Pump Capacity Determination For Two-Phase Vertical Fluid Flow

Project and Seminar Material for Petroleum Engineering

Pump Capacity Determination For Two-Phase Vertical Fluid Flow


Chapter One


Introduction

1.1 Background of Study

In the production system, Pressure drop has been a major issue in the field. These pressure drops could be experienced as a result of valves and fittings

installed, due to friction along pipe sections or in lifting fluid up to a certain level.

As these pressure drops are identified, and the economic flow rate of a reservoir fluid is known, pumps may be employed to reduce the effect of pressure drop and maintain a given fluid flow rate for good economic recovery. These pump applications are usually analysed to determine an optimum Hydraulic pump requirement for a given fluid system and pipe diameter. It can form one of the basic aspect to be considered during well completion in selecting production tubing diameter.

In general, a pump is a device used to transport liquids, gases, and slurries. However,the term pump is usually used to refer to liquid handling equipment. The purpose of the pump is to provide a certain pressure at certain flowrate of a process stream. The pressure requirement is dictated by the process andpiping involved, while the flow rate is controlled by the required capacity in thedownhole units.

At least one out of every 10 barrels of oillifted in the world’s oil and gas operations are produced using an ElectricSubmersible Pump (ESP). Typical installationsproduce liquids in the 2,000 to 20,000 bpd range,making the ESP an effective and economical meansof lifting large volumes of fluids from great depthsunder a variety of well conditions.

There are several types of pumps used for liquid handling. However, these can bedivided into two general forms: positive displacement pumps (including reciprocatingpiston pump and the rotary gear pump), and centrifugal pumps. The selection of thepump type depends on many factor including the flow rate, the pressure, the nature ofthe liquid, power supply, and operating type (continuous or intermittent).

The power requirement for a mechanical system, like pumps and compressors, isgiven by the general mechanical balance equation:

P = -mWs = m 1.1

All terms in this equation take their normal meaning with m being the mass flow rate,and α a coefficient used to take into account the velocity profile inside the pipe (forlaminar α = 0.5, while for turbulent α = 1). The required work (or power) given by Pis the total work that needs to be delivered to the fluid. This work will be drawn froma motor (operated with electricity or engines). The conversion between the motor andpump power is not complete and an efficiency is defined to describe the powerconversion. The efficiency is given by:

The input power can be measured from the source. For example, if the pump is

operated with electricity, the input power will be I×V (current times voltage). Theoutlet power can be determined using Equation (1.1).

  1. Static head (Δzterm): the height to which the fluid will be pumped.
  2. Pressure head ( term): the pressure to which the fluid will be delivered (ina pressurized vessel for example). The pressure units must be converted to lengthunits using relation.
  3. System or dynamic head (F term): the energy lost due to friction in pipes, valves,fittings, etc.

1.2 Statement of the Problem

It is important to accurately predict the pressure drop accross a production system. This has been a difficult task in the oil and gas industry as the production system in real life is not homogenous (single phase) as assumed in most theories. The reason for this is that the two-phase flow is complex and difficult to analyze. Ideally, gas moves at a much higher velocity than the liquid. As a result, the down hole flowing pressure of the liquid-gas mixture is greater than the corresponding pressure corrected for down hole temperature and pressure and this could be calculated from the produced gas-liquid ratio.

This pressure drop in a flowing (production) system could be identified using different existing correlations. Some of these correlations are empirical, mechanistic or numerical. Hagedorn and Brown is the most widely used correlation for vertical wells (Schoham, 2006). In planning well completion the tubing diameter that will give less pressure drop hence much liquid production can be selected by the use of multiphase correlation.

It is also very necessary to plan for pumps in tubing size selection should need arise on future production for pumping of the reservoir fluid to optimize production.


1.3 Objective of the Study

Determine the Hydraulic Horse Power Requirement needed to maintain production of reservoir fluid within economic limit.

The above objective can be achieved by using two-phase pressure drop correlations to determine pressure drop in selected production tubing used in the Niger Delta.


1.4 Scope of the Study

The determination of pressure drop using the selected two-phase correlations using production tubings used most often in the Niger Delta.


Chapter Five


Conclusion and Recommendation

5.1 Conclusion

Multiphase flow is a complex problem occurring in most industries. In the oil and gas industry, the ability to predict the holdup of each phase is of considerable importance. Therefore, in order to design and operate oil production systems in an optimized manner, it is necessary to accurately predict the behavior of two-phase flow of oil and gas in tubing.

Engineers performing multiphase-flow design calculations for wellbores are clearly faced with the question; which correlation or model should be used? Many companies have employ the two-phase flowdiscused in this study, several of these models are incorporated in the literature.

No existing comprehensive model properly accounts for all the effects of produced gas-liquid ratio in larger diameter tubing. Although excellent modelssuch as Duns and Ros (1963), Orkiszewski (1967) and Beggs and Brill (1973) are available to predict flow patterns at all tubing sizes.


5.2 Recommendation

This work is recommended for well completion operations. It is of great importance to determine the pump requirement for each tubing sizes used in two-phase fluid production considering the pressure drop that is likely to be experienced.

Anyfurther studies on the empirical correlations should improve results by increasingaccuracy in liquid holdup prediction as that is key factor that affects the pressure gradient predictions based on this studies. Studying the mechanistic model for pressure drop prediction in avertical well are recommended also to enhancethe calculations and better optimize vertical two-phase flow system.


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