2. Description of Related Art.

Scale deposits in tubular through which fluids such as oil may circulate disrupt production and cause costly intervention work. Scale deposits are formed in several ways and may be caused by several different phenomena. Scale may be generated as the result of water flooding, commingling of waters of different. composition, or simply by depressurisation of the fluids flowing through the tubular as they flow to surface. Scales occur as a mineral content of the fluid (usually water) has exceeded the fluid's saturation point in response to a change in conditions. The"change in conditions"may be a mixing of different waters in the fluid, changes in temperature and pressure at which the fluid is subjected, water evaporation from the fluid, or water chemistry and pH changes (such as the ones due to C02 out-gasing).

The nature of scale formation in oilfield tubular is unique by its environment. Oilfield scale forms in the presence of oil and gas, waxes and surfactants, metal corrosion, and in turbulent and high velocity flow, Oilfield scale often is composed of more than one mineral. It is not uncommon for several different compounds to be deposited together or in layers. Wax, oil and iron oxide can be trapped within the scale formation. Even the density of the scale can vary, depending on the depositional conditions.

Treating oilfield scale is a complex problem. In certain regions where tubular are prone to formation and deposition of scales, such as in the North Sea and Canada, treatments to prevent or minimize scale formation are commonly practiced. These techniques, including removal and/or inhibition of scales, however, are not 100% effective. For example, a removal or inhibition treatment applied uniformly to several wells with different scaling tendencies may result in some wells being under-treated and thus still displaying scales. Moreover, an inhibition treatment can lose effectiveness over time, as the production environment changes, leading to occurrence of certain conditions favourable to scale formation. Furthermore, when scales include more than one mineral the response to the inhibition treatment is partial.

Oilfield scale management programs have been designed to prevent scale deposition or, when the prevention is not feasible, to detect the early occurrence of scale deposition and to use the most efficient method to remove the deposits and inhibit further growth. Effective scale management also requires on-line monitoring of scaling tendencies as well as the detection and identification of scale deposits. A direct measurement of scale deposition not only would benefit the selection/design of an effective inhibitor for the treatment of scales, but it could signal changes in scaling conditions, indicating when a scale treatment needs to be modified.

A simple, reliable method to continuously monitor for scale formation is needed in a strategy to elude scale-fighting's costly effects.

A process of scale management typically involves: detection, identification (location composition, quantification), removal, inhibition or prevention, and monitoring. Detection is important because a whole sequence of reactionary events follows detection. Detection of scale all too often comes after production begins to decrease. Successful early detection is the first step to minimizing the effects of scale.

A commonly practiced method of scale detection, in one field where scale formation is undesirable, is monitoring for abnormal decline in oil production and/or pressure drop across the length of the tubular. As scale formation is not the only cause for decreasing production or increasing pressure drop, monitoring the existence of decline in oil production and/or pressure drop alone is generally not efficient to detect the presence of scales.

Several scale detection methods have been devised. One method relies on tracking residual scale inhibitor as a means to detect potential scaling conditions. Low inhibitor concentrations could indicate insufficient inhibitor and, hence, potential presence of scales. This method requires a constant water composition, as compositional changes would alter the inhibition requirements. The critical inhibitor concentration is usually based on lab measurements, which cannot reproduce field conditions adequately. Moreover, this method involves the use of the scale inhibitor before even a need for it has been determined by the detection of scales.

Another method relies on the use of a rotating disk electrode (RDE) as a way of detecting scales. Scaling intensity is given by the percentage of the electrode surface covered by scale deposits. To perform in-situ measurements, the RDE technique requires much further development due to its inaccuracy in the presence of oil.

For borehole scale deposits, pulsed neutron measurements have been used to detect sulfate scales. A post-production gamma ray log compared to a pre-production (openhole) gamma ray log has long been practiced as a technique to detect scale deposits containing naturally occurring radioactive material (NORM), which are common components of scale.

Logging techniques cannot detect all scale deposits, however, and are not used in surface pipelines.

Other common scale detection methods are based on intervention and physical observation. Scale is often detected when chokes or control valves are removed and inspected after a decline in performance. Pig runs can recover scale from pipelines. In some installations, a corrosion probe is used to make routine checks for scale deposits. Visual inspection, however, requires human intervention and is limited by the frequency of the inspections.

After scale is detected, the next challenge is identifying the scale's composition and quantity (thickness). If this information can be acquired early on in the process, a scale control program may be optimized so that a treatment for scale is provided whereby the cost of treatment is offset by a reduction in production losses otherwise occurring in the absence of the treatment.

Due to the difficulty in identifying and quantifying scale deposits in-situ, such steps are frequently neglected. Instead, knowledge of regional formation water chemistry and scale tendencies is often used to assess possible scale composition. Based on such assessment of scale composition, a removal and inhibition treatment is devised by chemical treatment. The evaluation of inhibition treatments is usually performed in laboratory environments, which cannot duplicate real oilfield pipe conditions.

The above-mentioned scale removal and inhibition treatments attempted before a thorough identification of the scaling compounds is made, often do not lead to effective removal of all of the scale present. One reason is that scales, most times, are formed as multiple scale compounds and removal of one type of scale does not lead to removal of all scales present in the compound.

Moreover, current in-situ measurements of scale are not made during inhibition treatments.

Scale deposit measurements are needed, however, to evaluate the success of scale removal and the effectiveness of scale inhibition. An in-situ measurement of scale could signal not only the need to commence a scale removal procedure, but could also indicate when the scale is fully removed, saving the overhead related to over-treating. An in-situ scale measurement may thus be a more reliable and effective way to evaluate different inhibition treatments. Furthermore, on-line monitoring for scale is another much needed service for which there has yet been no solution. Because conditions change, a successful inhibition of scale does not guarantee no return of scale in the future. Monitoring for scale, essentially a repetition of the detection and identification steps, is particularly important in any field where scale is anticipated or where production economics may be sensitive to scale-induced production declines.

Existent techniques thus suffer of various deficiencies either related to the fact that the detection and identification is not made in-situ, or to the fact that the detection and identification is not made on the fly without disrupting production. It is thus desirable, to provide a method of in-situ detection and identification of scales that overcomes the deficiencies associated with existent techniques.

SUMMARY OF THE INVENTION The present invention provides in one embodiment thereof a method of identifying scales on a surface of a passage through which a fluid is passing. The method includes the following steps. First, second, and third values are determined. The first, second and third values are related to attenuation of the fluid for first, second, and third energy levels respectively at which energy is emitted through the fluid. It is determined first and second fluid ratios r1f and r2f between the first and second values and between the second and third values respectively.

It is determined for a plurality of scales theoretical values related to attenuation of each scale of said plurality of scales for said first, second, and third energy levels. For each scale of the plurality of scales are determined a first ratio r1s between said first and second scale values and a second ratio r2f between said second and third scale values. Scales are identified based on comparison between (r1f, r2f) and (r1s, r2s).

Brief Description of the Drawings Figure 1 illustrates an apparatus that may be used for one embodiment of the method of the present invention; Figure 2 illustrates various solution triangles for dual-energy spectral gamma ray hold-up measurement in the presence of scale ; Figure 3 illustrates a diagram showing the attenuation ratios for various fluids (gas, oil, water) and major types of scales produced by way of a dual energy attenuation measurement Figure 4 illustrates a chart showing how scale compound may be estimated using the slope of the gas point translation (line) ; Figure 5 illustrates an energy distribution in the presence and in the absence of scale deposit for three energy levels used at 32 keV, 80 keV and 356 keV; Figure 6 illustrates a chart used for identification of scales by way of the method according to the present invention; Figure 7 illustrates a simulation of case with 50% gas volume fraction (GVF), 50% water liquid ratio (WLR) and increasing scale thickness of 0, 10,25, 100,250, 400 and 550 microns; Figures 8 to 12 show simulation data created using a random generator that produce a stochastic flow with added statistical noise to account for the Poisson nature of gamma ray detection; DETAILED DESCRIPTION OF THE INVENTION In the following description, numerous details are set forth to provide an understanding of the present invention. However, it will be understood by those skilled in the art that the present invention may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.

Nomenclature Symbols: A = Gamma-ray attenuation B = Apparent gamma-ray attenuation N = Count rate (cps) d = Throat Diameter (m) t = Thickness (m) n = Fluid fraction S = Differential p = Density (kg/m3) E = Mass attenuation Subscripts: o'= oil w = water g = gas m = mixture s = scale or substance vac= vacuum One embodiment of the method of the present invention utilizes principles related to the attenuation of a beam of gamma or X rays emitted through a fluid. The presence of scales may be detected and their nature identified as a modification (increase) in the attenuation observed in the path of the beam of gamma or X rays emitted. The reason for the change in the attenuation is due to fact that scales are typically composed of atomic elements that are heavier, and that cause a higher attenuation of the gamma rays, than the hydrocarbons (oil and gas) and water existent in the fluid.

Figure 1 illustrates an embodiment of an apparatus 100 that may be used by the method of the present invention. Apparatus 100 may be placed in the structures (piping and tubing in one embodiment) through which a fluid is flowing. In one embodiment, the fluid may be a multiphase fluid including oil, gas, and water, but the present invention is not limited in this respect to this composition.

Apparatus 100 includes a tubular portion 101 with a passage 106 through which the fluid may flow. Apparatus 100 also includes a measurement section 102 where a source 104, which may be a radioactive chemical source emits energy in the form of gamma rays or X rays at different energy levels. In a different embodiment, the source 104 may be an X-ray generator.

The following description makes reference to gamma rays but it also applies to embodiments where the source emits X-rays.

In one embodiment the source 104 emits gamma rays at three distinct energy levels through the fluid circulating through main passage 106 of the apparatus. A detector 108 placed across the passage 106, spaced apart from source 104 by distance d, is configured to detect the gamma rays that have not been absorbed by the fluid flowing trough passage 106. The source 104. is encapsulated except for a small opening on the detector side, permitting a collimated beam of gamma rays to pass across d to the detector 108. The detector 108 may include in one embodiment a conventional scintillator crystal such as Nal. A photo multiplier 110, coupled to the detector 108 converts light pulses detected by the detector into electrical signals, also referred to as count rates, which are digitally processed.

Consider a case where the source 104 emits gamma rays at a single energy level. The gap between the source and the detector is filled with substance, s, making up the fluid, of density, p5. If we consider a single energy of the source emission, the mass attenuation, M, of the substance can be determined as follows : where, us is the linear attenuation of the substance, and NVaC and N are the number of gamma ray counts detected over a given time after passing through a vacuum and through the substance, respectively. The term, is the full pipe attenuation, A, of the substance.

This relationship applies to solids, liquids and gases.

Consider now the case where the source 104 emits gamma rays at 2 different energy levels : high (H) and low (L). The lower energy, may be within the range of the photoelectric effect, and the higher energy may be within the range characterized by the Compton effect.

The detector 108 produces two series of signals NH and NL (count rates), representative of the numbers of photons detected per sampling period resulting from the emission of gamma rays through the fluid.

If the substance is a mixture or a compound, the mass attenuation of the mixture Mm or compound is determined as the mass fraction weighted average of the mass attenuations of its components or elements i: Applied to oil, water, gas and solids, in one embodiment, the mass attenuation of each phase can be shown as: <BR> <BR> <BR> <BR> <BR> Powywwgsd<BR> Po,w,g,sd The mass attenuations for oil, water, gas and scale can be calculated from the NIST tables (NIST X-Ray & Gamma-ray Attenuation Coefficients & Cross Sections, 1990, US. Dept. of Commerce) or measured directly.

Following equations (2) and (3), the attenuation of a mixture is the volume fraction average of the attenuations of it components: In a three phase, oil/gas/water mixture, the volume fractions of oil, gas and water are expressed as a,,, a, and a,,, respectively. Equation (4) may be expressed in two independent forms, i. e. , for attenuations AmH (high) and AL (low) at the two different energy levels. The three phase volume fractions a,,, a,,, ag may be computed by solving three equations for three unknowns.

Besides determining the phase volume fractions, the presence of scales in the passage 106 may be determined by way of dual energy attenuation measurements whereby values AH and Am are determined. The presence of scale causes an increase in the attenuations observed in the path of the gamma rays, as scale is composed of atomic elements that are heavier causing a higher attenuation than hydrocarbons and water existent in the fluid. Common oilfield scales attenuate preferentially the lower energy.

Monitoring attenuation increases thus provides a means to identify the scale compound (Fig. 2). Fig2 illustrates various solution triangles for dual-energy spectral gamma ray hold-up measurement in the presence of scale. The triangle shown on the right of the figure in continuous lines is obtained by drawing three lines that connect every two of the three operating points of the fluid for water, oil, and gas (the apexes of the triangle). The additional attenuation caused by the scale deposits produce a shift, corresponding to the effect of scale, in the triangle shown in continuous lines resulting in the triangle shown in dotted lines.

To have a reference point from which to measure a change in attenuation, a measurement is normally made in the presence of gas (known composition) by way of the apparatus of Figure 1 bypassed, with any liquids settling below the measure point. Provided that the gas composition does not change over the observation period, any change in attenuation in successive reference measurements may be attributed to scale formation. Similar reference measurements may be made for oil and water. As scale accumulates, the gas, oil, and water reference points progress linearly in the direction of the unknown scale point. The intersection of these lines defines the scale point (the leftmost point in the figure). The slope of a line passing through the scale point and the vacuum point (the origin of the X-Y axes) is unique for most common oilfield scales and indicates the nature of the scale. To express the slope as a non-fractional number the inverse slope, the ratio of the low energy attenuation to high-energy attenuation, A/AH, is used. The ratio ALLAH may vary significantly for different materials as one may see from (Fig 3).

Fig 3 illustrates by way of a chart dual-energy attenuation ratios for gas, oil, water and various types of scale. The type of scale may be determined from this chart from the ratio Af/Ah by looking up the scale corresponding to this ratio. This ratio may be determined as the slope of the scale line of Figure 2.

Because generally it is inconvenient to make the three reference measurements, the scale compound may be estimated using the slope of the gas point translation (line), as this slope is close to the slope of the scale point-vacuum point line (Fig 4).

In the presence of scale, apparent mixture attenuations can be written as: BmH,L = 1/d(t0A0H,L + twAwH,L + tgA0H,L + 2tsAsH,L) (6) where d = to + tw + tg + 2ts (7) and to w g s is the thickness of oil, water, gas and scale respectively. The fractions of oil, <BR> <BR> <BR> <BR> water and gas are:<BR> to,w,g <BR> <BR> <BR> <BR> <BR> <BR> <BR> αo,w,g = (8)<BR> <BR> <BR> d - 2ts The apparent attenuation then may be written in terms of the scale thickness ts and the mixture and scale attenuations: The scale thickness is roughly estimated by: The method explained above requires a separate measurement for one of the phases (gas), which would disrupt on-going production. An improved method of identification of scales provided in one embodiment of the present invention is based on continuous triple-energy spectral gamma-ray attenuation measurements made in-situ by using the apparatus shown in Figure 1. This method provides quick detection and identification of scale deposits on pipe walls such as the walls of the apparatus of Figure 1 without disrupting the flow of the fluid. The advantage of this method is an immediate scale identification, without time-lapse. The example below is given for 3 different energy peaks emitted by a 133Ba source at 32 keV, 80 keV and 356 keV (Figure 5). Figure 5 illustrates a graph showing the energy distribution (represented as a count rate) in the presence and absence of scale for the gamma rays emitted by the source of the apparatus of Figure 1. During a given time interval, the accumulated counts at each energy are measured as N 32, N 80 and N 356, The corresponding vacuum values, defined at calibration time, are respectively N32vac, N80vac and N356 vac.

The single-phase attenuations of oil, water, gas and scale can then be defined as: Alternatively, <BR> <BR> <BR> <BR> A32,-- 80, 356 dM32,80,356----<BR> <BR> Ao,w,g,s@@,@@,@@=#o,w,g,sαMo,w,g,s@@,@@,@@ (12) where M32,80,356o,w,g,s represents the mass attenuations for oil, water, gas and scale determined at each of three energies.

Two ratios r1 and r2 are computed: These ratios can be restated as : <BR> <BR> <BR> Po,w,g,sdM 32o,w,g,s M32o,w,g,s<BR> <BR> A32/80o,w,g,s=#=#=M32/80o,w,g,s (15)<BR> <BR> <BR> Po,w,g,sdM80o,w,g,s M80o,w,g,s<BR> <BR> <BR> <BR> and<BR> <BR> <BR> <BR> dm80 m80<BR> Po,w,g,saM--o,w,g, M--o,w,g,s<BR> A80/356o,w,g,s=#=#=M80/356o,w,g,s (16)<BR> D---dM356--- M356---<BR> po, w, g, s o, w, g, S o, tv, g, s The ratios of the attenuations are equal to the ratios of the mass attenuations for each phase, and consequently, are independent of the phase density and the diameter of the measuring section.

Therefore, one may determine: and Oil, water, gas and the various scale minerals may be represented on a Cartesian plot, M80'356 vs M32180. A scales identification chart illustrates several common scales encountered in oilfield wells (Fig. 6). The gas point is represented by CH4. The oil point is represented by CH2, which corresponds to the carbon/hydrogen ratio in oil.

The method according to the present invention for identifying the scale present is explained in connection with Figure 6. Initially, it is determined the oil, gas, and water point for the fluid flowing through the apparatus of Figurel by determining the ratios (r1, r2), i. e., (M801356, M32180) for oil, gas, and water. A measurement is thus made in the apparatus of figure 1 for each of the phases (oil, water, and gas) and the ratios (M80'356, M32180) are determined. Once the ratios for each of the water, oil, and gas phases are determined (oil, water, and gas points), they are plotted in the chart of Figure 6 and a line joining the oil, gas, and water points is obtained. Referring to Figure 6, the oil and gas points nearly overlie each other. The ratios rls and r2s (M80/356, M32180) corresponding to different scales (BaS04, CaS04+H20, etc) are determined by using known data such a NIST table. These ratios are then plotted on the chart as shown in Figure 6.

Then a measurement is made in real time in the pipe (apparatus of Figurel) across a fluid mixture containing oil, gas, water and scale, such as the multiphase fluid being produced from a reservoir. A point defined as operating point (r1f, r2f) (M80/356, M32'80) is determined for the fluid mixture at a given moment in time. The scales are identified by comparing the operating point of the fluid defined by (r1f, r2f) with the various scale ratios (r1s, r2s). The scale having its ratios (rls, r2s) closest to the ratios (r1f, r2f) are the most likely to be present in the pipe and thus identified. The operating point of a gasloil mixture will typically remain on the "hydrocarbon point"whatever the gas fraction value is. The operating point of a gas/oil/water mixture, without presence of scale, remains on the line between the hydrocarbon point (gas, oil in the chart) and the water point (H20). In the absence of scales, the operating point for a given fluid at a given time lies on the line shown in Figure 6 between the hydrocarbon point and the water point initially determined. As one may see in the figure, the scale points lie above the hydrocarbon/water line. If scale gets deposited on the wall of the pipe, it causes an increase the M801156 ratio, moving the operating point above the hydrocarbon/water line. Scale presence also moves the operating point strongly to the right, to higher M32'80 ratios. Thus, a movement of the measured operating point beyond the line joining the water and hydrocarbon points indicates the presence of scales. Moreover, movement of the operating points closer to a specific scale point plotted in Figure 6, is a strong indication that the respective scale of that type is present in the pipe.

Scale composition may thus be determined independently of oil, water and gas flow rates.

As scale accumulates over time, the accumulation displaces the operating point of the fluid mixture on the scale identification plot. The operating point, as seen in the plot illustrated in Figure 7, tracks along a curve that seeks the scale point and eventually ends at that point when the scale nearly clogs the pipe. Figure 7 shows the curve traced by the operating point in a fluid mixture having 50% gas volume fraction (GVF), 50% water liquid ratio (WLR) and increasing scale thickness of 0,10, 25,100, 250,400 and 550 microns for the BaS04, scale.

As one may see from Figure 7, as the thickness of scale increases, the operating point moves closer to the scale point identifying BaS04. small deposit of scale are thus sufficient to identify the scale minerals.

Figures 8 to 12 show that scale may also be identified when its thickness is constant.

Simulation data was created using a random generator to produce a stochastic flow, then adding statistical noise to account for the Poisson nature of gamma ray detection. As the gas fraction fluctuates, the high gas fraction points in the statistical set tend to distribute themselves narrowly towards the unknown pure scale point. This trend may be obtained in a few minutes, depending on the flow regime. The mean value is indicated by a cross within the"cloud" shown which represents a collection of operating points measured within a given period of time.

The location of the mean value, as well as the shape of the statistical set, clearly indicates the presence of scale. Figure 12 shows the case when no scale is present.

When the nature of the scale is identified by the method described above, the thickness of the scale deposit may be determined as follows. The oil, water, gas and scale densities at line conditions, p, W, g, s, and their respective mass attenuations at three energies Mo32w8g 356 are known. The attenuations of the gamma ray beam through four phase mixture, Am2, 80, 356, are measured for each energy within the instrument of internal diameter, d.

A linear system of four equations with four unknowns may be constructed to compute ao, w, g, s, the fractions of oil, gas, water and scale in the pipe.

The scale thickness is then determined as t d a (20) Using the fractions of oil and water, ao and crw, the water-cut at line conditions, known as the water-liquid-ratio, wlr, may be computed as wlr = °w (21) ao + aw Tracking the wlr aids in the continuous monitoring of scale formation since scale deposits may be associated with changes in the water-cut.

The gas fraction, gf = ag, and the liquid fraction, tf =1-ag' are additional outputs of the computation. The gas and liquid fractions may be used in pressure drop calculations and as indicators of flow regime.