Temperature bottom-hole

Sampling saturated reservoirs with this technique requires special care to attempt to obtain a representative sample, and in any case when the flowing bottom hole pressure is lower than the bubble point, the validity of the sample remains doubtful. Multiple subsurface samples are usually taken by running sample bombs in tandem or performing repeat runs. The samples are checked for consistency by measuring their bubble point pressure at surface temperature. Samples whose bubble point lie within 2% of each other may be sent to the laboratory for PVT analysis. 

Similar copolymers with N-vinyl-N-methylacetamide as a comonomer have been proposed for hydraulic cement compositions [669]. The polymers consist of AMPS in an amount of 5% to 95%, vinylacrylamide in an amount of 5% to 95%, and acrylamide in an amount of 0% to 80%, all by weight. The polymers are effective at well bottom-hole temperatures ranging from 200° to 500° F and are not adversely affected by brine. Terpolymers of 30 to 90 mole-percent AMPS, 5 to 60 mole-percent of styrene, and residual acrylic acid are also suitable for well cementing operations [253]. 

An N-vinylpyrrolidone/acrylamide random copolymer (0.05% to 5.0% by weight) is used for cementing compositions [371, 1076]. Furthermore, a sulfonate-containing cement dispersant is necessary. The additive can be used in wells with a bottom-hole temperature of 80° to 300° F. The fluid loss additive mixture is especially effective at low temperatures, for example, below 100° F and in sodium silicate-extended slurries. 

Cement accelerators are shown in Table 10-12. The most common accelerators are calcium chloride and sodium chloride. Calcium chloride may be used in concentrations up to 4% by weight in wells with bottom-hole temperatures less than 50° C. Calcium chloride tends to increase the final strength under pressure conditions. 

Sodium chloride can be used as an accelerator in formulations that are bentonite free. The maximal bottom-hole temperature is 70° C. In concentrations above 5%, the effectiveness is reduced. Saturated sodium chloride solutions act as retarders. 

Another method of sand control is use of a silicon halide which reacts with water at the surface of sand grains forms SiO which can bond the grains together (55). Reducing the cost of sand consolidation could be very useful since the applicability of gravel packing methods is limited by the bottom hole circulating temperature and the limited temperature stability of polysaccharide polymers. 

It seems probable that in this case the conditions were ideal for Shellflo-S. The water depth is in excess of 300 metres and the reservoir relatively shallow, with a bottom hole temperature of around 70 C, close to the transition temperature. 

Bottom Hole Static Temperature (BHST) Bottom Hole Static Pressure (BHSP) Formation fluid ... 

Bottom Hole Injection Temperature Average injection rate ... 

The reactor wall is constructed of a steam jacket to protect the steel from high temperatures. The slag produced is mainly leaving the reactor through a bottom hole. 

The col was filled with a bottom hole crude sample and immersed in a thermostatted bath. After one hour at 46°C, the temperature of the bath was gradually decreased at 1.5°C/hr to 4°C and maintained at this temperature for two weeks. After the test period, flow was obtained by applying 0.04 bar (equivalent to 30 psi In field with 5" flowline), indicating that cold start-up would not be a problem ir the field. 

Thus given the injection rate of the test fluid, say water, and its viscosity, and the bottom hole pressure, one can estimate the injection rate for the acid gas at a given bottom hole pressure, given the viscosity of the acid gas. Methods for calculating the viscosity of acid gas were given earlier, and the viscosity of water as a function of pressure and temperature is well known. 

Well Head Flowing Temperature 120 C Bottom Hole Flowing Temperature 120 C... 

Depth is depth below ground level of midpoint of perforation. Temp, is measured subsurface temperature. Pressure is original bottom-hole pressure in MPa TDS is calculated total dissolved solids. HCO3 is the field titrated alkalinity and includes organic and inorganic species. 

The stirrer must provide good circulation if the temperature of th thermostat liquid is to be uniform. One design which is quite efficient and which occupies relatively little space is shown in Fig. 5-27. It is made from a length of brass tube to which supports have been silver-soldered at the top and bottom. A number of holes are drilled in the sides of the tube, and a central rod is fastened to the assembly. As this is turned (usually at — 1,500 to 1,800 rpm), centrifugal force throws the water out of the holes on the side. The supply of water is replenished through the top and bottom holes. The stirrer requires considerable torque for its operations, and it is usually necessary to employ at least a i/oo-hp motor. 

But three facts suggest that Edwards brines today should contain less dissolved silica than when they initially formed (1) the most saline brines we sampled are only saturated with halite, and thus have probably been diluted since they formed (2) cooling to 160°C, the present bottom-hole temperature of the wells, may have caused precipitation of about half the original silica in the deep aquifer and (3) the solubility of silica in near-halite-saturated brines may be lowered significantly because of the reduced activity of water. Clearly the SiO2 values obtained today do not preclude quartz-saturation at the time the brine originally formed. 

Table 1. References to oilfield diagenesis studies from which data in Figs 3-8 were compiled (see also Abbotts. 1991) Formation Bottom hole Formation Depositional depth temperature ...

Calibration of the thermal model is possible using present-day bottom-hole temperatures from exploration wells (Deming Chapman 1989) and by the comparison of modelled and measured vitrinite reflectance (see Section 5.7.3), an example of which is shown in Fig. 5.50. There are other measurements that can provide time-temperature constraints, such as fission-track analysis (Naeser 1993 Gleadow Brown 1999), homogenization temperatures of fluid inclusions (Roedder 1984) and clay transformations (Hoffman Hower 1979). 

Figure 4. Relationship between geothermal gradient and zeolitic zonation. Temperatures were determined by the bottom hole temperature. Boundaries of the zonation are subparallel to each other and are influenced essentially by temperatures.

Present-day burial depth for the Norphlet in Fairway Field ranges from 6.6 to 7.0 km (21 600-23 000 ft). Corrected bottom hole temperatures are roughly 200-220 °C with a geothermal gradient of approximately 33°/km. The... 

Bossier sands in this area and throughout the East Texas Basin also exhibit abnormally high temperature gradients. Bottom-hole temperatures range from 280 to 325 °F at depths ranging from 12 500 to 13 500 ft. This corresponds to temperature gradients of 2.2 to 2.4 °F per 100 ft of depth. 

Oil well cements must usually perform at elevated temperatures and pressures, both of which increase with increasing depth. The maximum temperature encountered at the bottom of deep wells may reach 250°C, and may even exceed 300°C in geothermal wells. Under these conditions the temperature of the sluny during pumping may reach 180°C (bottom hole static temperature). The pressure to which the cement sluny is exposed is equal to the hydrostatic load plus the pumping pressure, and may reach 150 MPa. 

Cool and transfer heat away from source and lower to temperature than bottom hole. 

Emulsified fracturing fluids are typically very viscous polymer oil-inwater emulsions that may consist of60-70% hquid hydrocarbon dispersed in 30-40% aqueous solution or gel. The hydrocarbon phase may be diesel fuel, kerosene, or even crude oils and condensates. The aqueous phase may consist of gelled fresh water, a KCl solution or an acid solution. Emulsion fracturing fluids may be applied to oil or gas wells, particularly in low pressure formations susceptible to water blockage, and for bottom-hole temperatures of up to about 150 °C. They can provide excellent fluid loss control, possess good transport properties and can be less damaging to the reservoir than other fluids. However, emulsions are more difficult to prepare and can be more expensive. 

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