Supplementing the Vertical Lift Process

There are several techniques which are available to assist in bringing oil to surface and these are collectively referred to as Artificial Lift Techniques. These processes are widely applied in all geographical areas. In some cases, they are essential to the initial economic development of a hydrocarbon reservoir whilst in other cases they are implemented later in the life of the field to maintain production at economic levels. The various techniques can be further classified into those which simply provide additional energy to assist the lift process and those which provide some reduction in the vertical lift pressure gradient.

(1) Gas Lift

The gas lift process involves the injection of gas normally into the annulus between the production tubing and casing. The gas is subsequently allowed to enter the flowstream within the production tubing at some specific depth through a single or more usually a series of gas lift valves (Figure 15). The injection of gas into the production tubing provides a stepwise increase in the gas liquid ratio of the fluids flowing in the tubing at that depth and throughout the tubing above the injection point. This results in a reduction of the bottomhole pressure and offloading of the well. To be able to enter the tubing, the pressure of the gas in the annulus, at the valve which will permit its flow into the tubing, must be greater than the pressure of the fluids in the tubing at that same depth.

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Reservoir Production Concepts

Gas Injected

Gas

Gas Entry Valve Produced Fluids

to Separator

To understand more clearly the action of gas lift, consider the definition of ∆P_VL in equation 8

∆P_VL = ∆P_FRICT + ∆P_HHD + ∆P_KE (11)

By injecting gas, the GLR of the flowing fluid is increased, ie, its effective flowing density is reduced and accordingly ∆P_HHD is reduced. In addition, the compressibility of the gas will assist in the lift process since as the gas rises up the tubing with the liquid it will expand, causing an increase in the tubing flow velocity. However, as the gas expands it will introduce some increase in the frictional pressure losses which will negate some of the advantage due to the reduced hydrostatic head (refer to equation 8 above). With increasing gas injection volume, the hydrostatic head will continue to decline towards a minimum gradient at very high GOR. The benefits in reduced density may incrementally reduce whilst the increase in frictional pressure loss will increase significantly after a certain gas injection rate. Hence, an optimum gas injection rate will exist, as shown in Figure 16.

Figure 15

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Gas Injection Rate

Oil Production Rate Q_o ˘P_VL ˘P_HHD ˘P_FRICT ˘P_VL Q_o Consider Equation 10- Total System Pressure drop,

∆P_TOT = [∆P_RES + ∆P_BHC + ∆P_VL + ∆P_SURF + ∆P_CHOKE]_Q (12) If the system undergoes gas lift, then ∆P_TOT will be held constant, but ∆P_VL will decrease to a minimum and Q will increase through a maximum. Thereafter ∆P_VL will increase and Q will decrease as shown in equation 10.

Gas lift is a very effective method of increasing the production rate, provided that the gas is effectively dispersed in the flowing fluid column and the optimum injection rate is not exceeded.

(2) Downhole Pumping

Referring to Equation 7, if a pump system is used, then an additional term is introduced to reflect the supplementary energy provided ∆P_PUMP. This will allow a higher production rate to be attained by the well:

P_RES + ∆P_PUMP = [∆P_RES + ∆P_BHC + ∆P_VL + ∆P_SURF + ∆P_CHOKE]_Q + P_SEP (13) There are four principal methods which are as follows:

(a) Electric Submersible Pumps

This consists of a multi stage centrifugal pump located at some position downhole usually as an integral part of the tubing string (Figure 17). The requirement for the pump suction to be flooded will dictate setting depth in the well for the pump, depending upon the well pressure. An electric cable run with the production tubing supplies the power from surface to the downhole pump. As an alternative the pump can be run on coiled tubing or on its power cable.

Figure 16

Optimisation of gas injection rate

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Reservoir Production Concepts

To Power Supply Electricity Cable Multi-Stage Centrifugal Pump

This type of pump is ideally suited to relatively high rates of production, from < 1000 to > 25,000 BLPD.

(b) Hydraulic Downhole Pumps

This type of pump, normally run at depth in the tubing string, normally utilises hydraulic fluid power fed down a separate small bore tubing parallel to the tubing string (Figure 18). Alternatively, the fluid can be injected via the casing tubing annulus. Fluid pumped down the line at high pressure powers the drive unit for the downhole pump. The hydraulic fluid usually joins the flowing well fluid in the tubing and returns to surface. Alternatively the fluid can be ducted back to surface separately. The drive unit can range from a reciprocating piston for low flow rates, to a turbine for rates which exceed 20,000 BLPD

Figure 17

Electrical submersible pump installation

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Downhole Hydraulic Pump Unit Hydraulic Fluid Supply Tubing Produced Fluids Including Hydraulic Power Fluid to the Separator Hydraulic Power

(c) Sucker Rod Pumping

In this system, a plunger, cylinder and standing valve system is located downhole as part of the tubing string and connected by steel rods to a vertical reciprocation system at surface (Figure 19). The surface reciprocation system is referred to as a “nodding

donkey”and is driven by a beam suspended on a pivot point and creates reciprocation

through a rotary wheel. This type of system is suitable for very low to medium production rates i.e. < 1,000 BLPD and can operate with wells having no flowing bottomhole pressure.

Figure 18

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Reservoir Production Concepts

Figure 19

Sucker rod pump system

Nodding Donkey Rod Pump Tubing Anchor Standing Valve Production (d) Jet Pumping

In jet pumping, fluid is pumped down to the downhole pump where it is allowed to expand through an orifice and, using the venturi concept, this provides suction at the base of the well to lift fluid. The principle of this pump is shown in figure 20.

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Several other pumping systems are available in addition to the above, but they all operate by introducing additional power into the producing system either in the form of electricity, hydraulic power or mechanical reciprocation.

Summary

In this section we have considered general concepts of reservoir performance and well productivity. Key points include:

(a) Reservoir recovery performance and production rate profile is controlled by the reservoir drive mechanism

(b) Reservoir production can be maximised by system pressure drop optimisation

(c) Maintaining production rates can be achieved by fluid injection (d) Artificial lift processes can maintain or enhance production rates (e) Gas lift reduces the hydrostatic head pressure loss

(f) Pumps provide additional energy to assist lifting oil to surface

Well design is crucial to the control of fluid movement into the wellbore, their retention in the reservoir and hence maximising recovery and rates of hydrocarbon recovery.

Figure 20

Cutaway drawing of jet pump

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Reservoir Production Concepts

EXERCISES

1. A reservoir has been estimated to contain 100mm STB of oil (bubble point <1500 psia) at a pressure of 5000 psia. Based on an average isothermal compressibility of 20 x 10 –6_{/psi between the initial pressure and a proposed abandonment pressure}

of 1500 psia, estimate the recovery volume by depletion drive and the recovery factor considering only the oil phase expansion?

2. Compare the options of gas and water injection for both offshore and onshore oil reservoir applications in terms of potential performance, safety, economics and logistics?

3. For the reservoir in question one, how much oil could be produced and what recovery achieved if the reservoir were connected to an overlying gas cap of 25% volume compared to the oil column and an average compressibility of 400 x 10-6_/

psi? Assume that a gravity stable displacement will exist and the well design will permit retention of the gas in the structure.

4. Repeat exercise (3) for the oil reservoir without a gas cap but with an underlying aquifer of a volume 10 times that of the oil column and an average compressibility of 8 x 10-6 _{/ psi}

5. Compare and discuss the results of questions 1,3, and 4

SOLUTION

Question 1.

Fluid compressibility C dv

v dP

= = 1

Fluid expansion volume = dv_o = C. V_o.dP For the oil recovery

V_o = 100 x 106 _STB

C_o = 20 x 10-6 _{/ psi}

Pi = 5000 psia Paban = 1500 psia

dV_o = 20 x 10-6 _{x 100 x 10}6 _{x (5000 – 1500) = 7,000,000 STB}

Oil recovered by straight depletion drive based on an average fluid compressibility = 7 x 106 _STB

In document Heriot - Watt University - Production Technology I (Page 36-43)