Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. A science field dealing with prevention of scales, hydrates, asphaltene and paraffin deposits and other problems that could stop flow of fluid from the subsurface, wellhead or pipeline.
Using heat to treat crude oil emulsions has four basic benefits; It reduces viscosity, increases droplets, dissolves paraffin crystals, and increases density between oil and water. Which allows the water droplets to collide with greater force and to settle more rapidly. The chart in Figure 1 can be used to estimate crude-oil viscosity/temperature relationships. Crude-oil viscosities vary widely, and the curves on this chart should be used only in the absence of specific data. If a crude oil's viscosity is known at two temperatures, it can be approximated at other temperatures by drawing a straight line along those temperature/viscosity points on the chart.
Several approaches that use the activity coefficient model assume the oil and asphaltene as two pseudocomponents: one component representing the deasphalted oil and the other the asphaltenes. Andersen and Speight provided a review of activity models in this category. Other approaches represent the precipitate as a multicomponent solid. Chung, Yarranton and Masliyah, and Zhou et al. gave detailed descriptions of these models. The solubility model used most in the literature is the Flory-Huggins solubility model introduced by Hirschberg et al. Vapor/liquid equilibrium calculations with the Soave-Redlich-Kwong EOS are performed to split the petroleum mixture into a liquid phase and a vapor phase.
Asphaltene precipitation is caused by a number of factors including changes in pressure, temperature, and composition. The two most prevalent causes of asphaltene precipitation in the reservoir are decreasing pressure and mixing of oil with injected solvent in improved oil recovery (IOR) processes. Drilling, completion, acid stimulation, and hydraulic fracturing activities can also induce precipitation in the near-wellbore region. This page focuses on field and laboratory observations associated with asphaltene precipitation during primary depletion and IOR gas injection, along with the experimental measurements used for asphaltene precipitation. Heavier crudes that contain a larger amount of asphaltene have very few asphaltene precipitation problems because they can dissolve more asphaltene.
Many crudes contain dissolved waxes that can precipitate and deposit under the appropriate environmental conditions. These can build up in production equipment and pipelines, potentially restricting flow (reducing volume produced) and creating other problems. This page discusses how to anticipate, prevent, and remediate wax problems in production. Paraffin wax produced from crude oil consists primarily of long chain, saturated hydrocarbons (linear alkanes/ n-paraffins) with carbon chain lengths of C18 to C75, having individual melting points from 40 to 70 C. This wax material is referred to as "macrocrystalline wax."
It is evident that, to quantify formation damage and to study its impact on hydrocarbon production, one must have reasonable estimates of the flow efficiency or skin factor. Several methods have been proposed to evaluate these quantities for oil and gas wells. The most common methods are multirate tests, isochronal gas-well tests, and transient well tests (pressure-buildup analysis). Multirate tests can be conducted on both oil and gas wells. In these tests, several stabilized flow rates, qi, are achieved at corresponding stabilized flowing bottomhole pressures, pwf. The simplest analysis considers two different stabilized rates and pressures. The IPR can be written as ....................(6.6) Simplifying and solving for the flow efficiency, F, we obtain ....................(6.7) The above equation clearly shows that it is possible to obtain flow efficiency rather simply with two stabilized bottomhole pressures and two stabilized flow rates. A similar analysis can be performed to obtain an expression for a linear IPR (x 0). For many gas wells and some oil wells, flow rates are sufficiently high that turbulent or inertial pressure drops near the wellbore can be significant. In such cases, the additional pressure drop measured by the skin can be confused with the pressure drop because of non-Darcy or inertial flow.
Perhaps the most common formation damage problem reported in the mature oil-producing regions of the world is organic deposits forming both in and around the wellbore. These deposits can occur in tubing, or in the pores of the reservoir rock. Both effectively choke the flow of hydrocarbons. It is evident that crude oils contain substantial proportions of saturated and aromatic hydrocarbons with relatively small percentages of resins and asphaltenes. More degraded crudes, including tars and bitumens, contain substantially larger proportions of resins and asphaltenes.