Section 13 Fluid Guidelines

BP Exploration Section 13 – Completion Fluid Guidelines & Well Debris Management

SECTION 13

COMPLETION FLUID GUIDELINES & WELL DEBRIS MANAGEMENT

Prepared By:

Peter Wilson Doug Davidson

Date: Revision: 1 Reviewed By:

Darly Kellingray Paul Adair



CONTENTS Page 13

COMPLETION FLUID GUIDELINES & WELL DEBRIS MANAGEMENT

1

13.1 SUMMARY 13.2 INTRODUCTION 13.3 COMPLETION FUID GUIDELINES 13.3.1 Planning For Completion Fluid Selection 13.3.2 Function And Properties

1 1 1 1 4

13.3.2.1 Density 13.3.2.2 Crystallisation Temperature

13.3.3

Corrosion

13.3.3.1 Carbon Dioxide 13.3.3.2 Hydrogen Sulphide 13.3.3.3 Packer Fluids

13.3.4 13.3.5

Components Of Completion Brines Formation Damage

13.3.5.1 Formation Damage Mechanisms

13.3.6 13.3.7 13.3.8 13.3.9 13.3.10 13.3.11

4 4

5 5 5 6

6 6 7

Scale Emulsion Block pH Brine Selection Use Of Drilling Fluids For Completions Fluids For Sand Screen Installation

9 9 9 10 10 11

13.3.11.1 Conditioning 13.3.11.2 Special Grade Weighting Agents 13.3.11.3 Displace To An Appropriate Brine 13.3.11.4 Displace To A Solids Free Mud 13.3.11.5 Displace To Solids Free Inert Emulsion

11 12 12 12 12

13.3.12 Completion Fluids For Gravel Packing 13.3.13 Completion Fluids For Hydraulic Fracturing 13.3.14 Common Completion Fluid Contaminants

13 13 13

13.3.14.1Polymers 13.3.14.2Crude Oil and Condensate 13.3.14.3Solids

14 14 14

13.3.15 Control Of Downhole Losses

14

13.3.15.1Solids Free HEC Pills 13.3.15.2Bridging Solids

13.3.16 Brine Losses While Running Sand Control Screens 13.3.17 Brine Losses While Gravel Packing 13.3.17.1Gravel Pack Sand 13.3.17.2Mechanical Fluid Loss Control While Gravel Packing 13.3.17.3Kill Pills

13.3.18 Field Preparation/Handling Of Completions Fluids 13.3.18.1HSE 13.3.18.2Brine Formulations

13.3.19 Brine Cleanliness 13.3.19.1Filtration

13.3.20 Brine Recovery 13.3.21 Brine Discharge

14 15

17 17 17 17 18

18 18 18

19 19

20 20


13.3.22 Displacement Techniques 13.3.23 Displacement Procedures 13.3.24 Cementing In Completion Brines 13.4 WELLBORE CLEAN-OUT GUIDELINES 13.4.1 Sediment/Debris 13.4.1.1 Sediment 13.4.1.2 Debris

13.4.2

Problems Caused By Sediment/Debris

13.4.2.1 13.4.2.2 13.4.2.3 13.4.2.4 13.4.2.5 13.4.2.6

13.4.3 13.4.4 13.4.5 13.4.6

Wireline Packers Packer Seal Units/PBRs Control Lines Tubing Hangers Formation Damage

Aims Of A Wellbore Cleanout Objectives Of A well Clean-Out Clean-Out Design Pill Design

13.4.6.1 Risks And Issues 13.4.6.2 Best Practices and Design Criteria

13.4.7

Procedures

13.4.7.1 Pits And Surface Lines 13.4.7.2 Downhole Clean-Out

13.4.8

Chemical Removal

13.4.8.1 Brine Cleanliness Measurement

13.5 REFERENCES

20 22 22 23 23 23 24

24 24 24 24 25 25 25

25 26 26 27 27 27

28 28 28

30 31

32


1 1.1

COMPLETION FLUID GUIDELINES & WELL DEBRIS MANAGEMENT Summary

This section describes the various issues regarding the use of fluids and obtaining good wellbore clean-out to ensure the successful installation of completions. It describes the potential damage mechanisms from exposure to foreign fluids and describes the planning, selection and preparation of these fluids accompanied with an appropriate checklist. It also provides guidelines for wellbore clean-out which is essential to obtain trouble free completion installation.

1.2

Introduction

For many years wells were completed overbalanced with mud, or at best dirty brine, in the hole. Many wells were badly damaged by this process but often the damage could be overcome by perforating. In the modern oilfield open hole completions are very common. In such operations any damage that occurs during drilling and completion is not perforated past and attempted removal can only be made by costly remedial treatments. Clearly it is preferable that the damage does not occur in the first place. This led to the widespread use of specifically designed ‘drill-in’ fluids and ‘clean’ brine completion fluids. If the correct fluids and procedures are utilised during the drilling of the reservoir and the completion of the well, damage can be controlled to acceptable values. This chapter outlines the major factors that must be considered when selecting a low damage potential completion fluid. It should, however, be noted that no matter how much care is taken to optimise open hole completion operations this will not undo damage caused during the drilling phase. The same attention to detail must be made when selecting the reservoir drill-in fluid for planned open hole completions. In terms of well productivity, the majority of the completion fluid related issues discussed can equally well be applied to drill-in fluids. Another important fluids issue is debris left in the hole after the drilling and casing of the hole since this can lead to problems installing the completion and during well interventions. Debris can lead to the malfunctioning of completion equipment, prevent equipment reaching planned depths, premature setting of the packer, inability to set tubing hangers, plugging of tubulars, etc. During well interventions debris can result in problems with stuck plugs and toolstrings or hang-up while running in hole. These problems can lead to large amounts of lost time and, hence, high costs. It is essential that the hole is properly cleaned to permit completion installation. The aim of this chapter is to provide sufficient background information and practical guidelines to the engineer in the field to assist him/her to avoid potential problems resulting from inappropriate completion fluid selection and implementation and/or hole cleaning procedures.

1.3

Completion Fuid Guidelines

1.3.1 Planning For Completion Fluid Selection The following table represents a check list that should ensure that all aspects of completion fluid design are addressed in the planning stage. The issues mentioned briefly within this table are discussed in detail in other parts of this section.

Page 1


Subject

Density

Density

Density/ Crystallisation Temperature

Chemistry

Issue Fluid density must be sufficient to provide the required hydrostatic pressure at the reservoir. Effects of temperature and pressure on downhole density must be considered. Having determined the required density, ensure that the selected brine can readily be weighted beyond the anticipated requirement so that unforeseen pressures can be addressed. Don’t select a brine that is right at the upper limit of its maximum density. e.g. don’t select sodium chloride if 10.0ppg brine is required unless a more soluble salt (e.g. sodium bromide) is on hand to allow a density increase to be made. Ensure that the candidate brine has a workable crystallisation temperature for the lowest anticipated temperature to which it will be exposed. To avoid formation damage, the candidate brine must be compatible with formation water chemistry.

Chemistry

To avoid formation damage, the candidate brine must be compatible with pore lining clays

Chemistry

Bore hole stability of exposed clay/shale sequences within the reservoir.

Further Information

Data Requirements

Either a BP Fluids Experts or drilling fluid service provider will be able to provide this data.

BHP, BHT and required overbalance pressure.

Consult with either BP Fluids Experts or drilling fluid service provider to determine appropriate brine type.

Maximum required ‘safety margin’.

Either BP Fluids Experts or drilling fluid service provider will be able to provide this data.

Lowest anticipated temperature – this is usually the anticipated wind chill temperature in the riser.

BP Fluids Experts will be able to offer advice on this. Laboratory testing may be required. BP Fluids Experts will be able to offer advice on this. Laboratory testing (XRD and return permeability testing). may be recommended. Note: this is a lengthy procedure and may take up to three months to get all the results. Be sure this is initiated early in the planning programme Either BP Fluids Experts or drilling fluid service provider will be able to offer advice on this. Laboratory testing may be required.

Table 13.1 – Completion Fluid Check List

Page 2

Formation water analysis, BHT, BHP.

Information on clay types within the reservoir. If this is not available representative preserved core will be required

Representative shale samples, brine sample.


Subject

Issue

Metallurgy

Corrosion of down hole tubulars particularly at HT conditions and/or if acid gases are anticipated.

Cleanliness

Solids in brines can cause formation damage or prevent efficient operation of downhole tools.

Sand Control Screen Blocking

Sand control screens run in solids laden fluid can become blocked.

Downhole losses

Uncontrolled loss of completion fluid. Commonly associated with mechanical damage to down hole filter cake when running liner/screens.

Elastomer Compatibility

Lubricity

HSE

Completion fluids, notably divalent brines and oil based fluids, can cause elastomer components of tools to deform.

In highly deviated or tortuous well paths the poor intrinsic lubricity of most brines may prevent the completion reaching bottom.

For a given density some brines have better HSE profiles than others.

Further Information BPs metallurgy experts can provide advice. Autoclave testing may be recommended Note: this is a lengthy procedure and may take up to three months to get all results. Be sure this is initiated early in the planning programme. Drilling fluid service provider and filtration experts can provide advice. Refer to section 1.4 ‘Wellbore Clean up Guidelines’. Either BP Fluids Experts or drilling fluid service provider can proved maximum particle size that can be tolerated. Laboratory testing (mud flow through screens) should be performed Design low damage LCM pill. This should be tested for formation damage/ screen plugging potential. BP Fluids experts should be consulted. There is much published data regarding compatibilities of common oilfield elastomers. If the particular elastomer/fluid combination cannot be found testing will be required. BP’s Fluids Experts can provide information on this. Run torque and drag model with worst case friction coefficient. This can be done by BP in-house experts. Consider addition of lubricant. If this is required formation damage implications must be considered. Candidate lubricants can be evaluated in Sunbury. Consult with the brine supplier to determine best option for a given density. In general, the most benign fluid is preferred. There may be commercial issues to address.

Data Requirements

BHT, BHP, proposed brine type, candidate metallurgy, nature of reservoir fluids.

Mud samples and sand screen characteristics.

Reservoir pore size distribution, sand screen type and gauge. Representative, preserved core.

Elastomer samples, BHT, BHP at relevant depth. Completion fluid sample.

Well geometry data, brine sample, lubricant sample.

Table 13.1 – Completion Fluid Check List (Continued) Page 3


1.3.2 Function And Properties The specific properties required from a completion fluid will vary with the formation type, pore pressure, the reservoir fluid and type of operation. Factors which are critical during a completion operation may not always be as important in a drilling operation where the filtercake may prevent significant loss of the fluid to the formation. Similarly, a fluid may cause severe damage in one particular type of formation and be totally benign in another. The main function of a completion fluid is to control the formation pressure while exhibiting low formation damage potential and acceptable corrosivity. In certain operations such as gravel packing the fluid must also have the ability to transport solids. An acceptable HSE profile is also desirable. 1.3.2.1 Density Density is the single most critical property of a completion fluid, as the fluid column in the wellbore is often the primary means of well control. The density of the fluid has to be carefully selected to provide sufficient hydrostatic head to control the formation pressure. Brines are the preferred option as completion fluids as the required density can be achieved without the addition of any insoluble solids. Solids free fluids are preferred as they provide a stable density, avoid solids invasion of the formation and reduce the potential for solids settlement on top of downhole tools. A simple calculation of brine density requirement is given in the following equation: Density (lb/gal)

=

Pressure (psi) 0.052 x vertical depth (ft)

It is important to note that any density determined from the above equation is the average density required to just balance formation pressure based on BHP at TVD. Brine density is a function of both temperature and pressure. As the temperature of the brine increases, the volume increases and, hence, the density falls. Conversely a decrease in temperature will cause an increase in density. The effect of pressure is the opposite, i.e. density increases with increasing pressure and, to some extent, tends to compensate for the temperature effect, although in most downhole applications the temperature effect is dominant. Ignoring the effects of temperature and pressure and simply using the measured surface density will generally result in less hydrostatic pressure at the bottom of the well than predicted. Fluid specialists in BP and service companies utilise computer programmes to provide an accurate analysis of the effects of temperature and pressure on brines. These programmes can calculate the required surface brine density that will provide the required hydrostatic pressure for any particular situation. 1.3.2.2 Crystallisation Temperature Three temperature values are used to describe a brine’s tendency to crystallise:   

First crystal to appear (FCTA) True crystallisation temperature (TCT) Last crystal to dissolve (LCTD)

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The True Crystallization Temperature of brine is the API prescribed method for quantifying crystallisation temperature. When specifying the crystallization temperature of brine, the TCT should be close to the minimum expected ambient surface temperature to avoid the following problems:  

Lowering of the density of the solution as crystals form at surface which could lead to pressure control problems. If the salt starts to crystallize, it can quickly plug valves and lines resulting in costly delays.

It should be noted that the lowest temperature that a brine may be exposed to is often in the marine riser where wind chill factors come into effect. Should a brine give indications that it is close to crystallisation the brine should be diluted with drill water and the density increased to its required level with a more soluble salt. For instance should a calcium chloride brine begin to crystallise it should be diluted with 5% drill water and re-weighted with calcium bromide. 1.3.3 Corrosion Common soluble salts (e.g. sodium, calcium and potassium chloride) will increase corrosion rates due to increased conductivity of the brine relative to freshwater. This is true up to a limiting point, above which an increase in salinity may reduce corrosion rates due to lower oxygen solubility. For example, the highest corrosion rates occur in sodium chloride when the chloride concentration is approximately 20,000mg/lt, which is roughly equivalent to the salinity of seawater. Severe corrosion is usually caused by a combination of salinity and the presence of a gas, commonly oxygen but carbon dioxide and hydrogen sulphide may both be present in reservoirs and, therefore, capable of solution in the completion brine. Corrosion Guidelines can be found on the BP Website at: http://drilling.bpweb.bp.com/wp/downhole/ and also in section 6 of the Completion Design Manual. 1.3.3.1 Carbon Dioxide The presence of CO2 in a completion brine can lead to the formation of carbonic acid which will directly attack metal surfaces. The type of corrosion occurring will predominantly be pitting corrosion. This is a particularly damaging form of corrosion as the pits formed can act as stress raisers resulting in the initiation of fatigue. Corrosion inhibitors can be used to reduce the impact of carbon dioxide corrosion, however reference should be made to the comments below on the use of corrosion inhibitors. 1.3.3.2 Hydrogen Sulphide H2S dissolved in brine can react with steel surfaces, producing an iron sulphide scale which can result in deep pits in regions where the scale is breached. This form of corrosion is not common unless very high concentrations of H2S are present, however it can be exacerbated by the presence of dissolved oxygen. This can be minimised by the use of an oxygen scavenger and pH control. Of greater importance is the mechanism known as sulphide stress cracking (SSC). This can lead to a brittle-like fracture, which can occur quite quickly and without warning.

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Some brines are more corrosive than others and long term autoclave testing should be performed on candidate brine/metal combinations, particularly for critical wells, (e.g. HTHP or when the presence of acid gases is anticipated). 1.3.3.3 Packer Fluids Completion brines are often converted for use as packer fluids. In this case, where the fluid is isolated from formation fluids and gases, corrosion rates tend to be low after any dissolved oxygen has been depleted by reaction with the casing. This initial corrosion tends to be of the general kind with only a small weight loss across the entire area of the steel occurring. Basic corrosion treatment should be made to minimise this; increasing the pH and adding oxygen scavenger is usually sufficient. Filming type corrosion inhibitors should be used with caution. Inorganic inhibitors (e.g. chrome based) are anodic inhibitors. That is to say they inhibit corrosion by reducing the anodic reaction but do not affect the cathodic reaction. Such inhibitors can cause severe localised corrosion and actually accelerate the corrosion process if present in insufficient quantities to provide complete filming. BP have corrosion specialists who should be consulted prior to use of this or other types of filming chemicals. 1.3.4 Components Of Completion Brines The following Table 13 .2 identifies the main components of completion brines and briefly discusses the function of each component. 1.3.5 Formation Damage Formation damage that occurs during completion and workover operations is particularly critical in that it usually cannot be overcome by perforating and remedial treatments can be difficult and expensive. The selection and correct preparation and handling of completion fluid is, therefore, often fundamental to the well’s success. Formations with good permeability, will not only have good productivity, they will also freely take fluids from the wellbore. If the fluid entering the pore spaces is not compatible with both the formation clays, and the formation fluids, formation impairment will ensue. Tighter formations may be less likely to take fluid in, however small changes within the pore structure can have greater significance on permeability than in more permeable rock. If the formation has extremely poor permeability, then it is unlikely to be produced without hydraulically fracturing the formation and the selection of drilling fluid is not as critical. However, the selection of the frac and completion fluid is just as important as in non-fractured completions as these fluids will almost certainly, come into intimate contact with the reservoir at some stage. Information regarding this subject can be found on the BP Formation Damage Website at: http://damage.bpweb.bp.com/

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Component

Function

Drill Water Soluble Salt Caustic Oxide

Soda,

Bridging Agents

Corrosion Inhibitor

Lubricant

Defoamer

Biocide Flocculants

Clay Inhibitors

Magnesium

Base fluid for brine. The use of seawater should be avoided as it contains cations and anions that may form insoluble salts when mixed with formation brine. Salts are added primarily to increase density. They may also function as clay inhibitors Used to increase pH and thereby reduce corrosion rates. Excessively high pH values (>9.5) should be avoided as this can mobilise fines within the reservoir. Used to control loss of the completion fluid to the reservoir. Bridging is often critical in minimisation of formation damage. Selected products should be soluble in either acid, water or oil dependent upon the specific application. These are often cationic polymers which work by attaching tenaciously to surfaces of tubulars. This tenacious attachment can also occur on the surface of pore linings causing productivity impairment. When there is a possibility of the brine coming in intimate contact with the reservoir, corrosion inhibitors should only be used after low damage potential has been confirmed by core flood work and after their effectiveness as inhibitors has been confirmed with BP’s corrosion experts. These are added to reduce the coefficient of friction of brines to facilitate running of the completion in deviated wells. These are used to break down foam in surface pits. They can also be used as anti-foam additives when adding corrosion inhibitor or other surface acting treatments which can cause excessive foaming. Defoamers should not be added until there potential effect on well productivity has been verified as acceptable. By their very nature they are, if present in sufficient concentration, liable to alter the surface characteristics of the reservoir rock. Can be added to inhibit bacterial activity, particularly in packer fluids. However, if the brine is sufficiently saline, bacterial activity is unlikely Flocculants are occasionally used to aid in the solids removal and filtering processes. These chemicals should be added very sparingly and with good agitation. Overdosing may result in formation damage. May be required in low density brines to improve inhibition of both pore lining clays and any shales that are exposed in the well bore. Typical clay treatments used in brine are organic nitrogen derivatives which can be added directly to the brine at surface. The effect of such products on the reservoir permeability should be determined by return permeability core floods.

Table 13.2 – Components Of Completion Brines 1.3.5.1 Formation Damage Mechanisms There are many factors that can cause formation damage; the most common mechanisms are outlined below. To ensure that damage is limited to acceptable levels all of these issues must be addressed when selecting the completion fluid and associated pills. Planning should commence at an early enough stage to allow return permeability testing to be conducted. When considering this it should be recognised that formation damage testing is a lengthy process often taking two to three months to get complete results. Pore Lining Clays Clay Swelling Water sensitive clays such as montmorillonite and mixed layers clays can expand when exposed to fresh or low salinity water. Changes in salinity will bring about changes in hydration and changes in the forces between the clay particles. Cations, dependent on their charge, can alter expansion characteristics and inter-particle bonding of expanding clays. Therefore, it is to be expected that any change in the composition of the pore fluid will cause a change in the physical arrangement of the clay particles either through physical effects or through physico-chemical effects which can change inter-particle energies. Page 7


When this swelling occurs the clay lattice will occupy more space in the pore throat or may become fragile and prone to migration and subsequent plugging of the pore throats. Once this type of damage occurs it is irreversible. Laboratory work has shown that a great variation in salinity from that of the formation water can cause clays to either swell or be mobilised. Freshwater filtrate will in almost all cases cause some damage in rocks containing swelling clays. However, extremely high salinity brines can also cause problems in rocks with lower salinity formation water. If, however, the invading fluid has the correct ionic composition, i.e. close to the salinity of the formation water, the clays will remain in equilibrium and the likelihood of migration will be greatly reduced. Fines Migration Fine particles within the pore structure of reservoir rock can be mobilised by fluid flow when the Critical Fines Migration Velocity is exceeded. The force exerted on the particles by fluid velocity and viscosity can cause aggregated particles to become mechanically separated. The particles are then free to migrate to pore throats where they can become lodged resulting in a decrease in the permeability of the rock Wettability Changes Relative Permeability Effects Many sandstone formations in their natural state are water wet, that is, the surface of the sand grains is coated with a layer of water and the hydrocarbon phase resides in the pore space in equilibrium with the water coated grains. As fluids move, the oil phase will tend to slip along the water boundary leaving the water attached to the sand surface. However, if fluids containing oil wetting surfactants (oil mud surfactants, corrosion inhibitors, emulsion inhibitors, mutual solvents etc) or surface tension reducers invade the formation, the water wet nature of the rock can be changed reducing the efficiency of oil flow through the rock. Increase in Water Saturation When water or brine based filtrates invade the near well bore region water saturation is increased. This can greatly reduce the relative permeability to hydrocarbon. This effect is generally temporary as the invading filtrate is often back-produced when hydrocarbon flow is initiated. However, more permanent damage can result if:  

The invading filtrate contain any products that can cause wettability changes The reservoir is low pressure or of very low permeability. Capillary forces can be set up that will not allow the invaded filtrate to be cleaned up. Capillary pressures are inversely proportional to pore radius so in tight formations very high pressure may be required to displace filtrate from the near well bore. This effect is known as water block. This can be avoided by using oil based muds, however the potential adverse effects of OBM surfactants must be considered. Another approach that has been put forward is to reduce the surface tension of the water based filtrate or brine by the addition of fluorosurfactants.

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Polymer Invasion There are three major mechanisms related to polymer invasion that can result in formation impairment:  



Any polymers included in a fluid that contacts the reservoir can become attached to pore walls and reduce the absolute permeability of the rock. Polymers are added to increase the viscosity of brine for various operational reasons. (These viscous fluids are more difficult to clean up on hydrocarbon production and long term impairment can result. When planning such operations, it is important to confirm that a viscosity breaker will work and that the residual viscosity is low enough to allow the well to clean up.) Any unhydrated polymer (fish eyes) can enter pore spaces and swell with time to such an extent that severe permeability reductions can occur.

1.3.6 Scale The composition of formation brine can vary significantly and if the completion brine contains incompatible ions, the mixing of the two fluids can result in the precipitation of water insoluble salts. The degree of damage resulting from this is dependent on the nature and size of the precipitated particles and the type of formation. The most common incompatibilities occur between carbonate species in formation waters and divalent cations, particularly calcium, in completion brines. Another common form of insoluble scale is the reaction between calcium in formation brines and sulphates present when seawater is used as the completion brine. 1.3.7 Emulsion Block Filtrate lost to the formation can form emulsions. This may be either WBM filtrate with crude oil or OBM filtrate with formation brine. Emulsions generally only form if some surfactants are present in the system. Natural surfactants may be present in crude oil and manufactured surfactants are ever present in oil based mud filtrate. Laboratory testing can be performed to evaluate the risk of emulsion blocking. Remedial action is available in the form of mutual solvent squeezes, (e.g. EGMBE), which are effective emulsion breakers. Emulsions can also be created during the acidization of waxy or asphaltic crudes with a poorly designed fluid. The compatibility of acid with crude oil should be checked using API RP 42 guidelines. 1.3.8 pH High pH values should be avoided in completion brines as this can have an affect on the base exchange equilibrium of pore lining clays which may in turn cause them to migrate and block pore throats. Rocks that have amorphous silica as matrix cement can be adversely affected by high pH. The silica is dissolved and fines may then be released and available for migration to pore throats. To reduce corrosion rates it is desirable to increase pH values in packer fluids when there is no chance of contact with the reservoir.

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1.3.9 Brine Selection Once the required density has been determined the range of candidate brines capable of achieving that density must be examined and the final selection made based on:       

A workable crystallisation temperature at the required density Low formation damage potential Acceptable corrosion characteristics Acceptable HSE profile Shale inhibition (if required) Elastomer compatibility Commercial acceptability

These issues are discussed in detail below. The following chart shows the maximum working density for the more common brines.

Figure 13.1 – Maximum Working Densities 1.3.10 Use Of Drilling Fluids For Completions On occasion, wells are completed in drilling fluid. This may be commercially advantageous and may also offer benefits in terms of control of downhole losses, as mud possesses filter cake building properties that brines do not. Formation damage potential should already have been determined to be low prior to its use as a drilling fluid. There are, however, still significant risks attached to using mud as a completion fluid; these are:   

Inability to operate downhole tools due to solids settled out of the mud. Inability to operate downhole tools due to mud gelation. Loss of well control due to barite sag initiated by low shear conditions generated while running the completion. Page 10




Plugging of perforations by mud solids.

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These risks can, to some extent, be mitigated against by careful planning:  

The mud can be treated to minimise gelation and barite sag. Perforate under balance to avoid plugging perforation channels.

There are risks attached to the use of a suspended salt mud as a completion fluid particularly if it has previously been used to drill through shales or claystones. Conventional solids removal is not practical when using suspended salt systems because the costly salt is removed along with drilled solids Reactive drilled solids accumulate in the mud whenever shale sections are drilled. These solids will be incorporated in the filter cake and may also penetrate the formation. 1.3.11 Fluids For Sand Screen Installation Sand control screens can easily become plugged with solids if great attention is not paid to completion fluid solids content. The methods described below are those currently used to achieve successful deployment of sand screens. 1.3.11.1 Conditioning Always condition the drilling fluid prior to running the screens. There is a real risk associated with running sand control screens in mud. Typical solids size distribution in a drilling fluid will readily plug screens as they are run through the mud. To avoid this, the mud is commonly circulated over fine shale shaker screens. This conditioning of mud over fine shakers screens should remove sufficient solids to allow screens to be run successfully in light weight muds. Fine screen conditioning of heavy mud is not practical as much of the barite would be removed by shale shaker screens finer than 230 mesh. A piece of test equipment has been designed to determine when the mud has been conditioned to a suitable specification. These Mud Flow Through Screens (MFS) test kits are available for rig site use. These are used to determine when adequate solids have been removed to allow sand screens to be run without becoming plugged. The following table provides data on the aperture sizes of conventional, square mesh shale shaker screens and the nearest equivalent sand screen gauge. Reference should be made to the shale shaker screen manufacturer’s specification for other screen types. However, as a rule of thumb, the maximum solids size remaining in the mud after conditioning should be less than one-third the width of the openings in the sand control screen if plugging is to be avoided. Thus in this table when running a 6 gauge screen filtering with 325 mesh shaker screens is recommended. Shaker Screen Mesh

Aperture um

Sand Screen Gauge

Sand Screen Aperture um

100 x 100 120 x 120 150 x 150 200 x 200 250 x 250 325 x 325

140 117 105 74 63 44

6 5 4 3 2 1

152.4 127.0 101.6 76.2 50.8 25.4

Table 13.3 – Shaker Screen Size/Aperture Size

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The apertures given above are for dry wires. When the shale shaker screens or the sand screens are wet with mud the apertures may be significantly smaller. Determination of the actual size of solids passing through a particular shale shaker screen can readily be determined by particle size analysis of the underflow. 1.3.11.2 Special Grade Weighting Agents The conditioning of mud as described above can be time consuming and, therefore, an expensive operation. The use of a fine grade weighting agent such as micronised barite or Micromax can avoid the requirement for fine screen conditioning other than to remove drilled solids. There are risks attached to the use of these fine products as the may create high rheology and they also have formation damage potential. Both of these issues would need to be addressed prior to applying this technology. 1.3.11.3 Displace To An Appropriate Brine This removes the problem of solids blocking of screens completely. There is, however, another risk attached to this approach. It is easy to mechanically damage filter cake when running screens. Clear brines do not have any filter cake building properties so loss of large volumes of brine could occur. This would then require an LCM pill to be spotted which, in itself, introduces a risk of plugging the sand screen. 1.3.11.4 Displace To A Solids Free Mud This approach offers the advantages of the solids free brine but also overcomes the risk attached to large scale downhole losses as the mud contains polymers that will rebuild damaged filter cake. This approach is however not entirely risk free. As the mud does not contain solids, spurt loss should be anticipated to be high and polymer damage may result. 1.3.11.5 Displace To Solids Free Inert Emulsion After drilling an interval with an invert mud there are, rightly, concerns regarding displacing the hole to brine in order to run the screens. There is a risk of emulsion problems occurring which could cause formation damage or block the screens. Base oil would be an excellent solids free fluid for running screens. It is more lubricious than most brines and it will not react with water sensitive clays. However, with a density of approximately 0.8 SG it rarely has practical applications. A more practical fluid is an invert emulsion made with heavy brine as the internal phase. By using different density brine and oil/water ratios the density of these fluids can be varied up to a maximum of approximately 1.6sg (13.3ppg). To achieve these higher densities it is necessary to use very heavy brines such as caesium formate (2.2sg). This is a very expensive option but may be justified in some applications, for example when conditioning of heavy, barite weighted mud to the necessary specification is unpractical (see below). Note:

If it is decided to displace the drilling fluid to any other completion fluid the selection criteria for completion brines described above must be met.

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1.3.12 Completion Fluids For Gravel Packing Completion fluid selection is critical to the success of gravel packing operations. In a gravel pack operation the fluid has to perform a number of functions; transport and place the gravel, squeeze away to compact the gravel, prevent formation damage, control well pressure, limit fluid loss, reverse excess gravel out of the hole and flow back to surface with the produced fluid. Solids in the gravel pack fluid have the potential to bridge in the gravel pack and cause a severe reduction in permeability. Relatively small particles can bridge in gravel packs. For example, with 40 mesh sand the ‘spaces’ between the gravel are approximately 50 microns. Assuming that the gravel is perfectly spherical and particles 1/3 the size of the opening can bridge, then particles of around 15 microns can plug the pack. In reality, with a high concentration of particles and the fact that the sand is not perfectly spherical, the minimum size for bridging is probably even less. Any brine will have numerous particles in this range unless it is properly filtered; hence fluid cleanliness is critical to preventing damage in the pack. Gravel packs can, either, be cased or open hole. In cased hole gravel packs the perforations may be back surged or washed to remove damage around the perforations. During this process fluid may be lost to the formation and any solids in the fluid will not only damage the formation but this damage may be compounded with damage to the pack. In open hole packs, the producing interval is commonly underreamed to remove the damaged zone; again the cleanliness of the fluid used in the underreaming operation is critical. Filtered, clear brines are therefore the preferred completion fluid for gravel pack operations. Completion fluids for gravel pack operations are typically filtered to 2 microns To provide the required sand carrying capacity, viscosifiers such as HEC are added. Viscosity breakers are added to ensure that the viscosity reduces to near that of water in a matter of hours after the completion operation. This allows the fluid to clean up rapidly at low shear rates. Both solids and polymers can be employed to control fluid loss. As with all fluid loss additives, the main concern is the ability to remove them after completing the operation. Acid soluble carbonates can be difficult to remove from gravel packed completions because of the problem of contacting the particles with acid during gravel placement. The inclusion of acid producing enzymes in the gravel slurry offers one answer to this problem. This technology is relatively new and advice should be taken from BP’s formation damage experts before any field application All of the formation damage issues that impact on brine selection for conventional completions also apply to gravel packing operations. For example, as well as being of adequate cleanliness the fluid must also be compatible with formation water and formation clays. 1.3.13 Completion Fluids For Hydraulic Fracturing A major concern with hydraulically fractured formations is not damage to the formation itself but conductivity impairment of the fracture. The fractures are usually propped open with sand in the 20/40 mesh range and are, therefore, prone to plugging by solids in the 10 to 40 micron range. There is, hence, a high probability of plugging the propped fracture if the sand is transported in a dirty fluid or down a dirty well bore. 1.3.14 Common Completion Fluid Contaminants There are many contaminants that can affect the performance of a completion fluid. The most common are outlined below.

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1.3.14.1 Polymers Brines contaminated with polymers cannot readily be filtered. The effects of polymer contamination can be reduced by breaking the polymer with hydrogen peroxide. Every effort should be made to isolate polymer pills used in various completion operations from the active brine system. 1.3.14.2 Crude Oil and Condensate Produced hydrocarbons can reduce brine density and make brine filtration difficult. Separation is best achieved by gravity in an un-agitated pit. Oil will float on top of the heavier brine and can be pumped off the surface. 1.3.14.3 Solids Solids that have not deliberately been added to the brine are considered to be contaminants. The most common are polymer, oil and barite residues, rust and pipe dope. These can usually be removed by filtration although filtration efficiency may be low if contamination is high and may take some time if it is done on the critical path. 1.3.15 Control Of Downhole Losses The lack of bridging material, or cake building polymers, in conventional completion brines results in a tendency for the fluid to be lost to exposed formations, particularly if mud cake is damaged by mechanical action (e.g. running liner or screens) or deliberately disrupted by a breaker. Excessive loss of brine to the formation needs to be controlled for the following reasons:   

Well control can be compromised. Although the completion fluid should have been selected for its low damage potential, it is always better to avoid uncontrolled fluid ingress into the reservoir as this can impact on clean up time. Excessive loss of brine can be costly.

Brine losses are typically controlled by the use of an LCM pill which has increased viscosity, bridging additives (i.e. properly sized soluble particles) or, in some cases, both. It is important that consideration be given to formation damage potential and sand screen blocking potential when designing an LCM pill for use in the reservoir. Common LCM pills are detailed below. 1.3.15.1 Solids Free HEC Pills HEC is a non-ionic polymer which is soluble in most brine types however yield can be slow, or incomplete, in some strong divalent brine such as zinc bromide. The polymer can be used to make viscous pills to reduce downhole brine losses. Typically concentrations in the range of 2-4lb/bbl (5.511.5kg/m3) are used. It is important to be aware that the loss of viscous fluid to the formation can result in formation damage, especially if the viscosifier used is slow to degrade. The degradation of hydrated HEC is reasonably fast above 220°F. So on wells with BHT above this temperature any impairment should eventually clean up. At lower temperatures a breaker, such hydrochloric acid, can be used. There are risks attached to acidisation and formation damage testing should be used to identify any incompatibilities. Enzyme breakers are less liable to be damaging but may take longer to achieve clean up than would an acid.

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When mixing HEC, care should be taken to get the polymer completely dispersed before it begins to hydrate or yield. The most effective method is to prehydrate the polymer in neutral pH or very slightly acid drill water prior to adding to the brine. The yield of HEC is slow in a low pH which allows the polymer to be effectively dispersed before the yield commences. Another approach is to predisperse the polymer in an inert non-aqueous solution before adding it to the brine. This is supplied by the mud companies as ‘liquid HEC’. Either of these approaches will minimise the risk of ‘fisheyes’ (small chunks of non-dispersed polymer) forming. Great care must be taken to avoid pumping unhydrated polymer (fisheyes) downhole as it can enter pores in the reservoir and cause damage that may require a remedial acid squeeze which itself may be damaging to some formations. One simple rig site determination of whether or not the polymer is well dispersed and that fisheyes are not present, is to ensure that the fluid will pass through a sand content screen without leaving residue on the screen. 1.3.15.2 Bridging Solids When high fluid losses occur, bridging solids may be used together with viscosifiers in the pill. Three types of bridging solids are commonly used, calcium carbonate, sodium chloride and cellulose fibres. Organic resins are used on occasion but are not common. By adding particles of an appropriate shape, concentration and particle size distribution, it should be possible to form a filtercake on the formation face without greatly invading the pore space. To achieve this, the fluid should have a low spurt loss which is an indication that a filtercake should form quickly so that the movement of fluids and polymer into the pore space is minimized. An important consideration in the use of bridging materials is how well the perforations or sand face will clean up after the completion operation. Solids that do not clean up can greatly reduce productivity from perforations. In open hole completions, production through the wall cake is usually good, assuming a well designed drill-in fluid has been used. Chemical removal of the cake will probably be required if injection is to be achieved. Particular care should be taken in selecting the particle size distribution of bridging material if a sand screen completion is planned. Particle large enough to block the screens must be avoided. Calcium Carbonate Ground calcium carbonate is the most common material used as LCM in reservoir intervals. Various forms of this material are use in drilling operations, most typically marble and dolomite. Marble is the preferred material for completion operations as it offers better acid solubility. This material is readily available in a range of grind sizes and can be custom ground to any specific requirement. The most appropriate blend of sized carbonate can be determined if information exists with regard to the pore sizes within the reservoir. The major service providers and BP fluids experts have access to software to determine the particle size distribution required for efficient bridging. Clean up is often spontaneous when the well is brought on. In situations where insufficient clean up is achieved, an acid wash can be used. Pure calcium carbonate is completely soluble in acid. However, the potential for formation impairment or sand screen damage by acid should be evaluated prior to using any acid wash. As well as conventional acid placement, acid producing enzymes are available. These produce weak organic acid and have the advantage over conventional acid treatment in that they will not become spent until all of the carbonate has been reacted. The least damaging acid type should be identified by return permeability core flood testing.

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Sodium Chloride Sized sodium chloride particles are frequently used as bridging material in LCM pills for use in reservoirs. To prevent the solid salt from being dissolved in the pill, the base fluid must be saturated with respect to sodium chloride. In theory, solution of the salt by formation brine or a low salinity wash should effectively remove the filter cake. However, in practice, clean up effectiveness is reduced by the polymers used to keep the salt particles in suspension. Polymer breaking enzymes are often run in conjunction with the low salinity wash to aid in the removal of polymers in the filter cake. Formation damage tests should be conducted to ensure that the high salinity fluid is compatible with the reservoir Cellulose Fibres Cellulose fibres are available in a variety of sizes and can effectively bridge pores. They can be removed by oxidising with sodium hypochlorite, however this should only be considered after careful evaluation of potential formation damage and downhole corrosion of tubulars. In most cases calcium carbonate is every bit as efficient a bridging material and is generally more economical in its application Oil Soluble Resin Typically oil soluble resins are made of polymerised hydrocarbons or processed natural pine resin. Currently available resins have an upper operating temperature of approximately 220 oF. They are available in various grind sizes and as such function as LCM in a similar manner to sized carbonates. In theory, they offer an advantage of being soluble in oil and will clean up by dissolution by formation hydrocarbons. In practice, however, such clean up has often only been partial and washover with an organic solvent has been required. It has been noted that some of the resin in the LCM or kill pill will liquefy on contact with reservoir hydrocarbons. This can produce a viscous resinous mass that can invade the formation causing impairment which is difficult to remove. Failure to achieve a satisfactory clean-up is the greatest single problem with using oil soluble resins, and may be affected by several factors, including:    

Improper solvent wash diversion technique Temperature of the formation Improper sizing of the resin beads in relation to the formation pore size Ineffective final clean-up due to low production flow rate and/or gravity of the produced fluid

The limited use of oil soluble resins as a fluid loss control technique is largely due to uneasiness regarding adequate clean-up. Laboratory testing at the estimated BHT is essential before applying this technology in the field. The clean-up of any of the above bridging agents should not be taken for granted. The main problem is usually that the removal from the formation or perforations is not uniform in that all the dissolving fluid or produced fluid only flows to/from the perforations that are initially opened or ‘hot spots’ on the sand face. Once this occurs the use of diverting agents or selective stimulation may be the only remedy.

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Note:

Before selecting a lost circulation material for use in the reservoir, the proposed formulation should always be tested for sealing effectiveness and cleanup efficiency in a return permeability core flood.

1.3.16 Brine Losses While Running Sand Control Screens Running sand control screens into open hole sections can mechanically damage filter cake inducing brine losses. This represents a special case as, not only must the LCM be sized to bridge the formation but must also be sized such that it will not plug the screens. Prior knowledge of formation pore geometry, ideally from mercury porosimetry or SEM work, will allow the formation bridging size to be determined. BP fluids specialists have software available to allow the best blend of bridging agents to be determined. This computer programme can also be used to identify any potential problems with regard to screen blocking. Verification of blocking tendencies can be determined in the laboratory. 1.3.17 Brine Losses While Gravel Packing Brine losses during gravel packing operations may be controlled by the following methods. 1.3.17.1 Gravel Pack Sand In cased hole gravel packed wells, a critical factor to obtaining a successful completion, is to fill perforation tunnels with high-permeability gravel-pack sand. Fluid leak off during the perforation packing process is required to accomplish this, therefore, if a fluid loss control pill is pumped prior to perforation packing, very poor perforation filling may result. For this reason, the use of gravel pack sand as a fluid loss control material can prove to be very beneficial. Gravel pack sand does not require removal, has no temperature limitations and when placed in the perforations to limit fluid loss has the added effect of greater perforation filling efficiencies. If sand is utilised in conjunction with the perforating hardware, potentially damaging fluid loss control agents can be eliminated. This eliminates the need to remove fluid loss control agents prior to gravel packing and provides two opportunities to place the gravel in the perforations. The results include higher productivity and higher production longevity 1.3.17.2 Mechanical Fluid Loss Control While Gravel Packing Since any type of fluid loss control pill during the gravel pack operation has the potential of damaging the formation or the pack, it is advantageous for fluid loss to be controlled through mechanical means whenever possible. Numerous types of mechanical isolation valves are in use eg the Knock-Out Isolation Valve (KOIV), Formation Isolation Valve (FIV), Completion Isolation Valve (CIV), and the Iso-Sleeve assembly. Most of these mechanical fluid loss devices that prevents completion fluid losses and subsequent damage to the formation after performing a gravel pack. The closure mechanism (ball or flapper) is held open by the gravel pack service tools during the gravel pack. When the service tools are pulled through the valves, they close preventing fluid loss to the formation. The gravel pack service tools can be removed from the well and the completion tubing run. The valves need to be cycled open under pressure or with wireline/ coiled tubing, or open once the well is put on production. For one valve the flapper is made of a friable material which can be broken hydraulically or mechanically prior to producing the well.

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1.3.17.3 Kill Pills Essentially all of the LCM pills described earlier in this section will function as kill pills. Brine density should be selected to provide sufficient hydrostatic head to kill the well. When using brines viscosified with HEC as kill pills, the lack of long term thermal stability of HEC must be remembered. When long term loss control is required, for instance on a work over, and the temperature is above 220oF a more stable pill, including, for example calcium carbonate, will be required. As with LCM pills designed for use in the reservoir, all products used in kill pills should have been screened for formation damage potential prior to use. 1.3.18 Field Preparation/Handling Of Completions Fluids 1.3.18.1 HSE When working with brines, sacked salts and brine related additives, full protective clothing (PPE) must be utilised. This should include rubber boots (not leather), rubber gloves, apron, dust mask and goggles or face mask. Due to their hygroscopic nature, all strong brines have the potential to cause skin irritation and eye damage. As a general rule, brine solutions become more irritating to the skin as the density of the fluid is increased. Essentially potassium and sodium chloride and sodium bromide are only mildly irritating whereas calcium chloride, calcium bromide and zinc bromide can be extreme irritants. Initial treatment is prolonged washing with water or in the case of eye contact, eye was solution. If irritation persists, seek medical attention. If clothing becomes contaminated clothing must be removed and laundered. The person involved should shower as soon as possible to remove all brines. The continued wearing of brine wet clothing will eventually result in skin irritation the severity of which will depend on the brine type and strength. Calcium chloride and calcium bromide salt are exothermic when added to water and high temperatures can develop when mixing these brines. Care must be taken to avoid scalds. Brine spillages produce smooth slippery surfaces. After any spillage, surfaces should immediately be washed with detergent and rinsed well with water to remove this hazard. Prior to any brine related operations a safety meeting should be held to discuss handling procedures and potential risks to safety. All brine and brine related additives must be accompanied by the relevant MSDS product bulletins. 1.3.18.2 Brine Formulations Formulations to meet a specific density and crystallisation temperature will be supplied by the mud company or brine supplier. In general brines are mixed at the suppliers base in dedicated brine plants prior to shipment to the rig in dedicated brine tanks. To minimise logistics brine are often shipped as concentrated ‘liquors’ which can then be blended and diluted as required at the rig site. Seawater should never be used to dilute completion brines. Many of the ions present in seawater may form insoluble scale when they come into contact with formation brines.

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1.3.19 Brine Cleanliness There is a general acceptance that a significant amount of insoluble material in completion brine is undesirable. This is because:  

Fluid lost to the formation will carry with it any particulate matter that it contains. Solids in the brine may settle and compact to such an extent that they interfere with the operation of down hole tools.

The question of ‘how clean is clean enough’ has been debated ever since the concept of formation damage was discovered. The cost of obtaining clean fluids can be high, particularly when the reservoir has been drilled with oil based mud. In such a situation a displacement from mud to clear brine can take days rather than hours. Complicated chemical pills and lengthy filtration is usually required. Often this process occurs when the AFE has been exceeded and completing the well in the shortest possible time is becoming a priority. Whether a fluid is acceptable will vary with the formation and the operation being performed. If extremely clean fluid is not used in gravel packing operations then severe productivity impairment can be guaranteed. In more conventional completions the tolerable level of solids in the completion fluid is subject to much discussion. In recent years specifically designed clean up tools have been developed that provide an engineered approach to well clean up. Clean up effectiveness is increased and the time to achieve acceptable conditions has, in most cases, been decreased. Wellbore clean up guidelines are given in section 1.4. 1.3.19.1 Filtration There are four main categories of filters utilised to filter brine: cartridge filters, bag filters, multimedia filters and diatomaceous earth filters. Cartridge filters are perforated metal or plastic tubes with internal layers of permeable material. These materials may be made from polyester fibre, cotton, paper. Large particles are blocked by the outer surface of the cartridge, with the smaller particles being trapped within the inner layers. Cartridges are enclosed in a pressure vessel or pod. As the cartridges become clogged the differential pressure across the pod increases. Once this rises to a predetermined level, usually 30 to 40psi, flow is switched to the other pod. The blocked pod then is taken out of service and the cartridges replaced. Cartridge filters are rated as absolute or nominal. As the name implies, absolute filters obtain a sharp particle size cut off at the rated size, however, they are limited in flow rate and dirt capacity and will tend to plug prematurely with high solids content. A nominally rated cartridge may allow particles larger than its rated size through. Cartridge filters are available in 1, 2, 5, 10 and 25 micron. Bag filters or sock filters are fabric bags with a controlled mesh size mounted in a filter housing. Bag filters are available in the full range down to 2 microns. Multimedia filters utilize layers of different granular materials like sand, gravel and garnet, etc. The filters operate on a similar principle to gravel packing with the finer material bridging on the granular layers. As the filtered material builds up and the differential pressure increases, the system can be backwashed. Multimedia filters provide higher flow rates and are, therefore, used in high volume operations like injection water treatment.

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Diatomaceous Earth (DE) is used in a number of filters as a filtering aid. The most common is the filter press. DE is the fossil-like remains of diatoms (microscopic water plants). Packed diatoms are highly permeable, virtually insoluble and are frequently utilized as filter media. Perlite is also in common use in filter presses. The filter press consists of a series of recessed face plates which are pressed together with a hydraulic ram. A filter cloth is usually fitted over each plate as a receptor for the filter aid like DE. Once the plate is closed, the plates are coated with DE. Filter presses can provide very clean fluid, removing 90% of particles above 2 microns, however, care must be taken to prevent any DE going down hole as this can be particularly damaging. To prevent this, cartridge filters or bag filters are often placed downstream of the press filter to act as guard filters. The use of filter presses in tandem with cartridge press to ‘polish’ the brine is a common technique when large volumes of brine must be filtered to a high specification. 1.3.20 Brine Recovery Generally service companies will not buy back low weight brines, specifically sodium, potassium and calcium chloride. Higher density brines have some value and it is often economic to recover the fluid and can be sold back to the supplier, subject to a reconditioning programme. 1.3.21 Brine Discharge The discharge of brine is generally covered by local legislation but any planned discharge must be reviewed against BP’s Environmental Expectations. In the USA, discharge is covered by the End of Pipeline regulations under the MMS. In the UK/Europe, most brines are on the PLONOR (poses little or no risk to the environment) list and can be discharged (assuming they have not been contaminated with oil) during the coarse of completion operations assuming that they have been included in the PON 15B submission. However, it must be remembered that BP’s Environmental Expectations go beyond legislative compliance. Generally, recovery and reuse of brines is economically viable and should be considered as the first option. Some brines (notably Zinc Bromide) could have adverse environmental impacts and should never be discharged. BP’s Environmental Expectations can be found at: http://gbc.bpweb.bp.com/hse/default.asp? page=http://gbc.bpweb.bp.com/hse/stream_initiatives/upstream_main.htm 1.3.22 Displacement Techniques Prior to completion operations, fluids are often changed out to obtain the appropriate downhole condition for the various planned completions operations. Designing a displacement programme can be relatively complex and is dependent on a number of factors including:     

Fluid in the well. Fluid to be circulated into the well. Hole geometry. Circulation options (reverse/conventional). Required specification of the fluid left in the hole.

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The overall objective in displacing a fluid is to maximise the removal of the first fluid (usually mud) and minimise contamination of the second (usually brine). The key to a good displacement operation is an understanding of the two fluids and their interactions. Fluids may be incompatible when commingled, causing increases in viscosity and subsequent pumping problems or resulting in the precipitation of solids. Spacers, small volumes of specially formulated fluids, are generally used to avoid potential compatibility problems. Even when compatibility is not a particular problem, spacers are still commonly used to provide a cleaner displacement. Various types of spacers are employed for specific purposes. They include: Water Based Weighted Spacer Their function is primarily to separate the two fluids. The base fluid is usually fresh water or brine, with the density of the spacer usually being half way between the mud and the displacement fluid. HEC and XC polymers are commonly used to increase the viscosity, provide the carrying capacity and keep the spacer intact. High Viscosity/Solids-Free Spacers They are usually used when displacing mud from the hole with solids-free brine. This spacer does not need the same density as either of the fluids. In most case sodium chloride or calcium chloride brine are used together with HEC to provide the increased viscosity. Surfactant Spacers They are often used in mud displacement to help disperse or flocculate solids and clean the pipe, particularly if the fluid being displaced is OBM. The spacer usually consists of lightweight brine with a high concentration of surfactant. Scouring Spacers These generally precede a viscous solids free spacers with fine frac sand or silica flour providing the abrasive component. This is used to increase the physical removal of mud from pipe and casing. Lubricant Spacers These are often used in high angle wells or wells with tortuous geometry. They are designed to enable pipe rotation during the displacement. Combination Spacers More often than not, combinations of the above spacer types are used. Suppliers of clean up chemicals have software programmes to simulate the clean up operation and optimise pill regime and contact times.

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1.3.23 Displacement Procedures Prior to commencing the displacement, ensure that: a)

b) c)

Surface equipment is clean and ready to handle both the displacement and displaced fluids. With two, often incompatible, fluids onboard, efficient logistics planning before and during displacement operations are critical. There may, for instance be a requirement to have a workboat alongside to take off mud being displaced from the well. The fluid in the well is free flowing, i.e. it is not gelled. The tubing and casing are free of debris and obstructions.

Prior to displacing a mud, the viscosity should be reduced to a workable minimum. However, there is a risk attached to this that must not be ignored. In deviated wells excessive thinning of the whole mud system can induce barite sag. This could lead to well control problems or at very least, make the clean up less efficient as settled barite is very difficult to remove from the low side of the well. Rather than thinning the whole mud system consideration should be given to pumping a small (e.g. 25– 50bbl) pill of the mud’s base fluid (base oil or brine) to act as a low viscosity spacer. In most instances high pump rates will minimise fluid interfaces during displacements. The rate is often dictated by the frictional pressure drop. When possible pipe rotation should be used to break down gel structure sand hence minimise channelling of the displacement fluid. The conventional direction for flow is down the tubing and up the annulus with reverse circulation being the opposite. A general rule is to reverse circulate when the fluid being displaced is heavier than the displacing fluid. However, this is only a general guideline and specific well conditions and pressure limitations may dictate alternative procedures. In most displacements, the fluids being pumped will have different densities. This can result in a differential pressure across the tubing which can lead to tubing collapse or burst. This problem is usually overcome by using the pump pressure to correct for the difference in hydrostatic head. A further problem can occur when reverse circulating in that the upper section of casing may not be capable of withstanding the relatively high pump pressure to overcome the hydrostatic differential. More detailed information and operational learnings are given in Section 1.4 - Well Clean up Guidelines. 1.3.24 Cementing In Completion Brines Brine will generally affect cement in two ways; potassium and sodium brines may cause a delay in thickening time and a loss of strength, and calcium chloride and calcium bromide can accelerate the setting time when mixed in small quantities with the cement. To avoid these problems cement is pumped with a spacer. The spacer for pumping cement would generally consist of fresh water, polymers and barite.

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1.4

Wellbore Clean-Out Guidelines

The cleaning out and preparation of the wellbore to accept the completion is the key element to enable trouble free installation. It is well documented that poor wellbore clean-out is a major source of NPT and has been extremely costly in the past and currently. This problem is even greater in high angle wells which are increasingly becoming more widespread as debris or sediment is more difficult to wash out and hangs around in the wellbore. This not only causes failure in tool operation and causes fishing but can also lead to permanent damage to the producing formations due to pore plugging. To obtain optimum wellbore clean-out, it is usually necessary to use a mixture of methods, i.e.:   

Mechanical Hydraulic Chemical

In some instances the use of only two of the above may be sufficient. This can be determined from well histories and the technical help from OSCA and SPS. Wellbore Clean Up Guidelines can be found on the BP Website at: http://aberdeen.bpweb.bp.com/wellperf/Major_Projects/Wellbore%20Displacement/WD&C.htm A problem that arose in the past is ‘who is responsible for the well clean-out’? In many instances this was never made clear and the procedure then was, therefore, not properly planned in advance and resulted in poor performance. The Drilling Department are usually assigned this task as they are more experienced at running the type of workstring required and pumping pills, etc. However, they may not have the essential knowledge on the other aspects of the operation and often the compromise is to have the Completion and Petroleum Engineers design the clean-out operation and for the Drilling Department to conduct the operation. Before describing the clean-out these methods it is worthwhile to look at what the terms sediment and debris mean. 1.4.1 Sediment/Debris The following is the general descriptions of sediment and debris. 1.4.1.1 Sediment Sediment describes the fines particles of rock from the drilling operation, fines from the mud system, oil from oil based mud and cement scrapped from the casing walls. Sediment is usually easily removed from the well with scraping and hydraulic flushing. If however it is mixed through larger debris, the efficiency drops. If sediment is left in the well it is often more hazardous to some tool operation than debris and is the main cause of formation damage if it makes contact with the producing formations. Some of the sediment is removed at the shakers and settling tank but some of the smaller particles will remain suspended in the fluids and so it is necessary to remove it mechanically with filters or centrifuges. Filter packages are available to conduct clean-out operations and dependent upon the level of cleanliness required either cartridge or DE filtration is available and on occasions sometimes both are used. The advantages of the types of filters vis-à-vis centrifuges can be assessed for each particular well.

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To check for the amount of sediment and/or debris contained in the completion fluid, hence that in the well, it is measured by instrumentation, (refer to section 1.4.8.1). 1.4.1.2 Debris Debris comes from a number of sources and can be categorised as follows:        

Metal solids scraped off the casing or from previous milling operations, i.e. swarf. Metal solids from drillable equipment such as float shoes, squeeze packers, etc. Formation cuttings. Gelled mud. Sand from the formation or from sand control operations. Gunk, sand mixed with grease, pipe dope or any other sticky substance. Other solid materials left or dropped in the hole such as broken wireline equipment, rollers, screws, tape, tie wraps, pens, wrenches, sacks used as hole covers, etc, etc. Rubber from packers previously set in the hole for testing, or treating.

Much of this debris will be unknown to be in the hole and it is extremely difficult to remove, therefore it is better to assume the worst case for a well clean-out operation as insurance to cleanout the wellbore. 1.4.2 Problems Caused By Sediment/Debris The following is a comprehensive list of the problems caused by sediment or debris: 1.4.2.1 Wireline Wireline operations are notoriously sensitive to debris due to the need to connect/disconnect from downhole tooling and set/retrieve downhole devices such as plugs on a very low strength wire. Due to sediment or debris the tools may either have problems getting to depth, retrieving them or correct operation due to the small clearances and delicate parts such as collets, dogs and keys. If conditions are known to be dirty then some precautions can be taken such as only using plugs less sensitive to sediment or debris and the use of releasable toolstrings to enable better fishing. 1.4.2.2 Packers Although more robust than wireline tools, they are susceptible to premature setting due to drag against debris, setting failure due to jamming of the mechanisms or plugging of setting ports. Most packers have a gauge ring to ensure the hole is of sufficient size to get through and protect the delicate parts from contact with the casing wall but debris can get past the gauge ring or fall down onto the packer from a higher larger casing size. After conducting a wellbore clean-up, it is advisable to run a gauge ring/junk basket combination on wireline before installation of the completion string. 1.4.2.3 Packer Seal Units/PBRs Larger debris can cause havoc when caught between seal units and packer or PBR bores as the can jam the movement and cause leaks. Generally after this has occurred, even if the debris can be flushed out, the seals and possibly the bore will be permanently damaged. Page 25


The most prudent procedure for installing such items is to run them attached to prevent debris an opportunity to get between the items. Debris rings are also now usually provided to prevent smaller sediment settling out and dropping into the seals. In some completion designs a liner packer PBR system is employed and is even more susceptible to this problem as it is necessary to run the seals down to the PBR already installed. Also the PBR can be damaged by the clean-out operation itself. 1.4.2.4 Control Lines Control lines used in wireline retrievable surface controlled sub-surface valves are at risk of contamination of the control line fluid when the valve is out of its receptacle. Contamination of the control line fluid results in blockages or damage to the valve, hence non-operation. The usual procedure for avoiding this is to pump a sufficient amount of control line fluid through the line before setting the valve. 1.4.2.5 Tubing Hangers Metal or rubber debris can interfere with the installation of hangers by preventing the hanger from reaching it correct locating/locking position. This can be extremely serious in that the wellhead cannot be flushed again until the completion is pulled back to surface. Also in subsea completions the control line ports through the hanger are exposed to the riser before the tree is installed. This can lead to blockages and non-operation of downhole equipment. The solution to this problem is thorough flushing of the wellhead and BOP cavities before running the completion. 1.4.2.6 Formation Damage Whenever the wellbore fluids come into contact with the formation there is a risk that the smaller particles will plug pore throats even if the fluid is compatible with the reservoir rock. The remedy in this situation is to have the fluids prepared to a cleanliness level which will least damaging, however there is a minimum level which can be viably achieved. If perforating, the use of underbalance methods will help prevent wellbore fluid invasion of the perforations, especially if the wellbore fluids can be ejected from the well before it is shut-in. For a more comprehensive explanation of formation damage which can be caused by well bore fluids, refer to section 1.3.5. 1.4.3 Aims Of A Wellbore Cleanout The aims of a wellbore clean-out can now be defined to:     

Be able to install the completion into the wellbore. Be able to operate the various tools in the completion string. Enable wireline tools to be installed and retrieved trouble-free. Prevent contamination of control line fluids. Enable the locating and setting of the tubing hanger.

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1.4.4 Objectives Of A well Clean-Out To achieve the aims detailed in the previous section, the objectives of a wellbore clean-out are to remove:         

All mud solids. All mud associated fluids. All contaminants from casing walls. Sand and debris from perforating operations. Sand or proppants from stimulation or sand control operations. Metal debris from casing or milling operations. Metal debris from drillable equipment. Rubber and other non-metallic debris from packers and drillable equipment. All objects which may have fallen in the hole.

To enable these objectives to be achieved it is necessary to ensure the rig has the facilities to provide the fluid capacity, the cleanliness, the continuous rates and pressures required. 1.4.5 Clean-Out Design As previously described there are three elements to a wellbore clean-out, mechanical removal, hydraulic removal by circulation and chemical removal. All or a combination of these can be used for a particular well. A clean-out design should be made for each particular situation and there should be no fixed design. The design needs to include a number of aspects:   

Mud type – water based or oil based and within this whether pseudo OBM, low toxicity OBM with specific manufacturer. Well conditions – temperature, pressure, pump rates, well metallurgy, available pump HP, pressure limitations (liner top, etc), completion type (slotted liner, perforated liner, screens, etc) Reservoir conditions where the fluid train may contact the formation, i.e.: lithology, hydrocarbon characteristics, formation water chemistry, etc.

Laboratory evaluation can be carried out with the drilling fluid to take into account the effects temperature, velocity, density and the base fluids which may all have an impact on the performance of the clean-out design. Similarly, where there is formation contact checks can be performed to anticipate and correct for any potential incompatibilities. Whilst the wellbore clean-out design should never be prescriptive, there are a number of basic aspects to the design which are fundamental:     

Avoiding contamination of the brine by preceding the mud using spacers Removal of residual mud and cement by mechanical and chemical means. Increase effectiveness of removal by causing flocculation. Rendering the surfaces water wet. Maintain well control by using overbalanced density fluids.

Refer to section for fluid guidelines. Page 27


1.4.6 Pill Design Displacement pills need to be designed carefully to ensure effective mud displacement and water wetting of the casing in the event oil based muds are in use. The key roles of these pills are:      

Disperse and thin the drilling fluid Compatibility with the drilling fluids Lift out debris and junk Water wet pipe Remove pipe dope Effectively displace the mud

1.4.6.1 Risks And Issues      

Well control is a key consideration in selection of the pill sequence as in many cases it is only possible to get thin light fluids into turbulence. Pumping fluids to displace oil based fluids without suitable surfactant packages will result in gunk which is insoluble except in very aggressive solvents. For deep water wells low temperatures can impact surfactant effectiveness. Pills in turbulence lose their carrying capacity if the annular velocity reduces below that required for turbulence (e.g. entering the riser). In high mud weight the risk of inducing barite sag needs to be considered (displacement pills thin the mud to the point it can no longer support barite). HSE needs to be considered for all chemicals used, mixtures of displacement pills and mud have to be separated from the active mud and packer fluid for disposal (zero discharge issues).

Water pumped without surfactants to displace oil muds (e.g. for an inflow test) prior to clean up can form gunk, which is not broken down by subsequent clean up pills Clean up pills containing surfactants can foam during mixing (particularly when put through a hopper) XCD/Biozan are the preferred materials for mixing viscous spacers but do not work in calcium brines, HEC will yield in calcium brines but will not support solids. As depth and hole angle increase the minimum pill volume should increase to allow for contamination (e.g. if MD is < twice TVD, pills should have an annular fill length >80m, where MD> twice TVD, length >125m for the largest annular clearance). Contact time (time critical points in the well are exposed to the pill) is important, for surfactant pills aim for greater than four minutes 1.4.6.2 Best Practices and Design Criteria  

The best fluid for thinning a mud is the continuous phase of the mud, for water based mud pumping 50bbl of water as the first displacement pill will effectively thin mud, 50bbl of the base fluid oil can be pumped in the case of oil based muds. Before any displacement the compatibly of the spacers with the mud and the ability to water wet steel surfaces should be checked at room temperature and 85 oC/185oF to confirm compatibility (in deep water lower temperature tests may be necessary) Page 28




All tests should be done on field mud samples to ensure mud is effectively sheared.

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 

Water wetting surfactants are generally effective >3% vol/vol concentrations, little additional benefit is obtained at concentrations above 10%. Solvents are required to remove gunk and pipe dope

1.4.7 Procedures Over and above the downhole clean-out, the pits and surface lines also need cleaning. This section describes the methods of cleaning out of both the surface facilities and the methods applied downhole. 1.4.7.1 Pits And Surface Lines It is pointless to conduct a thorough wellbore cleaning operation if the pits and surface lines contaminate the fluids again. Before the pits are cleaned, a review needs to be carried out to determine:         

What is the volume and were is the displaced mud to be returned to. The amount of mud to be retained for kill purposes. Where the mud should be stored so as it does not mix with the clean wellbore fluids. Which tanks will be the clean brine supply and the returns. How the filtration will be plumbed in to filter the returned brine and feed it back to the supply tank. Where to keep a supply of water or seawater for mixing the brine. Where to make up and segregate the various pills required. If the waste can be dumped or require to be held for return to base for disposal. If the returns can be redirected to avoid the shakers.

Cleaning of the pits and sluices is usually a combination of physical shovelling and high pressure hosing down followed by cleaning with squeegees. The flowlines are usually cleaned by circulation of a surfactant pill from the same recipe to be used downhole. New pit washing tools have reduced the requirement for pit entry and reduced waste generation (e.g. Toftjorg in Central North Sea and West of Shetlands). The effectiveness of these systems relies on use of an effective detergent at ambient surface temperatures. Effective isolation between pits is key and heavy fluids have regularly drained across and contaminated lighter fluids in adjacent pits where poor isolation exists between pits. 1.4.7.2 Downhole Clean-Out The displacement of mud from a well is a complex physical phenomenon, the main driving forces which can be used to enhance the displacement are:  

Mechanical removal through agitation and density of the fluid Hydraulic removal through friction from circulation rate

Chemicals are also used to aid in cleaning the tubing walls and congealing the solids to improve hydraulic removal.

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Mechanical Removal The mechanical means is usually by running a scraper or similar function tool on a workstring to mechanically remove cement, mud and scale from the casing and liner walls. This is especially important over packer setting areas. Some operators also pump an abrasive such as nut plug or sand, however such materials can cause as much problems as the debris and sediment already in the hole and their use needs to be strongly justified. Hydraulic Displacement Hydraulic displacement is the displacement of the mud system by the circulation of the clean-out fluids at sufficiently high rates to cause enough turbulence to move all the mud, debris and sediment out of the hole followed by the brine. In deep or horizontal wells this is often more difficult to achieve due to greater velocity required with casing pressure limitations and available pump rates. In these cases, it is often necessary to use one or more circulation devices to enable staging of the process achieving higher rates at shallower stages. To displace the mud from the hole, two methods are available dependent upon whether the borehole is open to the reservoir or not. These are:  

Indirect Underbalanced Displacement Direct Balanced Displacement

The former can only be used on wells where the formation is isolated from the wellbore whereas the latter is designed for live well displacement. Indirect underbalanced displacement, (refer to Figure 13 .2), is the preferred method as large pills of water or seawater are used after the displacement of the chemical pills at as high a rate as is possible to cause maximum agitation and improve efficiency.

B r in e V is c o u s P ill S e a w a te r S e a w a te r

V is c o u s P ill

C le a n -O u t P ill(s )

V is c o u s P ill

S e a w a te r

M ud

Figure 13.2-Indirect Underbalanced Displacement

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The direct balanced method, (refer to Figure 13 .3), requires the clean-out pills to be weighted to maintain well control therefore the use of large water or seawater pills is not feasible. B r in e

V is c o u s P ill M ud C le a n -O u t P ill(s )

O il B a s e

Figure 13.3-Direct Balanced Displacement Hydraulic flushing is also used to clean-out the wellhead area and BOP cavities with a flushing tool. A high flow rate is necessary to obtain a good clean up and with subsea systems which have large bore risers, the use of circulating subs and a BOP boost line will aid the clean up. 1.4.8 Chemical Removal Chemical removal of sediment and drilling residue, usually involves circulating chemicals contained in pills which are designed to provide a contact time to remove residue from the walls of the pipe and then flush it to surface. The chemicals normally used are surfactants and flocculants and there are many commercial products on the market purely produced for well clean-outs. The sequence of pill displacement may vary with the product used but a typical sequence is: a) b) c) d) e) f) g)

HiVis pill to segregate the mud and cleaning agents. Surfactant pill of sufficient volume to give the correct contact time at the rate of pumping. HiVis pill for segregation. Flocculant pill to gather the fines into sizeable clots to aid displacement. A large water or seawater pill circulated at maximum rate to cause maximum turbulence. HiVis pill for segregation. Brine.

Depending on whether water based or oil based mud is used, then the amounts of chemicals can be reduced appropriately.

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1.4.8.1 Brine Cleanliness Measurement The objectives of the clean-out procedure will include the level of cleanliness of the brine required to prevent formation damage, or perhaps simply to get the wellbore sufficiently clean for completion installation. The cleanliness level is usually determined by measuring samples of the fluids coming out of the well. However, the required level of cleanliness can only be achieved providing the level of the fluids in are correct, therefore it is common practice to take samples of the fluids being pumped as well. Samples of the pills in and out are also generally retained in order that future investigation can be carried out if the system design is ineffective. Fluid cleanliness measurements can be carried out by number of different methods, these are described below: 

Turbidity This gives an indication of the overall amount of solids in a fluid using a tubidity meter which gives a reading in NTUs. This reading is achieved by shining a light through the fluid and measuring the amount of light received. Scatter of the light gives a reduced reading and therefore an indication of cleanliness. This method does not actually give a reading of the sizes of the particles or their distribution.



Volume Percent Solids The use of a centrifuge separates the solids from the fluid and a percentage measurement is obtained. Like the turbidity meter there is no measurement of particle size and distribution.



Particle Size Distribution If particle size is of the utmost import, a Coulter counter or laser particle size analyser can be used which gives readings of the sizes of the particles and their distribution. The Coulter counter is a fragile instrument but was commonly used until the laser instrument was introduced and although more expensive is more suited to offshore applications.



Drag Measurements A rough and ready technique is to monitor drag measurements as drag of the brine is much higher than muds (which are well lubricated). To analyse these a torque/drag model needs to be set up by a drilling engineer. This could give an indication but never to replace instrumentation measures of cleanliness.



Mud Residue Mud residue left on the surfaces of the workstring tubulars would be indication that the procedure has not been successful, regardless of instrument readings.

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1.5

References

Corrosion Guidelines http://drilling.bpweb.bp.com/wp/downhole/ Formation Damage Website http://damage.bpweb.bp.com/ BP’s Environmental Policy http://gbc.bpweb.bp.com/hse/default.asp? page=http://gbc.bpweb.bp.com/hse/stream_initiatives/upstream_main.htm Wellbore Clean Up Guidelines http://aberdeen.bpweb.bp.com/wellperf/Major_Projects/Wellbore%20Displacement/WD&C.htm

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Section 13 Fluid Guidelines

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