Hydrostatic pressure-depth plot construction

	Exploring for Oil and Gas Traps
Series	Treatise in Petroleum Geology
Part	Critical elements of the petroleum system
Chapter	Formation fluid pressure and its application
Author	Edward A. Beaumont, Forrest Fiedler
Link	Web page
Store	AAPG Store

A critical element in detecting the presence of hydrocarbons using formation fluid pressures is an accurate hydrostatic pressure gradient for zones of interest. We use the hydrostatic pressure gradient to determine the expected pressures for the zone of interest as if it had no hydrocarbons. Pressures exceeding hydrostatic pressures may be due to the presence of a hydrocarbon column. Most methods for determining hydrostatic pressures are not very precise. Other petrophysical data can help when the estimated hydrostatic pressure gradient is suspect.

The goal of constructing a hydrostatic pressure–depth plot is to identify pressures greater than the hydrostatic gradient that may correspond to a hydrocarbon-bearing zone. A hydrostatic pressure–depth plot can be constructed from any of the following:

Measured pressures
Regional rule-of-thumb pressure gradients
Pressures calculated from water density

Calculated pressures are much less accurate than measured pressures but can be used with some effectiveness when they are supplemented with other petrophysical data.

Procedure: constructing a plot

The table below outlines a procedure for constructing a hydrostatic pressure-depth plot for a single well.

Using graph paper with a linear grid, label the X-axis as pressure and the Y-axis as depth. Use as large a scale as possible. Also, make the Y-axis on at least one plot the same scale as on the well logs to aid in interpretation.
Plot measured pressure from the aquifers (100% water saturation [S_w] ) in the well. If none is available, go to step 3.
Plot measured pressure from the aquifers in nearby wells. If none is available, go to step 4.
Calculate and plot hydrostatic pressures for a depth above and a depth below the zone of interest. Use the rule-of-thumb pressure gradient for that zone. If it is not available, calculate the gradient from the water density using density measured from the formation water or calculated from the water resistivity (R_w) . For help, see the following sections.

Calculating pressure gradients from water density

The formation fluid pressure at any depth in a well is a function of the average formation water density (ave. ρ_w) above that depth, not the density of the formation water at any particular depth. Formation water generally becomes more dense with increasing depth.

To calculate water pressure gradient (P_grad), use the following formula:

{\mbox{P}}_{\rm {grad}}={\mbox{ave. }}\rho _{\rm {w}}\times 0.433{\mbox{ psi/ft}}

where:

$\mathrm {ave.} \rho _{\mathrm {w} }={\frac {\Sigma _{1}^{\rm {n}}\rho _{\rm {w}}}{\mbox{n}}}$
ρ_w = water density

For example, given ave. ρ = 1.13, the equation works as follows:

{\mbox{P}}_{\rm {grad}}=1.13\times 0.433{\mbox{ psi/ft}}=0.489{\mbox{ psi/ft}}

Table of water pressure gradients

The table below lists hydrostatic pressure gradients, water density, and salinity in weight percent total dissolved solids (TDS).

Gradient (psi/ft)	Density (g/cc)	TDS (ppm)	TDS (wt %)
04.33	1.000		0
0.437	1.010	13,500	13.5
0.441	1.020	27,500	27.5
0.444	1.029	37,000	37.0
0.445	1.030	41,400	41.4
0.451	1.040	55,400	55.4
0.454	1.050	69,400	69.4
0.459	1.060	83,700	83.7
0.463	1.070	98,400	98.4
0.465	1.075	100,000	100.0
0.467	1.080	113,200	113.2
0.471	1.090	128,300	128.3
0.476	1.100	143,500	143.5
0.480	1.110	159,500	159.5
0.485	1.120	175,800	175.8
0.489	1.130	192,400	192.4
0.491	1.135	200,000	200.0
0.493	1.137	210,000	210.0
0.500	1.153	230,000	230.0
0.510	1.176	260,000	260.0

Rules of thumb

Most sedimentary basins have a rule of thumb for average hydrostatic water pressure gradients. For the Gulf Coast Basin, it is 0.465 psi/ft. For Rocky Mountain basins, it is 0.45 psi/ft. For fresh water, it is 0.433 psi/ft. If measured hydrostatic pressure is not available for a well, find out the accepted rule-of-thumb average hydrostatic pressure gradient for the depth of the zone of interest where the well is located.

Example of total dissolved solids (TDS) vs. depth

Figure 1 TDS vs. depth plot from southern Arkansas. Copyright: Dickey,^[1] courtesy Chemical Geology.

Water density is a function of its TDS concentration. The hydrostatic pressure at any depth is a function of TDS concentration from the surface to that point. The plot in Figure 1 of TDS vs. depth is from southern Arkansas. It shows a gradual increase in TDS from the surface to about depth::2000 ft, probably due to meteoric effects, and then a linear, more rapid increase in TDS from 2000 to depth::10,000 ft. Generally, below the depth of meteoric water influence, the increase in TDS in connate brines is linear and ranges from 25,000 to 100,000 mg/1 per depth::1000 ft (80 to 300 mg/1 per m).^[1] There are exceptions to this general case.

Such consistent salinity increase with depth is not unique to the East Texas basin but is characteristic of most basins.

References

↑ ^1.0 ^1.1 Dickey, P. A., 1969, Increasing concentration of subsurface brines with depth: Chemical Geology, vol. 4, p. 361–370., 10., 1016/0009-2541(69)90055-2

External links

find literature about
Hydrostatic pressure-depth plot construction

[ch05r6-1] 1.0 ^1.1 Dickey, P. A., 1969, Increasing concentration of subsurface brines with depth: Chemical Geology, vol. 4, p. 361–370., 10., 1016/0009-2541(69)90055-2

[1]

Hydrostatic pressure-depth plot construction

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