What is Enhanced Oil Recovery ?

Enhanced oil recovery (abbreviated EOR) is the implementation of various techniques for increasing the amount of crude oil that can be extracted from an oil field. Enhanced oil recovery is also called improved oil recovery or tertiary recovery (as opposed to primary and secondary recovery). According to the US Department of Energy, there are three primary techniques for EOR: thermal recovery, gas injection, and chemical injection.Sometimes the term quaternary recovery is used to refer to more advanced, speculative, EOR techniques. Using EOR, 30 to 60 percent, or more, of the reservoir's original oil can be extracted, compared with 20 to 40 percent using primary and secondary recovery.

Primary recovery techniques: This implies the initial production stage, resulted from the displacement energy naturally existing in a reservoir. 

Secondary recovery techniques: Normally utilized when the primary production declines. Traditionally these techniques are water flooding, pressure maintenance, and gas injection. The recovery factor can rise up to 50%. 

Tertiary recovery techniques: These techniques are referred to the ones used after the implementation of the secondary recovery method. Usually these processes use miscible gases, chemicals, and/or thermal energy to displace additional oil after the secondary recovery process has become uneconomical. The recovery factor may arise up to 12% additionally to the RF obtained with the secondary recovery method. 

Primary Recovery In this recovery process oil is forced out of the petroleum reservoir by existing natural pressure of the trapped fluids in the reservoir. The efficiency of oil displacement is primary oil recovery process depends mainly on existing natural pressure in the reservoir. This pressure originated from various forces: Expanding force of natural gas Gravitational force Buoyancy force of encroaching water An expulsion force due to the compaction of poorly consolidated reservoir rocks Among these forces, expanding force of high-pressure natural gas contributes mainly to oil production. These forces in the reservoir either can act simultaneously or sequentially, depending on the composition and properties of the reservoir. The gravitational force is more effective in steeply inclined reservoirs, where it facilities the drainage of oil. This force alone may not be effective in moving large amounts of oil into a production well. Another, more effective, force for displacement oil is encroachment of water from the side or bottom of a reservoir. In some fields, edge water encroachment from a side appears to be stationary. The ability of the edge water to encroach depends upon the pressure distribution in the reservoir and the permeability. Compaction of the reservoir as fluids are withdrawn also is a mechanism for movement of oil to production wells. Part of the oil will be expelled due to the decrease in the reservoir volume.

Secondary Recovery When the reservoir pressure is reduced to a point where it is no longer effective as a stress causing movement of hydrocarbons to the producing wells, water or gas is injected to augment or increase the existing pressure in the reservoir. Conversion of some of the wells into injection wells and subsequent injection of gas or water for pressure maintenance in the reservoir has been designated as secondary oil recovery. 

When oil production declines because of hydrocarbon production from the formation, the secondary oil recovery process is employed to increase the pressure required to drive the oil to production wells. The purposes of a secondary recovery technique are: Pressure restoration Pressure maintenance The mechanism of secondary oil recovery is similar to that of primary oil recovery except that more than one well bore is involved, and the pressure of the reservoir is augmented or maintained artificially to force oil to the production wells. The process includes the application of a vacuum to a well, the injection of gas or water .

Water Injection In water injection operation, the injected water is discharged in the aquifer through several injection wells surrounding the production well. The injected water creates a bottom water drive on the oil zone pushing the oil upwards. In earlier practices, water injection was done in the later phase of the reservoir life but now it is carried out in the earlier phase so that voidage and gas cap in the reservoir are avoided. Using water injection in earlier phase helps in improving the production as once secondary gas cap is formed the injected water initially tends to compress free gas cap and later on pushes the oil thus the amount of injection water required is much more. The water injection is generally carried out when solution gas drive is present or water drive is weak. Therefore for better economy the water injection is carried out when the reservoir pressure is higher than the saturation pressure. 

Water is injected for two reasons: 

1) For pressure support of the reservoir (also known as voidage replacement).

 2) To sweep or displace the oil from the reservoir, and push it towards an oil production well. 

The selection of injection water method depends upon the mobility rate between the displacing fluid (water) and the displaced fluid (oil). 

The water injection however, has some disadvantages, some of these disadvantages are: 

• Reaction of injected water with the formation water can cause formation damage. 

• Corrosion of surface and sub-surface equipment. As part of water injection it is also common to find the water flooding technique. 

Water flooding consists of water Water is injected into the reservoir through injection wells. The water drives oil through the reservoir rocks towards the producing wells. For water flooding the most common pattern of injection and production wells is a five-spot configuration as shown in figures 3 and 4 show from different angles, where the water is injected in the central well displacing oil to the four surrounding production wells. 

Gas Injection It is the oldest of the fluid injection processes. This idea of using a gas for the purpose of maintaining reservoir pressure and restoring oil well productivity was suggested as early as 1864 just a few years after the Drake well was drilled. 

The first gas injection projects were designed to increase the immediate productivity and were more related to pressure maintenance rather to enhanced recovery. Recent gas injection applications, however, have been intended to increase the ultimate recovery and can be considered as enhanced recovery projects. In addition, gas because of its adverse viscosity ratio (higher mobility ratio) is inferior to water in recovering oil. Gas may offer economical advantages. Gas injection may be either a miscible or an immiscible displacement process. The characteristics of the oil and gas plus the temperature and pressure conditions of the injection will determine the type of process involved. The primary problems with gas injection in carbonate reservoirs are the high mobility of the displacing fluid and the wide variations of permeability. It is required a much greater control over the injection process than the one necessary with water-flooding. In order to evaluate the weep efficiency of the planned gas injection, a short-term pilot gas injection test should be driven. At the same time, this test would provide the necessary data to calculate the required volumes of gas; this in turn, will aid in the design of compressor equipment and estimating the number of injection well which will be required. In some cases gas injection can increase the ultimate recovery of oil such cases like having carbonate reservoirs. The benefits obtained by the gas injection are dependent upon horizontal and vertical sweep efficiency of the injected gas. The sweep efficiency depends on the type of porosity system present.

Artifical Lift Techinque : Sucker ROD PUMPS

Artifical Lift Techinque : Sucker ROD PUMPS

Introduction

(Sucker) rod or beam pump was the first type of artificial lift to be introduced to the oil field. It is also the most widely used in terms of the number of installations world wide. In 1993, some 85% of the USA population of artificially lifted wells was produced by rod pumps and more than 70% of these produced less than 10 barrels of oil per day. The low cost, mechanical simplicity and the ease with which efficient operation can be achieved makes rod pumps suitable for such low volume operations. Rod pumps can lift moderate volumes (1,000 bfpd) from shallow depths (7,000 ft) or small volumes (200 bfpd) from greater depths (14,000 ft). They are normally manufactured to standards set by the American Petroleum Institute (API). This means that, unlike other artificial lift methods, the equipment manufactured by the various supplies is fully interchangeable.

The Pumping Unit

The surface equipment for a rod pump is illustrated in Figure 1. The prime mover, normally an electric motor or gas engine, drives a speed reducing set of gears so that its fast rotation, of say 600 revolutions per minute, is reduced to as low as 20 strokes per minute or less. The connection between the surface pumping unit and the downhole pump is the polished rod and the sucker rods. The polished rod moves up and down through a stuffing box mounted on top of the wellhead. This stuffing box seals against the polished rod and prevents surface leaks of the liquids and gasses being produced by the well.

The Sucker Rods

The sucker rods, typically 25 ft long, are circular steel rods with diameters between 0.5 in and 1.125 in, in increments of 0.125 in. A threaded male connection or pin is machined at each end of the rod. The two rods can be joined together by use of a double box coupling (Figure 2). Square flats are machined near the pins and at the centre of the coupling to provide a grip for a wrench to allow the rods and couplings to be screwed together. The sucker rods are subjected to continuous fatigue when the pump is in operation. The weight of the rod string is one component of this fatigue load - it can be minimised by using a tapered sucker rod string. This involves installing lighter, smaller diameter rods lower down in the well where the load they have to support (weight of rods and fluid in the tubing string) is less than at the top of the well.

The Pump

The pump is located near the perforations at the bottom of the string of sucker rods. Figure 3 shows that it consists of a hollow plunger with circular sealing rings mounted on the outside circumference moving inside a pump barrel which is either inserted into the tubing or is part of the tubing itself. A standing valve is mounted at the bottom of the pump barrel while the travelling valve is installed at the top of the plunger. The standing and travelling valves consist of a ball which seats (closes off)

an opening.

The “UP” and “DOWN” movement of the pump barrel allows the fluid flow to open and shut these valves as shown in Figure 3. The left hand schematic shows the plunger status at the end of the “DOWN” stroke. The "Upward" rod movement reduces the pressure within the pump barrel and the upward flow of fluid from below the pump lifts the standing valve’s ball off its seat. The pressure due to the fluid column above the plunger keeps the travelling valve ball on its seat. The situation is reversed during the “DOWN” stroke - compression of fluid within the pump barrel forces it to flow through the hollow plunger and to lift the travelling valve off its seat; while ensuring that the standing valve remains closed. 

Selection of Artificial Lift Types

ARTIFICIAL LIFT METHODS

1. INTRODUCTION AND SELECTION CRITERIA

This module will introduce the topic of artificial lift - a production engineering topic of increasing importance in field development. The reasons leading to this increasing importance in the field development process will be reviewed. The main factors influencing the selection of the most important artificial lift techniques will be highlighted.

A brief description will then be given of all the common artificial lift techniques (rod pumps, electric submersible pumps, progressive cavity pumps and hydraulic pumps) apart from gas lift.

Hydrocarbons will normally flow to the surface under natural flow when the discovery well is completed in a virgin reservoir. The fluid production resulting from reservoir development will normally lead to a reduction in the reservoir pressure, increase in the fraction of water being produced together with a corresponding decrease in the produced gas fraction. All these factors reduce, or may even stop, the flow of fluids from the well. The remedy is to include within the well completion some form of artificial lift. Artificial lift adds energy to the well fluid which, when added to the available energy provided “for free” by the reservoir itself, allows the well to flow at a (hopefully economic) production rate.

2. THE NEED FOR ARTIFICIAL LIFT

Artificial lift is required when a well will no longer flow or when the production rate is too low to be economic. Figure 1(a) illustrates such a situation - the reservoir pressure is so low that the static fluid level is below the wellhead. 

Question: Is it possible for this well to flow naturally under and conditions.

Answer: Yes: If the well productivity Index is sufficiently high and the produced fluid contains enough gas that the flowing fluid pressure gradient gives a positive wellhead pressure. But, the well has to be "kicked off" (started flowing) by swabbing or other techniques.

Figure 1(b) shows how installation of a pump a small distance below the static fluid level allows a limited drawdown (Dp') to be created. The well now starts to flow at rate q. N.B. the static and flowing pressure gradients in figures 1(a) & 1(b) are similar since frictional pressure losses in the tubing are small at this low flow rate.

It can be readily seen that the same production rate will occur when the pump is relocated to the bottom of the tubing, provided the pressure drop across the pump, and hence the drawdown, remains the same. The advantage of placing the pump near the perforations is that the maximum potential production can now be achieved {figure 1(c)} by imposing a large drawdown (DP") on the formation and “pumping the well off” by producing the well at q2 is slightly smaller than the AOF. Artificial lift design requires that the pump to be installed is matched to the well inflow and outflow performance. 

Figure 1c Installation of pump suction below the perforations maximises potential drawdown and production rates

3. REVIEW OF ARTIFICIAL LIFT TECHNIQUES

The most popular forms of artificial lift are illustrated in figure 2. They are:

(i) Rod Pumps - A downhole plunger is moved up and down by a rod connected to an engine at the surface. The plunger movement displaces produced fluid into the tubing via a pump consisting of suitably arranged travelling and standing valves mounted in a pump barrel.

(ii) Hydraulic Pumps use a high pressure power fluid to: (a) drive a downhole turbine pump or (b) flow through a venturi or jet, creating a low pressure area which produces an increased drawdown and inflow from the reservoir.

(iii) Electric Submersible Pump (ESP) employs a downhole centrifugal pump driven by a three phase, electric motor supplied with electric power via a cable run from the surface on the outside of the tubing.

(iv) Gas Lift involves the supply of high pressure gas to the casing/tubing annulus and its injection into the tubing deep in the well. The increased gas content of the produced fluid reduces the average flowing density of the fluids in the tubing, hence increasing the formation drawdown and the well inflow rate.

(v) Progressing Cavity Pump (PCP) employs a helical, metal rotor rotating inside an elastomeric, double helical stator. The rotating action is supplied by downhole electric motor or by rotating rods.

4. SELECTION OF ARTIFICIAL LIFT CRITERIA

There are many factors that influence which is the preferred form of artificial lift.
Some of the factors to be considered are:

4.1. Well and Reservoir Characteristics

(i) Production casing size.
(ii) Maximum size of production tubing and required (gross) production rates.
(iii) Annular and tubing safety systems.
(iv) Producing formation depth and deviation (including doglegs, both planned and unplanned).
(v) Nature of the produced fluids (gas fraction and sand/wax/asphaltene production).
(vi) Well inflow characteristics. A “straight line” inflow performance relationship associated with a dead oil is more favourable than the curved “Vogel” relationship found when well inflow takes place below the fluid’s bubble point. Figure 4 shows that reducing the flowing bottomhole pressure from 2500 to 500 psi increases the well production rate by 125% for the dead oil. This is more than double the 60% increase expected for the same reduction in bottom hole pressure if a “Vogel” type inflow relationship is followed with a well producing below the bubble point.


Figure 4 Influence of fluid in flow performance on production increase achieved when well drawdown is increased

4.2. Field Location

(i) Offshore platform design dictates the maximum physical size and weight of artificial lift equipment that can be installed.
(ii) The on-shore environment can also strongly influence the artificial lift selection made. For example:
           (a) an urban location requiring a maximum of visual and acoustic impact or
         (b) a remote location with minimal availability of support infrastructure can lead to       different artificial lift types being selected for wells of similar design and producing characteristics.
(iii) Climatic extremes e.g. arctic operations will also limit the practical choices.
(iv) The distance from the wellhead to the processing facilities will determine the minimum wellhead flowing pressure (required for a give production rate). This may, for example, make the choice of an ESP more attractive than Gas Lift. This is because the extra pressure drop in the flowline, due to the injected gas, makes Gas Lift an unsuitable option for producing satellite hydrocarbon accumulations isolated from the main field.
(v) The power source (natural gas, mains electricity, diesel, etc) available for the prime mover will impact the detailed equipment design and may effect reliability e.g. the voltage spikes often associated with local electrical power generation have been frequently shown to reduce the lifetime of the electrical motors for ESP’s.

4.3. Operational Problems

(i) Some forms of artificial lift e.g. gas lift are intrinsically more tolerant to solids production (sand and/or formation fines) than other forms e.g. centrifugal pumps.
(ii) The formation of massive organic and inorganic deposits - paraffins, asphaltenes, inorganic scales and hydrates - are often preventable by treatment with suitable inhibitors. However, additional equipment and a more complicated downhole completion are required unless, for example, the inhibitor can be carried in the power fluid for a hydraulic pump or can be dispersed in the lift gas.
(iii) The choice of materials used to manufacture the equipment installed within the well will depend on the:
     (a) Bottom Hole Temperatures.
     (b) Corrosive Conditions e.g. partial pressure of any hydrogen sulphide an carbon                          dioxide, composition of the formation water etc.
     (c) Extent of Solids Production (erosion).
     (d) Producing Velocities (erosion/corrosion).

4.4. Implementation of Artificial lift Selection Techniques

As discussed the artificial lift design engineer is faced with matching facility constraints, artificial lift capabilities and the well productivity so that an efficient lift installation results. Frequently, the type of lift has already been determined and the engineer has the problem of applying that system to the particular well. A more fundamental question is how to determine the optimum type of artificial lift to apply in a given field.
There are certain environmental and geographical considerations that may be overriding.
For example, sucker rod pumping is by far the most widely used artificial lift method in North America. However, sucker rod pumping may be eliminated as a suitable form of artificial lift if production is required from the middle of a densely populated city or on an offshore platform with it’s limited deck area. There are also practical limitations - deep wells producing several thousands of barrels per day cannot be lifted by rod pumps. Thus, geographic and environmental considerations may make the decision. However, there are many considerations that need to be taken into account when such conditions are not controlling.
Some types of artificial lift are able to reduce the sand face producing pressure to a lower value than others. The characteristics of the reservoir fluids must also be considered. Wax & formation solids present greater difficulties to some forms of artificial lift than others. The producing gas-liquid ratio is key parameter to be considered by the artificial lift designer. Gas represents a significant problem to all of the pumping methods; while gas lift, on the other hand, utilizes the energy contained in the produced gas and supplements this with injected gas as a source of energy.
The “Advantages and Disadvantages of the Major Artificial Lift Methods” are listed and compared in Tables 1& 2.

Table 1 Advantages of major artificial lift methods

Table 2 Disadvantages of major artificial lift methods

Well Completion Equipments