Chapter 18
Erosion and Sand Management
Contents
18.1. Introduction
18.2. Erosion Mechanisms
18.2.1. Sand Erosion
18.2.1.1. Flow Rate of Sand and Manner of Transport
18.2.1.2. Velocity, Viscosity, and Density of the Fluid
18.2.1.3. Sand Shape, Size, and Hardness
18.2.2. Erosion-Corrosion
18.2.3. Droplet Erosion
18.2.4. Cavitation Erosion
18.3. Prediction of Sand Erosion Rate
18.3.1. Huser and Kvernvold Model
18.3.2. Salama and Venkatesh Model
18.3.3. Salama Model
18.3.4. Tulsa ECRC Model
552
18.4. Threshold Velocity553
18.4.1. Salama and Venkatesh Model553
18.4.2. Svedeman and Arnold Model
18.4.3. Shirazi et al. Model
18.4.4. Particle Impact Velocity
18.4.5. Erosion in Long Radius Elbows
18.5. Erosion Management
18.5.1. Erosion Monitoring
18.5.2. Erosion Mitigating Methods
18.5.2.1. Reduction of Production Rate
18.5.2.2. Design of Pipe System
18.5.2.3. Increasing Wall Thickness
18.5.2.4. Specialized Erosion-Resistant Materials
18.6. Sand Management
18.6.1. Sand Management Philosophy
18.6.2. The Sand Life Cycle
18.6.2.1. Sand Detachment
18.6.2.2. Sand Transport
18.6.2.3. Sand Erosion
18.6.2.4. Surface Sand Deposition
18.6.3. Sand Monitoring
18.6.3.1. Volumetric Methods
18.6.3.2. Acoustic Transducers
18.6.4. Sand Exclusion and Separation
18.6.5. Sand Prevention Methods
18.7. Calculating the Penetration Rate: Example
18.7.1. Elbow Radius Factor
18.7.2. Particle Impact Velocity
18.7.3. Penetration Rate in Standard Elbow
18.1 Introduction
The fluid associated with hydrocarbon production from wells is a complex multiphase mixture, which may include the following substances,
• Hydrocarbon liquids: oil, condensate, bitumen;
• Hydrocarbon solids: waxes, hydrates;
• Hydrocarbon gases: natural gas;
• Other gases: hydrogen sulfide, carbon dioxide, nitrogen and others;
Erosion has been long recognized as a potential source of problems in hydrocarbon production systems. Many dangerous elbow failures due to erosion have occurred on production platforms, drilling units, and other subsea equipment in the past decades. The inherently variable nature of the erosion process makes it very difficult to develop best practice recommendations for the design and operation of hydrocarbon production systems with elbows. The potential mechanisms that could cause erosion damage are:
Particulate erosion due to sand (sand erosion) is the most common source of erosion problems in hydrocarbon systems, because small amounts of sand entrained in the produced fluid can result in significant erosion and erosion-corrosion damage. Even in “sand-free” or clean service situations where sand production rates are as low as a few pounds per day, erosion damage could also be very severe at high production velocities. Sand erosion can also cause localized erosion damage to protective corrosion scales on pipe walls and result in accelerated erosion-corrosion damage.
However, all other mechanisms are equally aggressive under the right conditions. Erosion is affected by numerous factors, and small or subtle changes in operational conditions can significantly affect the damage it causes. This can lead to a scenario in which high erosion rates occur in one production system, but very little erosion occurs in other seemingly very similar systems. Detection of erosion as it progresses is also difficult, which makes erosion management difficult, especially for those unfamiliar with the manner in which erosion occurs.
The hydrodynamics of the multiphase mixture of hydrocarbons within a pipeline has a very important influence on a number of physical phenomena, which determine the corrosion and erosion performance of the system. In many pipeline applications, particularly those involving gas fields and gas production systems, liquid droplets are present as the dispersed phase. The impingement of these droplets onto surfaces can cause erosion.
Velocity is an important parameter for hydrocarbon production flow. Excessive fluid velocities caused by incorrect pipe sizing and/or process design can have a detrimental effect on the pipeline and fittings and the effectiveness of any chemical inhibitors. The phenomena involved are complex, involving aspects of the hydrodynamics of the pipeline, the chemistry of the multiphase mixture within the pipeline, and the materials used to manufacture the pipeline.
18.2 Erosion Mechanisms
There are two primary mechanisms of erosion. The first is erosion caused by direct impingement. Normally, the most severe erosion occurs at fittings that redirect the flow such as at elbows and tees. The particles in the fluid can possess sufficient momentum to traverse the fluid streamlines and impinge the pipe wall. The other mechanism is erosion caused by random impingement. This type of erosion occurs in the straight sections of pipe even though there is no mean velocity component directing flow toward the wall. However, turbulent fluctuations in the flow can provide the particles with momentum in the radial direction to force them into the pipe wall, but the turbulent fluctuations are a random process, therefore, it is termed random impingement. These two mechanisms can cause different types of erosion based on the fluid compositions, velocity, and configurations of piping systems.
Venkatesh [1] provides a good overview of erosion damage in oil wells. Regardless of the erosion mechanism, the most vulnerable parts of production systems tend to be components in which:
• The flow direction changes suddenly.
• High flow velocities occur that are caused by high volumetric flow rates.
• High flow velocities occur that are caused by flow restrictions.
Components and pipe systems upstream of the primary separators carry multiphase mixtures of gas, liquid, and particulates and are consequently more likely to suffer from particulate erosion, erosion-corrosion, and droplet erosion. Also the vulnerability of particular components to erosion heavily depends on their design and operational conditions. However, the following list is suggested as a rough guide to identify which components are most vulnerable to erosion (the first on the list being most likely to erode):
• Partially closed valves, check valves, and valves that are not full bore;
• Weld intrusions and pipe bore mismatches at flanges;
18.2.1 Sand Erosion
The rate of sand erosion is determined by following factors [2]:
• Flow rate of sand and the transport manner;
• Velocity, viscosity, and density of the flowing fluid;
• Size, shape, and hardness of the particles (sand);
• Configuration of the flow path such as straight tubing, elbow, or tee.
The effect of configuration of the flow path has already be described in the last section (section 18.2), only the effects of these factors are detailed in following programs.
18.2.1.1 Flow Rate of Sand and Manner of Transport
The nature of sand and the way in which it is produced and transported determines the rate of erosion within a production system. The sand production rate of a well is determined by a complex combination of geological factors, and it can be estimated by various techniques. Normally, new wells produce a large amount of sand as they “clean up.” Sand production then stabilizes at a relatively low level before increasing again as the well ages and the reservoir formation deteriorates. The sand production rate is not stable, and if a well produces less than 5 to 10 lb/day, it is often regarded as being sand free. However, this does not eliminate the possibility that erosion may be taking place.
The sand transport mechanism is an important factor for controlling sand erosion. Gas systems generally run at high velocities (>10 m/s), making them more apt to erosion than liquid systems. However, in wet gas systems sand particles can be trapped and carried in the liquid phase. Slugging in particular can periodically generate high velocities that may significantly enhance the erosion rate. If the flow is unsteady or the operational conditions change, sand may accumulate at times of low flow and be washed out through the system when high flows occur. The flow mechanisms may act to concentrate sand, increasing erosion rates in particular parts of the production system.
18.2.1.2 Velocity, Viscosity, and Density of the Fluid
The sand erosion rate is highly dependent on, and proportional to, the sand impact velocity. When the fluid velocity is high enough, the sand impact velocity will be close to the fluid velocity, and erosion will be an issue. Therefore, erosion is likely to be the worst where the fluid flow velocity is the highest. Small increases in fluid velocity can cause substantial increases in the erosion rate when these conditions are satisfied. In dense viscous fluids particles tend to be carried around obstructions by the flow rather than impacting on them. While in low-viscosity, low-density fluids, particles tend to travel in straight lines, impacting with the walls when the flow direction changes. Sand erosion is therefore more likely to occur in gas flows, because gas has a low viscosity and density, and gas systems operate at higher velocities.
18.2.1.3 Sand Shape, Size, and Hardness
Sand sizes in hydrocarbon production flow depend on the reservoir geology, the size of the sand screens in the well, and the breakup of particles as they travel from the reservoir to the surface. Without sand exclusion measures, such as downhole sand screens, particle sizes typically range between 50 and 500 microns. With sand exclusion in place particles larger than 100 microns are usually excluded. A sand particle density of about 2600 kg/m3 is generally accepted.
Particle size influences erosion primarily by determining how many particles impact on a surface. Figure 18-1 shows the paths of particles as they are carried through an elbow. The flow paths depend on the particle weight and the amount of drag imparted on the particles by the fluid as they pass through the elbow. Figure 18-1a shows particle paths typically seen for small sand grains (of the order of 10 microns) in a liquid flow. Figure 18-1b is representative of typically sized sand grains (of the order of 200 microns) in liquid flows, and Figure 18-1c is representative of typically sized sand in gas flows. Small light particles require very little drag to change direction. Therefore, they tend to follow the flow as shown in Figure 18-1a. This figure also represents a case of particles flowing in a highly viscous, dense fluid. Figure 18-1c illustrates the path of large heavy particles in an elbow, the large heavy particles have a relatively high momentum and they will hardly be deflected by the fluid flow; therefore, they tend to travel in straight lines, bouncing off the elbow walls as they go. Figure 18-1c illustrates the case where particles are flowing in a low-density, low-viscosity fluid.
Figure 18-1 Paths of Different Sized Particles through an Elbow [2]
Normally, hard particles cause more erosion than soft particles, and sharp particles do more damage than rounded particles. However, it is not clear whether the variability of sand hardness and sharpness causes a significant difference between the erosion rate in production systems associated with different wells or fields.
18.2.2 Erosion-Corrosion
Erosion often causes localized grooves, pits, or other distinctive patterns in the locations of elevated velocity. Corrosion is usually more dispersed and identifiable by the scale or rust it generates. Erosion-corrosion is a combined effect of particulate erosion and corrosion. The progression of the erosion-corrosion process depends on the balance between the erosion and corrosion processes. Erosion-corrosion can be avoided by ensuring that operating conditions do not allow either erosion or corrosion.
In a purely corrosive flow, without particulates in it, new pipe system components typically corrode very rapidly until a brittle scale develops on the surfaces exposed to the fluid. After this scale has developed, it forms a barrier between the metal and the fluid that substantially reduces the penetration rate. In this case, very low-level erosion is also taking place simultaneously with corrosion. In highly erosive flows, in which corrosion is also occurring, the erosion process dominates, and scale is scoured from exposed surfaces before it can influence the penetration rate. Corrosion therefore contributes little to material penetration. At intermediate conditions erosion and corrosion mechanisms can interact. In this case, scale can form and then be periodically removed by the erosive particles.
18.2.3 Droplet Erosion
Droplet erosion occurs in wet gas or multiphase flow systems in which droplets can form. The erosion rate is dependent on a number of factors including the droplet size, impact velocity, impact frequency, and liquid and gas density and viscosity. It is very difficult to predict the rate of droplet erosion because most of these values are unknown in the field conditions.
Experimental results indicate that under a wide range of conditions, the material lost by droplet erosion varies with time. Initially, the impacting droplets do not cause erosion due to the existence of protective layers on the surface. However, after a period of time, rapid erosion sets in and the weight loss becomes significant and will increase linearly with time.
The hydrodynamics of the multiphase mixture within the pipeline also affects the degree of wetting of the pipe walls and the distribution of corrosion inhibitors injected into the pipeline system. Above a certain velocity, the inhibitor film will be removed, leading to increased rates of corrosion. Currently, to determine the critical velocity, the following empirical correlations are used:
(18-1)
where
verosion: velocity of erosion, ft/s;
C: constant defined by Table 18-1.
Table 18-1. Erosion Velocity for Gas/Condensate Systems with Various Ratios of Condensate and Gas (CGRs)
Table 18-1 shows different erosion velocities proposed by various researchers. From the API specification [3], the maximum gas velocity should not exceed 15 m/s (50 ft/s) in order to prevent stripping of the film-forming corrosion inhibitor from the inside surface of the pipe. However, there is a suggestion that the API specification is overly conservative. The suggestion in DNV-RP-O501 [4] that droplet erosion and liquid impingement erosion are unlikely to occur in steel components at velocities below 70 to 80 m/s is probably more realistic although it is not clear where these values come from.
18.2.4 Cavitation Erosion
When liquid passes through a restrictive low-pressure area, cavitation can be generated. If the pressure is reduced below the vaporization pressure of the liquid, bubbles are formed. These bubbles then collapse and generate shock waves. These shock waves can damage a pipe system. Cavitation is rare in oil and gas production systems because the normal operating pressure is generally much higher than the liquid vaporization pressures. Evidence of cavitation can be sometimes found in chokes, control valves, and pump impellers, but is unlikely to occur in other components.
The onset of cavitation in equipment or components with flow constrictions can be predicted by calculating a cavitation number K, defined as below:
(18-2)
where
Pmin: minimum pressure occurring in the vicinity of the restriction, Pa;
Pvap : vapor pressure of the liquid, Pa;
A cavitation number of less than 1.5 indicates that cavitations may occur.
18.3 Prediction of Sand Erosion Rate
Knowing a facility’s erosion risk is of the utmost importance for well management optimization against sand production. Normally, the sand erosion models consider the erosion process into three stages. First, the fluid flow in the facilities is modeled or in some way approximated. This flow prediction is then used to derive the drag forces imparted by the fluid on the particles (sands); hence, the trajectories of a large number of particles are predicted. Computational fluid dynamics (CFD) software has been used to model the fluid flow and particle trajectories. It has been shown to be good at predicting erosion locations and erosion scar shapes. Second, the damage due to the individual particles’ impact on a wall is calculated using a material-specific empirical or a theoretically derived impact damage model. Last, the average impact damage of a large number of particles can then be used to predict the distribution and depth of erosion damage on a surface. However, the physical process is only partially understood and the prediction of the critical conditions has to rely on empirical or semiempirical models.
On the basis of experimental results, the sand erosion rate can be summarized in relation to the kinetic energy of sand fragments through the following parameters:
The sand erosion rate is expressed in the following form based on the impact damage model:
(18-3)
where,
E: sand erosion rate, kg of material removed/kg of erodant;
A: a constant depending on the material being eroded and other factors;
F(α): material dependent function of the impact angle, which is between 0 and 1.0;
18.3.1 Huser and Kvernvold Model
Huser and Kvernvold [5] developed the following impact damage equation:
(18-4)
where,
mp : mass flow of particles impacting on an area;
K, n: constants given for steel and titanium grade materials and Glass-reinforced plastics (GRP) piping.
The values for K, n, and F(α) are derived from sand-blasting tests on small material samples.
Figure 18-2 shows the angle relationship F(α) used by Huser and Kvernvold. This model has been used with both CFD particle models and with various empirical particle models. DNV RP -0501 [5] compiles these empirical particle models for the calculation of sand erosion in straight pipes, around welds, and in elbows, tees, and reducers.
Figure 18-2 F(α) Relationship for Ductile and Brittle Materials [5]
18.3.2 Salama and Venkatesh Model
Salama and Venkatesh [6] developed a method similar to that of Huser and Kvernvold, although they simplified their model by making a conservative assumption that all sand impacts occur at about 30°, therefore, F(α) is set to 1. This approximation is reasonable for gas flows, but does not account for the particle drag effects in liquid flows.
(18-5)
where:
Er: erosion rate, thousandths of inch per year;
Sk : geometry dependant constant; Sk = 0.038 for short radius elbows and Sk = 0.019 for ells and tees.
The predicted erosion rate based on the above equation is an average of 44% greater than the measured value in comparison with experimental air/sand tests of elbows. This method is consistently conservative. Svedeman and Arnold [7] also suggested using this equation, but they gave values of Sk for gas systems, with an Sk of 0. 017 for long radius elbows and an Sk of = 0.0006 for plugged tees.
18.3.3 Salama Model
Salama [8] updated the Salama and Venkatesh model [6] for gas/liquid systems and developed a new equation as follows:
(18-6)
d: particle diameter, microns;
Vm : mixture velocity (m/s) defined by Vm = Vliquid + Vgas
ρm : mixture density defined by ρm = (ρliquid · Vliquid + ρgas · Vgas)/Vm
Particle size and liquid effects are included in the equation. By calibrating against experimental data from Weiner and Tolle [9] and Bourgoyne [10], the geometrical constants are given as follows:
18.3.4 Tulsa ECRC Model
A range of particle models have been developed by the University of Tulsa Erosion Corrosion Research Center (ECRC) based on a significant amount of research work on pipe component erosion. Those models are utilized with an impact damage model of the form:
(18-7)
In the above equation the coefficient of FM accounts for the variation in material hardness. McLaury and Shirazi [11] give typical values of FM for a number of different steels ranging from 0.833 to 1.267, suggesting a ±25% in erosion resistance between different steels. These values have been derived from impingement tests. Table 18-2 summarizes material properties of hardness and material factor for noncarbon steels.
Table 18-2. Material Properties and Erosion Ratio Coefficients for Noncarbon Steels
The coefficient of FS accounts for sand sharpness: 1.0, 0.53, and 0.2 for sharp, semirounded, and rounded grains, respectively. A value of 0.53 is used to represent production systems.
18.4 Threshold Velocity
The commonly used practice for controlling sand erosion in gas and oil producing wells is to limit production velocity; the critical velocity is called fluid threshold velocity, below which an allowable amount of erosion occurs.
The API RP14E guideline [3] limits the production rates for avoiding erosional damage and the recommended velocity limitation described by the Equation (18-8). The recommended value for the constant C is 100 for continuous service and 125 for intermittent service. When sand is present, API RP 14E suggests that the value of C should be smaller than 100 but does not indicate what the value should be. Furthermore, the sand properties, fluid viscosity, etc., cannot be considered in API RP 14E.
(18-8)
The recently developed methods for predicting threshold velocities are based on the penetration rates in elbow geometry because the sections with this geometry are more susceptible to erosion damage than a straight pipe section.
18.4.1 Salama and Venkatesh Model
Salama and Venkatesh [6] developed a model for predicting the penetration rate for an elbow. Their suggested equation is:
(18-9)
where
By assuming the hardness of T is equal to 1.55×105 psi and allowing the penetration rate of h to equal mil/yr, Salama and Venkatesh obtained an expression for the erosion velocity of threshold velocity for sand erosion:
(18-10)
The authors also suggested that this equation be used for gas flows only and indicated that particle-impact velocity in gas flows with low density and viscosity nearly equals the flow stream velocity. They noted that this equation is not valid for liquid flows because the threshold velocity given by this equation actually represents the particle-impact velocity, which is generally lower than the flow stream velocity.
18.4.2 Svedeman and Arnold Model
On the basis of Salama and Venkatesh’s work, Svedeman and Arnold [8] suggested the following formula for predicting a threshold velocity based on the penetration rate of 5 mil/yr:
(18-11)
where
ve : erosional-threshold velocity, ft/s;
Ks : empirical constant based on data from [2].
18.4.3 Shirazi et al. Model
Shirazi et al. [12] proposed a method for calculating the penetration rates for various pipe geometries, in which the following expression is used for calculating the maximum penetration rate in elbows for carbon steel material:
(18-12)
where
h: the penetration rate, mil/yr;
A:coefficient dependent on pipe material;
Fs : sand sharpness factor as listed in Table 18-3;
Table 18-3. Sand Sharpness Factor, Fs
| Description | Fs |
| Sharp corners, angular | 1.0 |
| Semi-rounded corners | 0.53 |
| Rounded, spherical glass beads | 0.20 |
Fp : penetration factor (where Fp of 3.68 in./lb·m is obtained from experimental data for steel elbows and tees);
This method accounts for many of the physical variables in the flow and erosion processes and includes a way to predict the maximum penetration rate for sand erosion. The capabilities of the method are evaluated by comparing predicted penetration rates with experimental data found in the literature. A major difference between this method and the earlier work lies in that this method is developed to finding the “characteristic impact velocity of the particles” on the pipe wall, vp . This characteristic impact velocity of the particles depends on many factors, including pipe geometry and size, sand size and density, flow regime and velocity, and fluid properties.
Given an allowable penetration rate (of 5 or 10 mil/yr), a threshold flow stream velocity can be readily calculated and combined with the procedure of impact velocity particles using the iterative solution procedure as shown in the following section.
18.4.4 Particle Impact Velocity
Generally, the erosion rate is proportional to the particle impact velocity, so there is a necessity to analyze the characteristic impact velocity in detail.
A simple model is used to describe the characteristic of impact velocity of particles. Figure 18-3 shows the procedure presented conceptually. In this procedure, a concept “stagnation zone,” which represents the fluid layer that the sand particles must penetrate, is defined. Also a characteristic length, called the equivalent stagnation length L, is used to represent this distance in the simpler direct impingement model. Figure 18-4 illustrates erosion testing results of the equivalent stagnation length, which can be used to calculate L for elbow geometry.
Figure 18-3 Concept of Equivalent Stagnation Length [11]
Figure 18-4 Stagnation Length versus Pipe Diameter for Elbow [11]
The behavior of the particles in the stagnation region mainly depends on:
A simplified particle-tracking model is used to compute the characteristic impact velocity of the particles. This model assumes that the article is traveling through an inside diameter flow field that is assumed to have a linear velocity in the direction of the particle motion and uses a simplified drag-coefficient model.
The impact velocity depends on:
These parameters are combined into three dimensionless groups related to one another as shown in Figure 18-5. The dimensionless groups are defined as follows:
Figure 18-5 Effect of Different Factors on Particle Impact Velocity [11]
Particle Reynolds number, NRe
(18-13)
where
Dimensionless parameter, Φ
(18-14)
Figure 18-5 contains much useful information about how various parameters affect vp and sand erosion. For example, it shows how fluid and sand properties affect vp. Once vp is determined, it is used in Equation (18-11) to calculate the erosion and penetration rates for a specific geometry, such as an elbow.
18.4.5 Erosion in Long Radius Elbows
In this model, the erosion condition in a long radius elbow has been studied on the basis of a standard elbow mechanistic model. To extend the mechanistic model to be able to predict the penetration rate in long radius elbows, a new term called the elbow radius factor is introduced [13]. The elbow radius factor (ERFr/d ) is defined as follows:
(18-15)
where PnL is the maximum penetration rate in the long radius elbow, and Pnstd is the maximum penetration rate in a standard elbow. The introduction of elbow radius factor preserves the accuracy of the mechanistic model for standard elbows and extends it to predict penetration rates in long radius elbows.
(18-16)
where,
ERFr/d : elbow radius factors for long radius elbows;
This equation accounts for the elbow radius curvature effect in different carrier fluids and sand particle size. Note that this equation is based on a sand particle density of 165.41b/ft3.
The model did not investigate the effects of turbulent fluctuation on the erosion predictions because direct impingement is the dominant erosion mechanism for elbows. However, as the radius of curvature increases significantly, the long radius elbow becomes closer to a straight section of pipe and the random impingement mechanism can become important.
18.5 Erosion Management
Erosion management includes the erosion monitoring and erosion mitigation methods.
18.5.1 Erosion Monitoring
The following methods are used for erosion monitoring on steel pipes or special tab erosion [14]:
• Ultrasonic gauges are used to clamp to the external surface of the pipe. They send out an ultrasonic pulse to measure the thickness and the material loss from which to determine the erosion severity. The method is sensitive to the noise from other sources; also the primary limitation of this method is that it only checks a limited local region of the pipe.
• Weight-loss coupons made of the same or similar material as the pipe being monitored are installed and periodically retrieved and weighed. They provide only discrete monitoring and are unsuitable for subsea engineering equipment.
• Electrical resistance probes measure the accumulated erosion as an increase in electrical resistance on a known cross section. Calibration and temperature changes are of concern.
• Electrochemical probes determine the erosion rate through measurement of the linear polarization resistance between electrodes through a conductive electrolyte flowing inside the pipe. This method is suitable only for conductive liquids such as water, or oil systems with high water cuts.
18.5.2 Erosion Mitigating Methods
A number of measures can be taken to mitigate erosion [3], as discussed next.
18.5.2.1 Reduction of Production Rate
Reducing the production rate includes reducing the flow velocity and sand production rate. However, this has adverse financial implications.
18.5.2.2 Design of Pipe System
Minimizing the flow velocity and avoiding sudden changes (e.g., at elbow, constrictions, and valves) in the flow direction should be given much attention in order to reduce the severity of any erosion. Blind tees are generally perceived as being less prone to erosion than elbows, so the use of full-bore valves and blind tees in place of elbows can reduce erosion problems. Also, the flow regime has an impact on erosion problems and slugging flows can be particularly damaging; therefore, slug catchers may be appropriate for reducing the severity of any erosion.
18.5.2.3 Increasing Wall Thickness
Thick-walled pipes are often used to increase the wear life of a pipe system. However, the thick wall thickness reduces the pipe bore, which in turn elevates flow velocities and increases the erosion rate, particularly with small-bore pipe systems.
18.5.2.4 Specialized Erosion-Resistant Materials
Generally, in oil and gas production systems nearly all of the components will be made of ductile metals, although other materials such as plastic and rubber may also be used. Material properties have a significant effect on erosion problems. If erosion problems are suspected, specialized erosion-resistant materials such as tungsten carbide can be used.
The primary factor of ductile materials in controlling erosion is their hardness. Consequently, steels are more resistant than other softer metals. In vulnerable components, specialized materials such as tungsten carbides, coatings, and ceramics are often used. These materials are generally hard and brittle and have a super erosion resistance to steel (often orders of magnitude better). However, some coated materials’ resistance may rapidly reduce once the coating or its substrate fails.
Brittle materials erode in a different manner. Impacts on brittle materials abrade the surface, and erosion increases linearly with the impact angle, until reaching a maximum for perpendicular impacts.
18.6 Sand Management
Sand management is an operating concept in which traditional sand control means are not normally applied and production is managed through monitoring and control of well pressures, fluid rates and sand influx [14]. Sand management has proven to be an effective tool in North Sea oil and gas production wells.
Sand management has proven to be workable, and has led to the generation of highly favorable well skins because of self-cleanup associated with the episodic sand bursts that take place. These low skins have, in turn, led to higher productivity indexes, and each of the wells where sand management has been successful has displayed increased oil or gas production rates. Furthermore, expensive sand control devices are avoided and the feasibility of possible future well interventions is guaranteed.
Different analysis and design tools are necessary for evaluating the sand production probability, for quantifying risk reduction, and for establishing practical operational criteria for safe and optimum production. Such design tools include the capacity to predict:
• Sand quantities and production rate;
• Conditions of sand transported inside the production flow line.
Another essential tool is sand monitoring technology that allows for real-time quantitative sand influx tracking.
18.6.1 Sand Management Philosophy
Classical sand control techniques, such as gravel packing, use of wire-wrapped or expandable screens, frac-and-pack, and chemical consolidation, are based on a sand exclusion philosophy: Absolutely no sand in the production facilities can be tolerated. Alternatively, in the absence of means of totally excluding sand influx, the traditional approach is to reduce the production rate to minimize the amount of entering sand.
The most extensive field validation of the reliability and cost effectiveness of sand management is possessed by the Canadian heavy-oil wells. This approach is a combination of techniques that define and extend the safety limits. The too conservative approaches in which no sand is permitted into the production system are avoided or delayed.
18.6.2 The Sand Life Cycle
Risk management requires reliable analysis of the “sand life cycle,” starting with predicting formation conditions conducive to sanding, and ending with the ultimate disposal of the produced material at the surface. These techniques are based on:
• An extensive data acquisition of the field;
• Theoretical modeling of the involved physical processes;
Also, the techniques will help the production engineer optimize the design and provide risk assessment throughout the well’s production life.
18.6.2.1 Sand Detachment
Sand detachment is a mixed hydromechanical process, which releases sandstone fragments from the formation near the well, can be viewed as a mixed hydromechanical process. Many models have been established to predict the sanding initiation conditions.
First, due to excessive drawdown or reservoir pressure depletion, the production stratum fails in compression or extension from excessive local stresses at the free surface near the wellbore. Alternatively, sanding may result from formation weakening, perhaps from fatigue effects related to repeated well shut-downs, or from water breakthrough and related capillary or chemical cohesion loss.
Second, the yielded material is destabilized and fluidized by hydrodynamic forces from the fluid flow into the well. In addition, the force varies with time along with local geometry, so sand cannot flow constantly and is likely to be produced as bursts, which has been verified by small-scale laboratory experiments. Transient pressure gradient effects that result from well shut down and start-up and relative permeability changes are the major reasons for the episodic increases in the sand influx, also these are the best known causes for increased forces acting on the sand in the vicinity of wellbore.
18.6.2.2 Sand Transport
Once sand is detached, it follows the fluid through the perforations and into the well. Then gravity and hydrodynamic forces will act on the grains and sand fragments. The effects of sand, including the probability of transport to the surface, blocking of perforation tunnels, or settling into the well sump or horizontal well section, depends on the balance of the following factors:
In particular, sand may sediment and be remobilized later as conditions change (e.g., velocity changes, water cut increases) in long horizontal wells. These events may often be interpreted as sanding because of formation failure, rather than as a well cleanup process.
18.6.2.3 Sand Erosion
Sand erosion including the area of tubing, flow lines, and chokes is significantly related to the sand transport process. The kinetic energy of the moving particles is transferred to the steel when they impinge on a surface, causing abrasive steel removal. Generally, sand flow rate and sand fragment velocity are the two main factors determining the erosion risk. For heavy crude fields, the velocity is low and the risk is also low; however, HP/HT gas condensate fields, gas expansion and acceleration near the wellhead dramatically increase the erosion risk.
Erosion risk is a major technical and economical constraint because it may lead to severe safety problems. Erosion forces the production rate to be kept below a limit that is considered safe.
18.6.2.4 Surface Sand Deposition
Once sand passes the wellhead, it passes through the surface lines, or, for subsea wells, through the sea line, to deposit in the separator, which must be cleaned and flushed from time to time according to the expected average sand rate. The oil-contaminated sand that is produced is collected and sent for ultimate disposal. For subsea engineering equipment, it has been dumped into the sea in the past, but this practice is not viewed as an option in future operations.
18.6.3 Sand Monitoring
Sand monitoring is a critical aspect of sand management. Sand monitors are used when erosion problems are suspected. Current sand monitoring methods are discussed next.
18.6.3.1 Volumetric Methods
Volumetric methods include the following issues:
• Sand traps can be installed to capture sand at tees or bends usually. However, sand traps are not a real-time method because they need to be disassembled to measure the sand production. These techniques have not proven effective, because the majority of the produced sand is normally not captured. (North Sea experience indicates a recovery of 1% to 10%.)
• Fluid sampling, including centrifugation for water and sand cuts after the primary separator, includes measurements of bottom sediment and water, which are carried out during appraisal well testing or during normal production. However, this method cannot be guaranteed due to the much remaining in the primary separator.
• Another method that has been used quite extensively in the Adriatic Sea on gas wells consists of dismounting the sand separator, jetting it clean of all sand, and quantifying all produced solids. However, the accuracy and practicality (i.e., the time and manpower required to dismount, jet, and remount the separator) limit its application.
• Use of an in-line sand cyclone is a new method used on some North Sea platforms. Sand is effectively separated from the produced fluid and stored in a tank. The load cells or other devices on the tank allow for the measurement of sand accumulation in real time.
18.6.3.2 Acoustic Transducers
Acoustic transducers have proven to be an effective sand monitoring tool. Installed in the flow system, a transducer includes the following items:
18.6.4 Sand Exclusion and Separation
Downhole sand screens and gravel packs are often used to stop sand from entering the production system. Typically, sand screens prevent particles larger than 100 microns from entering the production stream. However, a balance should be struck between reducing the productivity by including a sand screen and having to choke back an unprotected well to avoid excessive sand production. In addition, even very small particles can generate a significant degree of erosion; therefore, sand screens and gravel packs cannot guarantee erosion-free operation.
Sand separation can be conducted at three principal levels:
• The primary separation facility topside;
• The subsea separation module (for offshore installations);
• In the downhole separator in conjunction with oil/water separation.
Surface modules include high-pressure horizontal baffle-plate separators, vertical gravitational separators, and centrifugal segregators. These devices can be very effective at protecting chokes in particular. In subsea and downhole separation, water-wet sand will normally be separated by gravity and stored or reinjected. A specially designed sand cyclone or sand centrifuge may be required for oil-wet sand.
18.6.5 Sand Prevention Methods
Table 18-4 evaluates and lists disadvantages of the different methods used for dealing with sand production. In general, sand control represents high-cost/low-risk solution. Sand management leads to a low-cost solution, but it also involves active risk management.
Table 18-4. Evaluation of Different Sand Prevention Methods
| Control Method | Major Short-comings |
| Chemical consolidation | |
| Screens, slotted liners, special filters | |
| Inside-casing gravel packing | |
| Open-hole gravel packing | |
| Propped fracturing, including frac-and-pack, stress frac, and use of resin-coated sand | |
| Selective perforating | |
| Oriented perforating | |
| Production rate control |
18.7 Calculating the Penetration Rate: Example
This example illustrates the calculation process for determining the maximum penetration rate for a long radius elbow. The calculation includes the following steps:
• Determine the elbow radius factor (ERFr/d ).
• Calculate the particle impact velocity;
• Equivalent stagnation length L
• Dimensionless parameters, NRe and Φ;
• vp/v based on Figure 18-5.
In this example, a 2-in. pipe with a Schedule 40, ASTM 234 Grade WPB seamless elbow with an ID of 2.067 in. was used. The r/d ratio of the elbow was 3.0, and the liquid used was clay/mud at a velocity of 25 ft/s; the sand rate is 1800 ft3/D. Detailed input data for the example is summarized in Table 18-5.
Table 18-5. Input Data for Calculating Penetration Rate
| Parameter | Description and Units | Value |
| A | Coefficient dependent on pipe material | 0.9125 |
| r/d | Long radius elbow | 3 |
| Fs | Sand sharpness factor (Table 18-3) | 0.53 |
| Fp | Penetration factor | 3.68 |
| qsd | Sand rate (ft3/D) | 1800 |
| ρp | Particle density (lbm/ft3) | 165.4 |
| ρf | Fluid density (lbm/ft3) | 65.4 |
| v | Fluid velocity (ft/s) | 25 |
| d | Pipe diameter (in.) | 2 |
| ID | Elbow diameter (in.) | 2.067 |
| μf | Fluid viscosity(lbm/ft·s) | 3.36 × 10−3 |
| B | Brinell hardness | 120 |
| dp | Particle diameter (μm) | 350 |
18.7.1 Elbow Radius Factor
The elbow radius factor (ERFr/d) is calculated according to Equation (18-16). In this calculation, the unit of density is lb/ft3 and the viscosity of μf is cp. The calculated ERFr/d is 0.304.
18.7.2 Particle Impact Velocity
The particle impact velocity is calculated based on the methods illustrated in Section 18.4.4.
Step 1: Equivalent Stagnation Length L
Calculation of the equivalent stagnation length L is based on Figure 18-4. For L0 = 1.18 in., Equation (18-17), shown in Figure 18-4, is used:
(18-17)
and L/L0 = 1.78 is calculated. Therefore, L =, so L = 1.78 × 1.18 = 2.1 in.
Step 2: Compute NRe and Φ
The dimensionless numbers NRe and Φ are calculated using parameters with consistent units. These parameters are used for Φ: L = 2.1 in., dp = 0.0138 in. (350 μm), ρf = 65.4 lbm/ft3, and ρp = 165.4 lbm/ft3. We obtain Φ = 60.285. For NRe, ρf = 65.4 lbm/ft3, v = 25 ft/s, dp = 1.148 × 10–3 ft (350 μm), and μf = 3.36 × 10–3 lbm/ft·s. We obtain NRe = 558.77.
Step 3: Determine the vp/v of a Valve
The vp/v is obtained from Figure 18-5 based on the given NRe and Φ. For this example, vp/v = 0.0175. Then, vp is calculated with vp = (vp/v) × v = 0.0175 × 25 = 0.4375 ft/s.
18.7.3 Penetration Rate in Standard Elbow
In this example, semirounded corner sand is assumed. From Equation (18-12), with A = 0.9125, Fs = 0.53, Fp = 3.69 in./lbm, vp = 0.4375 ft/s, qsd = 1800 ft3/D, and delbow = 2.067 in./1.0 in. = 2.067:
h = 1761 mil/yr.
18.7.4 Penetration Rate in Long Radius Elbow
Equation (18-15) is rewritten as the following equation:
(18-18)
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