Section 5 - Production Chemistry

BP Exploration

Section 5 Production Chemistry

BP Exploration

Section 5 Production Chemistry

SECTION 5PRODUCTION CHEMISTRY

Prepared By:John Ray

Date:21/11/2002

Revision:1

Reviewed By:Carl Argo

Richard Chapman

Ian McCracken

CONTENTS

Page

15Production chemistry

15.1Summary

15.2Introduction

25.3Mineral Scale

25.3.1Description Of Scale

35.3.2Problems Caused By Scale

35.3.2.1Drilling And Completing Wells

45.3.2.2Water Injection Wells

45.3.2.3Reservoir Damage

45.3.2.4Water Production

45.3.2.5Production Operations

55.3.3Scale Prediction

55.3.4Laboratory Evaluation Of Scale Inhibitors

55.3.5Application Of Scale Inhibitors

75.3.6Scale Dissolvers

75.4Wax

75.4.1Description Of Wax

85.4.2Impact Of Wax On Flow Characteristics Of Crude Oil

95.4.3Questions To Be Answered

115.4.4Testing Philosophy

115.4.5Crude Oil Pretreatments

125.5Asphaltenes

125.5.1Description Of Asphaltenes

135.5.2Asphaltene Precipitation

145.5.3Determining The Risk Of Asphaltene Deposition

145.5.4Operational Variables Effecting Asphaltene Deposition

155.6Hydrates

155.6.1Description Of Gas Hydrates

165.6.2Gas Hydrates Problems

165.6.3Prevention Methods/Options

165.6.4Hydrate Predictions And Modelling

175.6.4.1Low Dose Hydrate Inhibitors

175.6.4.2Anti-Agglomerates

175.6.4.3Kinetic Inhibitors

185.7Emulsions

195.8Sulphate Reducing Bacteria

195.9Wettability And Relative Permeability Changes

195.10Completion Fluid Chemistry

205.11References

1 Production chemistry

1.1 Summary

This section describes the behaviour of production, injection or treatment fluids through the life cycle of a production or injection well. It explains the various production problems which arise from interaction of production or injection fluids from scale, wax, asphaltene, hydrates, hydrogen sulphide, water wetting and emulsions. A description of each individual problem is detailed and the chemistry which causes them along with predictive measures and possible solutions.

Sufficient information is provided with references to other documents to give a completion design engineer an understanding of the basic principles of fluid behaviour and their implications on future production of a well. This information includes where help can be sought to ensure the completion design can accommodate the systems and procedures which would be required to counter anticipated problems.

1.2 Introduction

Downhole production chemistry concerns the behaviour of produced, injected or treatment fluids through the life cycle of the production or injection well. Understanding the interaction of fluids with the reservoir matrix as well as changes in fluids behaviour during the production or injection process is essential to avoid production losses and maintain flow assurance.

Although the completion engineer might not be expected to be an expert in production chemistry, it is important to understand the basic principles of fluids behaviour and the potential consequences of interactions and changes including:

Formation damage due to fluids/rock interactions causing wettability changes, and fines migration.

Mixing of incompatible fluids causing scale and emulsions.

Precipitation of solids due to changes in pressure and temperature.

Corrosivity and erosional corrosion caused by fluids acidity or high rates.

In general, prevention or avoidance of production chemistry related problems is the preferred strategy. Remedial treatments can be expensive and can lead to further problems. Increasing use of subsea facilities with reduced access increases the cost of remedial work.

However, there are certain instances where a remedial strategy might prove more cost effective such as the use of scale dissolvers to manage a low calcium carbonate scaling risk in a platform well.

In conjunction with other discipline specialists it is the completions engineers role to:

Assess potential risks from available data including fluids analysis.

Generate additional data further analysis and modelling.

Assess impact of risks on production and life cycle costs.

Determine optimum strategies/solutions to obviate or minimise impact.

Document experience and share lessons learned.

Through the BP digital business systems there a several relevant networks, websites and on-line documentation available to assist the completions engineer. To minimise the size of this document and to ensure ongoing access to regularly updated and expanding data sources, the format provides merely an introduction and overview of each production chemistry topic. At the end of each section there are links to relevant websites and documents.

1.3 Mineral Scale

1.3.1 Description Of Scale

Figure 5.1 Examples Of Scale Deposits

Oilfield scale is generally thought of as the carbonates or sulphates of the Alkaline Earth metals calcium, strontium and barium. However, complex salts of iron such as the sulphides, hydrous oxides and carbonates may also form solid deposits that give similar problems. As production moves into hotter and higher pressure environments, even common salt (halite) can deposit, often in tonne quantities.

The deposition of mineral scales is dependent on a number of variables including:

a) Degree of supersaturation (i.e., concentration above the solubility limit) of scaling ions in the water.

b) Absolute temperature and the rate of temperature change.

c) Degree of agitation during formation of scale crystals.

d) Size and number of seed crystals.

e) Presence of impurities.

f) Change in pH of solution.

g) Changes in pressure.

h) Relative volumes of incompatible waters.

Common oilfield scales form in one of two ways. First, a change in conditions such as temperature or pressure can promote carbonate scale to precipitate from a formation water. Secondly, two incompatible waters mixing (e.g. a formation water with sea water) can promote sulphate scale.

Iron scales (sulphides when production is sour, hydrous oxides when production is sweet) often reflect corrosion in the system, with iron originating from the pipework or vessels in the system itself. However, some formation brines naturally contain significant levels of dissolved iron in the reduced ferrous state, which can lead to problems under some circumstances.

1.3.2 Problems Caused By Scale

Scale does not restrict itself to any particular location in the oilfield. However some areas are more difficult and costly to treat than others. Problems include restrictions in pipeline diameter, solids stabilization of emulsions, under deposit corrosion, etc. Specific issues arising at each location are discussed below.

1.3.2.1 Drilling And Completing Wells

Scale can cause problems if the drilling mud and/or completion brine is intrinsically incompatible with the formation water. For example, allowing a seawater based mud to contact a formation water rich in barium and strontium ions would be undesirable, as would allowing a high-calcium brine to encounter a formation water rich in bicarbonate.

Note:Many oil-based muds also contain significant quantities of water and are not immune from causing scale problems.

Drilling the first well in a new prospect can be particularly hazardous. There is no way of knowing accurately the chemistry of the formation water that will be encountered and often a more dense mud than is actually required will be used to reduce the chance of kick backs. There is thus an increased risk of invasion and formation damage due to scale subsequently resulting in very high skin factors. In the extreme, productive zones could be entirely blocked off. Obtaining representative water samples as soon as possible are important to assess the consequences of drilling mud filtrate invasion in future wells in the field. Refer to Sampling Guidelines For Best Practices And Recommended Procedures at:

http://pwn.bpweb.bp.com/roadmap/sheets_htm/samplingguidelines.htm1.3.2.2 Water Injection Wells

Problems may arise at the commissioning stage of new injectors if the injection water is intrinsically incompatible with the formation water. For example, seawater injection into an aquifer rich in strontium or barium ions could cause problems. Thankfully, this is often only a temporary effect until the injection water has flushed away the formation brine from around the near-wellbore region. Initially, protection against scale may be desirable, for instance by deploying a scale inhibitor for the first few days. Such damage may be ignored if fracturing past the damaged zones is practical.

1.3.2.3 Reservoir Damage

This is an aspect of scale precipitation which is only now being seriously addressed by reservoir engineers. Scale formation in the near wellbore region of a producer could have a beneficial effect if it is restricted to the water producing zones, thereby reducing water cuts. However, scale blocks in the oil producing zones could kill a well. A better understanding of the reservoir/fluid interactions such as ion exchange and mineral dissolution/precipitation, and the movement and mixing of waters within the reservoir are needed before any predictions are possible.

The effect on oil production from scale precipitation in the bulk reservoir will be small. However, the consequences of scaling in the near-wellbore region could be significant.

1.3.2.4 Water Production

As soon as a production well begins to cut water, a risk of carbonate scale formation occurs. The severity of the problem obviously depends on the water chemistry but is aggravated by high drawdowns when large pressure drops increase the risk of carbonate scale in the formation, across perforations or at chokes.

When injection water breakthrough occurs in production wells additional (and potentially much more serious) scale problems may arise. Any mixing of incompatible brines can cause severe scaling wherever it occurs (whether in the production wells or in the reservoir). Experience suggests that problems are first observed in the production tubing rather than in the near well region. Timely remedial treatments to reduce downhole scale formation can then also protect the near formation. 1.3.2.5 Production Operations

Once water is first produced, process equipment such as heat exchangers, valves, pumps, filters and all associated pipework are at risk. Solubility limits of mineral salts may be exceeded by changing the temperature and pressure, or by mixing incompatible waters. The latter possibility may arise from a process operation (sand-washing, desalting, etc.) or because waters from different wells are mixed in the production system. This last point is particularly important; even if a well which has suffered sea water breakthrough does not suffer damage, the water which that well produces is unlikely to be compatible with 'pure' formation water and mixing such waters in the production system is sooner, or later, bound to cause problems. 1.3.3 Scale Prediction

Scale formation from oilfield brines takes place in a multi-component, multiphase environment. To predict the formation of scale in systems of this kind requires a sophisticated computer model together with accurate kinetic and thermodynamic data.

The technical target for such a predictive model is to assess:

How much scale will form as a result of a given operation

Where it will form

How damaging it will be

Satisfying the last criterion is rather difficult. Factors such as fluid dynamics (which influence the transport of ions to and from a surface) and crystal size and shape (which influence transport in porous media) are undoubtedly important. Frequently, detailed information is unknown and accurate prediction is therefore often a compromise.

In addition to solid and aqueous phases, gases are also included in ion pair models. Currently, all models are thermodynamic in nature and are unable to accurately represent kinetics of the scale precipitation process. The recommended BP model is ScaleChem, although MultiScale is also a competent predictive tool. For information on these models contact UTG production chemistry in the Well Performance teams in Aberdeen or Sunbury.

1.3.4 Laboratory Evaluation Of Scale Inhibitors

There are many techniques used to study scale deposition and inhibition but few testing standards have been laid down within the oil industry. Test methodologies and interpretation of results can vary widely from company to company. However, there are some common tests which are similar in approach, if not in detail, to evaluate scale inhibitor performance in the laboratory prior to deployment in the field. These are discussed on the web site at.

http://ut.bpweb.bp.com/RTPManual/homepage.htm 1.3.5 Application Of Scale Inhibitors

Scale inhibitors should be used wherever a risk of scale damage is predicted (or known to exist from past experience). For example, inhibitors are often incorporated into drilling muds, completion brines, and process water used for sandwashing or desalting. Scale inhibitors have been used in injection water that is incompatible with the formation brine present in the zones into which the water is being injected. Continuous injection of scale inhibitors into production systems is commonly practised, and batch of production wells is now a routine operation. Refer to BP web site:

http://ut.bpweb.bp.com/scale/pred/squeeze.htmA good scale inhibitor must be:

Efficient: i.e. it must be able to inhibit the scale in question, irrespective of the mechanisms operating.

Stable: it must be sufficiently stable under the conditions imposed.

Compatible: it must not interfere with the action of other oilfield chemicals, nor be affected itself by them.

Compatibility in this sense is understood to include direct chemical interaction and mechanistic antipathy.

Cost effective.

In order to optimise the field performance, a chemical must be deployed correctly. For example, injection of a scale inhibitor into a production header is wasted if it does not contact incompatible waters before they mix in the production system. In some cases it may be necessary to install continuous injection facilities downhole to ensure proper deployment of scale inhibitor.

After a well has suffers seawater breakthrough, scale formation could occur in the near wellbore region, across perforations or in the tubing. Whilst downhole injection of an inhibitor may protect the tubing, squeeze treatments may be needed to ensure protection of perforations and near-wellbore. In this technique production is stopped and a concentrated solution of scale inhibitor is pumped into the well and out into the formation. After a shut-in period of usually 6-24 hours, production is resumed, and the scale inhibitor leaches back into produced fluids, giving protection against scale formation until the scale inhibitor is exhausted, when the well is re-squeezed.

Following a squeeze, the concentration of scale inhibitor in produced fluids falls off exponentially. Successful treatments have as long a half-life as possible. There are many factors controlling the rate of inhibitor returns and effectiveness of squeeze treatments such as:

Adsorption/desorption behaviour of scale inhibitor on reservoir rocks and minerals. Work from Heriot-Watt University suggests a very steep rise in the adsorption isotherm at low inhibitor concentrations is a prerequisite for good squeeze lives.

Precipitation of scale inhibitor in the reservoir. A precipitation/resolution mechanism can increase the squeeze lifetime over adsorption/desorption treatments. However, the precipitation process must be carefully controlled in order to avoid blocking pore throats and suffering irreversible loss of chemical.

Entrapment of scale inhibitors in the formation for other reasons, such as changes in relative permeabilities of fluid as a result of actually applying the treatment;

Modification of inhibitor properties by the porous media.

Experience within the industry is increasing, and as new chemicals are developed, an improvement in squeeze treatments can be expected.

In more recent years focus has been on developing alternative delivery systems for scale squeezing:

Oil soluble inhibitors are frequently used for pre-emptive squeezing to address the risk of scaling during initial water breakthrough or to treat water sensitive reservoirs.

Microparticle dispersions of solid scale inhibitor.

Emulsified scale inhibitor.

Encapsulated scale inhibitor where beads of inhibitor are placed in the well sump.

Scale inhibitor encapsulated into gravel packs although these provide a once only treatment

1.3.6 Scale Dissolvers

The dissolution of scale in a liquid is the reverse of the crystallisation process by which the scale deposit was laid down. Carbonate scales are most readily dissolved with mineral acids, although in order to avoid corrosion and other forms of damage organic acids such as acetic acid are often preferred.

CaCO3 + 2HCl --- >CaCl2 + CO2 + H2O

The sulphates (especially barium sulphate) are particularly hard to remove once formed. They are largely insoluble in acid and require chelants and/or mechanical removal (such as high pressure water jetting).

Chelation or sequestration is the formation of soluble metal ion complexes in the presence of substances which would normally give a precipitate. The process of chelation is illustrated below:

Consider a system in which barium sulphate scale is present. In water/brine the solubility of barium sulphate is in the range 5-50 mg/l. There are, therefore, some barium ions in solution:

BaSO4 --- > Ba2+ + SO42- (1)

Ba2++L--->BaL(2)

L = chelating agent

More detail on scale management is contained in Appendix 7 of this completion design manual.

1.4 Wax

Although wax rarely impacts wells due to higher temperatures it is important for well engineers to understand the mechanisms of wax formation and deposition, the prediction of waxing tendency and preventative and remedial options in order to contribute to the development of a wax management strategy should it be required.

1.4.1 Description Of Wax

Waxes are a natural constituent of crude oils and condensates consisting of mainly heavier (>C17) paraffinic hydrocarbons. These may be straight or branched chain or cyclic, and they affect production in two ways.

Firstly they can have an adverse affect on the viscosity of the oil. This has important implication to pipelines, either in-field or export. They can impart non-Newtonian behaviour, i.e. that the viscosity of the oil depends upon the shear rates applied to it, in addition to the temperature. A good common example of this is household non-drip paint. Here, under low shear the paint does not flow (i.e. non-drip), but at high shear when applied by paintbrush, the paint flows naturally to cover the surface. Such behaviour in production operations normally manifests itself during shut-downs or under turn-down operations. Following a shut-in, when flow restarts, the initial shear rates may be very low. At low shear rates the apparent viscosity may be high, in some cases so high that the available pressure from the pumps is insufficient to start flow. This is particularly a problem in subsea lines where the shut-in fluid temperature is low, compounding the high viscosity.

Secondly, wax crystals can be deposited from bulk. In a pipeline system, this may reduce the internal dimensions, but the real effect upon flow through the line is an increase in the surface roughness of the pipewall. This causes an increase in the energy needed to pump the fluids through the line. Thus, for a given pumping pressure, the volume throughput would be less in lines where wax deposition has taken place. Wax deposition has also been noted in risers, manifolds, at wellheads and in separators in addition to pipeline systems. It is common to operate a clean pipeline policy, this prevents deposited wax from hardening with time which makes it more difficult to remove, and minimises the risk of large volumes of removed wax from upsetting downstream facilities.

Each of these phenomena is discussed below.

1.4.2 Impact Of Wax On Flow Characteristics Of Crude Oil

Most crudes are relatively fluid and easy to pump. However, this may not be the case for waxy or heavy crude oils. Typical ranges in the characteristics of crudes affecting pumpability are shown in Figure 5.2. Fluids eventually reach the ambient conditions surrounding wells or pipelines. Waxy crudes can show significant variations in flow behaviour at a given ambient temperature depending upon the conditions suffered in reaching the ambient temperature. For instance, dynamic viscosity curves are appropriate for normal flowing conditions, when a fluid cools under flowing conditions, but do not describe the flow behaviour following a shut-in when fluids have cooled statically.

During a prolonged shut-in, waxy fluids may form a gel if they fall below their pour point. This gel has mechanical strength and there must be available pressures from the wells or pumps to overcome that strength and restart flow. It should be noted that fluids can be and frequently are transported below their pour point when they have been cooled under flowing conditions. These effects become further complicated by the presence of gas. In a single phase system, the presence of gas can be beneficial by reducing the viscosity, the pour points and the gel strength. In a two phase system, the oil properties have a lesser impact on pipeline pressure drops than the effect of flow regime.

Therefore, it is important to understand not only the characteristics of the oil, but also the operating conditions of flow, temperature and pressure, and whether gas is present (i.e. two-phase (gas/liquid) flow).

Figure 5.2 Variability Of Crude Oil Pumpability Data

1.4.3 Questions To Be Answered

In a real system, fluids, their flow rates and the environment surrounding the pipeline may all affect pumpability problems. The following, therefore, need to be addressed:

i) What are the flowing (steady-state) pressure, temperature and flow characteristics?

Crude oil flowing temperatures fall along the length of the line. Thus, its viscosity increases away from the pipeline inlet. Figure 5.3 shows typical temperature profiles for different flow rates and how the local environment affects the profile.

Figure 5.3 Typical Pipeline Temperature Profiles

The flow rates, pipeline or well diameter, and the ambient conditions determine the viscosity of an oil. The viscosity, the pipeline dimensions and the flowrate determine the pressure drop in a pipeline or well. Figure 5.4 describes the pressure drop across a pipeline at different flow rates for three different types of crude. At high flow rates, the viscous crude behaves in a similar manner to the fluid crude.

Turbulent flow imposes high shear stresses which cause shear thinning and a reduction in the apparent viscosity. Thus, for high pipeline throughputs, the flow regime determines the apparent viscosity of the oils. During normal operation, most flowlines are in turbulent flow. However, in the latter stages of field life, or during shutdowns, the flowrates may drop, hence the applied shear stresses are lower which enables temperature to dominate the viscosity of the crudes. At very high viscosities, the viscosity can become more important to the pressure drop than the flowrates.

Figure 5.4 Pipeline Pressure Response

j) If a pipeline is shut-down and allowed to cool, can it be restarted?

Wax crystals precipitated in a crude cooled statically can interact and cause formation of a gel like structure. The temperature at which this gel forms is the pour point. The gel has mechanical strength and it exhibits a yield stress, i.e. until a certain minimum pressure is applied there will be no flow at all. Even if this minimum pressure is available, the flow rate for a line filled with cold viscous oil may not be high enough to allow hot incoming oil to warm the line up and achieve the normal operating flow again.

k) How long does it take a pipeline to cool?

In a subsea pipeline exposed to the seawater, cooling of the fluids in the line would be much more rapid than in a buried landline. Thus, the thermal capacity of the surrounding environment must be considered. Figure 5.5 shows the fluid temperature with respect to the surrounding soil for a buried line for 50 and 300 hours following a shutdown as a function of distance along the line.

Shutdown problems can therefore be avoided if flow can be restarted with the available pumping pressure within a specified period of time.

Figure 5.5 Cooling In A Typical Buried Marine Pipeline

1.4.4 Testing Philosophy

There are a number of tests available to measure the wax content of a crude oil. Since it is not possible to define wax without reference to the conditions by which wax is separated, the wax content is an empirical value. For instance, wax material that is precipitated at 0C is likely to have a different composition than any material separating at 20C. BP defines the wax content of a crude as the weight of material precipitated when a solution of asphalt free crude is dissolved in dichloromethane and cooled to -32C.

The wax appearance temperature is that below which wax crystals form. In practice this means the temperature above which either a sample of crude or a wall in which it is in contact must be maintained in order to avoid wax deposition.

1.4.5 Crude Oil Pretreatments

The rheological (flow) properties of a crude oil depend to a large extent on the nature of the wax it contains. The nature of the wax, in turn, depends upon the temperature changes and the shear stresses that the sample suffered during the time that wax was precipitating from the crude. It is vital to ensure that the temperature and shear histories of a sample are well known before any measurements are made. Thus, BP uses four standard pre-treatments which cover a full range of the likely rheological behaviour that a sample could exhibit from highly viscous to minimum viscosity states. By measuring fluid properties (pour point, yield stress and dynamic viscosities) after samples have been subjected to these pretreatments, likely field behaviour during normal conditions and those following shutdowns, etc, can be identified. More details on wax management can be found in Appendix 7 of this completion design manual.

1.5 Asphaltenes

1.5.1 Description Of Asphaltenes

The term asphaltenes describes a group of compounds naturally present in crude oils whose chemical structures are complex and difficult to analyse. They are not fully understood and several theories exist to describe their chemistry and behaviour. Generally, they form part of the high molecular weight fraction of a crude oil that, along with maltenes constitute asphalt. The asphaltene fraction of a crude oil is usually defined as the heavy polar aromatic fraction that is soluble in hot aromatic solvents such as toluene, but insoluble in normal alkanes such as n-heptane.

Pressure changes are the main initiating factor in asphaltene precipitation and for cases showing a problem, it is likely to be most acute in the vicinity of the bubble point

There is a close relation between asphaltenes and the higher molecular weight resins and polycyclic aromatic hydrocarbons that exist in crudes. During geological timescales, heavy polycyclic aromatics oxidise to form neutral resins. Resins are described as the material that is soluble in the n-alkanes that precipitate asphaltenes, but are absorbed by surface-active materials such as Fuller's earth. Asphaltenes probably arise from further oxidation of resins. They contain a broad distribution of polarities and molecular weights and the material precipitated will vary with the solvent used. Therefore asphaltenes are classified according to the precipitant and no single molecular structure is appropriate. For instance, the standard IP test for the asphaltene content of a crude oil determines the n-heptane insolubles. Lower molecular weight solvents such as propane will precipitate larger amounts of material since the precipitate also contains some resin material. The resultant molecular weight of the precipitated material therefore can vary enormously from thousands to millions, depending upon the solvent. Analysis of n-pentane precipitated asphaltenes might typically show 80-85% by weight carbon of which 50-60% is aromatic, 7-10% hydrogen, and up to 10% sulphur, 3% nitrogen and 5% oxygen, plus traces of heavy metals such as vanadium and nickel. The nature of precipitated asphaltenes also varies between different crudes.

Figure 5.6 is an attempt at illustrating a typical asphaltine structure.

Figure 5.6 Hypothetical Structures For Asphaltenes Derived From Oils Produced In Different Parts Of The World

In crude oils the asphaltenes are not normally present in true solution. They have a very strong tendency to associate with themselves and resins and form aggregates. One theory suggests that asphaltenes are present in a micellar state in which there is a central core consisting of very high molecular weight asphaltenes with many condensed aromatic rings. This is surrounded by a region of sheets of lower molecular weight asphaltenes and resins strongly bound by electrostatic forces. As the distance from the central core increases, the number of condensed aromatic rings falls and there is a gradual transition to less polarity and less aromaticity. The result is an onion-like structure with layers of resins surrounding further layers of resin-like asphaltenes surrounding a central asphaltene core.

Others suggest that asphaltenes do not exist as cumbersome aggregates, but as single asphaltene molecules stabilised in solution by resins through hydrogen bonding.

1.5.2 Asphaltene PrecipitationAsphaltenes are only a problem when they are precipitated. Asphaltene deposits have been observed in production tubing, restricting flow and causing production declines. Tubing deposits can cause severe problems for wireline operations. They have also been seen in production equipment, such as separators, where asphaltenes have collected after having been precipitated further upstream. Asphaltene deposition in the reservoir has been reported causing permeability reductions or changes to wettability, resulting in lower recoveries. Downhole safety valve problems have been attributed to asphaltenes in BP's Ula field and other asphaltene problems have been encountered Clyde and in the Middle East in Kuwait.

To identify whether asphaltene precipitation is likely and where it may occur, the precipitation process itself must be understood.

The physical state of the asphaltene molecules or micelles in crude oil is determined by the stabilising nature of the resins. In the stable well-dispersed state, the asphaltenes are referred to as being peptized by resins and maltenes. Any operations that causes the stabilising layers to be removed can result in the unpeptized asphaltene molecules or micelle flocculating and forming a deposit. The stabilising effect of resins can be illustrated by the nature of the asphaltene precipitate formed when n-alkanes are added to a crude oil. Lighter alkanes can only remove some of the lighter outer resins which more closely resemble alkanes in structure. Longer alkane chain lengths are able to remove more of the peptizing resins, resulting in a precipitate with a lower molecular weight. Higher alkanes produce a precipitate containing a lower percentage of resins and consequently less precipitate.

The nature of the crude oil itself also has an effect. An aromatic oil will be a good solvent for the peptised asphaltenes while a paraffinic crude will be a poor solvent. The risk of asphaltene deposition is therefore a result of not only the amount of asphaltene and resin material in the oil, the but also of the solvency power of the oil for its asphaltenes. Crudes that are aromatic in nature and have a high resin content will be less liable to asphaltene deposition.

Asphaltene deposits can appear hard and coal-like, or more sticky and tar-like. The nature of the deposits is determined by the crude oil and the conditions under which precipitation occurred. For instance, if all stabilising resins are stripped away and asphaltenes precipitate, they will be composed of the high molecular weight, highly condensed core species. These pack closely together leading to a very hard deposit. If asphaltenes are precipitated by lighter n-alkanes, fewer of the peptising resins may be removed. The resultant deposit may be a very viscous sticky fluid that can contain entrained oil.

1.5.3 Determining The Risk Of Asphaltene Deposition

In order to establish the risk of asphaltene precipitation during oilfield operations, the crude oil must be characterised for its asphaltene content and its solvency for its asphaltenes, and then the effect of the external conditions determined. Typical assays include asphaltene and resin contents and their respective molecular weights. The solvency of a crude for its asphaltenes can be determined via either a flow through cell apparatus or using a laboratory titration technique. The main stages of assessing the risk of asphaltene deposition in a well are:

Sampling.

Determination of asphaltene and resin content.

Determination of the molecular weight of the asphaltene and resins.

Determination of flocculation onset.

Modelling.

Each of these is discussed in detail in Appendix 7 of this completion design manual.

1.5.4 Operational Variables Effecting Asphaltene Deposition

Once on production there are several variables which can impact the onset of asphaltene deposition in a well, including temperature, pressure, gas lift, acid stimulations, miscible gas injection, electric fields and commingling different crudes. The mechanism and impact of these are discussed in detail in Appendix 7 of this completion design manual.

1.6 Hydrates

1.6.1 Description Of Gas Hydrates

Hydrocarbon gas and liquid water can combine to form crystalline solids which resemble wet snow or ice under conditions of high pressure and low temperature. Joule Thomson cooling effects due to pressure drops are a key cause of hydrate formation in wells and process systems particularly during shut-down or start-up operations. These solids are called Gas Hydrates or more correctly Natural Gas Hydrates (NGH). The crystal structure is composed of cages of hydrogen bonded water molecules which surround 'guest' hydrocarbon gas molecules such as methane, ethane and propane.

Gas Hydrates are unusual in that they behave as solutions of gases in crystalline solids rather than as chemical compounds. No strong chemical bonds are formed between the hydrocarbon and the water molecules. The ratio water molecules to gas molecules can lie within the range 5.7 to 19. For methane hydrate (5.7 ratio), 15 wt.% of the hydrate is methane gas. NGH exists in two crystal structures; type I (small cavity) and type II (large cavity). The two structures are composed of different ratios of 12-, 14- and 16-faced water cages.

It should be noted that it is not necessary for a free gas phase to be present as long as the hydrate formers are present in the system.

Figure 5.7shows hydrate snow being removed from a condensate flowline (photo courtesy of Deepstar).

Figure 5.7 Picture Of A Gas Hydrate

Refer to the Well Gas Hydrate Handbook for Completions, Well Testing and Intervention on the web site at:

http://ut.bpweb.bp.com/GasHydrates/download/Gas Hydrates for Completions Well Testing and Interventions.doc1.6.2 Gas Hydrates Problems

Gas hydrate formation has been a major concern in oil and gas production systems ever since Hammerschmidt identified pipeline hydrates in the 1930s. Hydrates can form blockages in oil and gas pipelines and production facilities.

Preventing gas hydrates forming in pipelines and facilities costs the oil and gas industry millions of dollars each year.

1.6.3 Prevention Methods/Options

The present technical solutions available to prevent hydrate formation include; lowering the system pressure, methanol or mono-ethylene glycol solvents as thermodynamic inhibitors, tri-ethylene glycol contactors to dehydrate gas, and pipeline insulation/heating to keep the system warm and, hence outside the hydrate forming region. In recent years new low dose hydrate inhibitors have been receiving considerable industry attention. Replacement of the traditional thermodynamic inhibitors, methanol and glycol, is highly desirable from both commercial and Health and Safety considerations. The operating costs for these solvent-based inhibitor treatments are expensive, and the off-shore facilities for these treatments can be complex and logistically intensive. From a safety perspective, it is becoming increasingly unacceptable to store large inventories of solvent on offshore platforms. BP Exploration has been working for several years to develop a robust and cost effective low dose inhibitor technology which can be commercially deployed in its oil and gas production operations.

1.6.4 Hydrate Predictions And Modelling

To determine the conditions of temperature and pressure under which hydrates can form from a hydrocarbon stream with water, the best approach is to conduct careful experimental measurements on the appropriate fluid mixture. In practice, however, this is not always convenient and methods for predicting hydrate behaviour using thermodynamic models are particularly valuable.

In BP the 'Multiflash' software (Infochem Computer Services Ltd.) is used to carry out hydrate predictions in addition to other models, and relate the results to a variety of operational circumstances where hydrates may be a concern. Applications include; subsea flowlines, multiphase export lines, gas processing facilities, and drilling muds. Fluids treated have spanned dry gases, through condensates, to heavy oils.

The information required for a model prediction is a compositional model for the hydrocarbon stream together with details of water cut (only if very small) and salinity. Hydrate suppression using methanol or glycol can also be treated, allowing estimates to be made of dosing rates required to achieve specified operating conditions.

An important aspect of the modelling studies is the comparison of results with experimental data that have been obtained for fluids with similar compositions. This has provided a useful means of quality assuring the predictions, and to this end, a database of such experimental data has been assembled.

It should be noted that the predictions of all models of this kind are of hydrate dissociation, which represents a 'worst case' situation. The results are normally presented in terms of a hydrate curve, such as that shown below in Figure 5.8. Conditions of temperature and pressure to the right and below the curve correspond to regions where hydrates cannot form. To the left and above the curve are conditions where hydrates can form, and are increasingly likely to do so within a given time period, at points further away from the curve.

Figure 5.8 Hydrate Formation Curves

1.6.4.1 Low Dose Hydrate Inhibitors

Low dose hydrate inhibitors (LDHIs) can be classified into two categories: anti-agglomerates (AA) and kinetic inhibitors (KI):1.6.4.2 Anti-Agglomerates

Anti-Agglomerates (AA) also known variously as hydrate dispersants, hydrate slurry additives and hydrate growth inhibitor (HGI). AAs work by suspending hydrate crystals in the oil or condensate phase, thus dispersing hydrates and preventing agglomerations into solid plugs. Some AAs, such as Baker Petrolites RE-4136, are surfactants which attach to hydrate particles and disperse them as they form. Other AAs, such as IFPs Emulfip, are emulsifiers. Emulsifying AAs function by forming a tight water-in-oil emulsion which limits hydrate crystal size by separating the water and ultimately the hydrates into small droplets.

AA inhibitors will be operationally more complex due to having to deal with transport of a slurry. There will also be issues about decomposing the hydrate slurry at the receiving facility and achieving good water/oil separation. The current AA products (Shell chemistries) are based on quaternary ammonium chemistry and have some toxicity issues.1.6.4.3 Kinetic Inhibitors

KIs disrupt hydrate nucleation and/or microscopic hydrate crystal growth. This interference retards hydrate growth kinetics and consequently the hydrate induction time. The goal is to prevent significant hydrate growth beyond the residence time of the produced fluids. The induction time is the time between entering into hydrate-forming conditions and the onset of hydrate formation.

LDHIs are still a new technology in offshore oil and gas production. In certain situations, applications of KI and AA technology can be significantly lower cost than traditional control methods such as methanol or glycol treatments. This is because LDHI dosage levels can be 50-100 times lower than the dosage levels of thermodynamic inhibitors. These low KI and AA dosage levels translate into lower pumping, storage and transportation Capex and Opex costs. LDHIs can also provide an alternative technical solution, e.g. in situations where sufficient volumes of methanol cannot be injected due to umbilical or injection limitations (Troika - GoM). LHDIs can also offer desirable improvements in off-shore HSE, for example by removing, or greatly reducing, the inventory of flammable methanol/glycol solvents.

The BP web site below is to the gas hydrates website which contains additional information and useful references:

http://ut.bpweb.bp.com/GasHydrates/1.7 Emulsions

Emulsions can reduce production due to their high viscosities and may cause formation damage both in production and injection wells. An emulsion is a stable dispersion of two immiscible liquids (e.g. oil/water), in which one phase (dispersed phase) exists as fine droplets suspended in the other phase (continuous phase). The water in-oil emulsion is more common and problematic than the oil-in-water emulsions.

Emulsions are formed by mixing/agitation (i.e. by turbulence in the formation, at restrictions or in pumps). They are stabilised by surfactants (particularly cationic surfactants), asphaltenes or finely divided solids (e.g. wax and clays). Emulsions are characterised by droplet size distribution and stability. Smaller droplets give tighter or more stable emulsions. This is usually determined as water break-out versus time or measured by voltage resistance across an immersed electrode.

Emulsions can be broken by demulsifiers (eg, anionic surfactants), by dissolving the finely divided solids and by heat

Water-in-oil emulsions can hold up to 70% water and have viscosities that are orders of magnitude greater than the oil viscosity. This creates severe production problems, such as poor inflow, high pressure drops, slow rod fall and overloaded ESP motors. Continuous downhole emulsion formation can sometimes be prevented by better completion practices (i.e., more perforations), but usually requires continuous chemical injection below the tubing shoe or pump intake to break or invert the emulsion.

Injecting brines or acid into a formation with highly surface-active crudes (asphaltic or paraffinic) can produce severe emulsion blockage which is very difficult to treat. Including the proper combination of anionic or nonionic surfactants in treating fluids and using a spearhead of a suitable aromatic solvent can prevent such problems. The compatibility studies, specified in API RP 42, should be conducted on all completion stimulation and injection fluids to evaluate the emulsion risks.

1.8 Sulphate Reducing Bacteria

Sulphate reducing bacteria (SRB) are micro-organisms found in surface water that convert sulphates to H2S. They can create serious problems in any anaerobic (oxygen free) conditions, such as those downhole, and particularly with seawater injection. SRB can sour reservoirs, cause severe corrosion and plug injection wells. Souring sweet reservoirs may require replacement of tubulars and surface equipment not meeting NACE MR01-75 specifications for sour service where catastrophic failure as a result of sulphide stress cracking can occur. SRB are also cathode depolarizers (by accepting hydrogen ion) and, therefore increase corrosion rates. They also produce slimes and ferrous sulphides (a black solid) which may plug injectors.

Microscopic counts or cultural techniques are the most reliable methods for determining bacterial activity. API RP 38 provides methods for determining bacteria counts and evaluating biocides.

Bacterial control is achieved by regular biocide treatment of injection waters and specific treatment of drilling and workover fluids.

1.9 Wettability And Relative Permeability Changes

Changing the reservoir wettability from mainly water-wet to oil-wet can significantly reduce oil production rates and waterflood sweep efficiency, particularly for low permeability formations. Naturally water-wet rock (sandstone, carbonates, clays) can become oil-wet by adsorption of surfactants or precipitation of organic scales. Cationic surfactants (corrosion inhibitors) may cause sandstones to become oil-wet, and anionic surfactants (scale inhibitors) may alter the wettability of carbonate reservoirs.

Injecting oil into a gas zone reduces the relative permeability to gas (decreases gas saturation) and, thus, should be avoided. Similarly, increasing the water saturation in a tight rock can reduce oil relative permeability and cause a water block. Hence, liquid emulsions and foams are often used to fracture tight reservoirs, instead of water-based fluids.

Solvents can be used to restore wettability, and mutual solvents are used in acids to minimise relative permeability damage in tight rocks.

1.10 Completion Fluid Chemistry

The major cause of downhole chemical problems is the injection of completion fluids that are incompatible with the reservoir or formation fluids. Scale precipitation due to seawater injection, wettability alteration due to cationic surfactants, clay damage due to salinity changes, or emulsion formation are just a few examples. Acids require special considerations since the large fluctuations in pH can dissolve or precipitate many components, such as iron compounds or asphaltenes. Completion fluids must also be compatible with the wellbore components to prevent corrosion of the metals or deterioration of the seals.

Simple compatibility tests are adequate to identify many of these problems. Mixing completion fluids with reservoir fluids in a standard high-pressure mud cell at reservoir temperatures is an established technique.

Refer to section 2.

1.11 References

BP Production Chemistry Website

http://pwn.bpweb.bp.com//guide_test/default_prodchem.htmSampling Guidelineshttp://pwn.bpweb.bp.com/roadmap/sheets_htm/samplingguidelines.htmBP Recommended Test Procedures

http://ut.bpweb.bp.com/RTPManual/homepage.htmSqueeze Treatments

http://ut.bpweb.bp.com/scale/pred/squeeze.htm

Scale Powerpoint Presentation

http://pwn.bpweb.bp.com/network/assetnews/2000/AugSep00/downholescale.ppt

Hydrates

http://ut.bpweb.bp.com/GasHydrates/

Specifications For Sour ServiceNACE MR01-75

Fluid Compatibility Study (Emulsions)

API RP 42

Determining Bacteria Counts And Evaluating Biocides

API RP 38

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DENSITY: 800-1160kgm-345 - 10 APIWAX CONTENT0 - 50%wtPOUR POINT-20 - 50CVISCOSITY10 - 100,000 mPas (cP) @ 20CYIELD STRESS0 - Well above Pipeline Values

FIGURE 1

VARIABILITY OF CRUDE OIL PUMPABILITY DATA

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