Abstract

Large expenditures are usually made to add both wells and compressor horsepower during development of a depletion type gas field. Profits can be enhanced if the proper combination of each is selected and installed prior to blowdown. A graphical technique has been prior to blowdown. A graphical technique has been developed and used for several large South Texas fields to determine the best horsepower/well combination. This technique is discussed and several field examples are shown.

Introduction

Depletion type gas fields are characterized by declining well productivities as reservoir pressure declines. During blowdown gas sales rates will decline rapidly unless additional monies are spent for either new wells, additional compressor horsepower, or a combination of these two deliverability-type expenditures.

If external controls such as field rules, lease equities, or ultimate recovery dictate the number of wells to be drilled, then the decision of how much compressor horsepower should economically be installed can be analyzed with a case study simulation technique. If wells can be varied, but only a few reservoirs are involved, a dynamic programming technique as described by Huppler can be used, if available. However, if many combinations of horsepower and wells are possible, then the above techniques may become either impractical or extremely time consuming to work.

A graphical calculation technique has been used for several large South Texas gas fields to determine the best horsepower/well combination. The technique utilizes a single case study for development of field well deliverability data and then expands this single case by simple hand calculations for other alternate cases. The set of cases generated for each fixed rate is plotted graphically to determine the HP/well combination that results in minimizing the remaining present value cost to deplete the field. External present value cost to deplete the field. External economic calculations are then made to determine the maximum field rate which can economically be achieved and the total amount of compressor horsepower and wells that should be installed.

BASIC ASSUMPTIONS

The principal costs associated with adding new wells are (1) the initial investment, and (2) the future well operating cost. The principal costs associated with adding compressors are (1) the initial investment less future salvage value, (2) compressor fuel, and (3) compressor operating costs. It is these five items that are considered "controlling" in the analysis technique which follows. Approximations are made in order to keep the technique simple and thereby allow hand calculations and graphical solutions. No attempt is made to optimize well density for ultimate recovery, to optimize surface facilities for reduced friction losses, or to optimize deliverability coverage or production schedules between reservoirs. All of this work must be done external to this calculation. Several papers have been published previously which discuss these optimization problems.

In summary, the basic assumptions which are made herein are:

  1. Pressure is uniform throughout the reservoir and can be predicted as a function of cumulative production only.

  2. Deliverability for new wells drilled can be defined by a single set of well deliverability curves and represented by a fractional increase to the total field deliverability curves. Each well drilled remains productive throughout the remaining field life.

  3. Gas sales delivery pressure is relatively constant such that compressor horsepower needed is a function of suction pressure and rate and is not affected by time.

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