Bottom hole pressure

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. 

A static bottom hole pressure survey (SBHP) is useful for determining the reservoir pressure near the well, undisturbed by the effects of production. This often cannot be achieved by simply correcting a surface pressure measurement, because the tubing contents may be unknown, or the tubing contains a compressible fluid whose density varies with pressure (which itself has an unknown profile). 

It is common practice to record the bottom hole pressure firstly during a flowing period (pressure drawdown test), and then during a shut-in period (pressure build-up test). During the flowing period, the FBHP is drawn down from the initial pressure, and when the well is subsequently shut in, the bottom hole pressure builds up. 

Reservoir pressure is measured in selected wells using either permanent or nonpermanent bottom hole pressure gauges or wireline tools in new wells (RFT, MDT, see Section 5.3.5) to determine the profile of the pressure depletion in the reservoir. The pressures indicate the continuity of the reservoir, and the connectivity of sand layers and are used in material balance calculations and in the reservoir simulation model to confirm the volume of the fluids in the reservoir and the natural influx of water from the aquifer. The following example shows an RFT pressure plot from a development well in a field which has been producing for some time. 

SIBHP — Shut-in bottom-hole pressure 8.000 psig... 

Because the fluid flow in annular space is upward, the total bottom hole pressure is equal to the hydrostatic head plus the pressure loss in the annulus. Bottom hole pressure (psi). 

Note that when the circulation is stopped, the friction pressure loss in annular space diminishes to zero and the bottom hole pressure is reduced to 5,000 psi. Pressure inside the string above the nozzle, p, (psi),... 

Stable Foam. When a well is drilled with stable foam as the drilling fluid, there is a back pressure valve at the blooey line. The back pressure valve allows for a continuous column of foam in the annulus while drilling operations are under way. Thus, while drilling, this foam column can have significant bottom-hole pressure. This bottomhole pressure can be sufficient to counter formation pore pressure and thus control potential production fluid flow into the well annulus. 

Weighting agents (Table 10-10) are added to increase the density of the cement. They are typically used to combat high bottom-hole pressures. Common additives are powdered iron, ferromat, powdered magnetite, and barite. Hematite ean be used to increase the density of a mixture up to 2200 kg/m (19 Ib/gal). Hematite requires the addition of some water. 

Matching Water-Oil Ratio, Gas-Oil Ratio or Bottom Hole Pressure... 

Similar findings were observed for the gas-oil ratio or the bottom hole pressure of each well which is also a state variable when the well production rate is capacity restricted (Tan and Kalogerakis. 1991). 

In this case the observed data consisted of the water-oil ratios, gas-oil ratios, flowing bottom hole pressure measurements and the reservoir pressures at two locations of the well (layers 7 and 8). In the first run, the horizontal permeabilities of layers 6 to 9 were estimated by using the value of 200 md as the initial guess. 

Figure 18.25 Observed data and model calculations for initial and converged parameter values for the 2"d SPE problem, (a) Match ofgas-oil ratio and water-oil ratio, (b) Match of bottom-hole pressure and reservoir pressures at layers 7 and 8 [reprinted with permission from the Society of Petroleum Engineers].

Oil was originally separated in two stages. The high-pressure separator operated at 1,050 psi, whereas the low-pressure separator operated at 275 psi. Initial studies predicted that the reservoir would produce using a fluid expansion drive, and that rapid decline in bottom-hole pressure would be experienced. Early predictions were confirmed as reservoir pressure declined from an initial pressure of 7,850 psi to 6,000 psi while recovering less than 5 percent of the oil in place. Plant inlet pressure was lowered from 1,100 to 275 psi and additional compres-... 

Consider the ten year cumulative gas production prediction of the JOE model shown in Figure 7.46 (note the logarithmic scale of both axes). From the figure it is clear that hot water circulation alone will not be productive for a period after 0.02 years, due to the low thermal conductivity of the hydrates and sediments. However, depressurization does appear to be a favorable production mechanism, comparing favorably to hot water circulation with reduce bottom hole pressure, or partial hot water injection. 

In all scenarios it was possible to inject the required volumes of working gas within a period of 1 - 5 months. The subsequent withdrawal of identical volumes of gas from the storage was possible in all scenarios5, except Scenario IV, without using additional cushion gas. In Scenario IV, it was possible to withdraw only 465 and not the required 480 million m3 gas, if no additional cushion gas was to be injected. It was demonstrated, however, that lowering the minimum well bottom hole pressure by 10 bar to 80 bar and optimising the individual well rates, would enable the withdrawal of the required 480 million m3 gas. 

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. 

Answer If the surface pressure for the water column is 700 kPa, or 0.7 MPa, then we can estimate the bottom hole pressure using the hydrostatic head equation (see Chapter 8). First, assume the density of water is 1000 kg/m3. 

Neglect this small change in pressure on the density and use this as the bottom hole pressure. 

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. 

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