Production Technology Pre-reading

Production Technology Pre-Reading

WELL BEHAVIOUR INFLOW PERFORMANCE The rate at which fluid will flow towards the wellbore depends on the viscosity of the fluid, the permeability of the rock, and the driving force. This driving force is not the reservoir pressure but the drawdown - the difference in pressure between the reservoir and the wellbore. The inflow performance relationship (IPR) quantifies the flow rate from a well as a function of the drawdown. This chapter is concerned with the inflow of fluid into the wellbore as depicted in Figure 5.38.

Radial Flow Behaviour Figure 5.39 shows the pressure distribution around a well which is producing at a constant flowrate, q. Inflow to the well occurs in a radial fashion and the variation in pressure with increasing radius away from the well will be a function of the properties of the rock, the properties of the fluid and the conditions at the inner and outer boundaries of the system.

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We can use discrete boundary conditions to define three key flow conditions in the reservoir: Transient Plow This condition applies when the outer boundary of the system has not yet been 'seen' in terms of its effect on the pressure profile at the well. As far as the well and the pressure profile around the well are concerned, the system behaves as though it were infinite in extent. This condition exists only for a short period of time after some pressure disturbance has been created in the reservoir, but it is the most important phase for well testing. Semi Steady State Flow This condition applies when the reservoir has been producing for a sufficient period of time that the effect of the outer boundary has been felt. Under semi-steady state flow, there is no flux of material across the outer boundary (which could thus be thought of as a 'brick wall'). The pressure profile between the inner and outer system boundaries no longer changes shape, but the profile will gradually decrease in pressure as more fluid is extracted from the system (Figure 5.40).

Steady State Flow This is the opposite extreme of semi-steady state and applies when the outer boundary of the system permits flux of material into the system in such a way as to maintain the pressure at © 2001 Shell International Exploration & Production B.V.

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Production Technology Pre-Reading the outer boundary constant. The pressure profile between the inner and outer boundaries is thus completely fixed (in terms of both shape and pressure) during steady state flow (Figure 5.41). This condition is applies when pressure is being maintained in the reservoir either by natural water influx, the expansion of a large gas cap or the injection of displacing fluid.

The Radial Inflow Equation for Steady State Flow Fluid flow is porous media was first described by H. Darcy (1856). Assuming that the reservoir is homogeneous, Darcy's law for the radial flow of a single phase fluid can be expressed as:-

The cross sectional area of flow bears the following relationship to radius:where h

reservoir thickness

and so the radial flow equation for a well completed over the entire reservoir thickness becomes: © 2001 Shell International Exploration & Production B.V.

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Assuming steady state flow (Figure 5.41) we can integrate the radial flow equation and solve for the pressure (Pr) at any radius in the system (r):

Although re may be known (or estimated), the corresponding pressure Pe at the drainage radius cannot physically be measured. Therefore, it is difficult to quantify the drawdown available to drive fluid towards the wellbore. It therefore becomes more convenient to express the above solution not in terms of the external boundary pressure, but in terms of the average pressure in the system ( p ), which can readily be estimated by analysing individual well shut-in bottom hole pressures.

In the following alternative solution we have also introduced the oil formation volume factor, so that the rate we will use will be that measured at surface (rather than at the wellbore) and we have expressed the solution in terms of the pressure at the wellbore itself:-

Straight Line Inflow Performance Relationship When we consider the parameters in the equation for the productivity index, the following comments can be made:

• h, re and rw are constant • u, and Bo are pressure dependent (possibly also k if significant compaction occurs). However for single phase flow, which occurs when the flowing pressure is above the bubble point pressure, these last three parameters can be considered constant (independent of pressure). Under these conditions the productivity index is constant and usually given the symbol PI. Hence, the equation:

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describes a straight line as depicted in Figure 5.42.

Vogel Inflow Performance Relationship When the flowing bottom hole pressure is below the bubble point pressure, two phase liquid and gas flow occurs in the reservoir. The parameters n and Bo (and possibly k) are no longer constant and hence the linear relationship defined above is no longer valid.

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Production Technology Pre-Reading This type of behaviour has been observed in solution gas drive reservoirs. Under these conditions, a plot of flowing bottom hole pressure against production rate results in a curved, rather than a straight line and there is a progressive deterioration in the inflow performance relationships as the reservoir is depleted (Figure 5.43). The inflow performance relationships shown above may be redefined as dimensionless IPRs. This is done by expressing the bottom hole flowing pressure as a fraction of the maximum shut-in pressure, and the relevant flow rate as a fraction of the maximum production rate for that curve at that point in time. When this is done, the curves appear to be very similar throughout most of the producing life of the reservoir. Because of the similar nature of the dimensionless IPRs, it is possible to group them into one representative curve, which closely approximates them all. The curve giving the best fit to the dimensionless IPRs is called the reference IPR curve, or the Vogel IPR (Figure 5.44).

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Production Technology Pre-Reading It has been shown that dimensionless IPRs apply to many different reservoirs. Exceptions are highly damaged wells, high viscosity crudes, and very high rate producers.

Combined IPRs We are often faced with the situation where the average reservoir pressure is above bubble point, but the flowing bottom hole pressure may be below bubble point. In this case a combined straight line and Vogel IPR will describe the full IPR above and below bubble point:

The solution for Pwf < Pb is (Vogel/Glass):

where J*

productivity index for the straight line part of the IPR

Gas Well IPRs In gas wells we are faced with the problem that both fluid viscosity and compressibility are highly pressure dependent. Therefore an IPR similar to the Vogel IPR above would appear to be appropriate. However, the situation is further complicated by high flow velocities around the wellbore, which often lead to turbulent flow. The Darcy flow model assumes purely laminar flow and is not valid for the additional pressure drops caused by turbulence in gas wells. The resulting non-linear IPR of gas wells is often expressed as:

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The constants a and b can be derived from a multi-rate well test or alternatively estimated from known reservoir and gas properties.

Establishing A Well's IPR The inflow performance relationship for a given well has to be established by a well test. In theory, one production rate with corresponding bottom hole pressure and the shut-in pressure will define the inflow performance relationship. In practice a number of flow rates may be taken to confirm the well performance.

If a sample of formation fluid is taken and analysed to establish the bubble point pressure, it will be possible to decide whether to use the straight line, the Vogel or the Vogel/Glass inflow performance relationship.

Use of the IPR The inflow performance relationship is useful as a tool to monitor well performance and predict the stimulation and artificial lift requirements of a number of wells. The IPR for a well must be known in order to size the well tubulars correctly. Based on interpolation between wells, if the initial IPR for a well is lower than expected in a particular part of the reservoir, it may then be suspected that the formation has been badly damaged during the drilling and completion phase. Mapping the IPRs across the field may highlight this situation. When wellbore damage is confirmed by a build-up survey the well may require stimulation. Even with stimulation, the inflow performance of a well will decline with falling reservoir pressure. Plotting this decline will indicate approximately when the well will have to be artificially lifted in order to maintain the required offtake rate from the field.

VERTICAL FLOW The previous section dealt with the inflow of fluid from the reservoir to the wellbore. In order to fully describe the performance of a well, we must extend the model to take account of what happens when fluids flow from the wellbore to surface. The ability to pass reservoir fluids through the tubulars is termed the vertical flow performance and it is totally dependent on the tubing size and the fluid properties. While the vertical flow of fluid in a tube is completely independent of the inflow performance of the reservoir, the two phenomenon are closely related because inflow from the reservoir and the outflow through the tubing must, obviously, be equal at the wellbore. Therefore, the capacity of the reservoir to pass fluid to the wellbore and the capacity of the tubing to pass the fluid to the surface have to be matched and be operating in equilibrium (Figure 5.46). The ability to predict vertical flow performance for various tubulars is important because in a flowing well the majority of the pressure loss can be attributed to flow in the tubing string. Typically, 75% of all the flowing pressure losses occur in the tubing, so minimising this pressure loss has a large effect in maximising the production rate from the well.

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To develop a full understanding of flowing and gas-lifted wells, it is essential to recognise that there are three distinct sets of conditions affecting the producing well. The first set of conditions affect the flow of fluid into the borehole, the second set affect the flow of fluid to the top of the well, and the third set govern the fluid flow through the choke on surface. Inflow performance has already described the conditions under which fluid will flow into a wellbore. Vertical flow and flow through chokes are described in the following sections, but this is done after a brief description on the sort of flow regimes that exist in a producing well.

Flow Regimes Petroleum hydrocarbons are volatile substances by nature. During the process of flowing oil from the reservoir to surface, the oil undergoes a large reduction in pressure. During this process, a pressure will be reached when gas is released from solution and there will be two distinct phases (oil and gas) flowing together. The analysis of vertical flow performance involves establishing a relationship between pressure and depth over a given length of pipe for a variety of conditions. In order to establish this relationship, a knowledge of the flow regimes, which exist in two phase flow in the tubing, is vital. The types of flow regimes that may occur are shown schematically in Figure 5.47.

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At the very bottom of the well, flow may occur above the bubble point, in which case there will be single phase flow of oil. When the pressure has reduced to below the bubble

point, gas will be liberated and distributed throughout the liquid phase as small bubbles, resulting in bubble flow. Further up the well, as the pressure is reduced more, gas will occupy a greater portion of the tubing volume and the small bubbles of gas will agglomerate to form large, bullet-shaped plugs of gas, causing plug flow. The flow regime passes from plug flow to slug flow and eventually to annular flow, in which liquid is transported partly as an entrained mist in the gas flow and partly by drag along the sides of the tubing inner wall. At very low pressures, practically all the © 2001 Shell International Exploration & Production B.V.

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Production Technology Pre-Reading liquid would be entrained as fine mist moving in a high velocity gas core, called mist flow. It should be noted that the foregoing description is hypothetical in that it covers all types of flow regimes whereas only two or possibly three of these flow regimes would normally exist in a producing well. Because of the complicated nature of the fluid regimes in a flowing well, describing vertical flow in wells mathematically is exceedingly difficult. Even the best analytical models available will only be able to predict the pressure losses to within an accuracy of about 5%

Vertical Flow Equation The general format for an equation describing the pressure losses in a well may be written as:

In a flowing well, both the density of the fluid and the volume of the fluid are a function of pressure. The above equation is therefore implicit in pressure and can only be solved by iteration, with the aid of computer programs, or by using empirical correlations.

Gradient Curves The vertical flow equation can be solved by the use of empirical correlations, or gradient curves. These curves are based on the observed pressure behaviour in flowing wells, and recognise seven primary quantities, as listed below:

When any six of these parameters are known or assumed, the seventh can be found by using the appropriate set of gradient curves. This shown in Figure 5.48, in which some assumed conditions are stated, so for a fixed tubing head pressure the intake pressure can be found.

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The Nature of Two Phase Flow It is worth briefly describing the way in which liquid and gas flow together in a tubing in order to gain an insight into the nature of the flowing well. The nature of two phase flow is largely the result of the interaction between two phenomena:

• The resistance to the flow of fluid • The slippage of gas through the fluid The pressure in a column of liquid and gas is due to the weight of the mixture, which is greatest at low gas/liquid ratios. However, it is less obvious that for any gas/liquid ratio and depth there is a flow rate through the tubing that requires a minimum lifting pressure, with lower flow rates requiring more lifting pressure due to slippage and higher flow rates requiring more lifting pressure due to resistance. Also, for given flow rates, it is true that a small quantity of gas is effective in substantially reducing the bottom hole pressure. The interaction between these parameters is described in the following paragraphs. Consider a length of tubing standing vertically with the upper end open to the atmosphere (Figure 5.49). At the lower end of the tubing liquid is introduced at a low rate. This liquid flow rate will be kept constant for all the conditions described below, during which time gas will be introduced into the tubing in gradually increasing quantities.

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Plotting the intake pressure against the GLR shows that the intake pressure is initially reduced by increasing the GLR (Figure 5.50). This effect becomes less significant with increasing GLR and a minimum intake pressure can be seen. Increasing the GLR above this minimum value causes the intake pressure to rise. This is because the total mass of liquid and gas being forced through the tubing is very high, with the result that flow velocities and hence frictional pressure losses are now significant.

Now consider representing tubing performance with different parameters; intake pressure (Pwf) and flow rate (Q). In this case the GLR is fixed as in the case of a naturally flowing well and intake pressure is plotted against flow rate to determine the minimum intake pressure as a function of flow rate (Figure 5.51). © 2001 Shell International Exploration & Production B.V.

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Initially, since the flow rate is low, the resistance to flow is negligible and the tubing intake pressure is approximately equal to the hydrostatic head of the liquid column. If a very small quantity of gas is now introduced, the overall density of the gas/liquid mixture should be reduced and so for the same liquid flow rate, the tubing intake pressure will be reduced. However, the introduction of a few gas bubbles will not reduce the tubing intake pressure significantly. This is because the high density difference between the liquid and the gas causes the gas to rise rapidly through the liquid to the top of the tubing, so that its effect in reducing the liquid density is minimal. This is the phenomenon called slippage. As the volume of the gas flowing in the liquid is increased, slippage still occurs but to a lesser extent. The effective density of the mixture is gradually reduced and so is the tubing intake pressure. Increasing the gas injection rate with a constant liquid production rate increases the total mass flow rate, which, in turn, increases the frictional effects. At some gas injection rate the energy loss due to friction will exceed the benefit gained by reducing the mixture density and the total energy loss in the system will rise. Thus for a particular tubing producing from a given depth at a fixed production rate, there is an optimum GLR which corresponds to the minimum energy needed to lift the gas/liquid out of the well. At lower gas/liquid ratios slippage occurs, while at higher gas/liquid ratios frictional losses dominates. The curve showing the relationship between tubing intake pressure and the flow rate is called the tubing Intake Pressure Curve (IPC). It is of most use because it can be compared with the inflow performance relationship to establish how much the well will produce at surface against the prevailing back pressure. A similar curve, called the Tubing Performance curve (TPC), shows the relationship between the tubing head pressure and the flow rate. This is useful because the tubing head pressure is a directly measurable quantity. In Figure 5.52 an intake pressure curve for a given tubing is shown on the same graph as the inflow performance relationship for a given reservoir. Each curve describes the relationship between the flow rate and bottom hole pressure, but for two different systems; flow from a reservoir, and flow through a tubing. We know that for the true producing well, the flowing bottom hole pressure dictated by the reservoir IPR must equal that dictated by the tubing IPC. In other words, the true flowing bottom hole pressure is given by the point at which the two curves meet.

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Note that the IPR and IPC may have more than one intersection. At the lower production rate, the well is producing under conditions of unstable equilibrium. If the flow rate reduces slightly from the point of intersection, the tubing requires more pressure than the reservoir can provide. The tubing acts as a choke in this situation and the well dies. At a slightly higher production rate, the tubing requires less pressure than the reservoir is supplying, so the reservoir is driving the tubing to a higher production rate. The production rate will therefore rise until the second intersection is reached, which is the point of stable equilibrium.

CHOKES It is normal practice to control the rate at which a well flows by installing a restriction in the wellhead. As well as technical considerations, the economic climate or local government restrictions may make it necessary to limit the offtake rate to less than the well can manage. In summary, the production rate may have to be restricted in order to: • Produce the reservoir at the most efficient rate to maximise the economic returns. ' Limit the well offtake rate to that decreed by local government. • Limit the drawdown and flow rate to prevent sand entry into the wellbore. ' Prevent the coning of water or cusping of gas which may be caused by producing the well at too high a rate. • Protect surface equipment from fluctuations in the production rate. ' Eliminate the effect of downstream pressure variations on the producing well.

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Choke Performance The conditions governing multiphase flow through a small restriction are complex and. as in the case of vertical flow, the equations that are used to describe this phenomenon are empirical, derived from observing wellhead pressures and flow rates in the field. One of the requirements of a choke is that it isolates the producing well from pressure fluctuations, which occur, downstream of the wellhead so that separator and flowline pressures do not control the well. This condition exists if the rate of flow through the choke is greater than or equal to the speed of sound in the flowing medium and is called critical flow. For single phase gas flowing through a choke, critical flow exists if the following condition applies:

Pth > I-9pfl where pfl flowline pressure For multiphase flow (oil, gas and water), critical flow exists if: Pth > I-7Pfl For critical flow conditions, an empirical equation for the tubing head pressure has been derived as follows:

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A Complete Model of a Flowing Well A complete model of a flowing well is shown in figure 5.53. It shows the IPR, IPC, TPC and CPC construction and how these relate to the various pressure drops in the production system.

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Production Technology Pre-Reading TUBING SELECTION The method by which the optimum tubing string is selected for a well involves the calculation of the I PR and the IPC for several different sets of conditions. These are usually as follows: • IPRs for the expected life of the field, incorporating reservoir pressure decline and changes in the PI. • IPCs for different tubing sizes, at different GORs, water cuts and/or tubing head pressures, depending on the expected performance of the reservoir. • Production requirements such as maximising initial offtake, optimising production late in field life, etc. A complete representation of the flowing well is then constructed for each possible set of conditions, and from this the optimum tubing size can be selected, depending on production requirements. An example of a series of IPRs and IPCs for a well is shown in Figure 5.54.

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Production Technology Pre-Reading ARTIFICIAL LIFT Having selected the optimum tubing size for the well completion, it may be apparent from the IPR and IPC constructions that at some point in the life of the well the reservoir will no longer be able to flow naturally to surface at the required rate. At this point in time, artificial lift will be required in order to maintain production at the required level.

There are four main types of artificial lift mechanism used in the industry, namely: • Gaslift • Beam Pumps • Electric Submersible Pumps • Hydraulic Pumps Each of these types of artificial lift is discussed briefly in the following sections.

Gaslift The technique of increasing the flowing lifetime of the well, or of increasing the production rate above the naturally flowing rate, by injecting gas into the tubing string is known as gaslift. There are two basic methods: • Continuous gaslift - Relatively high pressure gas is continuously injected into the casing from where it enters the tubing string through valves located at intervals along the length of the tubing. By virtue of the increased gas content of the fluid column in the tubing, the density of the fluid is reduced and hence the drawdown on the reservoir increased. • Intermittent gaslift - Gas is injected in a short burst into the casing-tubing annulus, causing a ball valve at the bottom of the tubing to close and pushing a slug of liquid from the bottom of the tubing to surface. The gas supply is then shut off, allowing the well fluids to enter the tubing from the reservoir ready for the next slug. Schematic diagrams of both types of gaslift are shown in Figure 5.55.

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Production Technology Pre-Reading Continuous gaslift is by far the most common form of gaslift used in Shell's operations. Intermittent gaslift is generally applied only to wells producing less than 30 m^/d. The mechanisms involved in continuous gaslift are described in more detail below. Continuous gaslift is essentially an extension of natural flow, whereby the producing GOR is artificially increased by the injection of gas. This results in the flowing bottom hole pressure being reduced for a particular rate. For maximum benefit, the gas should be injected as deep as possible, reducing the density of as much of the fluid column as possible. Gas is injected through gaslift valves, a series of which are run in side pocket mandrels together with the tubing string, and so designed that only one valve is open and passing gas at any one time. It is common practice to utilise the annular space between the casing and the tubing as the conduit for the gaslift gas down to the point of injection. The gaslift valves are such that they allow passage of gas from casing to tubing, but prevent the passage of fluid from tubing to casing. Continuous gaslift is basically a high rate production method. For a given tubing size, there is a gas/liquid ratio, which will result in the lowest intake pressure. This is called the optimum GLR, and it decreases as the production rate increases. Consequently, for low rate production, large quantities of gas are required to obtain the low intake pressures. Hence, continuous gaslift becomes inefficient at low rates and alternative artificial lift techniques are used. Continuous gaslift takes full advantage of the well's natural energy and can handle significant amounts of solid material. The major disadvantage is the inability to reduce the intake pressure to near zero levels, and the need for a high pressure gas supply. A typical gaslift system comprises of the following components (Figure 5.56): • Source of high pressure gas (compressor, gas well etc.) * Gas distribution lines • Surface controls

• Subsurface controls (gaslift valves) • Flow lines ' Separation equipment • Storage facilities

Beam Pumping The second type of artificial lift technique is beam pumping, also called rod pumping or sucker-rod pumping. It is used extensively in the USA, and can be recognised by the familiar nodding donkey units. A typical beam pumping system is shown in Figure 5.58 and consists of the following: • Power unit • Pumping unit ' Sucker-rod string

• Subsurface pump. The pumping unit is that part of the installation, which converts the rotary motion of the power unit to the up-and-down motion, required to drive the pump. This motion is then transferred to the subsurface pump via sucker rods, which are small diameter steel or fibreglass rods that run inside the tubing string. The subsurface pump is a simple device, comprising of a standing valve and a travelling valve, which open and close in sequence with the upstroke and downstroke of the sucker rods. A schematic is shown in Figure 5.59. During the upstroke, the travelling valve is closed and the standing valve opens, allowing wellbore fluids to enter the © 2001 Shell International Exploration & Production B.V.

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Production Technology Pre-Reading tubing string. During the downstroke, the standing valve closes and the travelling valve opens and fluid is forced up the tubing. The cycle is then repeated, bringing the fluid to surface.

The main advantage of the beam pump is that the bottom hole flowing pressure can be reduced to almost zero, allowing very low pressure reservoirs to be produced. The system is also very reliable and cheap. The main disadvantages are the presence of a large pumping unit at surface, and the inability of the system to handle high production rates, gas and solids. Consequently, beam pumps are used mainly in depleted reservoirs, where low rate, low GOR production is required.

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Electric Submersible Pumping Electric submersible pumps (ESPs) are rotating-impeller pumps submerged in the well fluid and driven by an electric motor installed immediately below the pump: A schematic of an ESP system is shown in Figure 5.60.

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Electric power is transmitted to the motor via an electric cable. The pump may be installed on the bottom of the tubing or run inside the tubing into a locking device in the tubing string. The pump itself consists of any number of stages (up to a hundred or so), each stage consisting of an impeller and diffuser with axial discharge. The number of stages depends on the ratio © 2001 Shell International Exploration & Production B.V.

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Production Technology Pre-Reading between discharge and intake pressure, and is the main design consideration. . The main advantages of the ESP are that it can produce low bottom hole pressures at almost any production rate, and without obtrusive surface units. However, it has the same disadvantages as the beam pump with regard to gas and solids, plus the added (major) disadvantage that the electric cable is highly prone to failure.

Hydraulic Pumping Hydraulic pumps are reciprocating plunger-type pumps located at the bottom of the tubing string, as schematically represented in Figure 5.61.

Power is transmitted by means of a hydraulic fluid to an engine attached to the pump, which in turn drives the pump. A hydraulic control valve directs the flow of power fluid alternately to each side of the engine, which is connected with a rod to the pump, and hence the produced fluid is pumped to surface. The power fluid returns to surface either mixed with the produced fluid or in a separate conduit. The pump may either be installed at the bottom end of the tubing, or may be pumped down into a locking device located in the tubing string. The latter type is particularly attractive in that the pump can be retrieved without the use of a workover hoist to pull the tubing. A variation on the hydraulic pump is called the jet pump. This type has no moving parts and operates by converting pressure into kinetic energy through a small nozzle (Bernouille principle).

The advantages of the hydraulic pump are that it can produce at high rates and at low bottom hole pressures, and that it is simple and cheap to operate. The main disadvantages are that it requires large volumes of a very clean power fluid, and that it cannot handle solids.

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Artificial Lift Selection The criteria for selection of a particular type of artificial lift mechanism are numerous and often complicated. Some of the main considerations are listed below:

• Reservoir parameters e.g. pressure, P.I., water cut, sand production, GOR. • Well parameters e.g. deviation, completion design. • Location e.g. land or offshore. • Cost. • Local experience. • Availability of resources. • Workover possibilities.

• Standardisation. • Reliability.

Some of the advantages and disadvantages of the four types of artificial lift mechanism are summarised on the next page.

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Production Technology Pre-Reading Advantages

Disadvantages

Gaslift No volume constraints No solids problem Low cost No deviation constraints No GOR limits

Requires high pressure gas Inefficient at low rates Limited drawdown capability Requires integral casing Safety aspects of high pressure gas

Beam Pumping Simple system Reliable Very low pressures achievable Flexible Cheap Easy pump replacement Electric Submersible Pumping Can handle high volumes Unobtrusive Simple to operate No deviation problem Cheap Rapid hook-up Hydraulic Pumping No depth limit No deviation problem Unobtrusive Flexible Low pressures achievable

Deviation limited Cannot handle high amounts of solids Cannot handle high GORs Depth limit (+ 2000 m.) Cannot be used offshore Obtrusive Cannot handle high rates. Requires source of electricity Impractical in shallow, low rate wells Electric cable unreliable Cannot handle high GORs Cannot handle solids Inflexible Minimum rate + 25 m3/d Requires power fluid Cannot handle solids Cannot handle high GORs Easy pump changeout

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Production Technology Pre-Reading WELL COMPLETION DESIGN Having selected the required tubing size and artificial lift method, the subsurface design can be finished by designing the well completion. The objective is the lowest cost completion that meets the demands placed on 'it for most of the life of the well. Hence, a reasonable estimate must be made of the reservoir and mechanical characteristics that will be encountered during the lifetime of the well. Some of these characteristics are described below.

Reservoir Characteristics • Production rate. This has already been considered when selecting the tubing size and the artificial lift technique, but may further be importance when designing casing sizes etc. • Drive Mechanism. This has also been considered in the tubing and artificial lift design, but may be important when considering corrosion problems, sand production, etc. • Producing Intervals. The number of reservoirs that produce into one wellbore, and whether each of these must be produced individually or whether they can be produced together (commingled). These considerations may lead to multiple zone completions, separated by isolation packers, and/or several tubing strings in one wellbore. • Secondary Recovery. A well may be planned as a water, gas or steam injection well in the future, and thus the completion must take this into account. • Stimulation. Future stimulation requirements may require special completion considerations, e.g. perforation patterns or packer configurations. • Sand Control. The requirement for sand control, either at the initial stage or later in the life of the well must be incorporated in the well design.

Mechanical Considerations • Simplicity. The simpler the completion, from both an equipment and an operational viewpoint, the less likely that something will go wrong. • Safety. The completion design must be intrinsically safe, and incorporate well control methods, automatic shut-in devices etc. • Workovers. Ensure that the completion can be easily worked over and/or abandoned. • Recompletions. Once a reservoir is exhausted, it may be possible to recomplete the well on another reservoir, either in the same wellbore or by sidetracking the well. Flexibility to carry out such an operation must be designed into the completion at the initial stage. Given the above lists of considerations, the following serves to summarise the data that is required before a completion string can be designed:Producing intervals

Single zone

Sand control

Internal Gravel pack

Artificial lift

Continuous gaslift

Tubing size

3 1/2 in, single string

Future requirements

Possible sidetrack updip to avoid water influx.

Corrosion

Downhole chemical injection may be required

The completion design for such a set of parameters is shown in Figure 5.63. Other types of equipment and completion accessories are presented in more detail in © 2001 Shell International Exploration & Production B.V.

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Production Technology Pre-Reading Chapter 6.

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6.1 WELL COMPLETIONS AND OPERATIONS The process of well completion consists of the operations necessary to cause the well to produce, following the installation and cementing of the casing. The term well completion is also used to refer to the equipment used. Well completion operations include: • Perforating • Sand Control • Production Packer Setting • Tubing String Installation • Christmas Tree Installation Each well is a means of communication with the reservoir. Although different types of wells present distinct installation problems, nevertheless the equipment installed in the wells is generally similar. Each completion must be designed to ensure that the particular well operates safely and economically throughout its producing life.

Reservoir Completions/Workovers The factors which must be considered in the initial design, or redesign of a completion are:

• Sand control Open hole Liner completion with or without gravel pack Perforated casing or liner Liner completion inside perforated casing with or without gravel pack In-situ consolidation • Reservoir drive mechanism Water drive - oil-water contact Gas drive - gas-oil contact Water production problems Artificial lift - gas lift Bottom hole pumps • Multiple reservoirs Multiple wells Multiple completions in one wellbore Co-mingling • Producing rate Tubular size © 2001 Shell International Exploration & Production B.V.

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Production Technology Pre-Reading • Stimulation/Removal of skin damage Zone isolation High injection rates High temperature processes • Workover aspects Single string Dual or more strings - wire line techniques Concentric strings. - wire line techniques Pump down methods

Mechanical Aspects of Well Completion • The method of completion • The number of completions within the wellbore • The liner-casing-tubing configuration • The diameter of the production conduit (tubing) • The completion interval • Frequency of well servicing • The method of ensuring well safety • Standardization of equipment and operations Extensive experience in well completion techniques and hence a sound knowledge of equipment is essential if personnel are to become involved in well completion design. The overall design of the well completion (including the equipment selection) can be based on a completion design/logic chart drawn up for the particular field. SAFETY Design safety is essential and must encompass all aspects of the completion and its equipment in accordance with Group, Company and local safety policies and regulations. Where possible, equipment should have a failsafe capability (this should be specified in the design). Safety of human life, of property and of the environment, in addition to safety at the well site, must be considered. The design must ensure that the well is controlled by wellhead equipment, possible kill systems and/or subsurface safety valves at all times during its operational life.

METHODS OF COMPLETION There are two basic methods of completing a well: • Open hole, or barefoot completion, where the product casing is set just above the producing zone. This type of completion is seldom used.

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Production Technology Pre-Reading • Perforated casing, or set through, completion, where the production casing is cemented through the producing zone and then perforated. In both cases, the production casing, and sometimes the preceding casing string, may be replaced by a cemented "liner" overlapping back into the previous casing. A liner completion may offer advantages in both cost and the diameter of the completion. However, to achieve these, the casing to which the liner completion is attached must be designed to accommodate the production conditions expected (after allowing for wear during the drilling operations).

Open Hole As stated, this method calls for production casing to be set above the zone of interest. The well is completed with the producing interval open to the well bore

(Figure 6.1).

Advantages: • Mud weight and chemistry may be controlled to minimize formation damage within the zone of interest. • Perforating expense is eliminated. • Log interpretation is not critical. • Maximum well bore diameter is opposite the pay section. • The well can easily be deepened. • The well is easily converted to perforated liner completion.

Disadvantages: • Excessive gas or water is more easily prevented and controlled. • The production casing is set before the objective horizon is drilled.

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Production Technology Pre-Reading • The producing interval cannot be selectively stimulated. • The openhole section may require cleanout frequently (no sump).

Perforated Casing In this method the production casing is cemented through the producing zone and the pay section is selectively perforated (Figure 6.2).

Advantages: • Excessive gas or water is more easily prevented and controlled. • The formation can be selectively stimulated. • The well can easily be deepened. • Casing will impede sand influx, and the completion is additionally adaptable to special sand control techniques. • The full casing diameter exists through the pay section. • Logs are available to assist the decision to set the casing. • This method is adaptable to all multiple completion configurations. • There is improved primary cementing in comparison to liner cementing. • Minimum rig time and logging expense is required. Disadvantages: • Perforating costs can be significant. • Log interpretation is critical. © 2001 Shell International Exploration & Production B.V.

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Production Technology Pre-Reading • There is a greater danger of formation damage in the pay section.

TYPES OF COMPLETION Plowing or Gaslift Well * Casing and/or Tubing Flow In this type of completion flow may be either up the casing string, up the tubing string or up both. Flow potential is lower than that possible with unrestricted casing flow; however, high flow rates are still possible. In addition, this completion method is not permissible offshore because the production casing is exposed to well pressure and/or corrosive fluids and because of the risk of collision damage as no SSSV can be installed. For these reasons, use of the casing flow method is also discouraged onshore. The tubing string can be used as a kill string and also for chemical injection. In this type of completion, as in the following types, gaslift valves may be installed in the tubing string. In gaslift wells the hydrostatic head is lowered and flow is "gasassisted" to the surface.

Flowing or Gaslift Well - Tubing Flow Both a tubing string and a packer are installed (Figure 6.3). Because of the latter, the maximum potential flow rate is restricted when compared to the casing or casingtubing flow types. The packer is normally installed to offer casing protection and subsurface well control. A no-go nipple is sometimes used and this may allow the fitting of a bottom hole choke, regulator or safety valve, but is primarily there to stop wireline tools dropping through the completion. A safety valve landing nipple is also often installed to permit installation of a surface controlled subsurface safety valve. Flow couplings may be fitted above, or above and below landing nipples to absorb erosion caused by turbulence and abrasion. A circulating sleeve (sliding side door) is fitted above the packer to displace the tubing content with a low density fluid following wellhead installation in order to bring the well in ("kicking-off"). It can also be used to clean out sand or dirt from above the packer prior to pulling the tubing or to circulate the well head.

Dual Completions Two packers are used to isolate the two producing intervals from each other, and from the annulus. Production form each zone is taken via its own tubing (Figure 6.4).

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PERFORATING The purpose of perforating the casing or liner of a well is to form a path through which fluids will flow between reservoir and borehole. Perforating is a vital part of well completion operations. If it is incorrectly carried out, the productivity of the well will appear to be low, which may result in individual productive zones or even an entire field being mistakenly condemned and possibly abandoned. At the very least, expensive diagnosis, stimulation, repair and perhaps reperforating will be required. There are two main categories of perforators - wireline conveyed and tubing conveyed. Wireline conveyed perforating guns are run into the well on electric cable and detonated by passing a current down the cable. Tubing conveyed guns are run on tubing or drillpipe and detonated by electric cable, mechanical impact or hydraulic pressure (Figure 6.5).

The jet perforator, sometimes known as the shaped-charge perforator, makes use of the shaped-charge technique of World War II projectiles and rockets designed to penetrate armour plate. If a solid mass of explosive is detonated in the vicinity of a steel target, only a small impression is made on the steel (Figure 6.6a) due mainly to the high pressure created by the explosion. If a conical cavity is hollowed out of the end of the charge (Figure 6.6b), the depth of penetration is increased to about half the base diameter of the cavity. When a thin metal liner is placed in the cavity (Figure 6.6c), detonation of the charge forms a jet of metal particles, which penetrate the target to four or five times, the base diameter of the liner.

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The pressure exerted by the jet on the target material (of the order of 100 - 250 kbar for oil well perforators) causes the casing and formation material to flow plastically away from the point of impingement of the Jet. Perforation is initiated by the tip of the Jet and is continued by the succeeding jet material, which strikes the end of the hole and gives up its energy to the formation at the point of impact. The process continues until the entire energy of the jet has been expended in this way. Temperature and explosion gases play virtually no part in the penetration process. There is therefore no fusing of the formation material as it is penetrated, although crushing and compaction are to be expected. Wireline conveyed perforators can be further sub-divided into three classes, depending on the type of charge carrier used: • Retrievable tubular steel carrier guns. • Expendable or non-retrievable guns. • Expendable guns with retrievable strip carriers, usually known as semi-expendable guns. A retrievable steel carrier gun consists of a cylindrical steel carrier which houses the shaped charges mounted opposite scallops (indentations) in the cylinder walls (Figure 6.7). The steel carrier is retrieved from the well after perforating. This type of perforator leaves no gun debris and (because most of the explosive energy not used in producing the jet is absorbed by the gun carrier) does not cause casing damage. The expendable and semi expendable guns are run through tubing after the well has been completed. The pressure in the wellbore can then be reduced below reservoir pressure so that there is an inflow immediately after perforating. This sudden inflow helps to "clean" the perforations. The expendable type of perforator disintegrates entirely when fired. The major disadvantage of the expendable perforator is the large amount of debris left in the hole.

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Production Technology Pre-Reading Expendable guns are more vulnerable to high temperature and pressure than the steel carrier type because the explosive charges are more exposed to well conditions. They can also be easily pulled apart by careless running and can cause casing damage. The semi-expendable jet perforator has a straight or twisted steel bar with holes or twin wire strips shaped to support the perforating charges. This type of perforator leaves less debris in the wellbore than does the completely expendable type and, for a given gun "outside diameter" (O.D.), can carry a larger charge than is housed in a steel carrier tube. Like the fully-expendable perforator, it can cause casing damage. The explosive is sometimes cased in a glass or ceramic housing (rather than metal) since this breaks up into minute particles on firing, thus reducing the gross volume of

gun debris. Tubing-conveyed perforators are steel carrier guns run on tubing (or drillpipe) and fired with electric cable, by dropping a bar or by applying annulus pressure. This allows long intervals to be perforated with heavy (large O.D.) charges under drawdown conditions, which is not possible with wireline perforators. The carriers may be left in the well as part of the tubing, dropped into the well sump or retrieved. Tubing conveyed perforating is becoming increasingly popular, despite the higher cost, for the following reasons: • There is no need for radio silence. In wireline perforating this is a necessary safety precaution to prevent premature firing by currents generated by radio waves in the rig. Radio silence is operationally undesirable - indeed on a large platform offshore it may be days before it can be arranged. On land locations it may be impossible to guarantee. • There is the combined advantage of using large charges under drawdown conditions. • The guns can be run in highly deviated wells where wireline guns (being much lighter) tend to stick and cannot be pushed down. © 2001 Shell International Exploration & Production B.V.

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Factors Affecting Perforation Results • Formation Properties The penetration of a perforation is influenced by the compressive strength of the formation. For jet perforators, penetration depth decreases as the compressive strength of the formation increases. • Clearance Clearance (the minimum distance along the jet axis between the gun body or charge case and the target surface) influences both hole size and depth of penetration. Depending on charge and gun design, a jet gun usually achieves its maximum penetration and hole size at a clearance of zero to 0.5 inch (1.2 cm). • Phasing Hole phasing is defined as the angle between vertical planes of sequential shots. A gun which fires in one direction only is therefore 0" phasing while a gun which fires in four equally -spaced directions is 90' phasing. • Perforation Plugging Perforations tend to be filled with crushed formation rock, mud solids and charge debris when perforating in mud. These plugs are not readily removed by backflowing, especially if the formation around the perforation has been compacted. The pressure difference between formation and wellbore necessary to initiate flow varies from one plugged perforation to another, consequently when a few perforations requiring a low pressure differential have been opened up, the flow through them makes it difficult to create the greater drawdown needed to open up more perforations. • Clean-up of Perforations Perforations should be cleaned immediately after shooting; once cleaned, they should be subjected to injection only with clean fluids. Perforations can be cleaned by: Flowing the well. Underbalance perforating (or "perforating under drawdown"). Backsurging. Perforating washing. Acid treatment. • Clean Fluids The task of cleaning up perforations will obviously be made easier if, in the first instance, the perforating is carried out in the presence of a clean fluid. If a particular perforator yields adequate hole size and penetration under given well conditions, well productivity will be maximized by perforating in clean oil (diesel), brine or water with a pressure drop from formation to wellbore during perforating and subsequent well clean-up. • Casing Damage The expendable and semi-expendable types of jet perforator can cause casing damage when fired. This takes the form of splitting or cracking of the casing above and below the perforation, and can cause subsequent production or stimulation problems.

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Production Technology Pre-Reading • Perforating Density The optimum perforation density depends on the formation permeability and the length of the perforated interval. In ail oil or gas wells, the number of perforations must be sufficient to give the required flow with reasonable drawdown. Laboratory studies have shown that four "ideal" perforations per foot of formation is equivalent to open hole flow potential. However, perforations are rarely ideal, and the current tendency is to shoot up to 16 shots per foot. • Perforation Penetration. In general, deep penetration improves well productivity, but the effect lessens with increasing penetration. In hard rock, experience suggests that holes should penetrate through the casing and cement sheath and about 20 cm (8 in) into the formation. In unconsolidated formations, shallow penetration (say 2.5 cm or 1 in) may be satisfactory because a deeper opening in the formation would probably collapse. • Temperature and Pressure In deep -well perforating, perforator temperature and pressure ratings are important in optimizing perforator performance. Bottom hole pressure may impose limitations on some exposed charge guns but is rarely a problem where steel carrier type guns are to be used. Depth Control Perforating depth for both wireline and tubing conveyed perforating is controlled by using a radiation log - usually gamma ray, sometimes neutron and occasionally both - in conjunction with a casing collar locator. By correlating the radiation log with the casing collar log, the position of the proposed perforating interval with respect to the casing collars is established. SAND CONTROL Sand Production is a major problem, which has plagued the petroleum industry for many years. Every year millions of dollars are spent cleaning sand out of wells and repairing problems related to sand production, and additional revenue is lost by restricted production rates. The production of sand is a worldwide problem. Areas of major problems include the U.S Gulf Coast, California, Canada, China, Venezuela, Trinidad, Western Africa, and Indonesia. At least some problems are reported in all areas of the world where oil and gas are produced. Although sand problems are more likely to occur with production from the younger Tertiary sediments (particularly the Miocene epoch), local earth stresses or completion and production practices may create unstable conditions that lead to sand production from older Tertiary sediments. The sand grains in the formation are stabilised by cementation between the grains, by the compression exerted as a result of the overburden, and by capillary forces. If the stresses that result from the forces due to fluid flowing through the sand become greater than the cohesive material can withstand, sand grains will be carried by the fluid into the wellbore. In some cases, the onset of sand production occurs late in the life of the producing field when the reservoir pressure has declined to the extent that the overburden is supported mainly by the vertical component of the grain-to-grain stresses rather than © 2001 Shell International Exploration & Production B.V.

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Production Technology Pre-Reading the pore pressure. This may cause the shearing of cementing material allowing sand grains to move and be produced into the wellbore or the grains themselves may collapse (Figure 6.8). Water breakthrough into an oil bearing sand may damage the stability of the formation. The influx of water may dissolve the cementing material if the inflowing water has a different chemical composition to that of the connate water. The injection of polymers, water, or steam may also have a detrimental effect on cementing material as might an acid stimulation.

The movement of sand particles is detrimental to the producing process and has a negative effect throughout the producing system from the formation to the surface facilities. These effects are summarised in the following: • Formation The movement of crushed sand grains lodging in voids and pore throats will cause the formation to become plugged with the consequent loss of permeability. The production of sand grains into the wellbore may cause the well to "sand up" and production may cease altogether. • Casing and Liners Compaction, or "reservoir shortening" can transmit compressive loads to the casing, which are sufficient to cause it to buckle and balloon. • Subsurface Equipment Sand grains carried by fluid moving at high velocity are very abrasive and are capable of eroding through and even parting tubing and tubing accessories. At low fluid velocities, sand may settle out causing the tubing to become plugged.

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Production Technology Pre-Reading • Surface Facilities Christmas trees, flowlines and separators may be eroded and possibly plugged. Some instances of fire and facility destruction have resulted from the loss of equipment at critical surface locations. Large quantities of sand settling out in the separators wilt cause them to become inefficient because of the reduction of volume available to the liquid and vapour phases. Liquid production may be lost to the gas phase coming off the separator. In extreme cases, production may have to be shut in completely while sand is removed from the separators. The erosive capacity of sand laden fluid flowing at high rates is more readily appreciated knowing that it can cut out a permanent choke in a matter of minutes. Formation damage reduces reservoir permeability. Downhole damage impairs well performance. Surface damage reduces the efficiency of the surface installations and introduces serious safety hazards. In "ecologically sensitive" areas, the disposal of large quantities of sand (particularly oil-stained sand) may pose an expensive problem.

Pros and Cons Of Sand Control The production of sand in oil and gas wells is expensive and everything possible should be done to successfully control the formation sand, but what is meant by "successful" control? The goal of any sand control treatment must be to stop sand production while maintaining or maximizing fluid production. It is not enough to simply stop sand production as this is easily done by shutting the well in or cementing off the producing interval. These two solutions, however, also stop fluid production. The total success or failure of a sand control treatment must be measured against three related criteria: • Stop sand movement and production of sand. • Maintain maximum well productivity. • Payout the treatment costs within a reasonable time. All three of these criteria must be met for a sand control treatment to be considered truly successful, and each item should be considered when designing, performing, and evaluating a sand control treatment. If there is an indication of potential sand production problems in a field, a decision may be made before development to gravel pack every well as insurance against sand production. Advantages: • Reduced cost of surface facilities to measure, separate, and dispose of sand. • Reduced cost of changing eroded chokes, subsurface safety valves, etc. • Reduced possibility of casing fill and collapsed casing. • Less risk of blowout due to eroded surface lines and valves. • Reduced cost of trying to determine if sand will or will not cause problems. Disadvantages: • Possibility of reduced well productivities. • More difficult to shut off water or workover the wells. © 2001 Shell International Exploration & Production B.V.

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Sand Prediction The only absolute method of determining whether a well produces sand is to flow it and observe. However, this may lead to any number of the problems discussed above, and may result in an expensive workover. Hence, some method of predicting whether a well is likely to produce sand during its life is required. Several methods exist and are briefly discussed as follows: • SPADE: A major study was undertaken within the Shell group to derive a method of predicting sand production. Named SPADE (Sand Prediction And Detection) it was completed in 1980. The study developed compatible criteria from both a study of the rock mechanics of perforation stability and a study of log and production data from a number of fields exhibiting sand production. These criteria can then be applied to data obtained from wireline logging and from core analyses, and a prediction made as to the requirement for sand control. SPADE has proved to be extremely successful in preventing sand production within the Shell Groups operations. • Experience In Area - Development Of Data Previous experience in a producing area or with a particular formation is the principal technique employed to predict sand production problems. It must be remembered, however, that reservoir characteristics are not constant across a field or producing area, and certain reservoir parameters change with time. These factors considered, offset well and reservoir data should be reviewed for known sand producing intervals or operating conditions which promote sand production i.e. high withdrawal rates or drawdown pressures, initiation of water production, specific depletion stage in reservoir life, etc. If offset data is not available, individual well "destructive" testing programs can be carried out to determine sanding tendencies. However, these tests are time consuming and expensive, and may lead to sand problems that would not occur under normal conditions. Another area to review for sand producing tendencies is core recovery and analyses. Missing sections in cored intervals, cores, which crumble easily, or analyses showing limited cementing material are all indicators of potential sand problems. • Logging Techniques Three different methods of predicting sand influx have been published. Two of these methods utilize the performance of a test well (as mentioned above) and comparison of associated acoustic and density logs to predict sand influx in nearby wells. The third technique involves using the resistivity, neutron, acoustic, and density log data to calculate shear moduli, bulk moduli, bulk compressibility, and the ratio of shear moduli to bulk compressibility. These are then empirically related to sand production. All of these techniques are useful only for measuring initial sand producing tendencies, but do not predict changes in rock properties as reservoir pressure declines or water production increases.

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Methods of Sand Control There are two principle methods of sand control, mechanically excluding the sand, and chemically consolidating the sand grains. Both methods are aimed at arresting movement of sand while maintaining initial permeability. Another method, which is used to prevent the well from producing sand, is to simply reduce the flow rate, which, in turn, reduces the hydrodynamic forces imposed on the sand grains around the wellbore. • Mechanical Exclusion

The mechanical exclusion of sand is effected by setting up a physical barrier to the sand movement, which still allows for the passage of reservoir fluids. The barrier takes the form of a screen surrounded by fine gravel, which is sized so that the formation sand cannot pass through the pore throats of the gravel. As such, the mechanical exclusion of sand is based upon the relationship between the size of the formation sand , the gravel, and the screen slot widths. • Chemical Consolidation By injecting certain chemicals into the formation it is possible to cement the sand grains together at their contact points, thus providing support and strength for naturally unconsolidated or inadequately cemented material. • Flow Control

By experience, it has been observed that a certain critical flowrate exists above which significant sand production occurs. Below this rate, little or no sand production occurs. The cessation of sand production is attributed to bridges and structural arches forming in the sand. The conditions under which this occur must be established empirically and will vary from well to well. Flow rate control by this method is obviously rather tenuous and is not considered to be a permanent method of sand control for a production well in poorly consolidated sands. For short term low rate well tests, it may prove to be an effective method of restricting sand entry until the test results have been obtained.

Gravel Packing Two basic types of gravel pack exist; the open hole or external gravel pack (EGP) and the inside casing or internal gravel pack (IGP). In either case, the principle requirement of the gravel pack is the same; namely the placement of gravel between the formation sand and the wire wrapped screen. A further classification is implied by the type of fluid used to transport the gravel down the wellbore, either a high viscosity gel or a low viscosity brine.

External Gravel Packing The hole is drilled, logged, and casing is set just above the reservoir interval. This interval is then underreamed to allow a large diameter screen to be used.

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Production Technology Pre-Reading A centralized, screen type liner is run and set, followed by the placement of gravel between the wire-wrapped screens and the underreamed open hole. Gravel is transported down hole in a low viscosity fluid, which should be clean and nondamaging to the formation (Figure 6.9). An external gravel pack can only be used on the lowermost productive interval in a well.

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Internal Gravel Packing The hole is drilled, logged and casing is set over the entire open hole section. The productive interval is then perforated and the perforations cleaned. A wire-wrapped screen is then set over the perforations, and the annulus between screen and casing filled with gravel using a high viscosity fluid (Figure 6.10).

An internal gravel pack allows flexibility to recomplete the well at either a shallower or deeper horizon than the original horizon. Internal gravel packs can also be used to complete very long intervals by using a number of packs positioned over the best zones. One vitally important factor is that the perforations of an internal gravel pack must receive special attention because the well productivity is very dependent on their quality.

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Chemical Consolidation Sand production is a result of the absence or inadequacy of cementing material between sand grains. Chemical sand consolidation, which has been available since the 1940's, is an attempt to overcome these problems by injecting chemicals into an unconsolidated formation in order to cement the grains together at their contact points. The sand consolidation process relies on a process comprising of four distinct stages: 1. Placement of resin in the formation using a carrier fluid. 2. Separation of the resin from the carrier fluid. 3. Accumulation of the resin around the grain contact points. 4. Curing of the resin. The Shell sand consolidation system is called "Eposand". One of the most important advantages of Eposand is that it can be carried out without a rig on site. The main drawback is that for longer completion intervals there is no guarantee that the whole interval is treated. High permeability zones are likely to receive the bulk of the treatment, while lower permeability streaks will continue to produce sand. Therefore completion intervals longer than 3-5 m are usually not treated with Eposand. To extend the application of Eposand also for long completion intervals a selective placement tool is currently under development. This tool consists of two inflatable packers on coiled tubing (CTU) and allows selective treatment of short "sections" within a long completion interval.

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6.2 WELL COMPLETIONS - PACKERS Ref.: Production Handbook Volume 3, Chapter 6.1.2 A packer is a subsurface tool used to provide a seal between the tubing and casing of a well, thus preventing the vertical movement of fluids past the sealing point.

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Production Technology Pre-Reading For a packer to perform its designated function, two things must happen. Firstly, the packer body must be positioned in the casing and anchored by means of tapered "slips". Secondly, a packing element must be compressed to effect a seal against the casing wall. The two most important basic components are therefore the slips and the sealing element(s). Packer slips can be unidirectional or may be designed to resist force from either direction. Sealing elements may be either of one piece construction or composed of multiple elements of different degrees of hardness. This section classifies the various types, the method of setting, the direction of pressure differential and the packer bore. It should be understood that there are many different packer types available. The following illustrations, including simplifications, show typical examples. Further data may be obtained from the appropriate manufacturers catalogues or technical manuals.

PRINCIPAL TYPES OF PACKER Packers are mainly classified in two groups, i.e. retrievable or permanent (Figure 6.11).

Permanent Packers The tubing can be released from this type of packer, and can be pulled leaving the packer set in the well. Tubing can subsequently be run back and re-sealed in the packer. The packer may be considered as an integral part of the casing and cannot be recovered as such, but can be destructively removed, e.g. by milling. It is sometimes termed a production packer, or a retainer production packer. Permanent packers are used for the following applications: • high pressure differentials • maximum dependability • large packer bore • when the exact location of the packer is critical and wire line set is used • to protect the zone below the packer from workover fluids should the well have to be killed and tubing have to be removed. Here the bottom extended packer is used. • casing straddle pack to permanently pack off old perforations The disadvantages of permanent packers are: • possible casing damage during mill-out operations • not suitable for multi-zone simultaneous production

Retrievable Packers The packer is run and set on the tubing. It can later be released by a straight pull and recovered from the well, on the tubing if required. Since it is an integral part of the tubing string, the tubing cannot be pulled without pulling the packer. The advantages of this type of packer are: • no mill-out required

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Production Technology Pre-Reading • suitable for multi-zone/-string simultaneous production The disadvantages are: • equalization of pressure across the packer during running or pulling may be difficult, which can result in swabbing-in the well • solid deposits on top of the packer, e.g. sand or wax may make it difficult to pull the packer • if it is not possible to pull the packer, mill-out is a lengthy process • tubing contraction may unseat the packer Where solid deposits are expected, the pulling of the packer can be planned in two stages. First the tubing is pulled, followed by a washover and pulling or milling of the packer. The tubing is detached from the packer by means of a detachable packer head, a safety joint, or by flash cutting the tubing. The latter is normally preferred.

Method of Setting There are several methods used for setting the various types of packer, e.g. mechanical, hydraulic, electric wireline. Refer to chapter 6.1.2.2 of volume 3 of the Production Handbook for details.

Direction of Pressure Differential (Packer-Forces) Packers may have to withstand pressure differentials from above, below, or both. For more details refer to chapter 6.1.2.3 of volume 3 of the Production Handbook.

Seal Assemblies The seal assembly, run on the tubing, packs off in the bore of the permanent packer. The sealing element that is frequently used is the chevron packing ring, fabricated from synthetic rubber, or from plastic such as Teflon. Rings are assembled in sets, facing opposite directions, to give a two-way seal. Packing rings should not be reused, but renewed. Some makes of packer use, instead of the chevron, a moulded rubber sleeve. In the locator seal assembly (Figure 6.12a), the top collar seats (locates) on the bevel of the packer body, just above the left hand thread. The anchor seal assembly (Figure 6.12b), has a latch sleeve, threaded to match the left hand thread of the packer. The lower part of the sleeve, carrying the thread, has vertical slots cut in it, and the lower flank of the thread is chamfered. On entry into the packer the latch sleeve collapses inwards, and then springs out to engage the thread of the packer. The anchor seal assembly permits the tubing to be landed in tension. The chamfer on the stub of the assembly, below the latch sleeve, ensures that it will not pull free. Landing under sufficient tension causes the tubing to be insensitive to temperature and pressure changes during production that might otherwise lead to buckling. The tubing therefore remains straight (within the limits of deviation of the well), contributing to the success of wireline operations. The anchor seal assembly can be released from the packer by pulling the weight of the tubing and turning clockwise at the surface. Because the latching sleeve is keyed to the seal assembly, a clockwise rotation will back it out from the packer. The locator seal does not permit landing the tubing with overpull. At most, the full tubing weight can be hung off at the well head. When the well is producing, the temperature of the tubing will increase, the tubing will expand longitudinally. With the locator seated on the packer, and the top of the tubing string fixed in the tubing head, expansion can take place only at the expense of buckling. By using a series of seals below the locator head, the tubing can be pulled back a calculated distance, and then landed, leaving the locator head this same distance © 2001 Shell International Exploration & Production B.V.

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Production Technology Pre-Reading above the packer, but with a seal nipple still within the packer bore. This will allow room for tubing expansion, However, seal rings are going to move through the packer bore whenever the well is closed in, or opened up, and this possibly, will cause wear and tear to the seals.

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6.3 TUBING Ref.: Production Handbook Volume 3, Chapter 6.1.3 The purpose of the tubing in a well is to convey the product from the producing zone to the surface, or to convey fluids from the surface to the producing zone. It should continue to do this safely and economically for the life of the well, so care must be taken in its selection and protection. Sizes up to 4" 12 inches (in) are classified as tubing. Over 4^/2 in, it is referred to as casing. In large capacity wells casing is used as tubing.

Tubing Design Considerations Ref.: Production Handbook Volume 3, Chapter 6.1.3.3 Tubing selection is governed by several factors. Anticipated well peak production rate, depth of well, casing sizes, well product, use of wireline tools and equipment, well pressures/temperatures and tubing/annulus differential pressures are among those which must be considered. The main considerations are: • Tension, which the tubing must withstand (tensile loading) due to its own weight, and when pulling out of or setting certain packers, and when landing the tubing under pretension to eliminate buckling due to elongation. • Couplings. Tubing must be free from leaks and contain the well fluid safely. Use of special "premium" connections may help in this respect as these have enhanced seal capability (other advantages are their tensile strength and smooth internal bore which provides greater protection against corrosion and erosion). • Burst. When tubing pressure is high and the annulus is empty. • Compression, which the tubing must withstand (compressive loading) when setting certain packers. • Collapse. When the annulus pressure is high and the tubing is empty; the standard for tubing collapse design is to consider the situation where the tubing is empty and the annulus is full of liquid and has a maximum wellhead pressure at the surface. • Corrosion, caused by H2S and/or C02. To protect the tubing string from excessive sweet and sour corrosion, always use a tubing steel with a Rockwell hardness less than 22. • Stimulation, which causes increased loading forces • Protection. Internally plastic coated tubing in injection wells. Flow couplings and blast joints for internal and external erosion respectively. • Lifetime. Replacement frequency and cost of API joints versus premium joints.

Tubular Joints Tubular joints are divided into two groups: • Threaded-and-Coupled (T&C): two threaded "pin" pipe-ends joined by a threaded "box" coupling.

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Production Technology Pre-Reading • Integral: a direct connection between the threaded pin end of one pipe and the threaded box end of another. The latter has half the number of threaded connections. Therefore, the chance that an integral joint will leak is half that of the T&C joint. Damaged threads on a T&C joint can be repaired by replacing the coupling, and rethreading the pipe ends. Integral and API EU joints, however, usually have an external upset, and normally can be recut only twice. Types of Thread Connections

Ref.: Production Handbook Volume 3, Chapter 6.1.3.1 MECHANICAL PROPERTIES OF TUBING Tubing is manufactured in various grades depending on the service required. These grades are based on the principles of Hooke's law. Some typical grades are shown below, their denominations being based on minimum yield strength: H-40

minimum yield strength

2800 bar

J-55

"

3800 bar

N-80

"

5500 bar

For further details refer to chapter 6.1.3 of volume 3 of the Production Handbook. For steels used in the manufacturing of tubular goods the API specifies the yield strength as the tensile strength required to produce a total elongation of between 0.5% and 0.6% of the gauge length. Heat Treatment of Alloy Steels The structure of a metal or alloy and the mechanical and physical (corrosion) properties connected with this are strongly dependent on the chemical composition and on the heat treatment given to the material. In heat treatment, the temperature and rate of cooling play an important part. Comparison of the chemical composition shows that in principle there is little difference between the various grades. The difference in mechanical properties is achieved mainly by a difference in heat treatment. Rapid cooling of the steel from above the crystallization temperature by quenching provides a hard, brittle steel. Slow cooling provides a soft low-strength steel. The hardness of a specific alloy steel is directly proportional to the strength of that steel. The methods of heat treatment are as follows: Annealing

The steel is heated above a critical temperature and cooled very

slowly (usually in a furnace). • Normalizing Identical to annealing except that the steel is air cooled. As an example API grades J and K-55 are heated to about 860 'C (1580* F). • Tempering Consists of reheating a quenched or normalized steel to a suitable temperature below the critical temperature, depending on the grade between 600'C and 680'C (1110' F and 1260T), for an appropriate time and cooling back to room temperature. This process makes the steel tougher at a small loss in strength. Stress Relieving Similar to tempering but is done to relieve internal stresses set up during the manufacturing process (e.g. upsetting). © 2001 Shell International Exploration & Production B.V.

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Production Technology Pre-Reading Quenching Same procedure as normalizing but rapid cooling, usually done in water, salt water or oil. Untempered quenched steels are very brittle. TUBING ACCESSORIES Several accessories have been developed over the years which contribute to completion and/or production control. The main categories are: • Landing Nipples

To locate: tubing plugs sub-surface safety valves bottom hole chokes

• Ported Nipples

To provide communication: sliding side door side pocket mandrel

Landing Nipples A landing nipple is a short tubular nipple with tubing threads and is run as part of the tubing string at a predetermined depth. It is internally machined with a specific profile, thereby providing a method of receiving a locking device. The landing nipple is also internally honed to receive high pressure/temperature packing, this being a part of the locking device. Nipples are furnished in all nominal tubing sizes, weights and threads, and are available in two basic types, selective and non-selective. The advantages of using landing nipples include: • The well may be plugged from above, from below, or from both directions. • With a plug set, the tubing string may be tested without affecting the formation. • Subsurface safety valves, bottom hole regulators and chokes, and other flow control devices may be installed and extension pipes can be hung-off. • Bottom-hole pressure and temperature gauges may be installed. • Pumps may be located and landed. • The nipples may be used as a reference point for checking depth measurements.

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Non-Selective Landing Nipples This type of nipple receives a locking device, which uses a no-go principle for the purpose of location (Figure 6.13a). This requires the O.D. of the locking device to be slightly larger than the I.D. of the nipple. If more than one non-selective landing nipple is place in a tubing string, each one must have a slightly different I.D. It is also essential that the O.D. of the locking device clears all of the upper nipples (i.e. the largest no-go I.D. is set uppermost in the string).

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Selective Landing Nipples These are essentially full opening and this allows the running of more than one in a tubing string, all having the same internal dimensions (Figure 6.13b). In the selective profile type, the locking and sealing devices are designed with fixed external profiles and the method of selection is determined by the running and setting device. This permits the use of an unlimited number of nipples of the same size to be run in the string.

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Locking Devices The regular locking device is used in combination with the landing nipples above (Figure 6.14). Another type exists for tubing without a landing nipple, which is set either in the collar recess of API tubing ("collar lock"), or on the tubing, consisting of a tapered body and slips.

Plow Couplings A flow coupling is tubular in construction, normally 0.5-1.5m in length, and made of high-grade alloy steel (Figure 6.14). It is machined with coupling-size outside dimensions and full tubing inside dimensions, which furnish a greater wall thickness as protection against possible internal erosion and corrosion. Flow couplings are positioned in the tubing string at points where excessive turbulence can be expected, e.g. above crossovers, immediately above and, on some occasions, below a landing nipple designed to receive a production control such as a subsurface safety valve, bottom-hole regulator, bottom-hole choke, etc.

Blast Joints Similar to flow couplings as far as internal and external dimensions. These give added protection against erosion resulting from the jetting actions of producing perforations. They are usually manufactured in 3-6m lengths, are run as part of the tubing string and are positioned opposite the perforated intervals in multiple completions.

Bottom-hole Chokes Bottom-hole chokes are usually anchored in the lower section of the tubing and provide the following facilities: • They reduce or prevent the freezing of controls by moving the point at which the pressure drop occurs to the warmer, lower portion of the well. • They reduce water encroachment through the stabilization of bottom-hole pressures. • They reduce gas-oil ratios under certain conditions. • They can be used to control (limit) production when required (e.g. for reservoir management purposes). PORTED NIPPLES (COMMUNICATION EQUIPMENT) Communication equipment is run on the tubing string and provides a method of selectively communicating between the tubing and the annulus by use of wireline. This type of equipment is of particular advantage in multi-packer installations, in that it allows access to alternate zones using wireline rather than costly workover operations, without disturbing tubing and packer settings or killing formations. There are three basic types of communication equipment, side port nipples, retrievable valve mandrels and sliding sleeves (sliding side doors).

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Side Port Nipples A side port nipple is a landing nipple with ports and internally honed sections above and below the ports, which receive the packing sections of a subsurface control (Figure 6.15).

Figure 6.15

Ported Nipples

Ported nipples have coupling outside diameters and have the advantage that the subsurface communicating device may be removed from the tubing string to repair or alter flow courses. In multi-zone completions utilizing side-port equipment, the zones are open to communication during service operations, the only restriction to flow being the port. Ported nipple installation introduces a production control in order to © 2001 Shell International Exploration & Production B.V.

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Production Technology Pre-Reading prevent communication. Therefore, if two ported nipple assemblies are installed in the same tubing string, it will be necessary to remove the upper control to retrieve the lower. The different controls used in conjunction with ported nipples are:• Side-door Chokes A side-door choke locks in a ported-nipple assembly and packs off above and below the ports in the nipple. This isolates the annular area and allows the lower or tubing zone to flow through the assembly. • Separation Tools A separation tool also lands in a ported-nipple assembly and seals off below the ports, blanking off the tubing zone and admitting the annular zone into the tubing. • Straight-flow Choke The flow course of the zones may be altered by what is termed a "straight-flow" choke. By removing the crossover choke and replacing it with a straight-flow choke, the upper zone or zone beneath the top packer flows up the annulus while the lower zone or zone beneath the lower packer flows up the tubing. However, this practice is not generally recommended nowadays as there is no safety device in the event of casing failure (e.g. due to erosion).

Side Pocket Mandrel (Retrievable Valve Mandrels) The side pocket mandrel was initially designed to receive retrievable gaslift equipment (Figure 6.16). However, since this mandrel receives retrievable locks and sealing devices, it has been used in the same manner as ported nipples and sliding sleeves. It is also used for chemical injection and shear valves. It offers advantages similar to side-port equipment, in that flow-control devices may be run and pulled by wireline, and advantages similar to a sliding sleeve in that it has full tubing internal dimensions with a flow device positioned in the side pocket. Because of the full internal bore the outside diameter must be larger than the tubing coupling at the side-pocket section. Gaslift valves and subsurface controls may be selectively set and retrieved from the mandrel by the use of a kick-over tool (which positions the flow device into the side pocket of the mandrel). With a flow device in this offset position, the possibility of sand or tubing debris falling on top of the flow device is reduced. Oval-shaped mandrels are used in multiple-string completions and are available in various tubing sizes and threads. However, the size of the ports is limited.

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Sliding Sleeves The sliding sleeve is run on the tubing string and is a full-opening device with an inner sleeve which can be opened or closed by wireline to provide communication between the inside and outside of the tubing (Figure 6.17). It is tubular in construction with tubing coupling O.D. and full-opening internal dimensions. A slotted inner sleeve, manufactured from corrosive-resistant materials and equipped with shifting profiles or shoulders provides a means for the wireline shifting tool to engage the inner sleeve during the opening or closing operation. © 2001 Shell International Exploration & Production B.V.

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Production Technology Pre-Reading The outer ported or slotted housing contains a sealing section on most types; some types place the sealing elements on the movable inner sleeve, Some sleeves are available with equalizing ports or slots; all types use either collets or snap-ring type locking arrangements. Sleeves are available in all nominal tubing sizes, weights, and threads, and are constructed to withstand tensile strengths equal to or greater than the tubing string. It is possible to run an unlimited number of sleeves in a tubing string and selectively operate them.

6.4 FIELD SURVEILLANCE Once a field is on production, it is necessary to constantly monitor the wells in the field in order to optimise that production. Field surveillance is primarily concerned with two fundamental questions, namely: • Is the well performing as it should? • If not, what should be done to improve the situation? In order to understand the principles involved, it is first necessary to define a few terms that are important in production operations (which also apply to injection © 2001 Shell International Exploration & Production B.V.

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Production Technology Pre-Reading operations) :•

Potential Potential is the maximum rate at which a system can and/or may produce with its existing installation and in a safe and technically sound manner.

•

Off Production Off production is the volume of production lost as a result of a temporary interruption of well flow.

•

Low Production Low production is the volume of production lost as a result of an actual production level lower than potential.

•

Availability Availability is the volume of hydrocarbons available for sales, taking into account the scheduled and (estimated) unscheduled deferment (Low & Off).

•

Target Target production is the volume of hydrocarbons required to be produced in order to meet offtake requirements.

Current Production Level The current production level (CPL) is the production level of a conduit, station or field required to meet the target. In general, this is equal to the target plus the estimated deferred production. IMPROVED FIELD PERFORMANCE In order to optimise field performance, each well in the field must be analysed to determine its performance relative to expectation. If this performance is below expectation, (i.e. the actual production rate is below the current production level, or the production potential can be increased), then ways must be devised for improving that performance by applying the available technology with the existing resources in the most economic way. This process can be described in terms of a number of steps in a cycle. Initially the production potential can be determined from several sources, namely: • Theoretical calculation, based on inflow performance relations. • The production forecast, incorporating the expected decline rate. • Comparing the performance of all the wells in the field. Having established the production potential, the current production level is set, based on the production target. The wells are then tested, the test data validated and the results compared directly with the current production level. If the two are significantly different, then the status of the well should be investigated, in order to determine the reason for the difference and to propose remedial action as required. If the two are the same, to within the accuracies of the test data, then the production potential should be optimised, and remedial action proposed as required. There is by nature a degree of overlap between investigating low production and optimising potential. Once remedial action is proposed, a decision as to whether to carry it out can be made. This decision depends on a number of factors, including the availability of the required resources, operational restrictions and economics.

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Production Technology Pre-Reading If the remedial action is carried out, then the resultant new potential is assessed and the process repeated. If not, then the current production level is reset and the process repeated from there (Figure 6.18).

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Production Technology Pre-Reading DETERMINING WELL POTENTIALS The potential of a well can be divided into four categories, as follows (Figure 6.19): • Reservoir Well Potential • Completion Interval Potential • Conduit Potential • Production Potential Reservoir Well Potential The reservoir well potential is defined as the maximum production rate that has no detrimental effect on the ultimate recovery of the reservoir. This is generally governed by the reservoir management guidelines, which might take account of the following considerations: • The overall reservoir depletion policy, which is designed to maximise the economic ultimate recovery. • Coning, cusping and linear displacement limitations. • Production / injection balance. • GOR control policy. • Limits imposed by authorities. This potential will usually be set according to analytical predictions of reservoir and well performance. The acquisition of actual production data may lead to revision of the constraints applied during the life of the field. Completion Interval Potential The completion interval potential is defined as the maximum production rate from the reservoir that has no detrimental effect on the completion interval. Factors, which govern this, are as follows: • Wellbore damage as a result of drilling and completion fluids. • Partial penetration of the reservoir. • Perforations. • Sand control. • Production of fines / sand. • Wax / asphaltene deposition. • Scale / emulsion formation. The inflow performance relation (IPR) is determined from these factors and the rock and fluid properties of the reservoir. The completion interval potential should be calculated separately for each completion © 2001 Shell International Exploration & Production B.V.

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Production Technology Pre-Reading interval in the wellbore, as well as for any combination of commingled intervals.

Conduit Potential The conduit potential is defined as the maximum production rate attainable from the interval with the installed completion that has no detrimental effect on the completion. It is obtained by superimposing the intake pressure curve (IPC) on the inflow performance relationship (IPR) and will be affected by the :• Tubing string design. • Tubing roughness. • Artificial lift performance. • Erosional velocities. • Bean performance. • Sand production. • Wax, scale and asphaltene deposition. • Hydrate formation. © 2001 Shell International Exploration & Production B.V.

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Production Potential The production potential is defined as the maximum production rate attainable from the conduit with the installed production facilities that has no detrimental effect on the surface hardware. This is governed by the following: • Flowline restrictions. • Separator backpressure. • Station capacity. • Erosion of equipment. • Emulsion formation. • Temperature. The production potential is the potential to be used for the production forecast. INVESTIGATING WELL PERFORMANCE Having established the current production level, based on the production potential, the offtake requirements, tanker scheduling, maintenance, BHP survey requirements etc., it can then be compared directly with the actual production data. If the two differ by a significant amount (i.e. larger than the measurement error), then the reasons for this difference should be investigated and remedial action proposed. It is important that the test data is reliable, that the actual production rate is confirmed by at least two tests, and that the test data is unreconciled. Significant changes in production performance over a short space of time often indicate a change in the completion status of the well, e.g. a leaking packer, failed gaslift valve or damaged wire wrapped screen. The first area of investigation should be the known or planned "off" production. This may consist of any combination of the following, although the list is not exhaustive: • Wireline activities. • Bean changes for offtake reasons. • Activation of safety valves. • Station shut-downs. • Artificial lift interruptions. • Engineering and maintenance activities. To determine the causes of any off production, relevant records should be examined, and the reasons for any of the above actions explained. If the difference between the current production level and the actual test data is not due solely to this known or planned "off" production, then the well status must be investigated. In certain cases, when only station or field production data is available (no individual well test data), then the first step must be the identification of the wells that are producing below potential. © 2001 Shell International Exploration & Production B.V.

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Production Technology Pre-Reading There are a number of tools available with which to investigate the status of the well and identify the source of any problem. These tools include the following: • Wireline runs to check hold-up depths, restrictions or wax, scale, asphaltene or sand deposition in the wellbore. • Flowing surveys to check for changes in PI, drawdown and gaslift performance. • Flowing and build-up surveys for skin determination. • TDT or PLT logging to determine fluid contacts, production profiles etc. • Dynagraphs and amp charts to check beam pump performance. • Sonologs to check fluid levels in pumping wells. • Amp charts to check electric submersible pump performance. • Inflow and pressure tests to check the integrity of the tubing, casing or packer. Once the source of a problem has been identified, relevant remedial action can then be proposed. The required action will depend on each individual set of circumstances, but some possibilities are included in the next section. OPTIMISING POTENTIAL If the actual production data and the current production level are similar, then the production potential should still be assessed in the same progressive order as used for the initial determination. The aim of such investigation is to determine areas where the potential can be increased, and to propose remedial action. This reassessment should be carried out at regular intervals throughout the life of the well. The iterative approach to potential optimisation is depicted in Figure 6.20. Various types of remedial action for each potential are then described. These lists are not exhaustive, but point to areas that should be considered. Reservoir Well Potential Reservoir management guidelines can be directed at the specific well, (e.g. for coning limitations), or at the wells draining the reservoir (e.g. for reservoir depletion constraints). Remedial action can be as follows: • If constraints were set according to analytical predictions of well and reservoir performance, check agreement between the models used and actual performance to see if any scope exists to relax the constraints (e.g. GOR or drawdown limits). • Recalculation of the offtake limits, particularly when they apply to the reservoir rather than the well, as any shortfall in one well can possibly be made up in another. • Negotiation with authorities to alter limitations. • Increased injection to balance additional production. This may involve supplying additional injection fluid, increasing injection pressure or drilling additional injectors. • If justified economically, start incremental development of the field (e.g. recompletion or sidetrack of existing wells, drilling new wells)

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Completion Interval Potential Remedial action is mainly concerned with rectifying damage or removing restrictions that have resulted from the drilling and completion operations. This can consist of: • Re- or additional perforations. • Stimulation by acidising, fracturing or chemical treatment, possibly with coiled tubing. • Repair, recompletion or sidetrack (if above fails or is not feasible).

Conduit Potential Remedial action is concerned with optimising the performance of the completion. This can include: • Bean changes. •

Installing artificial lift.

• Re-evaluating whether the current method of artificial lift is still appropriate. • Optimising artificial lift. Gaslift - valve changes, supply pressure, injection rate. © 2001 Shell International Exploration & Production B.V.

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Production Technology Pre-Reading Beam pumps - pump replacement, rod string design, balance pumps, install pump-off control. ESP - pump replacement, variable speed drives, slip stream, install timer, install softstart. • Installing downhole chemical injection to prevent e.g. scale formation, emulsion formation, wax deposition or corrosion. • Repair to change tubing size. Production Potential Remedial action is concerned with optimising the surface facilities. This can include: • Changing the separator pressure. This may affect other wells producing to the same separator. • Debottlenecking the facilities. • Changing the flowline size. • Minimising dehydration and de-oiling problems.

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6.5 FORMATION DAMAGE Before defining formation damage it is worth recalling the definition of permeability. Absolute permeability is a function of the nature and degree of interconnection between pores in the rock. It is independent of the fluid type. The absolute permeability may be reduced by any mechanism that changes the shape, or the degree, of interconnection between the pores. The permeability of rock to a particular fluid depends upon the fluid saturation. Thus, changing the fluid saturation may alter the effective permeability to that fluid although the absolute permeability of the rock remains unchanged. 'Damaging' mechanisms may act to reduce the absolute permeability, the effective permeability, or both. Formation damage may be defined as a reduction in the original value of either the absolute permeability of the rock or the effective permeability to the formation fluid in the vicinity of the wellbore. The zone of reduced permeability is called the skin, and the resulting effect is called the skin effect. The effect of damaging the original permeability in the vicinity of the wellbore is shown in Figure 6.21. The presence of a 0.5m radius zone around the well in which the permeability is reduced by 90% will restrict the potential of the well to less than 40% of the level that could be attained if the damage did not exist. The most obvious consequence of formation damage is that the well will not produce at the desired offtake rate. In prospect evaluation, it is important to recognise damage if it exists in exploration and appraisal wells and to take its presence into account when predicting the performance of development wells. Failure to do so may result in under-valuation of the prospect.

n the case that oil is being produced from stacked reservoirs with little or no vertical permeability, it is possible that reserves are lost because of formation damage. This is illustrated in Figure 6.22, in which the lower horizon is so severely damaged that it will not produce at all. Unless the damage is removed, or another well is drilled close by to provide an undamaged drainage point, the oil in the lower zone in this vicinity will never be produced.

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Virtually any well operation has the potential to damage the formation; this includes drilling, workover and, ironically, well stimulation operations. This fact does not make the resulting formation damage any more acceptable, and well operations should be screened for activities that may cause well impairment.

REDUCED ABSOLUTE PERMEABILITY Particle Plugging with Extraneous Material Particles alien to the reservoir may be carried into the system in the filtrate from drilling or workover fluid. The particles lodging in the formation pores completely clog or reduce the diameter of pore throats. Examples of damaging particles are as follows: • Weighting materials • Drilled solids • Lost circulation material • Viscosifiers • Undissolved salt • Cement • Mill scale • Pipe dope • Rust • Paint • Perforation debris

Formation Fines Beside particulate matter of extraneous nature, particles inherent to the reservoir can cause permeability reduction. Many sandstone reservoirs contain very small particles called "fines". These are mostly clays, which have some freedom of movement within the fluids flowing in the reservoir. The result of this movement is a bridging of the pore throats and a subsequent reduction in permeability. © 2001 Shell International Exploration & Production B.V.

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Clay Hydration and Dispersion In most sandstone reservoirs clay minerals are present. They occur as a coating on the individual sand grains and as discrete particles. The presence of clay minerals in reservoir rock is significant in the context of formation damage because of their sensitivity to water. This sensitivity is manifest in the way that clays either swell up and/or disperse and migrate blocking pore throats in the reservoir rock. Dispersion is the term used to describe the phenomenon where clay platelets unstack because the attractive forces between the platelets has been overcome. The degree to which this occurs is dependent on the type of clay mineral and the nature of the water that is altering the ionic environment.

Precipitation of Organic and Inorganic Deposits Organic deposits such as asphaltenes or paraffins may be precipitated as a result of the temperature of the crude oil being lowered, a change in pressure or some acid stimulation formulation. The precipitates will then plug the pore throats and reduce the permeability. The precipitation of inorganic deposits can occur anywhere in the producing system, from the reservoir to the tank farm. Inorganic deposits are usually referred to as scale and are formed as a result of altering the chemical equilibrium of the system by changing the temperature and pressure, or by mixing incompatible waters. The most common oilfield scales are calcium carbonate (CaCO3) and gypsum (CaSO4. 2HgO) These scales are acid soluble so they are fairly easy to remove. Less commonly occurring scales, which are not acid, soluble and therefore present a serious problem are: • Barium sulphate (BaS04) • Sodium chloride (NaCI) • Barium strontium sulphide (BaSr(S04)2) Dissolved iron is also present in most oilfield waters, particularly after using acids for well stimulations. Iron injected into the formation is almost always converted into iron hydroxide, which is a voluminous, flaky precipitate. The precipitate helps to catch formation fines and consolidate then as bridges in the pore throats. Compaction The weight of the overburden is supported by the vertical component of the grain-tograin stress and the pore pressure. As fluids are withdrawn from the reservoir, the pore pressure is usually reduced so the grain-to-grain stress is increased. This may cause the breakdown of cementing material, which may also contribute to the permeability reduction by clogging pore throats. REDUCED EFFECTIVE PERMEABILITY Recalling from Section 1.6 that: Effective permeability = relative permeability * absolute permeability it is clear that any form of damage that acts to reduce the relative permeability of the rock to a hydrocarbon fluid will, by definition, similarly reduce the effective permeability. The relative permeability of a formation to a fluid depends primarily on the saturation of the fluid, but also on pore geometry and the surface tension associated with the © 2001 Shell International Exploration & Production B.V.

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Production Technology Pre-Reading fluid and those that it is in contact with. Thus, changes in the relative permeability can be attributed to changes in: • The fluid saturation • The wettability of the reservoir rock

Changes in Oil Saturation A reduction in oil saturation is the result of an increase in either water or gas saturation. Increased water saturation may be the result of filtrate invasion during the drilling phase, or coning and/or water fingering during the production phase. It should be noted that once water has fingered or coned into the wellbore, its complete removal is virtually impossible. Increased gas saturation may develop as a result of drawing down the wellbore pressure too far, allowing gas to be liberated from the oil. The increase in gas saturation in the vicinity of the wellbore causes the relative permeability to gas to be increased, so gas is produced preferentially at the expense of oil production and the situation is aggravated. Gas wells may be affected by either water or, ironically, hydrocarbon condensate. Any type of filtrate invasion in a gas well is usually termed "water blockage". The extent of the reduced productivity depends on the degree of water saturation and the radius of the affected area.

Changes in Wettability Reservoir sediments are usually laid down in a water environment and so it would seem reasonable to assume that most reservoir rocks will be water wet after such prolonged exposure to water. However, observation of the performance of reservoirs lends weight to the idea that the wettability of the oil-bearing part of many reservoirs has been reversed by exposure to oil, even in the presence of connate water. Many reservoirs are thus thought of as being of mixed or intermediate wettability. Unfortunately it is very difficult to be certain as to the wettability state of the in-situ reservoir material because the process of recovering and analysing samples (cores) may itself affect the wettability. The relevance of this to the problem of formation damage is that the relative permeability to oil of a water wet rock is radically reduced if the wettability is reversed and the oil becomes the wetting phase. This type of behaviour is illustrated in Figure 6.23 for a fluid, which is present as either a wetting or a non-wetting phase. A change in the wettability of the reservoir rock is a phenomenon that usually takes place in the vicinity of the wellbore. Oil wetting can be the result of chemicals used in drilling, workover, or well stimulation fluids.

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Increased Fluid Viscosity For hydrocarbon liquids it is generally true that increases in viscosity are the result of: • Decreasing temperature. • Increasing pressure • Decreasing solution gas • Emulsification with water In the context of formation damage, the last two conditions are relevant. Decreasing reservoir pressure will allow the liberation of gas from solution. This means that there will be fewer light components in the liquid phase, which will, as a result, exhibit a higher viscosity. Emulsions do not generally form between oil and water, which are both indigenous to the reservoir. The formation of an emulsion is usually a problem in injection wells where extraneous water is injected into the reservoir and mixes with the oil phase. Alternatively, injecting water, which still contains small quantities of oil into a reservoir, can produce emulsions with very high viscosities. Generally, water-in-oil emulsions have viscosities many times higher than the viscosities of oil-in-water emulsions.

OTHER PRODUCTIVITY IMPAIRMENT MECHANISMS Perforation Quality

The factors affecting perforation performance are as follows: • Perforation diameter and penetration depth. • Phasing between perforations. • Shot density. • Completion fluid used when perforating. • Applied drawdown when perforating. © 2001 Shell International Exploration & Production B.V.

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Production Technology Pre-Reading Partial Completion A partial completion is defined as one in which the interval open to flow is only a fraction of the total thickness of the producing zone. This situation may occur when the oil zone is above a water zone or below a gas zone, or both. In such a completion, the flow towards the wellbore is no longer radial flow but is more properly described as spherical flow. This deviation from radial flow leads to an additional pressure drop towards the wellbore, which is interpreted as an extra or pseudo skin factor. The pseudo skin factor, which is a result of the flow pattern only, should be distinguished from the skin factor caused by formation damage or the diagnosis of productivity impairment will be incorrect. Gravel Pack Quality Gravel pack quality can have a large effect on the productivity of a well for a variety of reasons. These are summarised as follows: • The mixing of gravel and formation sand causes a reduction in the permeability of the gravel pack because the pore throats within the pack are clogged with finer formation sand. Fines laden carrier fluid used to transport the gravel into place can impair both the formation and the gravel pack. • Incompatible carrier fluid being mixed with formation fluid can cause precipitates to be formed in the formation • Poor quality gravel can be crushed and broken, thus generating large quantities of fines, which are deposited in both, the formation and the gravel pack. DETECTION OF FORMATION DAMAGE The first indication that formation damage is occurring comes from production data and is manifest as anomalies in producing rates, water cuts, and gas/oil ratios. If well parameters have been mapped across a field, an initial completion that is suspect may be compared with wells surrounding it. The suspect well may exhibit a PI that is lower than expected for the area, perhaps indicating excessive drilling damage. Plotting the productivity index against time may reveal that, for a particular well, the PI is deviating significantly from a predicted trend, which is usually considered to be accurate. Suspected formation damage can then be confirmed or otherwise by conducting a pressure build-up survey (see Section 2.5). It is in any case good practice to routinely conduct pressure build-up surveys in all wells every two to four years with the objective of (among other things) picking up evidence of formation damage that may not be detectable in the production data. A rapid increase in the GOR or water cut may indicate that a high production rate is causing coning or cusping, causing reduced permeability to oil near the wellbore. When dealing with changes in producing parameters, a general rule of thumb is that sudden changes in parameters may indicate some form of mechanical or equipment failure, whereas gradual changes in production parameters are more likely to indicate some type of formation damage.

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6.6 WELL STIMULATION Stimulation is the term used to describe the treatment given to a well in order to remove formation damage and improve upon the productivity or injectivity of the well. Attention to the complete type of lifting method may also have the same end result, so this aspect of increasing productivity is briefly addressed. Whether or not a particular stimulation treatment has any chance of success depends on many factors; these include chemistry, rock mechanics, fluid hydraulics, and reservoir parameters. Stimulation treatments are aimed at either removal or bypass of formation damage or at improving the permeability of tight reservoir rock (through fracturing). Parameters Affecting The Productivity of An Oil or Gas Well The parameters influencing the productivity of an oil or gas well can be divided into two groups. The first group includes parameters that are related either to the completion or to the method of lifting reservoir fluids; thus they cannot be influenced by stimulation treatments. The second group includes those parameters, which can be changed by stimulation treatment. The radial inflow formula for a producing well is:

The main parameters in this expression that are targeted by stimulation are the effective thickness being drained by the perforations (h) and that part of the skin (S) that may be due to physical formation damage. Parameters Unaffected By Stimulation • Well tubulars Production parameters prevailing when the well was initially completed may have changed to the extent that the tubing size is no longer optimum for the present reservoir pressure or gas/oil ratio. Before instigating a well stimulation programme, the effect of tubing diameter on the flowrate should be investigated. • The completion interval The formula for the productivity index of a well assumes that the well has been completed over the entire producing interval (h). Any partial completion distorts the flow pattern near the wellbore with the result that an increased pressure drop will be observed due to the flow being spherical rather than radial. A sufficient number of clean perforations is important in maximising productivity. Perforation performance is of particular importance in Internal Gravel pack operations, as it is essential that the perforation tunnels are tightly packed with gravel.

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Production Technology Pre-Reading • Deviated completions By deviating a well through the reservoir, productivity improvement can be achieved because of the increased length of the hole exposed to the pay zone ("h" or effective reservoir thickness). However, the deviation angle has to be considerable in order for the effect to be significant (e.g. horizontal drainholes). Further improvements are made when the well intersects vertical natural fractures. • Lifting method Changes in the producing parameters that occur throughout the life of a well may make it necessary to alter the method of lifting reservoir fluids to surface. • The oil formation volume factor (Bo) This factor represents the volume of oil and associated gas under reservoir conditions that will yield one volume of stock tank oil under surface conditions. For oil wells this factor can be minimised (i.e. the liquid yield maximised) by choosing the correct combination of surface separator conditions.

Parameters Affected by Stimulation • The skin factor (S) Recalling the definition of skin, the effect of formation damage is manifest as an additional pressure drop above that which would exist if the well were undamaged, the additional pressure drop being referred to as the result of skin (Figure 6.24). The radius over which the skin occurs is usually small, of the order of tens of centimetres.

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Production Technology Pre-Reading The skin factor is a dimensionless number (S), which is related to the magnitude of the pressure drop, which it causes. It represents the cumulative effect of all the causes of additional pressure drop in the near wellbore region, some of which may be related to physical damage (mechanical skin) and some to other causes, such as the geometry of the perforations relative to the total drained thickness (geometric skin). Both mechanical and geometric skin can be attacked using stimulation techniques, although the emphasis is usually on mechanical skin. It is of critical importance to the success of this type of stimulation to have as clear a picture as possible of what is actually causing the skin. Without this understanding it is possible that an inappropriate (i.e. ineffective) stimulation technique will be selected. in certain circumstances stimulation can be so successful as to cause the permeability near the wellbore to be higher than that in the surrounding reservoir. This will lead to a lower than expected pressure drop near the well and can be quantified in terms of a negative skin factor. Typical skin factors range from 50 if a well is very badly damaged to -5 for a stimulated well. It is virtually impossible for the skin factor to be less than -8: as can be seen from the steady state radial inflow equation above, the following condition must always be true and so the physical size of the reservoir (re) will dictate a minimum

value for skin (S).

Skin factors can be misleading because they depend not only on the additional pressure drop due to any damage, but on the permeability of the formation. A well in a high permeability formation, with very little damage, may still exhibit a high skin factor. What matters most is what fraction of the total pressure drop, or drawdown, (∆P) is being caused by the damage. From the radial inflow formula the pressure drop due to skin (∆Pskin) can be expressed as: • The wellbore radius (rw) The wellbore radius is a function of the way in which the well was drilled. It can be

increased either by underreaming, i.e. drilling a larger hole, or by fracturing. • The permeability (kabs) In low permeability reservoirs, the productivity can be increased by hydraulic fracturing or an acid fracturing treatment. This increase is also due to an increase in the effective wellbore radius because the combination of the fracture and the original wellbore may be considered to be equivalent to a different effective wellbore radius. Acid stimulation (without fracturing) may under very favourable conditions increase the permeability of the reservoir near the wellbore by removing any part of the grain cementation material that is acid soluble. This effect can also give a pronounced reduction in the rate dependent skin factor of gas wells (see section 2.5).

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Production Technology Pre-Reading • Relative permeability (kr) If the relative permeability to produced fluids has been reduced because of water blocking or condensate dropout, a higher relative permeability may be established by injecting e.g. surfactants. • The viscosity (n). If high viscosity is a result of emulsions forming under conditions, which allow the mixing of incompatible fluids, the well can be treated with a solvent designed to break down the emulsions. A high viscosity of the oil in the reservoir may be reduced by applying heat in the form of steam, hot water or in-situ combustion processes. STIMULATION TECHNIQUES This section on stimulation techniques describes the main stimulation methods i.e. acidisation and (acid) fracturing. Matrix Acidising This technique relies upon removing acid soluble material from the rock matrix and is used to remove skin damage. • Sandstones In sandstone formations, the injection of acid results in the dissolution of interstitial materials such as clays, feldspars and invading silicaceous material. The technique, known as matrix acidising, is primarily to remove the skin damage caused by drilling and completion fluids or fines that have been trapped near the wellbore during the producing process. The removal of these materials often result in a large increase in the productivity. The acid used to stimulate sandstones is called mud acid and is usually a mixture of 12% hydrochloric acid (HCI) and 3% hydrofluoric acid (HF). The latter reacts with clays, sand, mud and cement to improve the permeability, while the HCI is to remove calcites and to reduce the precipitation of by products by maintaining a low pH. • Carbonates As with sandstones, the acid stimulation of carbonates is primarily aimed at removing formation damage. In damaged carbonates, acidising usually significantly improves the productivity. In this case, the intention is to dissolve the rock matrix thus allowing damaging material to be released and be either displaced deeper into the formation or to be produced. Normally 15% HCI is used to acidise carbonate formations although concentrations up to 30% have been used. When acidising carbonate reservoirs, hydrofluoric acid should never be used since it produces insoluble calcium fluoride precipitates. Acid Washing Acid washing is the technique whereby the perforations are washed with small volumes of acid to remove any acid soluble material within the perforation tunnel. In addition acid may be spotted or circulated to remove CaCO3 scales deposited in the tubing.

Conventional Hydraulic Fracturing This technique can be applied to either sandstones or carbonates providing that the natural permeability of the formation allows the propagation of a fracture. © 2001 Shell International Exploration & Production B.V.

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Production Technology Pre-Reading In this technique, a fracture is created by pumping a "pad" of relatively low viscosity fluid down the well, at fracturing pressure. A narrow two wing fracture will be created and propagated at right angles to the minimum in-situ stress (usually vertical fractures). Next, a high viscosity pad is pumped to widen the fracture and to transport proppant to hold the fracture open after the fracturing pressure has been released. The type of proppant material depends on the effective rock stresses; 'it may be sand, gravel, or higher strength materials such as zirconium oxide or sintered bauxite. The resulting fracture may be several hundred metres long with a width of between 5 and 20 mm. The high conductivity of the propped fracture may increase the well productivity by up to 200%. Figure 6.25 shows a computer simulation, which predicts the growth of a fracture with time, and the fracture width. The fracture begins to grow in a penny shape, but then becomes contained by a more highly stressed cap rock. In the vertical plane of the fracture (Figure 6.25a), the "rings" show the progressive growth of the fracture as pumping continues. Figure 6.25b shows a three dimensional representation of one half of one side of the fracture. A typical fracture treatment may require 1000 m^ of fracturing fluid and 25,000 kg of a proppant such as "Ottowa sand". Additives to the fracturing fluid give it the desired rheological properties. Often, additives are essential to a successful fracturing

treatment.

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Massive Hydraulic Fracturing This technique is exactly the same as that for conventional hydraulic fracturing except that huge quantities of fluid and proppant are used with the intention of obtaining very long fractures. A massive hydraulic fracture may require 15,000 m^ of fracturing fluid and 250,000 kg of proppant.

Minifrac The objective of a minifrac treatment is to obtain a fracture of limited length in order to bypass near-wellbore damage. The fracture may be 30 m long and is designed to be fairly wide. Treatment volumes are small; typically 3 m^ per metre of reservoir interval.

Acid Fracturing This technique produces an acidised hydraulic fracture, which eliminates the need for proppants. A non-acid preflush is used to initiate and propagate a fracture, which is then acidised to etch the walls of the fracture. When the fracture closes, the etchings provide flow channels within the walls of the fracture. The design of acid fracturing treatments is complex, since it involves not only the dynamic fracturing mechanics already described, but also chemical reaction between the rock and the acid. Laboratory tests are required to provide inputs for the computer programmes used for designing acid fracs.

Safety Most stimulation treatments involve pumping of hazardous chemicals at high pressures. It is therefore essential that all relevant safety aspects are considered throughout the stages of selection, planning, detailed programming and execution of stimulation jobs. Equipment should be regularly inspected and tested to twice the rated operating pressures. Just before the job all exposed equipment should be tested to a pressure of some 25% more than is scheduled in the programme. Hydrochloric acid is usually applied in concentrations of 15% and is thus a very strong acid. The operators should therefore use acid-proof clothing (aprons, boots, safety-goggles) and back up facilities must be available (eye wash stations etc.). Hydrofluoric acid is so dangerous that it is never delivered on site; it is usually created inside the pumps and the well by reacting ammonium bifluoride salt with hydrochloric acid. Only a few notes on the safety aspects of well stimulation are given above, but it cannot be over emphasized that each step in the process should be critically reviewed vis-a-vis the safety risks.

Chemical Stimulation Without Acid • Surfactant flush Surfactants are injected into the formation to break down emulsions that have been formed by oil and water. They are also used to restore the relative permeability of the formation which may have been altered by water blocking or condensate drop-out. • Solvent Flush During production, the reduced pressure around the wellbore may have caused © 2001 Shell International Exploration & Production B.V.

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Production Technology Pre-Reading waxes and asphalt to have come out of solution and be deposited. These can be dissolved by an organic solvent, and then produced clean . • Mutual Solvent Flush Mutual solvents are used to break down oil/water emulsions and to remove oil and/or water blocks. Oil blocks may be a problem in water injectors where trace quantities of oil have accumulated near the wellbore and reduced the relative permeability to water so that high injection pressures are required.

Selection of Candidates for Stimulation Before a well is stimulated, the chance that the operation will be successful and the likely value of the economic returns must be assessed. The well with the highest likely economic returns should be the most desirable candidate for stimulation. Some of the factors that should be considered when selecting stimulation candidates are: • Reservoir Pressure. The state of depletion of the reservoir is important because highly depleted will are poor candidates. • Reservoir Geology Important considerations include; the presence of faults, the proximity of gas or water bearing zones, the in-situ stresses, which may indicate the possible fracture orientation and geometry. The in-situ stress profile should be determined by a series of micro-frac tests. • Formation Data Shaliness and clay content. Hardness and rock strength. Porosity and permeability. Skin factor kh value and vertical profile. Fluid invasion. Acid response. Fracture conductivity and orientation. • Fluid Data Type of fluid present in the reservoir, and the compatibility of these fluids with the stimulation chemicals. • Well History Previous operations, casing design, tubing stress limitations, cementation quality etc. In order to assess the likely reward from a stimulation treatment, Figure 6.26 gives a rough guide to the increases in productivity that may be obtained. Note that these increases are relative to the undamaged well, i.e. a skin factor of zero. For damaged wells, increased productivity resulting from a reduction in the skin factor can be estimated from the radial flow equation. The graph shows that a matrix acidisation will improve productivity by a maximum of 1.3, whereas a massive hydraulic fracture may result in an improvement of 6.5 times the original (undamaged) productivity.

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