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Gas chromatography (GC), is commonly used in analytical chemistry for separating and analyzing compounds that can be vaporized without decomposition. Typical uses of GC include testing the purity of a particular substance, or separating the different components of a mixture (the relative amounts of such components can also be determined). In gas chromatography, the mobile phase (or "moving phase") is a carrier gas, usually an inert gas like helium or an unreactive gas like nitrogen. The stationary phase is a microscopic layer of liquid or polymer on an inert solid support, inside a piece of glass or metal tubing called a column. The instrument used to perform gas chromatography is called a gas chromatograph (or "aerograph", "gas separator").
Since the most common use of matrix acidizing is the removal of formation damage, it is important to understand the nature of the damage that exists so that an appropriate treatment can be designed. Well testing and well test analysis generate a skin factor and well completion efficiency. This is insufficient alone for formation damage diagnosis. Well performance analysis has provided a beneficial tool to identify the location and thickness of damage at flow points in the near wellbore area. Models of flow into perforations and gravel-packed tunnels provide a way to relate the location and severity of damage to the completion procedure that preceded it.
Many data are interpreted to evaluate a petroleum-bearing formation, and we discuss the interpretations of data acquired through surface data logging in terms of the rock formation and fluid properties they help determine. The logging engineer or geologist gets information about the formation fluids directly from fluids that are released into the wellbore while drilling and circulating out suspended immiscibly in the drill fluid or remaining in the pores of larger cuttings that may not have been flushed. They receive information indirectly from remnants of the fluid that remain in pores of rock cuttings, as stains on the grain surface, or in solution in the drilling fluid. Oil may be identified as a sheen on the surface of water-based drilling fluid. If the circulating fluid density is sufficiently low as to render an underbalanced drilling condition, oil may be produced in large enough quantities that a sample may be skimmed off a whole mud sample.
While formation damage is typically a problem affecting the productivity of well, it can also pose problems for injection. Understanding the causes of this type of formation damage is important so that efforts to prevent it can be undertaken. This page discusses the types of formation damage that affect injection wells. In such projects, the cost of piping and pumping the water is determined primarily by reservoir depth and the source of the water. However, water treatment costs can vary substantially, depending on the water quality required.
Fines migration is a recognized source of formation damage in some production wells, particularly in sandstones. Direct evidence of fines-induced formation damage in production wells is often difficult to come by. Although most other forms of formation damage have obvious indicators of the problem, the field symptoms of fines migration are much more subtle. Indirect evidence such as declining productivity over a period of several weeks or months is the most common symptom. This reduction in productivity can usually be reversed by mud-acid treatments.
Researchers have developed a new sensor that could allow practical and low-cost detection of low concentrations of methane gas. Measuring methane emissions and leaks is important to a variety of industries because the gas contributes to global warming and air pollution. "Agricultural and waste industries emit significant amounts of methane," said Mark Zondlo, leader of the Princeton University research team that developed the sensor. "Detecting methane leaks is also critical to the oil and gas industry for both environmental and economic reasons because natural gas is mainly composed of methane." In The Optical Society journal Optics Express, researchers from Princeton University and the US Naval Research Laboratory demonstrate their new gas sensor, which uses an interband cascade light emitting device (ICLED) to detect methane concentrations as low as 0.1 parts per million.
Treatment evaluation leads to problem identification and to continuously improved treatments. The prime source of information on which to build an evaluation are the acid treatment report and the pressure and rate data during injection and falloff. Proper execution, quality control, and record keeping are prerequisites to the task of accurate evaluation. Evaluation of unsatisfactory treatments is essential to recommending changes in chemicals and/or treating techniques and procedures that will provide the best treatment for acidizing wells in the future. The most important measure of the treatment is the productivity of the well after treatment.
Stress concentration around the wellbore can create breakouts, fractures, or failures. Understanding the stresses on rocks around wellbores is important to well design. For a vertical well drilled in a homogeneous and isotropic elastic rock in which one principal stress (the overburden stress, Sv) is parallel to the wellbore axis, the effective hoop stress, σθθ, at the wall of a cylindrical wellbore is given by Eq. 1. Here, θ is measured from the azimuth of the maximum horizontal stress, SHmax SHmin is the minimum horizontal stress; Pp is the pore pressure; ΔP is the difference between the wellbore pressure (mud weight) and the pore pressure, and σΔT is the thermal stress induced by cooling of the wellbore by ΔT. At the point of minimum compression around the wellbore (i.e., at θ 0, parallel to SHmax), Eq. 1 reduces to The equations for σθθ; and σzz are illustrated in Figure 1 for a strike-slip/normal faulting stress regime (SHmax Sv SHmin) at a depth of 5 km, where the pore pressure is hydrostatic and both ΔP and σΔT are assumed to be zero for simplicity.
Knowledge of the dissolved constituents is important because these constituents are related to the origin and/or migration of an oil accumulation, as well as to the disintegration or degradation of an accumulation. The concentrations of organic constituents in oilfield brines vary widely. This page discusses the occurrence of dissolved gases, organic constituents, and dissolved solids in produced water. Large quantities of dissolved gases are contained in oilfield brines. Most of these gases are hydrocarbons; however, other gases such as CO2, N2, and H2S often are present.