed when the oil is cooled as a result of being produced from the well.
• Subsea pipelines
• Heat exchange
• Joule effect
• Gas lift (change in solubility)
The wax crystals are formed at a specific temperature (wax appearance point), and then they become so big that they deposit on the surface and block the pipes or process equipment.

Deposit Identification
Paraffin
• If it melts above l22’F
• If it floats on water
• If it dissolves in hot xylene
Asphaltene
• If it doesn’t melt but dissolves in
• hot xylene.
• Solids (scale, iron sulfide, sand,
• mud, etc.)
Solids
• If it doesn’t melt
• If it doesn’t dissolve in hot xylene
• If it sinks in water

Crude Oil Components

On average, crude oil are made of the following elements or compounds:

  • Carbon – 84%
  • Hydrogen – 14%
  • Sulfur – 1 to 3% (hydrogen sulfide, sulfides, disulfides, elemental sulfur)
  • Nitrogen – less than 1% (basic compounds with amine groups)
  • Oxygen – less than 1% (found in organic compounds such as carbon dioxide, phenols, ketones, carboxylic acids)
  • Metals – less than 1% (nickel, iron, vanadium, copper, arsenic)
  • Salts – less than 1% (sodium chloride, magnesium chloride, calcium chloride)

­Crude oil is the term for “unprocessed” oil, the stuff that comes out of the ground. It is also known as petroleum. Crude oil is a fossil fuel, meaning that it was made natural­ly from decaying plants and animals living in ancient seas millions of years ago — most places you can find crude oil were once sea beds. Crude oils vary in color, from clear to tar-black, and in viscosity, from water to almost solid.

Crude oils are such a useful starting point for so many different substances because they contain hydrocarbons. Hydrocarbons are molecules that contain hydrogen and carbon and come in various lengths and structures, from straight chains to branching chains to rings.

There are two things that make hydrocarbons exciting to chemists:

  • Hydrocarbons contain a lot of energy. Many of the things derived from crude oil like gasoline, diesel fuel, paraffin wax and so on take advantage of this energy.
  • Hydrocarbons can take on many different forms. The smallest hydrocarbon is methane (CH4), which is a gas that is a lighter than air. Longer chains with 5 or more carbons are liquids. Very long chains are solids like wax or tar. By chemically cross-linking hydrocarbon chains you can get everything from synthetic rubber to nylon to the plastic in Tupperware. Hydrocarbon chains are very versatile!

The major classes of hydrocarbons in crude oils include:

  • Paraffins

general formula: CnH2n+2 (n is a whole number, usually from 1 to 20)

m    straight- or branched-chain molecules

can be gasses or liquids at room temperature depending upon the molecule

examples: methane, ethane, propane, butane, isobutane, pentane, hexane

read more about Oilfield Paraffin and Asphaltene

  • Aromatics

general formula: C6H5 – Y (Y is a longer, straight molecule that connects to the benzene ring)

ringed structures with one or more rings

rings contain six carbon atoms, with alternating double and single bonds between the carbons

typically liquids

examples: benzene, napthalene

  • Napthenes or Cycloalkanes

general formula: CnH2n (n is a whole number usually from 1 to 20)

ringed structures with one or more rings

rings contain only single bonds between the carbon atoms

typically liquids at room temperature

examples: cyclohexane, methyl cyclopentane

  • Other hydrocarbons

Alkenes

  • general formula: CnH2n (n is a whole number, usually from 1 to 20)
  • linear or branched chain molecules containing one carbon-carbon double-bond
  • can be liquid or gas
  • examples: ethylene, butene, isobutene

Dienes and Alkynes

  • general formula: CnH2n-2 (n is a whole number, usually from 1 to 20)
  • linear or branched chain molecules containing two carbon-carbon double-bonds
  • can be liquid or gas
  • examples: acetylene, butadienes.

Crude Oil Price

First of all we have to understand the Classification of Petroleum Products
The petroleum products that may be subject to evaluation can be grouped as:
crude oil – natural gas – associated products

Crude oil is a liquid composite of many hydrocarbon compounds that, depending on the composition, has differing properties such as oil gravity, viscosity, and pour point which, at least in part, define the quality of the oil for end use and also influence the methods that would be used to develop and produce the oil. Crude that has a high API gravity and low viscosity is generally easier to produce than low gravity, high viscosity oil that may require stimulation to maintain production rates. The characteristics of the oil can, and often does, influence everything from well spacing to pump size to life of production-all of which has an impact on the economic value of the producing property.

Crude oil is a market commodity and is subject to considerable variation in its economic value. Oil price varies based on location, gravity, sulfur content and competition from other fuel sources. As an example, crude oil produced in California is consistently priced $3-4/bbl below similar oil in the mid continent in part because of oil gravity but also because of the sulfur content and the lack of access to other markets. At times, such as under the WPT, crude oil has been economically stratified based on when it was put on production and the status of the producing company.

Natural gas is a fluid also composed of many hydrocarbon compounds although generally not as complex as crude oil. The primary differences between gases are:
(1) the heating value (generally the methane content).
(2) the non-hydrocarbon gas (N2, 0,, HpS, etc.) content.
(3) the amount of liquid or heavy ends that can be obtained as natural gas liquids (NGL).

The economic value of natural gas is directly related to its composition. A gas with no non hydrocarbons and which is entirely methane and ethane has a high heating value. If it contains propanes and other strippable ends, the value increases. Natural gas enjoys a relatively high economic value because it has a low cost of production. However, it is highly regulated through pipeline and utility controls on transportation and pricing so that it rarely achieves equivalent value with crude oil on a $/Btu basis. In addition, due to the ease of transporting gas, there is substantial competition among gas producing regions, which acts as a control on gas prices.

Associated products include (a) natural gas liquids (NGL) that can include propane, butane, natural gasoline and virtually any other hydrocarbon that can be stripped from gas, (b) sulfur, (c) non hydrocarbon gases. The NGLs can have substantial economic value but require investment in specialized striping plants.

Pricing tends to be driven by the local market and can be volatile with demand. Sulfur is a common by-product in many Canadian fields and in some areas of the United States. The economic value tends to fluctuate considerably, and sulfur production may often be more of a nuisance than an economic benefit. Non hydrocarbon gases such as nitrogen and helium can be economic by-products, but in most cases where this occurs the non hydrocarbon becomes the primary product and the natural gas is secondary.

The economics of crude oil, natural gas and associated products can differ significantly depending on market conditions.

Petroleum Market

Petroleum-oil, gas and derivatives-are the primary sources of energy in the world today. There are other major fuel sources, such as coal and nuclear power, but petroleum remains the major source in the United States, Europe and Japan.

These markets together account for about 45% of world energy usage and petroleum provides over 60% of energy in these areas. Petroleum is likely to retain this position because there are very large volumes of oil and gas already discovered and available at relatively low prices. The combined reserves of the Persian Gulf states alone are sufficient to supply current world demand for 50-100 years. Moreover, these reserves can be produced at low cost when compared to production in the United States and other parts of the world.

Persian Gulf reserves are large enough and production sufficiently controlled, even though somewhat erratically, by the Gulf countries, that the increase in usage of higher-cost energy sources such as nuclear or environmentally acceptable coal would be very difficult unless heavily subsidized.

In the United States and other areas where similar industry conditions exist, petroleum economics will be controlled, indirectly and directly, for the foreseeable future by the baseline oil price either set by or derived by major producing countries. Under market conditions, oil priced in the United States cannot rise much above the world market level but can readily fall below that level. Production in the United States is generally in decline so that the United States, along with Europe and Japan, is a net importer of over 50% of crude oil demand, thereby tying the United States market more closely to world markets. In addition, United States production is very high cost relative to the Persian Gulf or anywhere else so that the difference between price (revenue) and cost of production can be, and often is, very narrow. As shown by the events of 1985-1986, a decrease in oil price is often enough to render a large volume of U.S. production uneconomic, causing wells to be shut in and abandoned; resulting in the cancellation or deferment of new drilling, exploration and other capital investment projects; and bringing about the financial collapse of oil companies, service companies, and whole regions that depend on the oil industry.

The primary impact of the market for petroleum is, of course, on price. Throughout history, prices for oil and natural gas have varied with demand and supply. In the United States, there have been periods of high production relative to demand causing prices to drop; as well as periods of high demand relative to production that resulted in price increases. For a long period, however, from the early 1930s until 1971, oil production was controlled by proration that limited production, particularly in Texas but also in other areas, to a certain “allowable” each month that was expected to fulfill, but not exceed, demand. The allowable production was set as a percentage of productive capacity. This regulation resulted in stable and relatively low oil prices for most of that period.

The increase in allowables over time to 100% in the early 1970s was one of the major reasons that control of the world market passed from the United States to OPEC and from industry to governments in the mid-1970s. The U.S. economy is, among other things, energy intensive. In this situation, changes in oil and gas prices take on national significance and can have immediate and serious impacts on the economy of regions and the country as a whole. The demonstration of this is in the relation between oil price and inflation. Since 1928, the first year that reliable inflation data in the form of the Consumer Price Index was kept, changes in oil price can be shown to be closely followed by changes in CPI or, more broadly, inflation. Major price increases such as 1971-1973 and 1979-1980 resulted in serious increases in inflation in those and following years. For most of the period from 1928 to 1994, however, oil production exceeded demand. Price was regulated through proration and in many years oil price declined. Inflation, however, being caused by many factors, continued even though at low rates so that, while the nominal or actual oil price may have increased slightly or remained essentially constant, the “real” price-the nominal price minus inflation-actually declined for many years and has, in fact, declined significantly since 1982.

Preparation of a Cash Flow

A cash flow consists of five basic elements: (1) production schedule, (2) product prices, (3) ownership interests, (4) costs of production and (5) capital investments.
The cash flow can be expanded in any of these segments and through the addition of income tax considerations. The cash flow is designed to model the production, price and cost expectations of the evaluator to an economic limit. A production schedule must be estimated for oil and gas production plus any associated production such as NGL or condensate. Previous discussion has described the methods of estimating future reserves and production. Extrapolation of existing or similar property production decline is the most direct method of estimating future production when either oil or nonassociated gas is the primary production stream. Associated gas may be projected as a function of oil production using a fixed or variable gas-oil ratio (GOR). Nonassociated gas may have associated condensate production that can be projected as a fixed or variable yield.

Where decline curve extrapdation is used, the form of the decline, whether exponential, hyperbolic or harmonic, must be defined and applied. It is always a good idea to compare the reserves obtained from production decline with reserves obtained from other methods such as ratexum or WOR-cum curves or to volumetric and/or material balance calculations. When decline curve extrapolation may not be appropriate, such as when projecting future production from a new field or reservoir or for an EOR project, production estimates can be obtained by converting the volume results of the material balance, frontal advance, or other method into annual or monthly production. This may require determining a limiting condition that can be identified, such as lifting capacity or injection rates and back-calculating a production rate. However it is done,
be sure to compare the production schedule with other similar projects or fields and with good reservoir and operating practice. Also, the selection of a schedule may have economic impacts, such as the requirement for investment, increased operating costs, or in some circumstances royalties and/or taxes that may cause an alteration of the selected production schedule. Finally, as noted earlier, the proper analysis of the source and form of the production data is very important to a valid cash flow analysis.

Product prices are the market price of oil, gas, condensate, or NGL. A cash flow is usually done as of a point in time so the prices would be those in effect at that date. Two basic sources for product prices are actual sales and posted prices. The actual price for oil and/or gas being received on the property to be evaluated is the best source of a price for a cash flow. In using actual prices, determine if there are any shipping, pipeline, dehydration or other deductions that would reduce the price actually received for the oil or gas produced. These charges must be accounted for in the cash flow. Also, gas sales prices are often based on the heating or Btu value of the gas not on the Mcf or volume of gas.

Since gas production is normally expressed in Mcf, a correction must be made if the gas price is in $/Btu. Posted prices (Figure 7-10) are the prices offered in the market by large purchasers of crude oil, such as major refiners. The appropriate price for the oil in the property being evaluated can be estimated by obtaining one or more posted prices for oil of a similar gravity in or near the same field and making necessary adjustments for gravity. Gas prices can be estimated from standard prices offered by pipelines in the area. Gas sales are not always as straightforward as oil sales. During periods of high demand, the purchaser may be willing to take all the gas that can be produced and will build the connection lines to the property. At other times, however, the purchaser may limit sales to a percent of capacity and may not be willing to provide connection. These conditions could not only reduce revenue from sales but could require additional investment and may have the effect of reducing production of other products if the gas is associated gas. Whatever the conditions, they must be considered in the production schedule and cash flow.

Condensate is generally treated and priced as crude oil. NGL is generally treated as a by-product of gas sales where “wet” gas containing NGL is sold to a “gas plant” that strips out the liquids and sells the “dry” gas and liquids. The producer may receive revenue from the dry gas sales and a share of NGL sales or he or she may receive a wet gas price.

The projection of product prices into the future depends on the perspective of the evaluator regarding future economic conditions and, to some extent, the purpose of the cash flow. The simplest approach is to determine the appropriate price(s) as of the date of evaluation and hold those prices constant for the life of production. This was virtually the only way projections were done prior to the price increases of the 1970s and is still relatively common. Constant pricing is required for SEC evaluations. Since the 1970s it has become more common to attempt to estimate whether oil and/or gas prices would change over the expected life of production and to build those anticipated changes into the cash flow by escalating or deescalating oil prices at certain rates over time.

The question of whether or not to escalate prices in a cash flow depends on the information available to the evaluator and how well the evaluator can translate information into expectation. Major companies often have economics departments whose purpose is to estimate future oil prices that are often implemented in cash flows. Smaller companies and others are generally without such resources and must rely on other, published and unpublished sources and their own intuition. Since the early 1970s, oil and, to a lesser extent, gas have been open market commodities subject to a wide range of forces causing prices to rise and fall. Most price projections that extend for more than a year or two will probably be wrong except that over time, because oil and gas are finite resources, the price must eventually increase. As will be discussed below, the use of several cash flows with differing price projections may serve to reduce

price risk

The prices used in cash flow projections are normally “nominal” prices that include expected inflation. In making projections of oil prices, it is important to keep in mind that the rate of increase of oil prices, the escalation rate, has rarely exceeded the rate of inflation for more than 2-3 years and that, after that time, the escalation rate may be equal to or less than the rate of inflation. On average the “real” price of oil (real = nominal minus inflation) has increased by an average of 1.1% over the 60 years from the late 1920s to the late 1980s, including the major increases of the 1970s . Most oil field operating costs are directly influenced by inflation so that price escalation should not exceed cost escalation for any extended period of time.

Fair Market Value.

Many investments, such as purchasing properties or valuations done for ad valorem or estate taxes, require a determination of fair market value as the goal of valuation. The most common definition of FMV is:

“The price that would be paid by a knowledgeable and willing buyer and which would be accepted by a knowledgeable and willing seller neither being under any pressure to conclude a transaction.”

This definition, in various forms, means that the real value of a property can only be established in the marketplace by the free interaction of buyers and sellers. The true FMV will only be known after a property has been sold. However, it can be (and often must be) estimated through property valuation. FMV evaluations require the use of price/cost projections and DCRs that reasonably approximate the marketplace for property sales.

References:
1. Petroleum & Natural Gas Engineering,part.2
2. Petroleum Engineering Handbook