Completion Manual Well Performance

BP Exploration

Section 3 Well Performance

BP Exploration

Section 3 Well Performance

SECTION 3WELL PERFORMANCE

Prepared By:Jonathon Bellarby

Henry Nickens

Date:

Revision:1

Reviewed By:Paul Adair

CONTENTS

Page

13Well peRformance

13.1Summary

13.2Introduction

13.3Definition Of Well Performance

33.3.1Inflow Performance Relationship

33.3.2Vertical Lift Performance

43.3.3Overall Pressure Drops

43.3.4Well Design For Life Of The Well

53.4Pressure/Volume/Temperature

83.4.1Direct Use Of Laboratory Data

83.4.2Equation Of State

103.4.3Empirical Correlations - Untuned

113.5Inflow Performance

123.5.1Radial Inflow Equation And Skin

133.5.2Vogel Inflow Performance

133.5.3Fetkovich

143.5.4Jones

143.5.5Hydraulically Fractured Wells

153.5.6Horizontal Wells

163.5.7Formation Damage

163.5.8Perforation And Deviation Skin

183.5.9Multiple Zone Completions

183.5.10Gravel Pack Completions

183.5.10.1Cased Hole Gravel Packs

193.5.10.2Open Hole Gravel Pack

203.6Stimulation

223.6.1Selection Of Stimulation Candidates/Methods

243.6.2Acidising

253.6.2.1Breakdown Treatments

253.6.2.2Scale And Corrosion Removal

263.6.2.3Matrix Acidising Of Sandstones

283.6.2.4Matrix Acidising Of Carbonates

293.6.3Types Of Acids And Additives

293.6.4Acid Placement Methods

293.6.4.1Bullheading

303.6.4.2Coiled Tubing/Snubbing Workstring

313.7Vertical Lift Performance

323.7.1Correlation Selection

333.7.1.1Fancher-Brown Correlation

333.7.1.2Hagedorn And Brown

333.7.1.3Duns And Ros

333.7.1.4Orkiszewski

343.7.1.5Beggs And Brill

353.7.1.6Ansari

353.7.1.7Petroleum Experts Correlations

353.7.1.8Gray

353.7.2Use Of Correlations For Well Dying Prediction

363.7.3Tuning Pressure Drop Correlations

373.7.4Natural Flow

373.7.5Shut-In Conditions

393.7.6Artificial Lift

393.7.6.1Gas Lift

433.7.6.2Electrical Submersible Pumps

443.7.6.3Jet Pumps

463.7.7Heat Transfer

473.7.8Erosion

493.7.9Tubing Selection

493.7.9.1Natural Flow Production

513.7.9.2Tapered Strings

523.7.9.3Pumped Production

523.7.9.4Gas Lift

533.8Well And Field Optimisation

553.8.1Practical/Theoretical Optimisation

553.8.1.1Practical Methods

553.8.1.2Theoretical Methods

553.8.1.3Combined Method

563.9References

1 Well peRformance

1.1 Summary

The contents of this section give engineers an insight into the aspects of engineering which enable a wells performance to be assessed. It relates these to the computer programmes available and normally used to determine well performance. The wells performance is critical for the completion engineer to design the completion to cater for the pressures, flow rates, temperatures and producing conditions to meet with the planned life of the completion.

1.2 Introduction

The purpose of this section of the manual is to define well performance and how it is assessed and modelled. It has been written from a users viewpoint rather than any theoretical perspective. The more theoretical aspects are covered in many available industry publications.

This section of the manual should be used in conjunction with the well performance software Prosper Manual and the Near Wellbore Completion Manual. This section does not attempt to cover any of the mechanics of using Prosper, rather what issues need to be addressed when attempting accurate and representative well performance modelling. There are some areas of overlap, between the Prosper manual and this section, however these have been included to emphasise particular points.

The Prosper Software can be accessed at:http://upstream.bpweb.bp.com/EPT/home.asp?id=2603The Near Wellbore Completion Manual can be accessed at:http://aberdeen.bpweb.bp.com/dwo/documents/TS-D-008/default.htm1.3 Definition Of Well Performance

Following the review of the reservoir and assessing what is known about it, the planning process then focuses on well design. A major component of this is the selection and design of the completion to be used. There are a large number of tools and techniques available to the completion engineer to address the specific properties of the reservoir and to maximise the productivity of the planned wells. However, central to the entire well design process is the means of defining well performance.

The classic approach to expressing well performance is a graph of the well bottomhole flowing pressure versus the produced fluid rate. The following example is for an oil well:

Figure 3.1 Typical Inflow And Outflow Plot

Superimposed on the graph are two well properties indicated by blue and red lines.

The blue line represents what the reservoir will deliver to the well and is termed the inflow performance relationship (IPR). The concept was introduced in the 1920s with the development of the bottomhole pressure gauge. From the gradient of this line the productivity index, or PI, can be calculated and is quoted as stock tank barrels per day per psi drawdown. This gives a means of comparing productivity between wells.

The red line defines what the bottomhole flowing pressure has to be in order for the well to produce at the rate on the bottom axis. This relationship accounts for the pressure required to get the produced fluids up through the tubing used to construct the well and is termed the vertical lift performance (VLP) or tubing performance. If the datum point for each system is the same, the point at which the two lines intersect defines the rate at which the well will flow and the bottom hole pressure at this point. This is an example of nodal analysis, so called because the whole system performance is described by two independent subsystems. The two subsystems are upstream and downstream of a common node. It is possible for this node to anywhere in the system, for example when looking at facilities performance as well, it is often useful to define the node as the wellhead or where the flowline meets the manifold. Such concepts are explored more in the well optimisation section 3.8.

Having defined the means of describing well performance, the design of the well can be considered in order to optimise this. In this context, optimisation does not mean the same as maximisation. High rate wells can certainly be designed, however, this may have implications on the performance of the reservoir throughout field life that may reduce overall hydrocarbon recovery. The key issue is that a means of reviewing well performance is available to contribute to the overall review of the best production strategy for the reservoir.

As shown in the graph above, there are two parameters to consider when assessing well performance:

The inflow into the well (described by the IPR)

The outflow through the well to surface (described by the VLP)

An analogous relationship exists for injection wells.

1.3.1 Inflow Performance Relationship

The reservoir will have specific properties defined by the geological processes occurring as it was laid down. Similarly, the hydrocarbon fluid will have properties defined by its source and the environment in which it was converted from Kerogen. The issues the completions engineer has control over are:

Geometry of the well

What sections are allowed to flow

Order in which this occurs

Selection of the interface between the reservoir and wellbore

For example, a horizontal well may be selected with flowing sections towards the toe end and beginning heel end. The toe may be produced first to ensure maximum clean-up from these sections through a wire wrapped completion to prevent the production of sand from the reservoir.

As well testing became common a large effort took place within the industry to define mathematical equations that describe the IPR based on reservoir and fluid properties. From this work, reservoir and fluid parameters have been identified that control the inflow. In turn these can be used in order to predict the potential IPRs of new wells as a basis of effective well design programs. This chapter will discuss the various IPR relationships available and criteria for their applicability to a given well. How the appropriate IPR can then be used to evaluate the potential well performance for a specific well design will then be discussed with a proposed methodology.

1.3.2 Vertical Lift Performance

The vertical lift performance (VLP) or tubing performance is controlled by both the properties of the produced hydrocarbon and the construction of the well. Whilst the completions engineer has no control over the hydrocarbon characteristics, defined by the pressure - volume - temperature relationship or PVT, they have options to use different tubing sizes and artificial lift methods in order to optimise production. The two most common methods of artificial lift are using gas lift, where produced gas is injected at a series of points down the well, or running a pump of some sort, (refer to section 4). Both methods have the effect of reducing the hydrostatic column pressure in the well. Without this to overcome, produced fluids can be far more easily flowed to surface.

The dimensions of the tubing that the produced fluids flow through to surface:

The material used

The degree of corrosion

Other factors such as scale build up also effect the VLP

Clearly the completion engineer has far more control over these along with the wellhead flowing pressure. By considering all of these parameters, the most appropriate well design can be identified.

1.3.3 Overall Pressure Drops

It is useful to take an overall view of the pressure drops in the field/well. This enables the real influences on the field/well performance to be identified. For example in a gas well in a tight reservoir, the majority of the pressure drops are frictional in the reservoir. In an oil well, hydrostatic pressure drops in the tubing are more important. This allows both the effort in prediction to be focused on the areas where it maters, but also the areas where the completion designer can have an impact on improving performance, (refer to Figure 3.2).

Figure 3.2 Generalised Pressure Drops In Hydrocarbons Production

1.3.4 Well Design For Life Of The Well

A major issue to be considered during the well and completion design process is how the well should perform for the entire period of its operational life. Factors that impact on this are:

The performance of the reservoir throughout the field life. For example, pressure support (or lack of it) or water/gas coning.

Reservoir constraints. For example on the Harding field, the reservoir is so conductive that rates in excess of 40,000bpd could be achieved. However, gas and/or water coning would occur at these rates and, therefore, the wells do not need to be designed to handle these rates. Likewise sometimes bottomhole pressures are deliberately maintained above the bubble point in order to prevent relative permeability effects.

The fluids handling and how this may change, e.g. there is no point in designing a large well to cope with high GORs if the wells will have to be constantly choked back because the gas cannot be managed at surface.

Production problems. Scales, asphaltenes, wax etc. all impact the well design and productivity. Asphaltene deposition occurs at a certain pressure and, therefore, the bottom hole pressure is maintained above this point in order to prevent asphaltene depositing in the reservoir or at the bottom of the well (e.g. perforations).

The likelihood of workovers. This will allow for a tubing size change or implementation of artificial lift.

1.4 Pressure/Volume/Temperature

The Pressure Volume Temperature (PVT) relationship describes how a fluid behaves under changing conditions. With an accurate PVT relationship, the density, viscosity and gas-oil ratio for the fluid under expected pressures and temperatures can be reliably extracted. This is then used to determine the inflow performance and more importantly the tubing performance.

As a hydrocarbon fluid is produced, the temperature and pressure changes. These changes will initially only cause the oil or gas to change viscosity and density. At a certain point, however, the fluid will change from a single phase to two phase. For a black-oil fluid, the gas will start to come out of solution at the bubble point. For a condensate, condensate will start to come out of solution at the dew point. For a given fluid composition, these points (the saturation points) define the phase envelope. Outside the phase envelope, the fluid is single phase, inside the fluid is two phase. The critical point is the point on the phase diagram where to the left the fluid that first comes out of solution is a gas. To the right, the fluid that first comes out of solution is a liquid. Figure 3.3 shows an example of a phase envelope.

Figure 3.3 Example Phase Envelope

The definitions of the different fluids are:

A black-oil or volatile oil is one where with a drop in pressure, gas will come out of solution. The difference between a black oil and a volatile oil is purely arbitrary and relates to the higher GOR and formation volume factor (FVF) of a volatile oil compared to a black oil. The FVF for a volatile oil will be above approximately 1.5, below this it will be a black-oil.

A retrograde condensate is one where with a drop in pressure, liquid will first come out of solution. Note most retrograde condensates will exhibit the behavior where as the pressure is reduced further, the liquid may vaporise again.

A gas is where a drop in pressure will not result in the phase envelope being crossed.

These definitions apply to the conditions in the reservoir (isothermal). In the tubing, cooling will occur and therefore the fluid will almost certainly cross the phase envelope at some point. Therefore a gas will produce some liquid (condensate) before it reaches the surface.

It is possible to have all of these fluids with the same composition, it is just the initial pressure and temperature that may change. For example in the phase envelope, (refer to Figure 3.3), a reservoir temperature of 650F or below would result in a black or volatile oil. A reservoir temperature of between 650F and 858F would be a retrograde condensate and a reservoir temperature of above 858F would be a dry gas. Note: In this example a black-oil fluid is likely as most reservoir temperatures are below 650F.

Below the saturation pressure, the proportions of the phases will change. This can be examined on the phase envelope plot (as in Figure 3.4).

Figure 3.4 Fluid Behaviour From Reservoir To Surface

As the fluid proportions and properties change, this will clearly affect the well performance.

The reservoir or near wellbore performance will be effected by:

Viscosity

Expansion or contraction of the fluid (included in the formation volume factor)

Any relative permeability effects due to liquid or gas break-out (note: Prosper cannot handle gas relative permeabilities and these will have to be estimated separately)

The tubing performance on the other hand will be effected by:

Density of the fluid(s) - accounted for by the FVF and oil/gas gravity

Proportion of gas to liquid (the GOR or CGR)

Viscosity (to a lesser extent)

The PVT data is therefore critical to the well performance predictions. Historically most errors in well performance prediction have been attributed to poor or inaccurate PVT data.

Regardless of which PVT system is used to describe the fluids within Prosper, it is vital that the original laboratory PVT data is both representative of the reservoir fluids and covers well performance issues as well as reservoir performance issues:

a) Ensure that the well has cleaned-up adequately (as evidenced by stable flow with a steady GOR and water cut).

b) There are two options, either, bottom hole single phase samples, or separator samples, recombined according to the GOR. Sampling at the separator introduces more errors than downhole sampling as the proportions of oil and gas have to be accurately measured. Whichever method is chosen, ensure that the fluid is single phase at the sandface, otherwise condensate or gas breakout may make the produced fluids unrepresentative. Sampling of fluids where the reservoir pressure is close to the bubble or dew point is always going to be error prone and this uncertainty must be acknowledged.

c) The value of accurate samples is huge. For example, on Pompano, approximately $20 million US could have been saved if the paraffin content had been accurately known and the expensive TFL completions avoided. The only oil sample was unfortunately lost in the laboratory.

d) Multiple samples should be checked against each other. The bubble point is the most useful consistency check.

e) The PVT analysis should include a constant composition expansion experiment for conditions between the bubble point and separator pressure. Note: The reservoir engineer is more likely to be interested in differential expansion where at each stage of the expansion, the produced gas is removed and, therefore, the composition changes. The two methods will produce different GORs, and Formation Volume Factors and, hence, different predictions about well performance. Constant composition is more valid in the tubing as the oil and gas will be in constant contact with each other.

f) Any PVT model may be ideal for the reservoir or the facilities, but not the tubing. For example, the correct fluid density may not be critical for either the reservoir or the facilities model. However, for the tubing the correct fluid density over a large range of pressures and temperatures is absolutely vital. Likewise, the reservoir fluids do not need to include a large sensitivity to temperature and facilities correlations do not necessarily need to cover a large range in pressure.

1.4.1 Direct Use Of Laboratory Data

It is possible to use laboratory data, if it is available, over the expected range of pressures and temperatures. Interpolation will be performed between pressure and temperature data points, but so long as there are sufficient data points and that for each temperature, there is a data point at the point bubble, the errors will not be substantial. The real problem comes from the inflexibility this approach introduces. It does not allow the user to alter the composition to any extent, i.e. gas lift, or changing GORs cannot be incorporated.

1.4.2 Equation Of State

An Equation of State (EoS) is a mathematical method for modelling a fluid based on the components in the fluid. As a reservoir hydrocarbon contains hundreds of different components, the EoS is usually limited to the major components or groups of components. The properties of these components and these pseudo components must be specified. The equations of state were originally developed for pure substances but through time their use was extended to mixtures. With mixtures (e.g. reservoir fluids) some method of introducing a measure of the polar and other interactions between pairs of dissimilar molecules is required. The binary interaction coefficients change the ideal Equation of State to match the reality of many mixtures.

The Equation of State used by Prosper is the Peng-Robinson (P-R). The Prosper programme can be accessed at:

http://upstream.bpweb.bp.com/EPT/home.asp?id=2603with templates available at

http://houston.bpweb.bp.com/ewp/integ_assest_model/integrat.htmIt has been well established that the capability of two-parameter equations of state, such as P-R, in predicting the liquid density can be improved by introducing the volume shift parameter. The method is particularly attractive because it does not change the predicted phase equilibrium, but affects the phase densities by shifting the volume axis. The accurate prediction of density is vital for tubing performance predictions. However, this technique is arbitrary and non-rigorous/unscientific. The inclusion of the third parameter in EoS, may deteriorate the predicted density at some conditions. This could occur for systems with high concentrations of supercritical compound(s), particularly methane. Moreover, using a constant shift parameter for light hydrocarbons, the phase densities cannot be predicted accurately.

With an accurate EoS, in theory, the properties of the mixture can, therefore, be calculated for any pressure and temperature.

Some of the specific issues concerning equation of state models are:

g) They may give the impression of being highly accurate. Like any model, they are only as good as data they are based on.

h) They are only valid for a fixed input composition. Although they are very good at predicting the phase to phase transfers vital for separator performance, they require a feed composition. Therefore, each EoS is only valid for a single GOR. They are, therefore, difficult to use for gas lift completions and any model where the reservoir GOR may change (e.g. gas cap expansion).

i) As the equations of state are often produced specifically for reservoir or facilities engineers, they may, therefore, be invalid for tubing conditions. This is particularly the case if they have been tuned excessively using volume shift or binary interaction coefficients. In the example below (refer to Figure 3.5), the bubble point is ridiculously high at low temperatures and may indicate other potential problems at likely conditions.j) It is known that many EoS models poorly represent the liquid density of fluids and errors of around 5% are commonplace. Errors in liquid densities would not significantly effect either reservoir models or most facilities models, but will seriously effect the tubing performance.

k) An EoS model is not particularly accurate at determining the viscosity of fluids. This can be improved by the entering of critical volumes for each component.

Figure 3.5 Example Of Unreliable PVT Caused By Excessive Tuning

1.4.3 Empirical Correlations - Untuned

Various correlations are available that attempt to predict a fluids properties based on the fluids oil and gas gravity, and the GOR. Each correlation has been designed for a particular range of fluids and is purely empirical in nature.

The correlations available in Prosper are:

Black Oil FVF, GOR

Glaso

Standing

Lasater

Vazquez-Beggs

Petrosky et al

Black Oil Viscosity

Beal et al

Beggs et al

Petrosky et al

Gas Viscosity

If a gas is chosen, all the condensate drop out is assumed to occur in the separator and not in the tubing. Therefore, any condensate hold-up problems cannot be analysed.

Lee et al

Carr et al

Any of these correlations can be used directly without tuning so long as the GOR and densities are known. It would be possible to examine each of these correlations in turn to see which correlation was developed to model a similar fluid to one in question, however, this implies a complete lack of understanding of the reservoir fluids. At the very least, the bubble point should be matched and the correlation chosen accordingly.

Retrograde Condensate

Prosper has its own Retrograde condensate empirical model that is capable of predicting fluid properties and condensate gas ratios (CGRs) below the dew point. Even more than a black oil model, this model is only realistic if it is matched to real conditions.

1.5 Inflow Performance

Efficient well design requires a proper understanding of the reservoir inflow performance (IPR) and of how it is affected by the near wellbore completion. Completion, well kill and workover techniques that minimise damage or enhance performance should be adopted, especially where the objective is to maximise well deliverability.

The attainment of a near optimum, or stimulated, IPR requires a proper understanding of the causes of skin effects and the application of techniques to avoid damage and to enhance flow efficiency, however, a trade-off must often be made between maximising deliverability and minimising operational problems, lifting costs and capital expenditure. Production forecasts must be adjusted to reflect resultant inflow capabilities. By quantifying the effect of the various options on near wellbore performance, it is possible to develop economic justification for improved operational procedures and completion methods, or for workover and stimulation operations.

Formation damage is a major cause of production deferment, therefore, by understanding the damage processes and associated risks, steps can often be taken to avoid damage at minimal cost to the overall development. Where well testing results indicate that damage has already occurred, analysis of the most probable causes allows more efficient design of measures to bypass, or remove, the damage.

Perforation is one of the most critical steps in the completion process, which can have considerable impact on the inflow efficiency. With the proper choice of perforation interval, charges, gun system type, perforating method and drawdown, it is possible to consistently get close to the idealised performance of an open hole completion, especially if tubing conveyed, underbalanced perforating techniques are used. However, to be cost effective, the designer must select a technique that is appropriate to meet with the production objectives and operational environment. Guidelines have been developed to aid the less experienced engineer in making these judgments.

Stimulation techniques, such as acidizing and fracturing, can be used to remove, or bypass, damage areas and to enhance the natural IPR. However, many stimulation treatments are expensive and involve a degree of risk, so that a basic understanding of the processes is required to select the most appropriate treatment. Design and operational procedures are discussed and quality control requirements stressed.

Sand problems plague many developments in shallow, unconsolidated formations and in over-pressured, shaley sands. The techniques to assess the risks of sand production and possible strategies to avoid the problem are, therefore, an integral part of development planning. Where sand control must be installed, cased hole gravel packing is usually selected. This completion technique will always impact on the wells inflow capacity; however, the degree of damage incurred depends heavily on the design and installation of the completion.

Part of the completion interval may, at some time, need to be isolated to prevent excessive gas or water production, (refer to section 14.8). Various mechanical and chemical techniques are available for this, and selection of the most appropriate option will impact, not only the costs, but also the probability of success. Thus, the design and modification of the near wellbore completion is a fundamental element of production engineering that can have substantial impact on well deliverability, completion and workover costs, and on the daily operating costs.

1.5.1 Radial Inflow Equation And Skin

The fundamental equation of liquid flow from the reservoir into the completion is the radial inflow equation or Darcy equation:

Equation 1Where:

Q=flow rate (bpd)

k=permeability (md)

h=reservoir thickness (ft)

Pr=reservoir pressure (psi)

Pw=bottom hole flowing pressure (psi)

B=formation volume factor or FVF (dimensionless)

=viscosity (cP)

re =drainage radius

rw =wellbore open hole radius

S=skin (dimensionless). The skin is a measure of any additional pressure drops that are present if the well

This defines the flowrate for a given pressure drop for a vertical well fully penetrating a reservoir interval with a constant pressure outer boundary. The skin is a catch all term for any additional pressure drop. The kh and skin can be determined from well testing data.

This equation can be simplified even further, if all the constants are grouped together:

Equation 2Where:

J=productivity index or PI.

These equations are only applicable above the bubble point and for oil wells.

In Prosper, this equation uses the Dietz shape factor and drainage area rather than the reservoir/no flow boundary radius. The Dietz shape factor accounts for the fact that the drainage area may not be circular. Each shape (round, square, rectangular etc.) will have its own number - for example a well in the centre of a circular drainage area has a Dietz shape factor of 31.6. A table of shapes and factors is included in the Prosper help files.

The skin combines various different aspects of the well performance:

Formation damage skin

Perforation skin

Partial completion skin (i.e. if not all of a reservoir interval has been completed)

Deviation skin

Stimulation effects

Reservoir heterogeneity skin

Multiphase flow effects

Darcy effects of sand or gravel filled perforations

Non Darcy (or turbulence) effects associated with any of the above

Note:It is not possible to treat any of these effects in isolation. For example a well perforated in a small proportion of the reservoir will make any poor perforation effects more pronounced.

More details on the inflow performance can be found in the BP Near Wellbore Performance Manual at:

http://aberdeen.bpweb.bp.com/dwo/documents/TS-D-008/default.htm1.5.2 Vogel Inflow Performance

This empirical equation is used for producing wells below the bubble point:

Equation 3Where:

Qb and Pb are a flowrate and a corresponding bottom hole bubble point pressure.

In order to use this correlation test data must be available.

1.5.3 Fetkovich

Equation 4Jo is the PI above the bubble point adjusted for any relative permeability effects. This empirical relationship has similar application to the Vogel IPR and should be used below the bubble point.

1.5.4 Jones

Equation 5This empirical equation is an expansion of the Darcy inflow equation to include rate dependent or non Darcy effects and is, therefore, applicable to oil and gas wells. The b term is the same for the Darcy equation. The a term accounts for the flow velocity:

Equation 6Where:

hp=is the completed interval.

Note:The Jones equation does not account for any flow convergence around perforations or for any case that is not a simple open hole completion.

1.5.5 Hydraulically Fractured Wells

A fractured well performance depends on getting the fluids to the fracture face and along the fracture. The first is dependent on the reservoir permeability and the fracture length, the second is more dependent on the fracture conductivity.

The (dimensionless) fracture conductivity (Fcd) is dependent on the fracture width and proppant permeability:

Equation 7Where Kf and K are the permeabilities of the proppant and reservoir respectively, Wf is the fracture width and Xf is the fracture half length (distance from the well to the tip of the fracture). Fracture widths are usually in the order of 0.15 to 0.75 inch. A fully effective fracture should have an Fcd > 10. Note: The permeability of proppant is much less under real conditions than measured in the laboratory due to compression, gel residues, fines entrapment, long term crushing, non Darcy effects or contamination. A useful rule of thumb is to reduce the lab derived permeability value by a factor of 10. The fracture width will also be reduced by embedment of the proppant into the rock. In severe cases, this can lead to a severe reduction in the effectiveness of the fracture and techniques for extending the width of the fracture to compensate (i.e. tip-screen out techniques) should be used.

The model used within Prosper is a transient model and accounts for the early time being dominated by fracture conductivity and the later time being dominated more by overall reservoir performance. An example of the effect this has is shown in Figure 3.6.

Figure 3.6 Propped Fracture Transient Performance Example

In this example, only after twenty days has the well settled down to close to steady state performance.

1.5.6 Horizontal Wells

Prosper uses three models for horizontal wells.

The first is the horizontal well model of Kuckuk and Goode. It assumes a horizontal well in a closed rectangular drainage volume bounded by sealing surfaces. The pressure drop in the wellbore itself is not accounted for. This is acceptable for cases where the drawdown is an order of magnitude greater than this frictional pressure drop.

The second model is similar except that a constant pressure upper boundary is assumed. This would be the case for a well with an active gas cap. Such a case will give higher productivities than an upper no flow boundary.

The third method allows for pressure drops along the completion interval itself. A number of horizontal well models are available including the preferred ones of Goode and Wilkinson2 and Kuckuk and Goode. Both of these formulations are valid even when the horizontal wellbore length approaches the length or width of the reservoir. The method of Goode and Wilkinson is less recommended when frictional pressure drops are included, but is preferred when friction is ignored (infinite conductivity). Note: In order to use Goode and Wilkinson with Infinite conductivity, set the roughness to 0 (this turns off friction), rather than assuming friction for a smooth pipe. The other horizontal well models are included for completeness and should not be used in practice.

1.5.7 Formation Damage

Productivity damage is one of the major causes of production deferment. Damage can be defined as any barrier to, or effect within the confines of the near wellbore area or wellbore completion interval, that causes lower productivity than would be expected from an ideal reservoir with an ideal completion. Hence, plugged perforations, screens or gravel packs, blocked pores due to solids or emulsions, reduced absolute or relative permeability, or increased water saturation in the near wellbore area, all constitute productivity damage.

The most common causes of damage are from drilling, completion and workover operations carried out under overbalanced conditions resulting in an influx of solids and fluids into the formation. The effects of this can be calculated for both open hole and perforated wells.

A detailed discussion on the causes of formation damage can be found in the Near Wellbore Manual found at:

http://aberdeen.bpweb.bp.com/dwo/documents/TS-D-008/default.htmDamaged can often be minimised or avoided by the use of solids free or non-damaging wellbore fluids, adopting underbalanced perforating techniques or alteration of produced fluid properties to prevent the formation of emulsions, solids precipitation, etc. and is preferred. Post-damaged formations can often be treated to reduce the damage by conducting stimulation operations such as bypassing (through perforating or fracturing) or acidising, scale removal, etc. (refer to section 3.6).

1.5.8 Perforation And Deviation Skin

Prosper uses three options for models to calculate the skin in a deviated, perforated well. Lockes method is the original model and is included in Prosper for completeness. Mcleods method includes an option of over or underbalanced simplification. The crushed zone permeability is reduced to 10% for over balanced perforating, and 40% for underbalanced perforating. This is rather arbitrary and a more detailed discussion is found in the subsections of the BP Near Wellbore Performance Manual including gun performance and perforating techniques which can be found at:

http://aberdeen.bpweb.bp.com/dwo/documents/TS-D-008/default.htmKarakas and Tariq is a more general technique and is recommended for most applications. It can deal with high deviations as long as radial flow is reached away from the wellbore and, therefore, the well is not too long in comparison to the reservoir.

The input data for Karakas and Tariq is rather involved. The possible provenances of the various data inputs are included in Table 3.1.

Perforation DiameterThis is the diameter in the rock (not the casing). It can be extracted from the gun vendor with a correction for the rock strength. Alternatively, the equation is , for deep penetrating charges.

Where:

D=the perforation hole diameter

UCS=is the unconfined compressive rock strength

EHN80=is the entrance hole diameter in N80 steel (available from perforation catalogues).

Shots per FootFor underbalanced perforating this will be the guns shot per foot. If overbalance perforating with dirty fluids, the open perforation may only be 0.1 - 0.25 the nominal shot per foot.

Perforation LengthThis is a property of the gun and charge, with corrections for confining stress and rock strength. These corrections are vital and the equations will be incorporated into Prosper but are available in THoR and from the gun companies. Typical numbers are between 12 and 24.

Damaged Zone ThicknessThis will depend on the mud and rock properties and how the wells are drilled. Typical values are 3 to 12. The actual value is not particularly critical so long as the perforations extend behind this. The actual thickness can be determined from filter cake tests on cores or estimated from filtrate depth of invasion calculated from mud losses but this is difficult to achieve in practice.

Crushed Zone ThicknessFrom CAT scans and thin sections of perforated core, this is typically 0.5" thick.

Crushed Zone PermeabilityAssuming an optimum perforation underbalance, this should be the same as the formation permeability, otherwise a figure of up to half the formation permeability can be used.

Shot PhasingThis is a choice for engineers. Low values (60 - 90 degrees) will normally give optimum perforation efficiency.

DeviationThis is also a choice for engineers.

PenetrationThis is the fraction of the wellbore that is open to flow. Prosper assumes that it is the top interval only that is completed, (i.e. from the top boundary of the reservoir downwards).

Vertical PermeabilityThere is some uncertainty around what figure should be used. In THoR and KT Perf, there was a natural division between short and large scale kv/kh. Short scale Kv/kh applied to the scale of the perforations i.e. on the scale of a few inches. Large scale kv/kh applied to the effects of anisotropy on the deviation or partial penetration skin. Prosper assumes that the large and small scale kv/kh are the same. In a vertical fully completed well, the small scale kv/kh should be used, but in a high angle or partially completed well, the large scale effects may be more important and the lower large scale kv/kh should be used. Therefore, some judgment is required in order to pick the correct vertical permeability. This anomaly should be corrected when the method of Wong and Clifford is included in Prosper v.6.

Wellbore RadiusThis is the drilled open hole radius.

Table 3.1 Prosper Perforating Input Data

1.5.9 Multiple Zone Completions

Prosper has various options for looking at multizone completions. It can, either, include or exclude the frictional pressure drop between each zone. Note: That although crossflow is included, it is only in the wellbore and no fluid flow is allowed between different layers in the reservoir.

1.5.10 Gravel Pack Completions

Prosper can handle, both, cased and open hole gravel packs. It can also deal with open hole completions with sand control but no gravel. The subject of gravel packing cannot be dealt with in detail here, only the basic drivers on productivity and how to calculate it for a gravel pack completion. The BP sand control guidelines contain much more detail at:

http://upstream.bpweb.bp.com/EPT/home.asp?id=42301.5.10.1 Cased Hole Gravel Packs

A cased hole gravel pack is where screens are installed in a cased and perforated well. Gravel is pumped to fill the volume between the casing and the screen and also, critically, the perforations.

The cased hole gravel pack pressure drops include those of a cased and perforated completion, (i.e. phasing, perforation length and crushed zone permeability all have a contribution to the pressure drop). However in addition, there will be a substantial pressure drop through the gravel in the perforations and in the gravel between the casing and the screen.

The model is for cased hole gravel pack pressure drops, therefore incorporate the perforating parameters discussed in 3.5.7. The following variables are required for the pressure drops in the gravel:

l) Gravel pack permeability (this can be extracted from the table Table 3.2, although due allowance must be given to downhole conditions, e.g. any debris or compaction).

m) Perforation diameter, this is critical and the reason why big hole charges (1 diameter) are preferred.

n) Shots per foot, again this is critical 12spf is preferred (dependent on liner size).

o) Gravel pack length - in Prosper this is the distance from the sandface (not the casing) to the screen OD. This means that the liner size is not included in any of the calculations and, therefore, the validity of these calculations.

p) Perforation interval

q) Perforation efficiency

US Mesh RangeSieve Opening (mm)Permeability (Darcy)

6/102 3.362703

8/121.68 2.381696

10/200.84 2.00652

12/200.84 1.68630

16/300.589 1.19250

20/400.42 0.84171

40/600.25 0.4269

50/700.21 0.29745

Table 3.2 Gravel Pack Permeability (for clean, uncompressed gravel)

Note:The criticality is getting a large number of large diameter perforations filled with high permeability gravel. In the event that the perforations are not effectively packed, they will fill with reservoir sand. The permeability of the loose reservoir sand is likely to be much lower than properly sorted and clean gravel.

1.5.10.2 Open Hole Gravel Pack

An open gravel pack is where a screen is installed across open hole and the volume between the screen and the open hole is packed with gravel. The same model can also be used to model an open hole sand control completion where the formation collapses around the sand screens.

The productivity of an hole gravel pack will be dependent largely on the permeability of the gravel or formation sand. If there is no gravel and the formation is heterogeneous, the collapsed sand may contain significant fines or clay and the permeability will be reduced as well as these fines potentially plugging the screens.

1.6 Stimulation

Stimulation involves reducing the skin by removing, or bypassing, damage or improving the wells ideal IPR by creating an enlarged contact area between the wellbore and formation. As stated above, formation damage is much easier to avoid than remove so many of the more sophisticated mud acid stimulations are unnecessary incremental investments to compensate for poor design and execution of the near wellbore completion, or of well kill or workover operations. Often attempts to achieve relatively minor cost reductions in these operations (e.g., by not filtering base fluids) result in significant damage that causes production deferment and necessitates much more costly and risky remedial treatments.

As shown in Figure 3.7, the fact that a well has high deliverability does not necessarily imply that it is undamaged. Conversely, if the offtake is limited by reservoir or regulatory requirements, it may be possible to achieve the target by reducing the wellhead pressure and thus deferring stimulation until increasing water cuts or pressure depletion mean that the target is no longer attainable by natural flow. Therefore, wells with deliverability close to, or just below, their production targets are often excellent candidates for testing and acidisation. Moreover, as shown in Figure 3.7 discussed in the Near Wellbore Manual, re-perforation is often an alternative to acidisation.

Figure 3.7 Prosper Analysis Of The Effect Of Damage, Re-perforation, Acidisation On Well DeliverabilityThe three most common stimulation techniques are:

Acidizing

Propped fracturing

Acid fracturing

Acidizing is intended to remove damage in the near wellbore area, thus potentially reducing the skin factor to around zero (+1 to 3).

There are a number of chemical treatments which can be used singly or in combination to remove damage. These include:

Organic solvents to remove wax and asphaltenes.

Hydrochloric acid (HCl) to dissolve calcium carbonate, dolomite and iron compounds or to break gels.

Hydrochloric acid (HCl/HF) to dissolve fines and clays in the near wellbore area (10%) of swelling or migrational clays loosely attached to the sand grains; or where the well fluids were of poor quality. However, some of these shaly, or dirty, sandstones exhibit a migrating fines problem, especially during initial clean-up and water breakthrough (this is often termed natural damage), which necessitates a regular programme of periodic acid stimulations.

Naturally fractured and high permeability carbonates nearly always require a clean-up acid job to bypass deep drilling and perforation damage and to fully reopen the fractures. Once this is removed, they will demonstrate a natural negative skin (-2 to -5).

Low permeability reservoirs (kgas 150F). Only small volumes of acid are generally required for dissolving carbonate scale (100gal 15% HCl per ft3 of scale). Treatment of scales with a solvent, as well as acid, may be necessary where scale and wax or asphaltenes have been deposited together.

It is important to remember that many scales are not acid soluble and, therefore, it is essential that samples be analysed before designing a treatment.1.6.2.3 Matrix Acidising Of Sandstones

Most books and papers on matrix acidizing in sandstones focus on the removal of clays and fines from the immediate wellbore areas with mud acid (HCl/HF). As discussed in 3.5.7, this type of damage is mostly caused by:

Solids invading the pore structure due to poor quality wellbore fluids or filtercake.

Destabilization of the native clays by the invading fluids and filtrate.

Transportation of migrating clay particles into the wellbore area during clean-up or water breakthrough.

The problem is most severe, and most difficult to treat, in low permeability (10%) content formations, like those found in many deltaic depositional environments (e.g. Gulf of Mexico, South East Asia, etc).

When fine materials and clays are trapped in the pore throats, they usually have to be at least partially dissolved with hydrofluoric acid (HF) in the form of mud acid (HCl/HF) or fluoboric acid (HBF4). Regular mud acid has a concentration 12% HCl and 3% HF and is most successful in well consolidated sands with high quartz-to-clay ratios.

However, poor acid response was noted in many shaly, weakly consolidated formations. Therefore, in recent years, there has been a tendency to use lower strength mud acid (6.5/1.0) or fluoboric acid (0.1 to 0.2% HF) in formations containing large amounts of shale. Straight HCl is also widely used for formations containing large amounts of acid soluble material and in situations where the purpose is to dissolve acid soluble lost circulation material.

An acid selection guide for sandstone acidizing, based on the permeability and clay content of the formation has been compliled:

HCl Solubility 20% 15% HCl only

Removal of Acid Soluble LCM 15% HCl only

High Permeability (100md or more)

High quartz (80%), low clay (20%) 13.5% HCl and 1.5% HF*

High clay (>10%) 6.5% HCl and 1% HF**

High iron chlorite clay 3% HCl and 0.5% HF**

Low Permeability (10md or less)

Low clay (2.2), or to complex the iron into solution. Commonlyused additives include:

Acetic acid (T