Salinity formation

The SSP is derived from the departure in millivolt scale units from shale baseline of the SP curve it is corrected where possible for the effects of thin beds, mud resistivity, and fluid invasion of the formation. Salinity or the salinity of NaCl solutions having resistivities corresponding to observed resistivities can then be calculated from Rwe We have used the Arps—Hamilton log analysis slide rule or calculator program (e.g., Schoonover and Fertl, 1979). 

A publication that specifically focuses on the screening criteria for chemical processes has not been seen in the literature. Screening criteria for broader EOR processes have been discussed by several researchers—for example, Taber et al. (1997a, 1997b), Al-Bahar et al. (2004), and Dickson et al. (2010). This section briefly summarizes several critical parameters regarding chemical EOR application conditions. Many parameters could affect chemical EOR processes however, the most critical parameters should be reservoir temperature, formation salinity and divalent contents, clay contents, and oil viscosity. Eor polymer flooding, permeability is another critical parameter. 

The hydrophile-lipophile balance (HLB) has been used to characterize surfactants. This number indicates relatively the tendency to solubilize in oil or water and thus the tendency to form water-in-oil or oil-in-water emulsions. Low HLB numbers are assigned to surfactants that tend to be more soluble in oil and to form water-in-oil emulsions. When the formation salinity is low, a low HLB surfactant should be selected. Such a surfactant can make middle-phase... 

Fig. 7. Histograms of homogenization temperatures of fluid inclusions in ankerite and calcite in the Oseberg Formation. Salinities derived from limited Tm data are indicated. Vertical black arrows represent present-day reservoir temperature.

Data gathering in the water column should not be overlooked at the appraisal stage of the field life. Assessing the size and flow properties of the aquifer are essential in predicting the pressure support which may be provided. Sampling of the formation water is necessary to assess the salinity of the water for use in the determination of hydrocarbon saturations. 

Formation water density is a function of its salinity (which ranges from 0 to 300,000 ppm), amount of dissolved gas, and the reservoir temperature and pressure. As pressure increases, so does water density, though the compressibility is small... 

Hydrocarbon-water contact movement in the reservoir may be determined from the open hole logs of new wells drilled after the beginning of production, or from a thermal decay time (TDT) log run in an existing cased production well. The TDT is able to differentiate between hydrocarbons and saline water by measuring the thermal decay time of neutrons pulsed into the formation from a source in the tool. By running the TDT tool in the same well at intervals of say one or two years (time lapse TDTs), the rate of movement of the hydrocarbon-water contact can be tracked. This is useful in determining the displacement in the reservoir, as well as the encroachment of an aquifer. 

Cationic surfactants may be used [94] and the effect of salinity and valence of electrolyte on charged systems has been investigated [95-98]. The phospholipid lecithin can also produce microemulsions when combined with an alcohol cosolvent [99]. Microemulsions formed with a double-tailed surfactant such as Aerosol OT (AOT) do not require a cosurfactant for stability (see, for instance. Refs. 100, 101). Morphological hysteresis has been observed in the inversion process and the formation of stable mixtures of microemulsion indicated [102]. 

The substantial decrease of polyacrylamide solution viscosity in mildly saline waters can be uti1i2ed to increase injection rates. A quaternary ammonium salt polymer can be added to the polyacrylamide solution to function as a salt and reduce solution viscosity (144). If the cationic charge is in the polymer backbone and substantially shielded from the polyacrylamide by steric hindrance, formation of an insoluble interpolymer complex can be delayed long enough to complete polyacrylamide injection. Upon contacting formation surfaces, the quaternary ammonium salt polymer is adsorbed reducing... 

Acrylamide—polymer/Ct(III)catboxylate gel technology has been developed and field tested in Wyoming s Big Horn Basin (211,212). These gels economically enhance oil recovery from wells that suffer fracture conformance problems. The Cr(III) gel technology was successful in both sandstone and carbonate formations, and was insensitive to H2S, high saline, and hard waters (212). 

If the technical regulations are adhered to for constructional steels in neutral waters, there are no conditions for H-induced corrosion. On the other hand, hardened and high-strength materials with hardnesses above HV 350 are very susceptible [60,82,92], since anodic polarization encourages crack formation in saline media and anodic pitting occurs with acid products of hydrolysis [93]. 

I Ualloy ferrous materials Neutral waters, saline and soil solutions (25°C) <-0.53 <-0.85 Protection against weight loss corrosion Fig. 2-9 [29-34] (with film formation is more positive)... 

Another problem is when the carbon dioxide content of natural gas is too high and must be lowered to produce pipeline-quality gas. Although the current practice is to vent this CO, sequestration of CO, in underground geologic formations is being considered. Already, in the Norwegian sector of the North Sea, CO, has been injected into saline aquifers at a rate of 1 million tons a year to avoid... 

The mud contamination with chlorides results from salt intrusion. Salt can enter and contaminate the mud system when salt formations are drilled and when saline formation water enters the wellbore. 

Common salt, or sodium chloride, is also present in dissolved form in drilling fluids. Levels up to 3,000 mg/L chloride and sometimes higher are naturally present in freshwater muds as a consequence of the salinity of subterranean brines in drilled formations. Seawater is the natural source of water for offshore drilling muds. Saturated brine drilling fluids become a necessity when drilling with water-based muds through salt zones to get to oil and gas reservoirs below the salt. 

Short Normal Resistivity (after Anadriii). The short normal (SN) resistivity sub provides a real-time measurement of formation resistivity using a 16-in. electrode device suitable for formations drilled with water-base muds having a moderate salinity. A total gamma ray measurement is included with the resistivity measurement an annular bottomhole mud temperature sensor is optional. The short normal resistivity sub schematically shown in Figure 4-273 must be attached to the MWD telemetry tools and operates in the same conditions as the other sensors. 

Salinity reversals or decrease of the formation brine salinity with depth are generally associated with overpressured formations. The mud salinity or chloride content reflects the formation water salinity if there is a close control over the mud properties and analyses. 

There have been numerous reports of possible allergic reactions to mercury and mercury salts and to the mercury, silver and copper in dental amalgam as well as to amalgam corrosion products Studies of the release of mercury by amalgams into distilled water, saline and artificial saliva tend to be conflicting and contradictory but, overall, the data indicate that mercury release drops with time due to film formation and is less than the acceptable daily intake for mercury in food . Further, while metallic mercury can sensitise, sensitisation of patients to mercury by dental amalgam appears to be a rare occurrence. Nevertheless, there is a growing trend to develop polymer-based posterior restorative materials in order to eliminate the use of mercury in dentistry. 

It is generally more saline than seawater. Most North Sea formation waters have salinities two to three times that of seawater. 

Archie [23] examined electrical resistivity of various sand formations having pore spaces filled with saline solutions of different salt concentrations. Based upon his own experimental results, he obtained a simple relationship for the conductivity of beds of sand (assuming the sand itself is nonconductive) containing saline solution in terms of the porosity. In terms of diffusion coefficients his expression is... 

It seems likely that the mixing of acid sulfate solution with nearly neutral low salinity Au-bearing fluids seems the most likely mechanism for the formation of epithermal Au-Ag vein-type deposits. 

D and 5 0 data on fluid inclusions and minerals, 8 C of carbonates, salinity of inclusion fluids together with the kind of host rocks indicate that the interaction of meteoric water and evolved seawater with volcanic and sedimentary rocks are important causes for the formation of ore fluids responsible for the base-metal vein-type deposits. High salinity-hydrothermal solution tends to leach hard cations (base metals, Fe, Mn) from the country rocks. Boiling may be also the cause of high salinity of base-metal ore fluids. However, this alone cannot cause very high salinity. Probably the other processes such as ion filtration by clay minerals and dissolution of halite have to be considered, but no detailed studies on these processes have been carried out. 

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