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INPUT   DATA

Title

Flow Direction

Production   Injection

Wellhead pressure		psia
Wellhead temperature		° F
Bottomhole temperature		° F
Inside diameter		inches
Tubing length		ft
Gas relative density
Gas flow rate		Mcf/day

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OUTPUT   VARIABLES   &   GRAPHS

	Depth	Temperature	FLOWING:		STATIC: No flow
			Z-factor	Pressure	Z-factor	Pressure
#	ft	°F		psia		psia
1
:
11

Static & Flowing Bottomhole Pressures In Gas Wells

It is a common and economic engineering practice to make surface measurements of gas pressure (and flowrate), and from thence predict the static and flowing pressure at the subsurface sand face.

The widely-used equation for estimating both static and flowing bottomhole pressure for a single-phase vertical gas flow in a tubing is given as:

Where:

   Q = gas rate at surface, Mcf/d, i.e. 1000cf/d
   + = gas production
   − = gas injection
   P_s = flowing sandface pressure, psia
   P_w = wellhead pressure, psia
   T_a = average temperature, °R
   G = mean gas relative density (air = 1)
   Z_a= mean gas compressibility factor
   d = inside diameter of pipe, inches
   h = tubing length/well depth, ft
  ƒ = Moody friction factor

Z depends on both T & P and, T & P vary across the length of the tubing, and P is the primary unknown. Thus the equation can only be solved in an stepwise iterative fashion. The method of successive substitution is used here to solve the equation. The tubing is discretized into 10 equal sections, such that the P_w of one section is set equal to the P_s of the one above it, and so on. Z is computed via the Yarborough & Hall correlations.

BIBLIOGRAPHY

• Maddox R.N. & Lilly L.L.; Gas Conditioning & Processing, Volumes 2 & 3; Campbell Petroleum Series, Norman, Oklahoma, 1990.
• Katz D.L. & Lee R.L.; Natural Gas Engineering - Production & Storage; McGraw-Hill Publ. Co., New York, 1990, chap. 6.
• Smith R.V. & Cullender M.H.; Practical solutions of gas-flow equations for wells and pipelines with large temperature gradients, Trans. AIME, 1956, p 281-287.