concentration

In-situ combustion processes are largely a function of oil composition and rock mineralogy. Laboratory studies, using crude and matrix from a prospective in-situ combustion project, should be performed before designing any field operation. A more recent and more accurate kinetics model has been developed.[1] Only two reactions are used, but in addition, the geometry of the reacting residual fuel in the pore spaces is taken into account, as indicated in Figure 1. LTO can be described as oxygen addition to the crude oil.

Demulsification is the breaking of a crude oil emulsion into oil and water phases. A fast rate of separation, a low value of residual water in the crude oil, and a low value of oil in the disposal water are obviously desirable. Produced oil generally has to meet company and pipeline specifications. For example, the oil shipped from wet-crude handling facilities must not contain more than 0.2% basic sediment and water (BS&W) and 10 pounds of salt per thousand barrels of crude oil. This standard depends on company and pipeline specifications. The salt is insoluble in oil and associated with residual water in the treated crude. Low BS&W and salt content is required to reduce corrosion and deposition of salts. The primary concern in refineries is to remove inorganic salts from the crude oil before they cause corrosion or other detrimental effects in refinery equipment. The salts are removed by washing or desalting the crude oil with relatively fresh water. Oilfield emulsions possess some kinetic stability. This stability arises from the formation of interfacial films that encapsulate the water droplets.

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.[1] Fluid samples are thus required to enable advanced physical and chemical analyses to be carried out in specialized laboratories.

Produced or fresh water being treated may have suspended solids, such as formation sand, rust from piping and vessels, and scale particles, or dissolved solids (various chemical ions). For most uses or disposal methods, these solids may need to be removed. It may be necessary to remove these solids to prevent wear in high-velocity areas, prevent solids from filling up vessels and piping and interfering with instruments, and comply with discharge restrictions on oil-coated solids. This page discusses appropriate removal technologies and handling of the removed material. Solid particles, because of their heavier density (compared to water) and net negative buoyant force, will settle to the bottom with a terminal velocity that can be derived from Stokes' law, as shown in Eq. 1. This equation applies strictly to creeping flow regimes in which the Reynolds number is less than unity; this is mainly concerned with spheres of very small diameter surrounded by a liquid. For very small particles, the inertial forces are much less than the viscous forces because of the low particle mass, and the particle does not enter into a turbulent settling regime. Most sedimentation basins are rectangular flumes with length-to-width ratios of 4:1 or greater to limit crossflow.

Both water and hydrocarbon dewpoints are represented as the maximum solubility of each phase in the other. Because F 2, two intensive variables are needed to specify the system. At a given temperature and pressure, the user can determine the saturated water content of gases, the point at which a liquid water phase will precipitate. For this reason Figure 1 frequently is called the water dewpoint chart. Despite its limitations, Figure 1 [1] is very useful and provides a check against high water content values calculated by commercial phase equilibria computer programs.

Sour gas is natural gas or any other gas containing significant amounts of hydrogen sulfide H2S).Sour gas reserves are historically left undeveloped because of the technical challenges and costs involved in their extraction and processing.[1] Natural gas that contains more than 4 ppmv of hydrogen sulphide (H2S) is commonly referred to as "sour". This is because the odour of hydrogen sulphide gas in air at very low concentrations is similar to that of rotten eggs. Significant quantities of natural gas resources around the world are known to contain H2S. These have been difficult to produce in the past because of the tendency for sour gas to cause corrosion and sulphide stress corrosion cracking, particularly in pipelines.

The prevention of hydrate-plug formation and safe removal of hydrate plugs represent 70% of deepwater flow-assurance challenges; the remaining 30% deal with waxes, scale, corrosion, and asphaltenes. Before considering prevention of hydrate plugs, it is important to consider safety problems involving hydrate plug removal. What is a typical pressure at which hydrates will form? Hydrate-formation data, at a typical deep seafloor temperature of 39 F, were averaged for 20 natural gases (listed in Chap.

For systems containing both water and small ( 9Å) hydrocarbons, hydrates are an important part of the phase diagram. More information about the impact of hydrate formation can be found beginning at Hydrates. Hydrocarbon guest repulsions prop open different sizes of water cages, which combine to form the three well-defined unit crystal structures shown in Figure 1. The smallest hydrated molecules (Ar, Kr, O2, and N2), with diameters of less than 4.0 Å, form sII; still smaller molecules cannot be enclathrated except at extreme pressures. These three common hydrate structures each have large and small cavities.

In cold heavy oil production with sand (CHOPS) production, the two limiting physical mechanisms for sand are compact growth of the remolded zone as a cylindrical (or spherical or ellipsoidal) body or extension of an anastomosing piping channel system comprising a network of tubes ("wormholes"). These lead to different geometries in situ, although the impact on well productivity may not be quantifiable through measurements. In compact growth, the ratio of the area of the fully yielded zone to the volume enclosed approaches a minimum because a cylindrical or elliptical shape is spatially more compact than a channel network. Discrete zonal boundaries do not really exist: a gradual phase-transition zone develops, although it may be treated mathematically as a thin front, just as in a melting alloy. The complex and diffuse boundary shape is approximated by a geometrically regular shape and a distinct liquefaction front. A circular 2D assumption is simplest for analysis because the radius of the zone and, hence, the pressure gradient can be scaled directly to sand-production volume with no additional assumptions. Also, overburden stress, σv, plays a dominant role in the destabilizing and dilation process, and a 2D model cannot capture this process in a rigorous manner.

Systems of nonlinear partial differential equations (PDEs) are needed to describe realistic multiphase, multidimensional flow in a reservoir. As a rule, these equations cannot be solved analytically; they must be solved with numerical methods. This article provides an overview of these methods. As a reminder, v is velocity, D is dispersion, and C is concentration. Eq. 1 is a good example to use because it illustrates many useful numerical methods that can be compared with the analytical solution given by Eq. 2. We first introduce the concept of finite differences to convert Eq. 1 to an equation that can be solved numerically.