Abstract

In order to minimize the tubing corrosion during production in a gas well, it is necessary to determine the factors such as wettability of tubing and critical erosional velocity etc. for the design of tubing corrosion prevention. The purpose of this work is to study the phase behavior of the production fluid in a production tubing in connection with the flowing velocity and wettability of tubing. Data from a CO2-rich offshore gas well of Taiwan are analyzed by a procedure developed in this study. It is shown by our calculation that the tubing in the well should not be corroded seriously during production because the tubing inner wall is oil-wet and the flowing velocities are much less than the critical erosional velocities.

Introduction

A gas reservoir may be filled with natural gases, water, and possibly water vapor, condensate vapor saturated in natural gases may condense due to changes in pressure and temperature in the production tubing. The water and carbon dioxide may form carbonic acid which is corrosive to the tubing wall. The degree of tubing corrosion is affected by two major factors:

  1. the wettability of the tubing wall;

  2. the tubing flowing velocity.

The wettability of tubing is determined by the amount of water and oil (condensate) adhering to the tubing wall. The amount of condensed water and oil is related to the phase behavior of flowing fluids in tubing. The pressure in tubing, playing an important role in the phase behavior, is varied with the production rate which is in turn related to the tubing flowing velocity. Therefore, two factors mentioned above have close relation with phase behavior of production fluids.

Determination of the phase behavior can provide information for locating the occurrence of condensed oil and water which are important for the possibility of forming carbonic acid and for determining the wettability of tubing. In addition, a critical erosional velocity, a threshold value to increase tubing corrosion rate of a factor of four, should be estimated for the production control to prevent tubing corrosion.

The purpose of this work is to study the phase behavior of the production fluid in a production tubing and to determine the wettability of tubing, critical erosional velocity, and flowing velocities for corrosion control. The result of the study is intended to provide key information for corrosion prevention design.

PRESSURE DISTRIBUTION

In order to estimate the amount of condensed oil and water in tubing, it is necessary to determine the flowing pressure distribution. The pressure distribution in tubing can be calculated by the equation suggested by Cullender and Smith for a vertical well.

Productivity of a Horizontal Well

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Copyright 1988 Society of Petroleum Engineers, Inc.

This paper was prepared for presentation at the 63rd Annual Technical Conference and Exhibition of the Society of Petroleum Engineers held in Houston, TX, October 2-5, 1988.

This paper was selected for presentation by an SPE Program Committee following information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper Is presented. Write Publications Manager, SPE, P.O. Box 833836, Richardson, TX 75083-3836. Telex, 730989 SPEDAL.

APPENDIX A

Two appendices describe the mathematical and algebraic details that led to the formulas provided in the text of this paper. Appendix A presents the general solution, and briefly describes the techniques for deriving simple, closed form expressions for single, double, and triple sums of infinite series. Appendix B describes these procedures in a little more detail, and also indicates certain methods for averaging the variable wellbore pressures in the general anisotropic cases.

Uniform Flux Boundary Condition

For well problems similar to the one treated in this paper, a uniform flux, or a uniform pressure is commonly imposed as a boundary condition at the well surface. Recognizing that neither is entirely correct, the question that has been debated is whether one is preferable to the other, or whether both give satisfactorily accurate solutions. Muskat showed that the uniform flux boundary condition gives values accurate to 0.5 percent. We also investigated the implication of the uniform flux assumption. We used our exact solution (Equations A1-A3) and computed the wellbore pressure, Pwf at various locations y along the well length L. We did this for isotropic and anisotropic systems where the wells were located at the center, or away from the center. For the anisotropic runs the value of kx was equal to, or twice as large as, that of ky, and was ten times that of kz. Also L/b=0.5. We found that the maximum variation in Pwf values was 7 psi for the worst case. This was the anisotropic case with kx=2ky, kx=10kz, and the well was located away from the center.

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