Introduction

Analyzing well performance is an important step toward increasing profits by improving production techniques. The analysis is made by field tests and examination of well data. The acoustic liquid level instrument offers valuable information since downhole pressures can be determined from the depth to liquid pressures can be determined from the depth to liquid measurement.

FLUID FLOW

Fluid flow in a reservoir is caused by movement of fluid from a high-pressure area to a low-pressure area. Fluid flow into a wellbore occurs when fluids present in the wellbore are removed so that the present in the wellbore are removed so that the pressure is decreased in the wellbore. Then, fluid from pressure is decreased in the wellbore. Then, fluid from an area of higher pressure flows into the lower pressure wellbore (Fig. 1). pressure wellbore (Fig. 1).Fluid flow increases as the differential pressure increases. Vogel presents a curve for predicting pressure increases. Vogel presents a curve for predicting flow rates based upon the ratio of the wellbore pressure to the reservoir pressure. This curve is shown pressure to the reservoir pressure. This curve is shown on the Well Analysis Sheet. Note: approximately 70% of the maximum flow rate will occur when the wellbore pressure is one-half of the reservoir pressure. Also pressure is one-half of the reservoir pressure. Also note, 90% of the maximum flow rate will occur when the wellbore pressure is 25% of the reservoir pressure.

NECESSARY DATA FOR WELL ANALYSIS

Four factors are extremely important in analyzing well performance:

  1. reservoir pressure,

  2. producing bottom hole pressure,

  3. well test and

  4. producing bottom hole pressure, (3) well test and (4) pump capacity. pump capacity.

For maximum withdrawal, the producing bottom hole pressure must be low compared to the reservoir pressure. A producing bottom hole pressure of 75 psia pressure. A producing bottom hole pressure of 75 psia is low compared to a static reservoir pressure of 2300 psia and practically all of the production is being psia and practically all of the production is being obtained. However, if the static reservoir pressure is 100 psia, approximately 40% of the maximum production rate is being obtained. The well test and pump production rate is being obtained. The well test and pump capacity must be known. If the pump capacity is not matched suitably to the well's production, excessive wear and a mechanical loss of efficiency are occurring if the pump capacity greatly exceeds the production rate. A production loss occurs if the pump capacity is less than the well's producing capacity.

Note the importance of each item by trying to determine proper action on each of the wells in Table 1 when only one of the four items on each well is omitted.

DETERMINING WELLBORE PRESSURE

The pressure at the wellbore can be obtained from the depth to the liquid, the casing pressure, and a knowledge of the fluids present in the casing annulus. The wellbore pressure (whether the well is at static or producing conditions) is the sum of the casing pressure, the gas column pressure, and the liquid column pressure.

The casing pressure, gas column pressure and liquid column pressure must be totalled to determine the producing bottom hole pressure of a well making gas, oil and water. All the liquid above the pump will be oil due to gravity separation. This is often seen in a well which temporarily flows 100% oil out of the casing when sufficient bottom hole pressure exists, even though the well produces in excess of 90% water through the tubing. The liquid below the pump and above the formation will be oil and water in pump and above the formation will be oil and water in the same ratio as is produced from the well.

If the bottom hole pressure at static conditions is desired, additional information is necessary. If the well was pumped down before being shut in, the liquid that collects in the annulus will be approximately the same ratio of oil and water that is produced from the well (Fig. 2A). If the well was not produced from the well (Fig. 2A). If the well was not pumped down before closing in the well, the liquid pumped down before closing in the well, the liquid above the pump while the well was being produced must be determined. This liquid above the pump is entirely oil if the formation has produced enough oil to fill the annular space. The liquid level rise after the well is shut in consists of the same ratio of liquids that are normally produced (Fig. 2B).

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