Appendix 7 Production Chemistry Reference Documents

BP Exploration

Appendix 7 – Production Chemistry Reference Documents

APPENDIX 7

PRODUCTION CHEMISTRY REFERENCE DOCUMENTS

Oilfield Wax

Asphaltenes

Water Chemistry & Scale

BP Exploration


BP Exploration


APPENDIX 7 PRODUCTION CHEMISTRY REFERENCE DOCUMENTS

OILFIELD WAXES

INDEXPage No.

1. INTRODUCTION TO WAX 1

2. PIPELINE FLOW CHARACTERISTICS FOR CRUDE OILS 1

2.1 Introduction2.2 The Questions to be Answered

2.3 Experimental Parameters2.3.1 Pour Point2.3.2 Viscosity 2.3.3 Yield Stress (Pipeline Start-Up)

2.4 Destroying Sample Past History

2.5 Modelling Pipeline Systems2.5.1 General Purpose Model2.5.2 Modelling Static Cooling of a Buried Pipeline

2.6 Overcoming Pumping Problems2.6.1 Insulating or Heating Flowlines2.6.2 Dilution2.6.3 Thermal Pre-Treatment2.6.4 Oil-in-Water Emulsion2.6.5 Core Flow2.6.6 Local Crude Oil Processing2.6.7 Chemical Additives

3. WAX DEPOSITION IN CRUDE OIL PIPELINES 7

3.1 Introduction

3.2 Mechanisms of Wax Deposition3.2.1 Molecular Diffusion3.2.2 Shear Dispersion3.2.3 Gravity Settling

3.3 Appropriate Laboratory Measurements3.3.1 Wax Content3.3.2 Wax Appearance Temperature3.3.3 Wax Deposition Tendency

3.4 Prediction Deposition Rates in Pipeline Systems

Page 1

BP Exploration


3.5 Controlling Wax Deposition3.5.1 Pigging3.5.2 Chemicals3.5.3 Hot Oil Flushing

FIGURES 1-20

Page 2

BP Exploration


1. INTRODUCTION TO 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, ie that the viscosity of the oil depends upon the shear rates applied to it. A good common example of this is household non-drip paint. Here, under low shear the paint does not flow (ie 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. 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 fluid temperature falls, 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.

Each of these phenomena are discussed below.

2. PIPELINE FLOW CHARACTERISTICS FOR CRUDE OILS

2.1 Introduction

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 1. If a crude has a pour point of 50°C, but the flowing fluid temperature in the line is only 40°C, there is potentially a pumping problem. 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 (ie two-phase (gas/liquid) flow). Neither is it sufficient to consider only normal flowing conditions. Unfortunately, periodic shut-ins are inevitable, whether planned or unexpected. If the fluids stop flowing in the line, heat transfer to the pipewalls and into the environment could cool the pipeline fluids significantly. For instance, over a period of days shut in, the temperature of the contents of a subsea pipeline could fall to that of the surrounding sea water. This could be as low as -2°C in regions subject to Arctic currents. The characteristics of the crude at these low temperatures may differ considerably. Generally low temperatures increase viscosity, but in the extreme, some crudes can form a gel structure which requires considerable pumping pressure to move and restart flow.

2.2 The Questions to be AnsweredIn a real system, fluids, their flow rates and the environment surrounding the pipeline may all affect pumpability problems. We therefore need to address the following:

(a) What are the flowing (equilibrium) pressure, temperature and flow characteristics?

Page 3

BP Exploration


Crude oil flowing temperatures fall along the length of the line. Thus, its viscosity increases away from the pipeline inlet. Figure 2 shows typical temperature profiles for different flow rates and how the local environment affects the profile.

The flow rates determine the type of flow which also has a large effect on the viscosity. Figure 3 describes the pressure drop across a pipe 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 under which many crudes show Newtonian like behaviour. 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. The applied shear stresses are lower, and this enables temperature to dominate the viscosity of the crudes. Thus, the pressure across the pipeline is much greater for the viscous than the fluid crudes.

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

The viscosity of the crude oils can increase to a point that they exhibit a yield stress. That is 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.

(c) 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 land line. Thus, the thermal capacity of the surrounding environment must be considered. Figure 4 shows the fluid temperature with respect to the surrounding soil for a buried line for 50 and 300 hours following a shut-down as a function of distance along the line.

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

2.3 Experimental ParametersIn order to characterise the crude oils, there are several measurements that can be made in the laboratory.

2.3.1 Pour PointThis defines the temperature below which flow may not occur. It is a very widely used, simple test but provides only a rough guide and is of no use in quantitative predictions.

2.3.2 ViscosityCrude oils, particularly the more viscous ones, become non-Newtonian at lower temperature. That is, viscosity depends upon "speed" or rate of shear as well as temperature. Rate of shear is the velocity gradient normal to the direction of flow. In a pipe this is zero at the centre and maximum at the pipe wall. The following equations describe shear rate for two different flow regimes:

DL8x(MeanSpeed)

Diameter Laminar Flow

DT D

L x 0.0048x(ReynoldsNo) Turbulent Flow

Page 4

BP Exploration


NB: for turbulent flow Reynolds No. >2200.

Typical pipeline rates of shear are between 1 and 1000s-1.

Viscosity should be measured in concentric cylinder viscometers such as the Ferranti Portable, Brookfield UL or Haaka Rotovisco. A range of different flow rates and temperature should be covered in order to simulate pipeline flow. Figure 5 shows a family of typical results obtained for a 'non-Newtonian' crude.

2.3.3 Yield Stress (Pipeline Start - up) This is measurement of the force needed to start flow again following a shut-down. It is conducted in a model pipeline (see Figure 6), in which the oil is cooled to the tests temperature in a similar manner to that which would occur in a pipeline on shut-down. A small pressure is applied, and if no flow is detected from movement in the oil level a higher pressure is applied. The restart pressure at which flow is first detected (a movement of 20mm during 15 minutes) is then gives the yield stress. This model pipeline restart pressure can be scaled up to full size pipelines via the pipe wall shear stress:

S ShearingForcePipeWallArea

(PressurePa)x(Diameterm)4x(Lengthm)

Paw

For 1000psi across 10km of 10 inch line SW = 4.4 Pa. This is equivalent to 6psi across the model pipeline in Figure 6.

This simple scale-up is complicated in reality by the presence of void spaces and many other factors. However, it is still a very useful quantitative guide. A safety factor of about times 2.0 is normally applied.

2.4 Destroying Sample Past HistoryThe pour point, viscosity and yield stress as measured today depend very much on the previous thermal and mechanical history of the oil. This is because this may have generated wax crystals of different shapes and sizes dispersed throughout the sample. Additionally, the rate at which the sample is heated or cooled, or the mechanical shear it is subjected to may affect these wax structures. Figure 7 indicates how previous history and how the sample is subsequently handled alters the measured viscosity.

Therefore to make meaningful and comparable measurements, these structures must be destroyed, and the samples returned to their 'reservoir state' before they had been subjected to such history. This is done by heating the sample to a temperature sufficient to melt the wax crystals and return the wax to solution. The process is known as beneficiation. Then, by cooling in a controlled manner, comparative viscosity and yield stress measurements can be made.

Figure 8 shows a typical laboratory simulation. Here the sample is heated to 80°C for 1 hour, then under appropriate shear rates cooled at a rate of 15°C per hour to 45°C (simulating flow to platform), warmed to 65°C at a rate of 15°C per hour (simulating platform processing), a pour point depressant added, then, again under appropriate shear, cooled at three different rates (simulating pipeline flow) before loading into the viscometer to measure viscosity. Thus, the behaviour towards the end of the pipeline can be effectively determined.

In any process, the key parameters are cooling rate, temperature cycles and mechanical shear.

Page 5

BP Exploration


2.5 Modelling Pipeline SystemsComputer programs link laboratory measurements to full scale predictions. The associated theory is a combination of fluid dynamics and heat transfer. Over many years Sunbury have developed a number of programs, which have been validated in practical applications.

2.5.1 General Purpose ModelThis programme (S007) can account for pressure, temperature and flow calculations. For instance, typical studies may include:

(a) Temperature profile along the length of a pipeline using heat transfer correlations for:

Oil to pipePipe and insulation or concrete coating conductivityPipe to air or water (and part buried)Conductivity through ground or sea-bed (fully buried)Transfer from ground to air or sea-bed to water.

(b) Pressure drop calculations for:

Laminar flowSmooth turbulent flow (Blasius correlation)Rough turbulent flow (Colebrook-White correlation)

(c) Non-Newtonian behaviour accounted for by using viscosity measurements under shear rates matching those at pipe wall in Newtonian equations.

(d) Some assessment is also made of the increase in flow rate as cold oil is displaced by warmer oil during start-up.

This programme can handle two-phase flow if it assumes that this flow is homogeneous. It assumes that the mixture can be treated as a single fluid but of variable density, but does not take account of complete separation of the gas and liquid phases ("slugging", etc.)

Input data are laboratory measured viscosity (over appropriate temperature and shear rate range), pipe dimensions, thermal conductivities and other physical parameters.

2.5.2 Modelling Static Cooling of a Buried PipelineThis programme SQ13/19 predicts the temperature at different distances from the pipe centre, both in the pipe and in the surroundings as a function of time following shut-down. It is based upon on the finite difference and Schmidt approximation technique. Inputs required are basic physical conductivity data.

2.6 Overcoming Pumping ProblemsThere are a number of ways to alleviate pumping problems. For example:

2.6.1 Insulating or Heating FlowlinesIncreasing the fluid temperature may be prohibitively expensive, particularly by heat tracing flowlines. If relying solely on insulation, this may not overcome problems following a shut-down, since cooling still occurs albeit more slowly.

Page 6

BP Exploration


2.6.2 DilutionDiluting the viscous or heavy crude with a either a lighter crude or refined light fraction will aid pumpability, but may be impractical, particularly if the diluent must be transported to the right place.

2.6.3 Thermal Pre - Treatment The sensitivity of waxy crude oils to thermal and mechanical history (see Figure 7) can be turned to advantage by applying beneficial pre-treatments in the field. This is the basis of a BP developed process, which has been used for many years in the Indian Nahorkatiya field. In essence a lower viscosity state can be achieved if the waxy crude is cooled statically under controlled process conditions as opposed to dynamically under flowing pipeline conditions. Clearly this will not be an option in many cases.

2.6.4 Oil - in - Water Emulsion The viscosity of an oil-in-water emulsion is very much closer to that of water than it is oil (see Figure 10). With a suitable surfactant, such an emulsion can be deliberately formed, reducing pumping pressures accordingly, (see Figure 11)

Conversely, a water-in-oil emulsion can have a viscosity greater than the oil. Thus, if produced fluids are transported for some distance before processing, pumping pressures may simply rise as a function of water cut. Work is now underway to examine how viscosity of these emulsions varies with temperature, shear stresses and water cut.

2.6.5 Core FlowIf a layer of water can be maintained at the pipe wall very viscous oil can flow as a plug or solid core. All of the shear occurs in the water, which acts as a lubricating layer. This technique, developed by Shell, has been used in Indonesia. The annular ring of water is first created by a special injection system. An extension to this is to use surfactants in the water to keep the pipe wall water wetted and keep the water and oil apart.

2.6.6 Local Crude Oil ProcessingIn some instances, heavy crude can be processed in the field before transport, for example by separating the heavier fractions. The economic consequences need careful consideration even if the separated fractions have a subsequent use such as local energy production.

2.6.7 Chemical AdditivesThere are two main chemical types that are used to affect flow properties; pour point depressants and drag reducers. They operate by two totally different mechanisms.

1. Pour Point Depressants

These are chemical additives that influence the shape of wax crystals and therefore the viscosity and yield stress of a crude oil as it is cooled. They can significantly reduce both normal pumping pressures and yield stress after an extended shut-down. However, they must be injected while the oil is still hot, before wax crystals are first formed. Their performance depends very much on crude type and the additive itself, and there is no guarantee that a suitable pour point depressant can be found for every waxy crude. However, viscosity or yield stress can be significantly improved. Figure 12 shows a typical effect upon the characteristics of a crude oil. Figure 9 shows typical performance data for pour point depressants.

Page 7

BP Exploration


It should be noted that additive doped waxy crude is even more sensitive to mechanical shear. Some additives perform excellently in the absence of shear and not at all with shear. Evaluation of additives is therefore a complex process.

Typically, pour point depressants are polymers at concentrations of 20-50 percent in a hydrocarbon solvents (e.g. toluene). Injection rates of as high as 100-1000ppm are commonly required. Therefore this is not a cheap option, and chemical costs alone can run into thousands of dollars a day. However pour point depressants have been used economically in the Indian Bombay High and North Sea Beatrice fields.

2. Turbulent Drag Reducing Additives

Turbulent flow is characterised by fluid moving in irregular random motions transverse to the direction of flow. Eddy currents are generated at the pipe wall and grow in size as they move into the mainstream flow resulting in energy dissipation in the fluid and hence frictional pressure losses in pipelines. Flow in crude oil and oil product pipelines is usually turbulent with Reynolds Numbers normally at the upper end of the range 103 - 106. Drag reduction is the proportional reduction in the pipeline pressure drop when a drag reducer is injected into the pipeline. These chemicals work by reducing the frequency of turbulent eddy bursts from the pipe wall and hence stabilising the wall layer. The rate of energy dissipation within the turbulent eddy flow is reduced and the frictional drag and hence pressure drop in the pipeline is reduced.

If pipelines are operating at their maximum line pressure, drag reducers may provide an attractive alternative to uprating the line. Figure 13 shows data of how the flowrate can be increased for the same pumping pressure. Alternatively, if flow rates are limited by available pumping pressures, applying a drag reducer may be cheaper than upgrading pumps. Figure 14 shows data on the increased flowrate achieved by drag reducer addition. In the Trans Alaska Pipeline, drag reducers have increased throughput from 1.4-1.65 million b/d for the same pumping pressures and pipeline conditions. Another possibility is using drag reducers to increase pumping efficiency and allow booster pumping stations to be shut down. Recent applications include in water injection wells where the benefit of increased water injection has more than offset the cost of the chemical.

Drag reducing additives are high molecular weight polymers, usually with molecular weights of at least 5 x 105. They work by reducing turbulent flow losses and hence frictional pressure drop within the flowing oil and do not coat the pipe wall nor change the bulk oil properties as viscosity improvers or pour point depressants do. A common type of drag reducers are the non-crystalline polyalpha-olefins. They are oil soluble and form 'snake like' long chain structures in the flowing oil which interact to reduce the frequency of turbulent eddy bursts at the pipe wall. They are usually supplied as highly viscous fluids containing around 10%wt of active polymer dissolved in a kerosene carrier. For crude oil pipelines they should be oil soluble, must not be broken down by mechanical shear such as in centrifugal pumps and have no downstream effects on refinery equipment or on refinery products.

The effectiveness of a drag reducer is expressed in terms of the percent drag reduction. At a given flow rate the percent drag reduction is defined as:

%DRDP DP

DPx100DR

(1)

Page 8

BP Exploration


where P is the pressure drop of the untreated oil and PDR is the pressure drop of the oil containing drag reducer.

Alternatively a drag reducer can be thought of increasing the flow for the same pipeline pressure drop. The percent flow increase can be defined as:

%FIQ QQ

x1001

1

2 (2)

where Q2 is the increased flow rate with drag reducer and Q1 is the original pipeline flow rate.

The relationship between percent drag reduction and percent flow increase can be estimated from the percent drag reduction using the equation:

Page 9

BP Exploration


%Fl1

1−%DR100

⎛

⎝

⎜ ⎜ ⎜

⎞

⎠

⎟ ⎟ ⎟

0.55

−1

⎡

⎣

⎢ ⎢ ⎢ ⎢

⎤

⎦

⎥ ⎥ ⎥ ⎥x100

Page 10

BP Exploration


(3)

Equation 3 assumes the pressure drop for both the treated and untreated oil is proportional to flow rate raised to the 1.8 power. Figure 12 shows typical flow increases and drag reductions for both a light and a heavy crude oil.

Note that drag reducers have no effect on frictional pressure losses in laminar flow.

Drag reducer performance can be affected by either the properties of the oil in the pipeline or the pipeline construction as follows:

1. They work best with lower viscosity oils. Hence higher temperatures therefore improve performance (Higher temperatures may also increase the solubility of the drag reducer, providing additional benefit)

2. Performance is impaired by high water contents or high levels of dispersed wax crystals.

3. Smaller diameter pipelines will generally have greater turbulence and therefore improve drag reducer performance.

4. If susceptible to mechanical shear, sharp bends, valves, or orifice plates could reduce drag reducer performance. Main pipeline pumps are likely to completely degrade drag reducing polymers. This impacts upon the location of the injection points.

3. WAX DEPOSITION IN CRUDE OIL PIPELINES

3.1 IntroductionIn addition to affecting the flow properties of a crude oil, wax can also be deposited. This can occur if the internal surface of the pipeline falls below the wax appearance temperature of the crude, ie the temperature at which wax crystals first start to form. Wax can accumulate on the pipewall and if left untreated built-up into a wax layer. This increases the surface roughness at the pipe wall and leads to an increase in frictional pressure drop across the pipeline when the fluids are in turbulent flow (as is the case under normal operating conditions). The wax layers can also reduce the effective cross sectional area of the pipe causing a loss in throughput in systems which are pressure limited.

For example wax deposition in the first Forties pipeline caused a steady pressure drop increase of about 4% per day unless remedial measures were taken.

To assess the risk of wax deposition, firstly, the crude oil is examined for its wax content, the temperature at which wax is first observed, and the rate at which it can deposit wax onto a cooled surface. The laboratory generated data is subsequently used in pipeline models to simulate the real system. The model can then predict the wax build up in a pipeline, and the consequential pressure drops that could occur. Such information is required to assess how regularly remedial treatments are required, and hence estimate likely operating costs.

In reality, wax deposits frequently include entrapped oil, and other solids such as asphaltenes, sand, corrosion products or inorganic scale. They may be relatively soft and easily removed or dense, hard deposits.

3.2 Mechanisms of Wax Deposition

Page 11

BP Exploration


In a pipeline operating under turbulent flow, there is a laminar boundary layer adjacent to the pipe wall and a turbulent core in which temperature, velocity and wax concentration are almost independent of radial position. Over the laminar sub-layer there is a high rate of shear, and a high temperature gradient, usually cooling towards the pipewall. The rate of wax deposition is determined by what happens in this laminar region.

There are two principal mechanisms by which wax deposition is thought to take place, namely molecular diffusion and shear dispersion. Molecular diffusion transports wax which is in solution and precipitates it directly on the pipewall. Shear dispersion transports solid particles of wax already precipitated in the turbulent core to the pipewall. Each is discussed below.

3.2.1 Molecular DiffusionAs a crude oil is cooled the solubility of the crude for its wax falls. At a particular temperature (characteristic of each crude) the wax reaches its saturation point and begins to precipitate out. This is the cloud point or wax appearance temperature. If the temperature of the pipewall is less than this, molecular diffusion can take place, wax will precipitate out directly on the cold pipewall. Across the laminar boundary layer there is a temperature gradient, which results in a wax concentration gradient between the dissolved wax in the turbulent core and the wax remaining in solution at the pipe wall. This causes dissolved wax to diffuse towards the pipe wall where it is subsequently precipitated. Since the pipe surface is inherently rough, it provides suitable nucleation sites and the precipitated wax becomes incorporated into an immobile layer.

The rate of transport of dissolved wax to the pipe wall is given by Ficks diffusion equation:

n DdCdr

D dCdT

dTdr

where

n = mass flux of dissolved wax molecules to the pipe wall (kg/cm2).

r = density of solid wax (kg/m3).dCdr

= concentration gradient of dissolved wax with respect to distance from pipewall (∞C/m)dCdT

= concentration gradient of dissolved wax with respect to temperature (∞C-1).

dTdr

= radial temperature gradient close to the pipewall (∞C/m).

The diffusion coefficient for a crude oil is inversely proportional to the crude's dynamic viscosity:

D = B/

where B = constant for a particular crude (N). = dynamic viscosity of crude oil (Ns/m2).

If the crude and the pipewall are above the wax appearance temperature, the oil is under-saturated with dissolved wax and the concentration gradient of the dissolved wax is zero. However, as the temperature of the oil at the pipe wall falls below the wax appearance point there is a small

Page 12

BP Exploration


concentration gradient and deposition will take start.

The wax diffusion coefficient and the radial temperature gradient both fall as the oil temperature falls in a pipeline. Therefore wax deposition rates are at a maximum when the bulk oil temperature is high, and fall as the crude cools towards the temperature of the environment. Thus, if the fluids are at the same temperature as the pipewall, there is no molecular diffusion, and wax buildup cannot occur by this mechanism. There is thus a wax deposition profile along the length of a pipeline, depending upon the temperatures of the fluids and the pipewall. These two parameters are themselves determined by the nature of the fluid, its flow rate, the material of the pipeline and the environment surrounding the line.

3.2.2 Shear DispersionSmall wax crystals suspended in a flowing crude, are carried at the same speed and in the same direction as the fluid. The higher shear rates at the pipewall, however, cause some lateral movement, known as shear dispersion. Thus wax particles already precipitated out in the fluids can form a deposit on their own or combine with wax already deposited by molecular diffusion. Since shear dispersion transports solid wax particles, there is no tendency for nucleation to occur at the pipe surface. This tends to cause less tenacious deposits than those formed by molecular diffusion. Shear dispersion becomes important only when the precipitated wax content in the turbulent core is high, that is when the bulk oil temperature has fallen well below the wax appearance point.

Page 13

BP Exploration


The parameters that affect the shear dispersion mechanism are: the wall shear rate, the amount of wax out of solution and the shape and size of the wax particles. Whilst an increase in shear rate should encourage more wax particles to disperse towards the pipe wall, the same wall shear stress may increase the rate at which these loosely held deposits are stripped away.

3.2.3 Gravity SettlingThere is a third, although rather less important mechanism by which wax can be deposited from a crude in a pipeline. Wax crystals tend to be more dense than the bulk fluids. Although turbulent flow is more than able to overcome gravity and keep the wax crystals suspended, if flow stops the wax can settle out. The amount of wax that can deposit in a pipeline is low and usually will redisperse once flow is re-started and the fluids heat up once more. Thus, gravity settling tends to be a problem only in storage tanks.

3.3 Appropriate Laboratory MeasurementsIn determining the risk of Wax deposition, several laboratory measurements are used.

3.3.1 Wax ContentWax contents may only be assigned with reference to the conditions under which the wax is separated. For instance, wax separated from a crude oil at 0∞C is likely to have a different composition to that separated at 20∞C. BP defines the wax content from the weight of material precipitated when a sample of asphalt-free crude is dissolved in dichloromethane and cooled to -32∞C.

3.3.2 Wax Appearance TemperatureThe wax appearance temperature is that below which wax crystals are precipitated. This may be determined visually through optical microscopy through crossed polars or by differential scanning calorimetry which measures heat changes on precipitation of wax.

3.3.3 Wax Deposition TendencyThe basis of laboratory measurements lies in building up actual wax deposits on cooled surfaces in test cells under controlled conditions. By measuring the daily wax build-up on the plate, M, and the average heat transfer through the plate, H, the deposition tendency M/H of the crude can be measured for particular plate temperatures. This provides measured an estimate of the daily rate of wax build-up per unit of heat transfer and is characteristic of each crude. By knowing the heat transfer rate through a pipe wall, we can predict the likely deposition rates in the field, based upon laboratory generated data.

The simplest deposition cell is a static cell (Figure 15) which comprises a water-cooled flat box which is immersed in a reservoir of oil maintained at approximately 8°C warmer than the depositing plate surface. The inlet and outlet temperatures of the coolant are monitored together with its flow rate throughout the test. The oil and plate temperatures are also monitored. Each test is normally run for a period of six hours after which time the cell is dismantled and the deposit is inspected, removed and weighed and the daily mass of wax deposited, M can be determined. The average heat transfer H is calculated by:

H = T x Q x C

where DT is the difference between the inlet and outlet temperatures of the coolant.Q is the flow rate of coolantC is the specific heat of the coolant.

To simulate full scale conditions more accurately, deposition tests are performed under shear. For

Page 14

BP Exploration


these measurements a coaxial shearing cell (Figure 16) is used which comprises a water cooled stationary inner cylinder around which an outer cylinder rotates to impart the appropriate rate of shear to the oil in the 6mm gap between the cylinders. This arrangement closely simulates full scale pipeline deposition in that the cooled surface is subjected to the highest rate of shear. The test procedure is similar to that described for the static cell.

Generally stabilised crude samples are used to determine deposition rates, but the effect of dissolved gas can be established from tests in a pressurised shearing cell. The design is similar to a coaxial cell, but the equipment is rated to higher pressures to simulate more closely the situation in field pipelines.

Wax deposition will also be affected by the flow type. For instance, in a multiphase line, gas slugs may travel the length of the pipeline. These slugs will alter the shear stresses at the pipewall, affecting the rate of wax deposition, or even stripping off wax already deposited. Deposition in multiphase lines is the next big where research is needed to understand the effects.

To predict wax deposition throughout a pipeline system, a series of deposition rate laboratory tests are needed covering the temperatures likely to be encountered. Figure 17 shows typical deposition curves as measured under static and shear conditions for stabilised crude and also under shear conditions with "live" crude spiked with gas at 350psi. It is interesting that dissolved gas tends to reduce the deposition tendency. A crude with its dissolved gas will be less viscous, and hence should increase the rate of deposition from molecular diffusion. Clearly, the gas has a greater effect upon other factors, although this is poorly understood at present. Results also indicate that deposition is reduced under conditions of shear. Figure 18 shows how the deposition tendency decreases with increasing shear as measured in a coaxial cell. This phenomena could be due to an increase in shear dispersion, but is probably due to wax deposits already formed being stripped off at higher wall shear rates, even though molecular diffusion may be higher. This balance between an increased rate of deposition and the possibility of stripping off deposits is why these laboratory measurements are required and that field conditions should be matched as closely as possible.

3.4 Prediction Deposition Rates in Pipeline SystemsBP has developed a model to predict deposition rates in pipeline systems (based upon Fick's diffusion equation and molecular diffusion theory) using the laboratory wax deposition tendency data. Figure 19 shows typical wax profiles in mm/day wax build-up down the line in the first Forties export line for flow rates of 450,000 bbl/day and 600,000 bbl/day. At 450,000bbl/day deposition is not predicted until some 40km down the line. Until this point the fluid temperature maintains the pipewall at above the wax appearance temperature. Deposition rates rise quickly from this point but then fall off again further down the pipeline where the fluid temperature falls closer to that of the pipewall. The total daily deposition rate in the line was predicted to be 19 tonnes/day. At 600,000 bbl/day, the increased flowrate alters the temperature profile, the location inn the line where deposition first occurs and the overall rate at which wax deposits.

The wax is assumed to be distributed evenly over the depositing region, increasing the surface roughness by an amount equal to the thickness of the wax layer. By using a Colebrook-White correlation which takes into account the inherent roughness of the pipe wall, the increase in friction factor and hence pressure drop can be estimated from the predicted increase in pipe wall roughness. Hence the model will also produce pressure drop profiles of a pipeline.

Page 15

BP Exploration


As the wax layer is allowed to accumulate, it will act as an insulating layer thus reducing heat transfer. This will subsequently reduce further deposition by increasing the temperature at the depositing surface and reducing the temperature gradient in the boundary layer. Therefore, the initial deposition rate drops off until the wax layer is thick enough to insulate sufficiently to create no temperature difference between the fluids and the depositing surface.

In pipelines which are submarine and concrete coated, the heat transfer will be limited by the concrete and not by thin layers of wax which form on the pipe wall. This means that the equilibrium thickness is likely to be unacceptably high from an operational point of view. However, there are other effects which impact upon the equilibrium thickness. As the thickness of the wax layer increases, the shear stresses at the depositing surface increase. Whilst this may increase the rate at which wax is brought to the surface by shear dispersion, the shear may be sufficient to strip off further wax. Thus, the equilibrium thickness may not be that predicted from molecular diffusion alone. Work is currently examining these longer term effects.

3.5 Controlling Wax DepositionThe three most common methods of controlling wax deposition are:

3.5.1 PiggingThis is the most commonly used method for removing wax deposits accumulated on the pipe wall. The pig is sent down the line, carried along by the flow of crude, and mechanically scrapes off the wax and redisperses it in the bulk oil in front of the pig. The pig is unlikely to completely remove the wax deposits but leaves behind a smooth layer which reduces pipe wall friction and hence pressure drop.

3.5.2 ChemicalsPigging may be operationally inconvenient or even impossible and an alternative method of the wax removal is required. Chemical additives can provide an effective means of controlling wax deposition. However, there is no universal wax inhibitor and to identify the most effective additive the chemicals must be tested under the specific operating conditions for which they will be used. Figure 20 shows how simply temperature can affect the performance of several inhibitors. One of these additives actually increased deposition at certain temperatures.

Generally, complete inhibition of wax deposition is economically not feasible and it is more efficient to slow down the deposition process and periodically remove the built-up wax deposits using an alternative method such as pigging. There are three main types of chemicals:

(i) Wax Crystal Modifiers or Wax Inhibitors

Wax crystal modifiers inhibit deposition by co-crystallising with the wax crystals and preventing structured lattices from forming at the pipe wall. Most will only slow down the process of wax deposition and will not completely inhibit the formation of wax deposits. Thus it is usually still necessary to pig the line occasionally. Some inhibitors may reduce the amount of wax deposited but can make it harder to remove the wax that does deposit. This is because these crystal modifiers do not influence the higher molecular weight waxes.

Page 16

BP Exploration


(ii) Dispersants

These chemicals are usually added to remove existing deposits, but can also inhibit wax deposition. They chemically coat small wax particles and decrease their tendency to stick together at the pipe wall. A good dispersant can penetrate an accumulated mass of wax, coat individual particles and allow them to move freely into the surrounding oil.

(iii) Surfactants/Detergents

If the crude oil contains produced or added water then paraffin surfactants can be very effective in removing or inhibiting wax deposition. These additive cause the wax crystals to become "hydrophilic" so they preferentially adhere to the water molecules and not to each other or the pipe wall.

3.5.3 Hot Oil FlushingAn increase in flowing temperature and flow rate will encourage wax removal even in the absence of any wax dispersant, by "softening" the wax on the wall and making it unstable and easy to remove. If flowing temperatures are increased significantly (~10°C) with no increase in shear, laboratory test results show that wax layers can be completely and quickly removed. The effectiveness of hot oiling in a pipeline system as a removal mechanism will depend on the hardness, wax/oil ratio and resilience of the wax deposits.

Page 17

BP Exploration


ASPHALTENES

INDEX

Page No.

1. INTRODUCTION

1.1 What are Asphaltenes?1.2 Asphaltene Precipitation

2. DETERMINING THE RISK OF ASPHALTENE DEPOSITION

2.1 Sampling2.2 Asphaltene Content2.3 Resin Content2.4 Molecular Weight of Asphaltenes and Resins2.5 Onset of Asphaltene Flocculation

2.5.1 Flow Through Visual Cell2.5.2 Asphaltene Flocculometer

2.6 Modelling

3. ASPHALTENES IN OILFIELD OPERATIONS

3.1 Effect of Temperature3.2 Effect of Pressure3.3 Effect of Gas Lift3.4 Effect of Acid Stimulations3.5 Effect of Miscible Gas3.6 Effect of Oxidation3.7 Effect of Electric Fields3.8 Effect of Mixing Different Streams

4. TYPICAL ASPHALTENE STUDIES

4.1 Pipeline Studies4.2 Ula Asphaltene Deposition Study4.3 The Effect on Asphaltene Precipitation of Miscible Gas

5. TREATING ASPHALTENE PROBLEMS

5.1 Chemical Treatment5.5.1 Dissolving Precipitated Asphaltenes5.5.2 Asphaltene Inhibitors

5.2 Plastic Coatings5.3 Engineering Solutions5.4 Operational Changes

6. REFERENCES

FIGURES 1-12

Page 18

BP Exploration


1. INTRODUCTION

1.1 What are 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 various 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". Boussingault, in 1837, first used the word "asphaltene" to describe that part of a crude oil distillation residue that was insoluble in alcohol, but soluble in turpentine, since its appearance was similar to that of the original asphalt. Now, 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.

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 1 is an attempt at illustrating a typical asphaltene molecular structure.

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. Figure 2 illustrates this. Others suggest that asphaltenes do not exist as cumbersome aggregates, but as single asphaltene molecules stabilised in solution by resins through hydrogen bonding.

Page 19

BP Exploration


1.2 Asphaltene Precipitation

In the oil industry, asphaltenes 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 to 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. Figure 3 shows the molecular weight of the asphaltene precipitated by a homologous series of n-alkanes. 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. Figure 4 illustrates how much of an asphaltenic crude can be precipitated by alkane solvents from propane to n-heptane. Higher alkanes produce a precipitate containing a lower percentage of resins and consequently less precipitate. These figures do not illustrate the amount of alkane required to form a precipitate, nor the weight of precipitate for a given volume of alkane.

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.

Page 20

BP Exploration


2. 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. Each is discussed below. Before any characterisations are undertaken, it is important that a representative sample of crude is taken.

2.1 Sampling

Studies have shown that asphaltene precipitation can be essentially irreversible. Once the intermolecular force which stabilises the asphaltene resin micelle is broken, the precipitated asphaltene cannot be easily resolubilised. Therefore, to obtain a representative sample from which to determine the risk of asphaltenes the oil must not have lost any of its asphaltenes. To achieve this, samples must be taken at pressures above the bubble point and maintained single phase. When the fluids are below their bubble point in the reservoir, this is clearly impossible. Even when the bubble point falls in the production tubing between the perforations and the wellhead it is not easy. Frequently, only wellhead samples are available. Wellhead samples may have lost some asphaltenes, however, providing the well has been flowing for some time, the amounts lost are likely to be only a fraction of the total asphaltene content. Once sampled, further asphaltene deposition should be avoided. This could be achieved by sampling into a high pressure vessel, and pressurising the sample to above its bubble point.

2.2 Asphaltene Content

The asphaltene content of an oil can be determined by the IP laboratory test method IP 143, [1]. This method extracts asphaltenes and the waxy fractions from a crude oil using n-heptane. Asphaltenes are then extracted into toluene, which is finally evaporated off leaving the solid weight of asphaltenes. The asphaltene content of a crude oil is insufficient alone to predict the likelihood of asphaltene precipitation, and as such is of limited value without further information.

2.3 Resin Content

Resins provide a protective shield around the asphaltenes to prevent them from aggregating and precipitating. When this resin encapsulation shield is removed by addition of n-alkanes, asphaltene precipitation takes place. It is important to establish the balance of the asphaltene and resin fractions of the crude since this information is essential to identifying the instability of a stock tank crude sample.

The resin content of a crude can be measured by an HPLC technique. Resins are isolated on an amino propyl normal phase HPLC column. A known amount of the oil from which the asphaltene has been removed is separated. Using isocratic elution with the same solvent, saturates and aromatics are eluted from the column for a specific time period. Resins are then eluted by backflushing the column with chloroform/methanol. The resins are recovered by evaporation, determined by weight and reported as a percentage of the original oil.

Page 21

BP Exploration


2.4 Molecular Weight of Asphaltenes and Resins

Gel Permeation Chromatography can be used to establish the molecular weight distributions of asphaltene and resin fractions precipitated under known conditions.

Resin and asphaltene samples are individually made up as 0.2 w/v% solutions in tetrahydrofuran (THF). The sample solutions are then characterised by GPC. BP use the following conditions.

Equipment calibrated using polystyrene standards in THF.200 µl sample solution injection with eluent flow of 1 ml/min.Waters µ styragel columns 104 Â, 103 Â, 500 Â, 100 Â.Waters 410 refractive index detector.GPC data collection using a Waters 860 data system.Asphaltene and resin molecular weight parameters Mn, Mw etc are calculated using an 'Expertese software' package.

It has been found that crudes with a resin to asphaltene ratio approaching unity tend to be more susceptible to the influence of n-alkane additions. In other words, crudes with a ratio tending to unity are more likely to suffer from asphaltene precipitation than those with a ratio less than unity.

2.5 Onset of Asphaltene Flocculation

The asphaltene and resin contents do not define whether asphaltenes will be precipitated from any given crude under operational conditions. BP have used two methods to establish how close to asphaltene instability a crude will be.

2.5.1 Flow Through Visual Cell

This apparatus allows a crude oil to be pumped through a windowed cell at pressures and temperatures similar to those experienced under field conditions. A narrow path length and a powerful light source are used to examine the transmittance through the oil as the pressure and/or temperature are altered. On reduction of pressure, the solvency of a crude for its asphaltenes is reduced, and asphaltene flocculation can take place. This can be observed by the formation of flocculated black deposits which adhere to the window. The pressure required for this to commence is then noted.

The technique is not appropriate for all crudes, since the solvency of many for their asphaltenes is sufficient that a pressure drop alone will not result in asphaltene flocculation.

2.5.2 Asphaltene Flocculometer

The solvency of a crude oil for its asphaltenes can be determined quantitatively by titrating the crude with an n-alkane flocculant and measuring the volume of alkane required before sufficient resins are removed to allow asphaltenes to precipitate. The asphaltene flocculometer was designed by the Institute Francais du Petrole and built by Geomechanique of Paris. Light scattering is used to detect the onset of asphaltene flocculation, whilst an oil sample is titrated at the required temperature and pressure.

Page 22

BP Exploration


The detection system is a 900nm monochromatic light source attached to an optical probe contained inside a steel tube, which can be immersed in the oil sample. The probe consists of two fibre optic cables and a mirror assembly. One fibre optic is connected to the light source and carries light into the sample. At the end of this fibre optic, the light travels through the sample, across a 1-10mm adjustable gap, before being reflected by a mirror. A second fibre optic carries the reflected light to a silicon photo-diode which converts the returned light into a voltage signal. The voltage response is plotted by a chart recorder. The titration takes place in a 500cm3 pressure vessel which is equipped with a magnetic stirrer and temperature controlled heating jacket. The flocculant is added by a positive displacement Gilson pump.

A diagram of the flocculometer is shown in Figure 5 and the fibre optics shown in Figure 6.

To measure the onset of flocculation, a known volume of the test oil sample is transferred to the pressure vessel. This may be a downhole pressurised sample, a recombined high pressure sample, a wellhead or a stock tank sample, depending upon sample availability or the pressure rating of the flocculometer. Clearly, downhole samples are preferable but must be injected at pressure via a suitable piston vessel. The steel tube containing the fibre optic probe and mirror assembly is immersed in the oil, and the vessel heated to operating temperature. For stock tank samples an over pressure of nitrogen is applied. Nitrogen has been shown not to influence the test results. Once at temperature, the oil sample is titrated with the flocculant. The volume of flocculant added is recorded against the voltage signal from the photo diode. As the flocculant is added, the crude becomes lighter and there is an increase in the returned signal. When sufficient flocculant is added, the oil reaches the threshold of flocculation, and there is a marked decrease in the returned signal, as asphaltene particles scatter the reflected light. Figure 7 shows a typical output trace from the flocculometer with the onset of flocculation marked.

These data provide an immediate comparison between different crudes, condensates or hydrocarbon mixtures. A new reservoir crude can be ranked with crudes where asphaltene risks are well known.

2.6 Modelling

Wellhead samples are often the best that are available. Since it is possible that asphaltenes have been lost from these, studies to determine the onset conditions necessary before asphaltene precipitation can occur may underestimate the risks. Partly to overcome these problems, and to predict the potential for asphaltene problems in fields under development when only small samples are available, BP has constructed a computer model to predict when and where asphaltene problems are likely. The information needed to run the model includes standard PVT data, asphaltene and resin molecular weights and the production temperature and pressure profiles.

The model defines the stability of asphaltenes in terms of a critical chemical potential for the associated resins based upon the physical characteristics of the crude oil. The conditions that the crude oil will encounter are then examined, and the resin potential calculated for the expected temperatures and pressures. If the resultant resin potential is exceeded, then asphaltene flocculation can occur. The model has been used to predict the onset conditions for asphaltene precipitation in several BP fields in the North Sea and in Alaska. Predictions made using the model have been confirmed by field measurements (see section 4).

Page 23

BP Exploration


One major advantage of this model is that changes to the operating conditions can be examined for their impact upon the risk of asphaltene precipitation. For instance, artificial lift would be expected to increase the risk of asphaltene precipitation since the lift gas consists essentially of light straight chain hydrocarbons that remove resins. The model can predict the impact on asphaltene precipitation of introducing lift gas into a production stream for any given conditions. Such information has been used in optimising the design of artificial lift apparatus to minimise the risk of asphaltenes. The model has also been used to establish the impact on asphaltene precipitation of a miscible gas flooding programme.

3. ASPHALTENES IN OILFIELD OPERATIONS

As stated in the introduction, asphaltenes deposits can cause production rate declines by blocking tubing or reducing the permeability to oil in the reservoir surrounding a producing well. The more resins are precipitated with the asphaltenes, then the more oil-like the deposit may appear. Thus, it is not surprising that asphaltene and paraffin wax deposits are often confused. Whilst they may be observed in the same deposit, and both are due to species becoming insoluble in the parent crude oil, the mechanisms by which they form are different. Temperature is the dominant effect for wax deposition. For asphaltenes the picture is more complicated. With asphaltene molecules stabilised as colloidal particles peptised by resins, any actions of a chemical or electrical nature which depeptise these particles will lead to flocculation and precipitation [2,3]. In production systems changes in temperature, pressure and the chemical composition of the crude, combined with streaming potential effects in the production tubing will affect the stability of the crude [4]. The effects which contribute to the insolubility of asphaltenes and their subsequent precipitation are discussed below.

3.1 Effect of Temperature

Whilst the effect of temperature is critical in the mechanism for paraffin wax precipitation, it is much less obvious how temperature affects the precipitation of asphaltenes. Little work has been reported, but it appears that when asphaltenes are precipitated by non polar solvents such as alkanes, then an increase in temperature increases the amount of precipitate for a given amount of solvent. The effect is thought to be due to the influence of temperature on the surface tension of the solvent. The peptizing or precipitating properties of different solvents with respect to asphaltenes have been shown to be related to their surface tension. Flocculation can occur when the solvent has a surface tension below 25dynes per cm. Peptisation occurs when the surface tension is over 26dynes per cm. Higher temperatures result in a reduction in surface tension and hence a greater push towards asphaltene precipitation. More importantly from an operational standpoint is the fact that asphaltenes precipitate more rapidly at higher temperatures.

Page 24

BP Exploration


3.2 Effect of Pressure

Pressure has a large effect on the flocculation of asphaltenes. Studies of asphaltene deposition in production well tubing have found that deposition occurs below the depth at which the bubble point for the crude occurs, i.e. when the oil is still single phase [5,6]. No deposition is found further up the tubing at pressures below the bubble point. An illustration of typical asphaltene deposition in production tubing is shown in Figure 8. At the bubble point, gas breakout occurs, where lighter gases such as methane, ethane and propane are lost from the oil. These are the very species which remove the stabilising resins from asphaltene molecules or micelles, destabilising them and leading to precipitation. The loss of these alkanes therefore increases the solvency of the crude for its asphaltenes, and no further precipitation would be expected once pressures fall below the bubble point. There may be a secondary effect of two phase flow where the greater shear forces at the tubing wall strip away any further depositing asphaltenes.

Asphaltenes may precipitate at pressures above the bubble point, ie lower down in the tubing. The greatest chance of precipitation however, occurs at a depth just below where the fluids are at their bubble point. As the fluids rise in the tubing the pressure gradually drops and the oil expands. Different species in the oil expand at different rates depending upon their compressibilities. The lighter ends such as methane expand to a greater degree than the heavier components. This has the effect of increasing the molar volume of the lighter ends in the crude, increasing their influence on the stabilising resins, and hence increasing the likelihood of asphaltene precipitation. This effect is shown in Figure 9. Solubility theory and thermodynamic equations of state can be used to confirm this reduction in asphaltene solubility as an oil approaches its saturation pressure [7].

3.3 Effect of Gas Lift

Lift gas usually consists mainly of light alkanes which are able to strip away the peptizing resins. In wells where gas lift has been installed, there can therefore be an increased risk of asphaltene precipitation. The magnitude of the risk depends upon how close to flocculation the oil was before mixing with lift gas and the nature of the lift gas.

3.4 Effect of Acid Stimulations

Production wells subjected to acid stimulation can result in asphaltene deposits when during normal production none were observed. Acid stimulation treatments have been shown to adversely affect the asphaltene stability of certain crudes causing sludging and rigid film emulsions [8]. There are examples in the literature of methods to limit these effects [9]. Asphaltene sludges and emulsions stabilised by asphaltenes have been observed. The polar nature and consequent surface activity of asphaltenes attracts them to oil/water interfaces. This is enhanced during acid treatments.

3.5 Effect of Miscible Gas

In some CO2 miscible flood programmes, formation damage has occurred which subsequently was considered to be due to asphaltene deposits plugging the formation. Little is reported on the nature of the deposits but it appears that CO2 can destabilise asphaltene micelles by two mechanisms. Firstly, dissolution of CO2 into the crude depeptises the resins in much the same manner as light hydrocarbons. Secondly, CO2 tends to strip out the lighter hydrocarbons, further increasing the risk of asphaltene precipitation.

Page 25

BP Exploration


3.6 Effect of Oxidation

Exposure to air can cause resins to oxidise. Where this has occurred, the resultant measured asphaltene content was shown to rise. This effect would not normally be considered important during normal operations.

3.7 Effect of Electric Fields

The polar nature of asphaltenes can cause an attraction to positive or negative electrodes, and electrodeposition has been reported (10) in some heavy crudes. This could occur, for instance, in electrostatic separators. However, the effect is likely to be small, and any crude which is susceptible to asphaltene precipitation is likely to have lost asphaltenes before this point in the production system.

3.8 Effect of Mixing Different Streams

Each hydrocarbon has a given asphaltene content and a particular solvency for its asphaltenes. In a major export line, there may be several streams from different reservoirs all using the same line. Mixing different crude streams can have a significant impact on the risk of asphaltene precipitation. For instance, a light condensate with little asphaltenes can destabilise a crude with a high asphaltene content which on its own has good asphaltene solvency. This is discussed in more detail in Section 4 below where a study on a North Sea export line is reported.

4. TYPICAL ASPHALTENE STUDIES

4.1. Pipeline Studies

The addition of oils or condensates in common pipelines can alter the overall solvency of the blend. Therefore the fluids should be tested to ensure compatibility. This can be done using the asphaltene flocculometer apparatus for both single crudes and blends. The volume of alkane titrated to induce asphaltene flocculation, at set conditions of temperature and pressure, describes the stability of the crude for its asphaltenes and is used to define a solvency number. When a given crude blend has been assigned a solvency number, additions of other hydrocarbons could reduce the solvency number and make asphaltene instability more likely. Oils can thus be classified on a common scale and the compatibility of entrants to the pipeline determined.

This method is an adaptation of a method reported by Reichart [11] for measuring the solvency of various mixtures of bitumen solutions.

4.2 Ula Asphaltene Deposition Study

A programme of laboratory and field studies was carried out to determine the onset point of asphaltene precipitation and to predict future trends as operational conditions changed in Ula, a BP field in the Norwegian sector of the North Sea. In this field, asphaltenes were considered responsible for several operational difficulties experienced in the production facilities. This work has been subsequently published (6).

Page 26

BP Exploration


The flow through apparatus described in Section 2.5.1 was used to establish that asphaltene flocculation started at 30 bar above the saturation pressure and ceased once the saturation pressure was reached. A Kinley Caliper survey indicated that the restriction in the diameter of the tubing thought to be caused by asphaltene deposition coincided precisely with the pressures at which asphaltene flocculation would occur as identified in laboratory studies. A similar survey for a Clyde well is illustrated in Figure 10. Subsequently, BPX developed an asphaltene precipitation model which calculates a critical chemical potential for the stabilising resins. If the actual potential calculated for given pressure and temperature conditions exceeds the critical, then asphaltene precipitation can occur. Figure 11 illustrates the results of the modelling study for Ula. For the fluids examined, asphaltene precipitation is possible if the pressure is between about 100 and 200 Bara.

4.3 The Effect on Asphaltene Precipitation of Miscible Gas

A study was undertaken into the effect of miscible injectant gas (MI) on asphaltene stability at Prudhoe Bay. This study characterised the Prudhoe Bay crude oil, and through modelling, the asphaltene stability in terms of the resin critical potential was determined. The actual potential was then calculated when miscible gas was added at various mixing ratios to the crude and compared to the critical. It was predicted that miscible gas would only result in asphaltene precipitation at very high levels against Prudhoe crude. This is illustrated in Figure 12. Further, with the relatively high asphaltene and resin content, the amount of asphaltene that could be precipitated would be high and any deposit would be tar-like.

5. TREATING ASPHALTENE PROBLEMS

5.1. Chemical Treatment

5.1.1 Dissolving Precipitated Asphaltenes

Despite the worldwide occurrence of asphaltenes in oil fields and the many examples in the literature detailing the serious effects on production resulting from deposition, there is a lack of data on successful inhibition. Many operators however rely upon periodic solvent washes to remove asphaltenes that have formed. Typically hot aromatic solvents such as xylene prove effective, although production wells must be shut in for several hours for such a treatment. There is an additional risk if the solvent reaches the formation, since changes to wettability can alter the relative permeability to oil, and cause a dramatic reduction in oil production rates. Further, aromatic solvents can pose environmental hazzard and tend to dissolve elastomer seals.

Long chain carboxylic acids have been identified as effective for deasphalting, probably by reacting with precipitated asphaltenes via hydrogen bonding. Long chain anionic surfactant have also been reported as effective although this chemical type would not be suitable in production systems since they would encourage formation of emulsions.

5.1.2 Asphaltene Inhibitors

Several treatments have been reported using long chain molecules that mimic the stabilising effect of a resin layer, preventing flocculation. This is also the proposed mechanism for a recently developed polymeric asphaltene dispersant chemical produced by Nalco.

Page 27

BP Exploration


C-10 through to C-20 aliphatic alcohol partial esters of phosphoric acids are claimed to improve the stability of asphaltenes in bituminous oils at dose rates of as low as 50ppm. These were designed as a preventative treatment, deployed by "squeezing" it into the petroleum bearing formation in a similar manner to many scale inhibitor treatments.

At the time of writing, considerable work is underway to develop improved asphaltene inhibitors.

5.2. Plastic Coatings

Epoxy resin coatings have been applied to tubulars (12) in an attempt to stop asphaltenes from sticking and building up into a deposit. No improvement was reported here although the technique may still have some merit.

5.3 Engineering Solutions

Dual completions have been used in the Prinos field in Greece to allow the injection of Xylene [13] directly into the production stream. Details are limited of how effective this method was and the high cost of such completions probably eliminates this is a possible solution in most cases.

Coiled tubing has also been used to inject asphaltene solvents/inhibitors (12), although in this reported case results were disappointing, possibly as a result of the relatively poor performance of the chemicals used.

Mechanical scraping devices can been used to remove blockages in production tubing. In one field a downhole hydraulic motor has been used, lowered and powered from coiled tubing, and has been found to be the most economical method of controlling asphaltenes (12).

A recent report (10) has indicated ultrasonic treatments can clean up asphaltenes deposited in near wellbore regions, although at the time of writing, no commercial equipment is available.

5.4 Operational Changes

The greatest risk of asphaltene deposition occurs at pressures just above the bubble point. If the reservoir pressure can be reduced by rapid depletion such the bubble point occurs away from the production tubing in the reservoir itself, then asphaltene precipitation will not impact production. This may not of course be an option, since liquid hydrocarbons and condensates are at a premium.

Page 28

BP Exploration


6. REFERENCES

[1] Institute of Petroleum, London Standard Methods for Analysis & Testing of Petroleum and Related Products IP143/84

[2] Leontatritis K.J. and Mansoori G.A.

1987 Asphaltene Flocculation Duriong Oil Production and Processing: A Thermodynamic Colloidal Model. SPE Paper 16258. Symposium on Oilfield Chemistry, San Antonio, Texas, Feb 4-6

[3] Lichaa P.M. and Herra L. Electrical and Other Effects Related to the formation and prevention of Asphaltenes Deposition. SPE Paper 5308 Oilfield & Geothermal Chemistry Symposium, Dallas, Jan, 16-17.

[4] Haskett C.E. and Tantera M.

1965 A Solution to the Problem of Asphaltene Deposits - Hassi Mesoud Field, Algeria. J. Pet. Tech. (April 1965), 387-391.

[5] Adalialis S. 1982 Investigation of Physical and Chemical Criteria as Related to the Prevention of Asphalt Deposition in Oil Well Tubings. MSc thesis, Petroleum Engineering Department, Imperial College University of London.

[6] Thaver R. Nicoll and Dick G.

1988 Asphaltene deposition in Production Facilities. SPE Paper 18473.

[7] Kawanaka S. Park and S.J. & Mansoori G.A.

The Role of Asphaltene Deposition in EOR Gas Flooding: A Predictive Technique. SPE/DOE Paper 17376

[8] Tuttle R.N. 1983 High-Pour-Point and Asphaltic Crude Oils and Condensates. J. Petroleum Tech. 35. Jan-June 1983

[9] Newberry M.E. and Barker K.M.

1985 "Formation Damage Prevention through the Control of Paraffin and Asphaltene Deposition." SPE Paper 13796, Oklahoma City, March 10-12, 1985

[10]

Gollapudi U k, Bang S S, and Islam M R.

1994 "Ultrasonic Treatmentfor Removal of Asphaltene Deposits During Petreoleum Production." SPE 27377 Louisiana , February 7-10. 1994

[11]

Reichert C, Fuhr B J, and Klein LL

1986 "Measurement of Asphaltene Flocculation in Bitumen solutions." JCPT Montreal, Sept-Oct 1986

Page 29

BP Exploration


[12]

Akbar S.H. and Saleh A.A.

1989 A Comprehensive Approach to Solve Asphaltene Deposition Problems in Some Deep Wells. SPE Paper 17965. Middle East Oil Technical Conference and Exhibition, Manama, Bahrain, 11-14 March.

[13]

Adailas, S. 1982 Investigation of Physical and Chemical Criteria as Related to the Prevention of Asphaltene Deposition in Oil Well Tubings. MSc Thesis.

Page 30

BP Exploration


WATER CHEMISTRY AND SCALE

INDEX

Page No.

1. THE OCCURRENCE OF SCALE 1

2. PROBLEMS CAUSED BY SCALE 1

2.1 Drilling and Completing Wells2.2 Water Injection2.3 Reservoir Damage2.4 Water Production2.5 Production Operations2.6 The Cost of Failure

3. SCALE PREDICTION 3

3.1 Thermodynamic Background3.1.1 Effect of Bulk Ionic Strength on Solubility3.1.2 Effect of Temperature on Mineral Solubility3.1.3 Effect of Specific Ions on Mineral Solubility3.1.4 Phase Behaviour3.1.5 Effect of Pressure on Mineral Solubility

3.2 Geochemical Aqueous Modelling3.2.1 Concept of the Ion Pair3.2.2 Treatment of Non-aqueous Phases

4. SCALE INHIBITORS 7

4.1 Scale Inhibitor Types4.1.1 Inorganic Phosphates4.1.2 Organophosphorous Compounds4.1.3 Organic Polymers

4.2 Scale Inhibitor Mechanisms4.2.1 Nucleation and Growth4.2.2 Inhibition4.2.3 Blending Scale Inhibitors

5. LABORATORY EVALUATION OF SCALE INHIBITORS 8

5.1 Static Scale Precipitation Test5.2 Dynamic Scale Precipitation Test (Tube-Blocking Test)5.3 Dynamic (Porous Media) Tests

6. APPLICATION OF SCALE INHIBITORS 9

7. SCALE DISSOLVERS 10

Page 31

BP Exploration


TABLE 1FIGURES 1-5APPENDIX 1 SCALE PREDICTION STUDY FOR FORTIES

TABLE 1FIGURES 1-5

APPENDIX 2 SCALE PREDICTION STUDY FOR PRUDHOE BAYTABLE 1FIGURES 1-2

Page 32

BP Exploration


1. THE OCCURRENCE OF SCALE

Water is the most common and in many respects the most important fluid known to man. Were it not for water however, it would be simpler to produce oil and gas. Water is always in the process of dissolving or depositing solids and it is the precipitation of these dissolved solids as a hard, adherent deposit of inorganic mineral which constitute 'scale'. It is not only the oil industry that suffers from scale. Nineteen centuries ago the Romans experienced calcium carbonate scale in their aqueducts and canals. In areas of hard water, scale can build up in domestic kettles and steam irons.

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.

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

(i) degree of supersaturation of scaling ions in the water(ii) rate of temperature change(iii) degree of agitation during formation of scale crystals(iv) size and number of seed crystals(v) presence of impurities(vi) change in pH of solution(vii) changes in pressure

Common oilfield scales form in one of two ways. Firstly, a change in conditions such as temperature or pressure can promote carbonate scale 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.

Typical analyses of Magnus, Forties, Wytch Farm, Miller, Ula and Prudhoe Bay formation waters and North Sea water are given in Table 1. These formation waters reflect the typical variations in formation water chemistry encountered in BP's reservoirs.

2. PROBLEMS CAUSED BY SCALES

Scale does not restrict itself to any particular location in the oilfield. However some areas are more difficult and costly to treat than others.

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 sea-water 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.

Page 33

BP Exploration


Drilling the fist 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.

2.2 Water Injection

Problems may arise at the commissioning stage of new injectors if the injection water is intrinsically incompatible with the formation water. For example, sea water 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 desireable, 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.

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.

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 or across perforations. 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.

Page 34

BP Exploration


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.

2.6 The Costs of Failure

These include the cost of stimulating damaged wells, cleaning or replacing damaged equipment and from lost production. For example, a typical workover for a North Sea well may cost several hundred thousand pounds for a platform well and up to two million pounds for a satellite well. If a well produces 10000 barrels of oil per day, the gross cost of 1 day's lost production is £200,000 (@ £20/bbl). Platform production shutdowns are enormously expensive; a platform processing 125000 barrels of oil per day generates £2,500,000 of gross revenue daily.

If scale precipitation in the body of the reservoir is proved to impair ultimate oil recovery, the costs involved could be very large, involving not only reduced cash-flow but also reduced gross revenue.

It is thus vital to ensure that scale is predicted well in advance, and that effective remedial treatments can be put in place.

3. SCALE PREDICTION

Scale formation from oilfield brines takes place in a multicomponent, 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.

3.1 Thermodynamic Background

Consider barium sulphate, a sparingly soluble salt. If excess barium sulphate is suspended in water, some of it will dissolve, until the solution is saturated. The following equilibrium then applies:

Ba SO4 (s) Ba2+ (aq) + SO42- (aq) (1)

Page 35

BP Exploration


This extent of this reaction can be described by the equilibrium constant, K, such that:

K = ABa2+ . ASO42- (2)

--------------------A BaSO4

where A is the activity of each species.

By definition, the activity of a pure solid is unity, thus the equilibrium constant can be written:

K = ABa2+ . ASO42- (2a)

This equation can be rewritten in the more familiar terms of concentrations as follows:

K = [mBa2+ . mSO42-] . [ÿBa2+ . ÿSO4

2-] (3)

where m is the molality and ÿ the activity coefficient of the ions in aqueous solution. Activity coefficients usually have a value in the range 0-1.0 and represent deviations from ideal solution behaviour.

Therefore, to determine the solubility of barium sulphate (or any other mineral) in a given water requires not only the equilibrium constant K but also the activity coefficients to be calculated. Both are functions of temperature and pressure, and the presence of other ions in solution also has a marked effect upon the value of the activity coefficients. The total concentration of ions is given by the ionic strength, µ, where:

µ = ci zi2 (4)

where Ci is the concentration of the ith ion and Zi its valency.

In summary, the solubility of barium sulphate scale depends on solution ionic strength, temperature, pressure and the concentration of specific divalent ions in the solution.

For carbonate scales, the concentration of carbon dioxide gas in solution is an additional factor to consider. For a two-phase system the concentration of CO2 in solution is related to the partial pressure of CO2 in the gas phase (Henry's Law).

Most scale prediction models are therrmodynamic in nature and take account of all of the above effects. Production from oilfields is however a dynamic process which may only approach thermodynamic equilibrium in the reservoir. Care should therefore be taken in relying on thermodynamic based predictions without some understanding of the processes involved. Generally, thermodynamic scale prediction models overestimate the risk of scale.

The importance of these parameters are discussed below.

Page 36

BP Exploration


3.1.1 Effect of Bulk Ionic Strength on Solubility

A plot of barium sulphate solubility as a function of ionic strength is given in Figure 1. As ionic strength increases from zero, barium sulphate (and all other scales) becomes more soluble. This can be understood in terms of ionic activities: the presence of foreign ions shields the barium and sulphate ions from each other, reducing their activities and allowing more of them to co-exist in solution. A solubility plateau is then reached, and then further increases in ionic strength reduce the solubility. At these ionic strengths the ions are 'unhappy' because they are not well solvated, and their activities begin to increase again with ionic strength. (For comparative purposes, the ionic strengths of various formation waters and North Sea water are included in Table 1).

3.1.2 Effect of Temperature on Mineral Solubility

The dissolution of barium sulphate in water is an endothermic process (over the temperature range 35-110°C). Therefore, increasing the temperature causes more to dissolve (although the effect, in absolute terms, is small). In contrast, the dissolution of strontium sulphate is an exothermic process (over the same temperature range). Increasing the temperature therefore reduces the solubility of strontium sulphate. The effect of temperature on solubility is more pronounced for strontium sulphate than for barium sulphate.

Appendix 1 contains an example of a scale prediction study illustrating the effect of temperature on both sulphate and carbonate scale formation.

3.1.3 Effect of Specific Ions on Mineral Solubility

The solubility of any given scale is affected by the concentration of other ions in the brine. These other ions affect the solubility of the scale and may change the predominant phase of the scale. The former property is considered here.

The effect of magnesium, calcium and strontium ions (ie other divalent cations) on the solubility of barium sulphate, is conventionally understood by the formation of ion pairs. For example, in a mixed electrolyte, the following equilibria operate:

BaSO4(s) Ba.SO4 (aq) Ba2+ (aq) + SO42- (aq) (6)

MgSO4(s) Mg.SO4 (aq) Mg2+ (aq) + SO42- (aq) (7)

CaSO4(s) Ca.SO4 (aq) Ca2+ (aq) + SO42- (aq) (8)

SrSO4(s) Sr.SO4 (aq) Sr2+ (aq) + SO42- (aq) (9)

where the species M.SO4(aq) are the ion pairs.

Even though the respective concentrations of magnesium, calcium and strontium may not be high enough to cause precipitation of their respective sulphates, they are nevertheless able to 'tie-up' significant levels of sulphate in the form of ion-pairs. This effectively reduces the overall activity of sulphate ions in solution, thereby increasing the solubility of barium sulphate in that solution.

Page 37

BP Exploration


3.1.4 Phase Behaviour

Some scales are capable of existing in more than one crystal form. For example, calcium sulphate may exist as gypsum (the dihydrate), hemihydrate, and anhydrite (the anhydrous form). Calcium carbonate may exist as calcite, aragonite, or the metastable vaterite. The imposed temperature and pressure largely determine which morphological form will be most stable. Figure 2 shows the solubility of calcium sulphate as gypsum or anhydrite as a function of temperature.

3.1.5 Effect of Pressure on Mineral Solubility

The effect of pressure on ionic equilibria in aqueous systems is neglected in many scale prediction models due to the scarcity of reliable, relevant thermodynamic data. To take account of pressure effects, the variation of the equilibrium constant with pressure must be known for every pertinent equation in the model. For instance, K values for each of the following reactions must be known as a function of pressure when considering the formation of calcite scale.

CO2 (g) CO2 (aq) (10)

H2O + CO2 (aq) H2CO3 (11)

H2CO3 H+ + HCO3- (12)

HCO3- CO3

2- + H+ (13)

H2O H+ + OH- (14)

Calcite (S) Ca2+ + CO32- (15)

Ca2+ + HCO3- CaHCO3

+ (16)

Ca2+ + CO32- CaCO3

° (17)

Le Chatelier's principle indicates that a drop in pressure will tend to move an equilibrium in the direction where the total volume of the system is increased. In a system as complex as that shown above, the effect of a pressure drop may not be immediately apparent, since the equilibrium constants for the equation above vary over several orders of magnitude. However, the overall effect may be summarised as follows; H2CO3 and H+ concentrations decrease, whilst CO2 (aq) and CO3

2- increase. A reduction in calcite solubility results. As a consequence of the reduction in H+ concentration, the pH also increases.

The operational consequences are as follows. A reservoir brine, initially at equilibrium with calcite and containing a high concentration of CO2 , can deposit scale when the brine is produced as the pressure falls.

Appendix 2 contains an example of a scale prediction study showing the effect of pressure and CO2 on calcite scale formation.

Page 38

BP Exploration


3.2 Geochemical Aqueous Modelling

The first truely successful treatment of brines was by Debye and Huckel. Current aqueous models use various extensions of their theory to calculate the activity coefficients of the ions in solution. These extensions increase the range of the original model to encompass high ionic strength brines as are often found in oilfield operations.

3.2.1 Concept of the Ion Pair

The natural attraction between ions of opposing charge can temporarily overcome the thermal energy that tends to separate the hydrated ions in solution. These 'contact' ion pairs which form may be very short lived and are better described as 'sticky collisions'. On average a significant number of the ions may be present as ion pairs and the resultant solution properties deviate significantly from simple Debye-Huckel theory. The ion pairs that form in solution may retain some or all of their water of hydration. Although these ion pairs do not form true complexes, an association constant for the coalescence of the anions and cations can be measured experimentally. This deviation from Debye-Huckel theory must be taken into account if a scale prediction model is to describe a brine satisfactorily.

Geochemical models (ie that take account of ion pairs) represent the aqueous phase as a set of equilibrium equations. Equilibrium constants for all mineral dissolution and ion pair formation reactions (for example equations 1, 6-17) are contained in a database which the model uses to correctly define the aqueous phase. With this information, together with the activity coefficient calculation outlined in the previous section, predictions of scale formation and other phenomena can be made with greater accuracy.

3.2.2 Treatment of Non Aqueous Phases

In addition to solid and aqueous phases already discussed, gases are also included in ion pair models. The preferred BP model, SPAM, includes up to seven gases, CO2, N2, H2S, CH4, NH3 and H2 although others can be readily added if thermodynamic data are available. Partitioning data has now also been included and other organic matter such as CH2O can also be included as a reactant. This has proved useful for instance in modelling sulphate reduction/oxidation of carbon containing species.

4. SCALE INHIBITORS

Scale in the oil industry is generally controlled in two ways (Figure 3). Firstly, it may be periodically removed after it has formed, for instance by mechanical removal or chemical dissollution. These methods may be inappropriate if production losses are incurred and can be extremely costly. Thus, the second method is more common, ie by treating the water chemically or mechanically in order to prevent or control scale formation from the outset. The usual strategy is to adopt a 'prevention is better than cure' approach, commonly relying upon chemical inhibitors to achieve it.

Scale inhibitors are chemicals that stop or interfere with scale nucleation, precipitation and adherence to equipment, ie the three elements leading to scale problems.

Page 39

BP Exploration


4.1 Scale Inhibitor Types

It is estimated that there are now more than 2000 chemical scale inhibitors commercially available. Scale inhibitors used in the oil inductry generally fall into four main types:

4.1.1 Inorganic Phosphates

These compounds are both cheap and easily prepared. They are readily soluble in water, non-toxic and effective at low treatment concentrations (typically 0.5-20 ppm), particularly in controlling calcium carbonate scale. However, their use in oilfield applicationsis limited since, even at fairly modest temperatures, they hydrolyse in water to form orthophosphates that have little scale inhibitor activity.

4.1.2 Organophosphorous Compounds

This family of scale inhibitors can be further sub-divided into two classes.

1. Organic Phosphate Esters

These chemicals are derived from inorganic phosphates and alsol suffer from hydrolytic instability.

2. Organophosphonates

These are often based on amines and are compounds containing the hydrolytically more stable -N-C-P moiety. Organophosphonates are now commonly deployed as scale inhibitors for calcium, strontium and barium scales.

4.1.3 Organic Polymers

Polycarboxylic acids are now more commonly used in oilfield applications. Effective polymers tend to have a low molecular weight (typically 1000-5000) and have regularly spaced ionisable groups. These compounds have excellent thermal and hydrolytic stabilities. The most common classes of inhibitors include polyacrylates, polyphosphinocarboxylates, polymalates, polyvinylsulphonates and polyacrylamides.

Examples of the chemical structure of all four inhibitor types are given in Figure 4.

4.2 Scale Inhibitor Mechanisms

4.2.1 Nucleation and Growth

The first stage of the scale-forming process is nucleation, either in solution (homogeneous nucleation) or on a substrate (heterogeneous nucleation). Typical substrates in the oilfield include sand grains, clay (and other) minerals, metallic surfaces and scale crystals themselves (the latter called secondary nucleation). Nucleation is the creation of a sub particle or ion cluster consisting of several individual scaling ions. These form either in bulk solution or on a substrate. The size of the cluster can vary but is generaly of the order of about 10 ions. Smaller ion clusters are thermodynamically unstable and break apart. Once formed, the cluster can grow along well defined crystal planes as more ions or more ion clusters become attatched to the growing crystal surfaces. Once the crystal is sufficiently large, it can not be held in suspension and will fall out of the fluid due to gravity.

Page 40

BP Exploration


Many crystals dropping out lead to scale deposits. Nucleation will only occur once the concentration of the scaling ions exceeds the solubility limit of the mineral scale in question within the physical conditions imposed. Scale growth can continue, gradually removing scaling ions from solutions, until the concentration of the scaling ions falls below saturation.

4.2.2 Inhibition

There are many proposed mechanisms by which scale inhibitors operate. Generally they interfere with either nucleation and/or with crystal growth. Those inhibitors that disrupt nucleation are small enough to diffuse readily in the bulk brine in order to get to the ion cluster, but are sufficiently large to disrupt it. Good crystal growth inhibitors have a strong affinity for the active growth sites, but should readily diffuse over the crystal surface to other active sites as they form. These inhibitors must be sufficiently small to be able to do this, but large enough to avoid being engulfed in the growing crystal (although this can be beneficial, if it leads to the formation of soft, easily-removed scale).

Evidence suggests that some inhibitors operate by promoting the formation of multitudes of ion clusters but preventing their growth beyond a few nanometers in size. The result is that the saturation of the scaling species in the bulk fluid is reduced, effectively removing the propensity to form other clusters or for growth of those clusters already formed. Other inhibitors may operate by adsorbing onto the crystal surface and preventing the crystal from adhering to pipe walls or other substrates.

All scale inhibitors operate in a 'threshold' manner, ie. at concentrations below the level required to react directly with scaling ions. Typical inhibitor concentrations recommended for deployment in the field would be 5-50 ppm.

4.2.3 Blending Scale Inhibitors

Some synergistic behaviour between different scale inhibitors (particularly the polyacrylates and phosphonates) has been observed. The reasons for this synergism could be that different chemical types act via different mechanisms. One possible explanation is that the anionic polymer chain interferes with the nucleation process whilst the smaller phosphonate molecule adsorbs onto crystal nuclei, blocking active growth sites and preventing further crystal growth.

5. 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 below.

The strategy used in BP is to test several chemicals in simple tests under a wide range of conditions that are likely to be encountered. The best of these can then be selected for further examination in more complex tests that match more closely the field conditions.

Perhaps the single most important conclusion is that a chemical which shows excellent activity in one water chemistry may not necessarily perform well in another. That is, there is no universal scale inhibitor system.

Page 41

BP Exploration


5.1 Static Scale Precipitation Tests

This procedure is an adaption of the NACE Standard Testing Method for screening scale inhibitors.

Synthetic brines are prepared in the laboratory and mixed in defined ratios and pH values in the presence and absence of scale inhibitors. The mixing ratios are chosen to represent the 'worst case' in terms of scale formation for the situation under investigation, identified from computer scale predictions. Once mixed, the brines are stored at an appropriate temperature for a defined time (usually 16 hours). After this time the supernatant is filtered and analysed for scaling ions remaining in solution. The effectiveness of a chemical is then determined by its ability to retain scaling ions in solution compared to the supernatants from uninhibited bottles.

This test is quick and cheap and, when used in conjunction with microscopy and spectrometry techniques, can provide information on the nature of the deposit and the effect of the inhibitor on crystal growth. The test can however be less accurate for water chemistries with very high concentrations of scaling cations. If relatively small amounts of scale are deposited from these, then the difference in concentration of supernatant scaling ions could be very small compared to the magnitude of the concentration. Here, gravimetric analysis of the scale deposits themselves can be valuable.

5.2 Dynamic Scale Precipitation Test (Tube - Blocking Test)

Unlike the static scale precipitation test, this test takes into account the adherence of scale to pipework. A schematic diagram of the apparatus is given in Figure 5. Two incompatible brines are pumped separately at temperature and pressure into an oven where they mix and flow through a coiled capillary tube. Any build up of scale in the coil is detected by a differential pressure transmitter which monitors the pressure drop across the coil. At a differential pressure of 100 psi the coil is judged to be blocked and the apparatus automatically shut down. The time taken for the coil to block in the presence and absence of scale inhibitors is noted and in this way a suitable ranking of scale inhibitors can be achieved, and optimum inhibitor dosage concentrations identified.

These tests are more complex and thus more expensive, but have the benefit in approaching field conditions of temperature, pressure and can be conducted in the presence of dissolved gases such as CO2.

5.3 Dynamic (Porous Media) Tests

In these tests, scale is induced to form not in tubes but in porous media . Additionally, the behaviour of chemical inhibitors in reservoir substrate can be determined. Apparatus available ranges from simple core flooding at ambient conditions to full reservoir condition rigs that can operate up to150°C and 10000psi and in the presence of live crudes.

Tests of this nature are particularly useful in designing scale inhibitor 'squeeze' treatments where the elution characteristics of scale inhibitors flowing through porous media determine the timing between successive squeeze treatments. Such tests are usually labour intensive, but provide vital data for optimising scale inhibitor deployment.

Page 42

BP Exploration


6. 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 (squeeze) treatment of production wells is now a routine operation.

A 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. (This is more fully discussed elsewhere in this Course.)

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 sea water 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 mobilities 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

Page 43

BP Exploration


in squeeze treatments can be expected.

7. SCALE DISSOLVERS

The dissolution of scale in a liquid is the reverse of the crystallisation process by which scale was laid down. Carbonate scales may be most readily dissolved with mineral acids.

CaCO3 + 2HCl Ca Cl2 + 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

As the barium is complexed in reaction (2), more barium sulphate dissolves to maintain the equilibrium of reaction (1), and as the reactions continues further the barium sulphate gradually dissolves.

Successful use of chelants requires a clean scale surface on which to operate. Often, oilfield scale is coated in hydrocarbons which must be removed first (for example by using an appropriate surfactant) before the chelant can work. EDTA (EthyleneDiamineTetraAcetic acid) forms the basis of many commercial chelants for sulphate scale.

Page 44

BP Exploration


TABLE 1

WATER ANALYSES

MAGNUS

FORTIES WYTCH MILLER

ULA PRUDHOE

N. SEA

FARM BAY WATER

(Sherwood)

Na+ 7805 29370 76950 28100 52225 8000 11010

K+ 200 372 960 1630 3507 83 460

Mg2+ 25 504 760 113 2249 84 1368Ca2+ 70 2808 4550 615 34675 180 428Sr2+ 20 574 140 65 1157 24 8Ba2+ 70 252 <1 770 91 4 <1Fe2+ <1 <1 1.5 <1 107 - <1Cl- 11500 52360 129340 46050 153025 115100 19700SO4

2- 0 11 1130 4 44 10 2960HCO3-

1650 496 100 1655 134 2222 124

TDS 21350 86747 79003 247214 22107 36058 0.359 1.58 1.35 5.28 - 0.712

Page 45

BP Exploration


APPENDIX 1

SCALE PREDICTION STUDY FOR FORTIES

TABLE 1

WATER ANALYSES*

ION FORTIES CHARLIE SEA WATER

Sodium 28200 10890Potassium 365 460Magnesium 490 1368Calcium 2770 428Barium 250 0Strontium 640 8Sulphate 6 2960Bicarbonate 390 124Chloride 54800 19700

pH 6.9 8.0

* All concentrations in mg/L

Page 46

BP Exploration


APPENDIX 2

SCALE PREDICTION STUDY FOR PRUDHOE BAYPRODUCED WATER ONLY

TABLE 1

PRUDHOE BAY PRODUCED WATER

ION MASS (mg/L)

Sodium 8000Potassium 83Magnesium 84Calcium 180Strontium 24Barium 4Chloride 11500Sulphate 10Bicarbonate 2222

pH 7.7

Page 47

BP Exploration


Page 48