Deposition of the high-molecular-weight components of petroleum fluids as solid precipitates in surface facilities, pipelines, downhole tubulars, and within the reservoir are well-recognized production problems. The deposits also can contain resins, crude oil, fines, scales, and water. Asphaltenes and waxes are a general category of solids and, thus, cover a wide range of materials. Understanding the fundamental characteristics that define the nature of asphaltenes and waxes is valuable in reducing or avoiding the production impacts of their deposition. This page examines the general chemical classifications and types of asphaltenes and waxes, in addition to their solidification behaviors.
Many general petroleum engineering texts have sections covering the measurement of phase behavior or pressure/volume/temperature (PVT) analysis, but few have detailed descriptions of reservoir fluid-sampling practices. This article discusses the rationale for fluid sampling, general guidance for establishing a sampling program, and some special cases that go beyond the typical fluid sampling approaches. An enormous range of reservoir fluids exists, and this means that the limited measurements of produced oil and gas properties that can be made in the field are far from adequate to provide the detailed characterization that modern petroleum engineering requires. The lack of such data could easily represent more risk than that tolerated when the decision to perform sampling and laboratory studies is taken. Examples of the financial impact of errors in fluid-property measurements are given elsewhere. Fluid samples are thus required to enable advanced physical and chemical analyses to be carried out in specialized laboratories.
From a purely thermodynamic point of view, an emulsion is an unstable system because there is a natural tendency for a liquid/liquid system to separate and reduce its interfacial area and, hence, its interfacial energy. However, most emulsions demonstrate kinetic stability (i.e., they are stable over a period of time). Produced oilfield emulsions are classified on the basis of their degree of kinetic stability. Water-in-oil emulsions are considered to be special liquid-in-liquid colloidal dispersions.
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.
Deposition of the high-molecular-weight components of petroleum fluids as solid precipitates in surface facilities, pipelines, downhole tubulars, and within the reservoir are well-recognized production problems. Depending on the reservoir fluid and the type of recovery process, the deposited solid may consist of asphaltenes, waxes, or a mixture of these materials. The deposits also can contain resins, crude oil, fines, scales, and water. Models for solid deposition in the reservoir and in pipelines also are presented. Although some of the laboratory techniques for determining solid precipitation are applicable to both waxes and asphaltenes, the characteristic behaviors of these materials can be very different; therefore, wax and asphaltene topics are treated separately.
After precipitation, asphaltene can remain as a suspended solid in the oil or deposit onto the rock. Here, the term precipitation corresponds to the formation of a solid phase from thermodynamic equilibrium and deposition means the settling of solid particles onto the rock surface. Deposition will induce alteration of wettability (from water-wet to oil-wet) of the rock and plugging of the formation. These aspects have been known for a long time and are the subject of many recent investigations. This section reviews the investigations and laboratory observations of these aspects.
With the exception of one-phase gas reservoirs, prolonged production will cause all reservoirs to reach saturation conditions, thus bringing about changes in the fluid composition throughout the reservoir. When this happens, there is no longer any possibility of obtaining truly representative fluid samples. Thus, although in one-phase gas reservoirs (and for a certain length of time in undersaturated reservoirs), the fluid will remain unchanged during pressure depletion--the true nature of the fluid will be unknown until samples actually have been analyzed in a laboratory--it is strongly recommended to take samples at the earliest opportunity in the life of a well. Both in openhole and in cased-hole completions, the best depth or production interval for sampling will be as far away as possible from gas/oil, gas/water, and oil/water transition zones to reduce the chances of coning. Every attempt should be made to test zones individually because commingled production may be difficult to detect and is impossible to correct in the laboratory. Problems such as the liberation of carbon dioxide (CO2) or H2S after acid treatments are possible, as is the release of other components such as metal ions, and these could affect analyses. On the other hand, sampling after an acid treatment has been properly cleaned up has the probable advantage of reduced drawdown in the near-wellbore region. Because of the enormous variety of constraints, there can be no definitive guidelines for well conditioning. The first phase of conditioning involves the cleanup, in which the well is flowed to the surface to remove any solids resulting from perforating activities, drilling mud or completion fluids in the well, and mud filtrate or workover fluids that may remain in the formation near the wellbore. Here, the production rate must provide a sufficient flow velocity in the production string to lift solids, hydrocarbon liquids, and water to the surface, but conditioning is typically performed at the maximum rate, as this reduces the total length of the cleanup period. The cleanup period typically lasts from a few hours to 24 hours, and progress is monitored by regular measurements of flowing wellhead pressure, basic sediment and water (BS&W), and other brmeters. At the end of the cleanup period, production may be diverted through the separator to check its operation. This is an ideal moment to take backup samples.
These deposits may plug the wellbore tubing and valves, as well as coat surface safety and process control equipment. Asphaltenes can also accumulate in separators and in pipelines. Asphaltenes are a compound class, not a single compound, concentrated in the high-temperature distillation residue of petroleum ( 530 C). The asphaltene class is defined in accord with the solubility sequence illustrated in Figure 1. Figure 1--Solubility sequence used to define asphaltenes. See Asphaltenes and waxes for a more detailed characterization of asphaltenes.