Special Core Analysis (SCAL)

(adsbygoogle = window.adsbygoogle || []).push({}); Learning Objectives After completing this topic "Special Core Analysis", you will be able to: Summarize the method and purpose for each test typically included in special core analysis (SCAL). Discuss some common subsurface interpretation techniques which use SCAL data. Introduction Special core analysis, commonly abbreviated to "SCAL," includes laboratory procedures and analyses conducted on core plugs cut from an interval of full diameter core acquired from hydrocarbon reservoir rocks (Figure 1). Figure 1: Core plugs (left) and conventional full diameter core samples (right) Special core analysis is distinguished from routine, or conventional, core analysis by the addition of a number of supplementary experiments. In particular, SCAL often includes the measurement of two-phase flow properties to determine the relative permeability, as well as the determination of the capillary pressure and wettability. Special core analysis also establishes a number of electrical properties of the formation which can then be used to interpret LWD and wireline well logs, especially the calculation of the water saturation. SCAL includes a number of specialized studies, such as petrographic, micropalaeontological and palynological, trace element identification and insoluble residue studies, as well as computer-assisted tomography (CAT) scanning and nuclear magnetic resonance logging. Carpenter (2013) summarized recent advances in special core analysis data interpretations on multi-scale measurements, from whole cores to small core trims, with respect to a complex carbonate reservoir. Two-phase Flow Properties Two-phase flow in porous media depends on a number of parameters which together determine how the two fluids are distributed in the reservoir rock’s pores, for example, whether they flow in separate channels or side-by-side in the same channels, either with both fluids being continuous or only one fluid being continuous and the other discontinuous. Relative permeability is the ratio of the effective permeability of a particular fluid at a specific saturation to the absolute permeability of that fluid at total saturation. The SCAL measurement of the relative permeability allows a comparison of the abilities of different fluids to flow in the presence of each other, since the presence of more than one fluid tends to inhibit flow. Capillary pressure is the difference in pressure across the interface between two immiscible fluids (Figure 2). Figure 2: Capillary pressure Core Samples for SCAL Special core analysis tests on heterogeneous formations are normally made on 1 to 1 1/2 inch (2.5 cm to 3.8 cm) diameter cylindrical plugs, which are from 1 to 3 inches (2.5 cm to 7.5 cm) long (Figure 3). Figure 3: Cylindrical core plugs (adsbygoogle = window.adsbygoogle || []).push({}); Samples are selected so as to encompass the porosity, permeability and rock type ranges within the cored interval or reservoir (Figure 4). For homogenous formations (Figure 5), tests can be made on the full diameter cores. In some cases, measurements are made on fresh, preserved cores that are not extracted and leached prior to the laboratory tests. In other cases, samples are extracted, leached and dried. After the porosity and permeability have been determined in routine core analysis, the samples are restored to the reservoir saturation conditions. Figure 4: Plug samples selected to cover the permeability, porosity and rock type ranges Figure 5: Homogenous sandstone The problem of unsuitable cores for special core analysis may sometimes arise when the cores were acquired for routine core analysis without consideration of subsequent special core analysis work. The remote location of some oil wells (Figure 6) may occasionally make the use of a desired coring fluid and packaging technique impractical. Either way, the responsible engineer, petrophysicist or geologist must use the available rock in the state in which it exists. Figure 6: Coring at a remote location Special core analysis studies and the accompanying detailed petrophysical evaluations normally require several months, and occasionally up to one year, to finalize. It is not until the SCAL analysis has been completed and all the capillary pressure and electrical property data have been generated that the well log analysis can be finalized. (adsbygoogle = window.adsbygoogle || []).push({}); Wettability of the Core Rock (adsbygoogle = window.adsbygoogle || []).push({}); Other than poor storage processes causing deterioration of the core, the primary factor that may affect the soundness of special core analysis results is the potential change of the rock’s wettability. Wettability is the tendency of one fluid to adhere to a solid surface in the presence of other immiscible fluids. If there is more than one immiscible fluid within the reservoir, then one of them will be the wetting phase. This wetting phase will completely occupy all the smallest pores and will be in contact with most of the rock surfaces, provided its saturation is sufficiently high. The non-wetting fluid will occupy the centers of the larger pores. That non-wetting fluid occupying the larger pores will tend to have the higher relative permeability. Reservoir wettability is a critical parameter in many types of oil recovery process. Different reservoirs can have different types of wettability, depending on the adherence of the liquids within the pore surfaces, as follows: Fully water-wet, when water occupies the small pores and contacts the majority of the rock surface, with oil occupying the larger pores; perfect wetting state is the extreme wettability state, also known as extremely water-wet rock Neutral-wet, when the rock has no strong preference for either oil or water Oil-wet, when oil occupies the small pores and contacts the majority of the rock surface, with water occupying the larger pores Fractional wettability (also known as heterogeneous, or spotted), when crude oil components are strongly adsorbed in certain areas of the rock, rendering part of the rock oil-wet while the rest is water-wet The crude oil components, which are adsorbed on the rock surface, are heavy oil components, referred to as surface-active components, like asphaltenes. The Different Wettability Measures Wettability measures include contact angle and wettability index. Contact Angle Wettability is complex in theory but can be expressed in terms of the contact angle, θ, as shown in Figure 1, with the extreme end point cases of θ = 0° indicating strongly water-wet and θ = 180° indicative of the extremely oil-wet case. Figure 1: Contact angle as an indication of wettability Figure 2 illustrates, with some intermediate stages of water spreading and oil spreading, the contact angles at smooth, solid surfaces. Figure 2: Contact angles at smooth solid surface Wettability Index (adsbygoogle = window.adsbygoogle || []).push({}); The wettability index ranges from +1 for the extremely water-wet case to -1 for extremely oil-wet rock. Neutral wettability is designated at 0. The Amott test and the USBM test are the most commonly used methods of characterizing the wettability of oil/brine/rock systems. Both tests depend on capillary pressure and microscopic displacement efficiency. In the application of these tests, the common practice is first to displace water by oil to reach an initial saturation. The sample is then immersed in water, and the oil recovered by spontaneous imbibition is measured. (Imbibition is the process of absorbing a wetting phase into a porous rock.) In the Amott test, the sample is subjected to forced displacement, either by centrifuging or waterflooding. In the USBM test, the sample is subjected to forced displacement of oil by centrifuging while incrementally increasing the speed. The benefit of measuring the wettability index is that it is the average wettability of the whole core. The contact angle is measured at one specific point. Table 1 shows the approximate relationship between the wettability, contact angle and the USBM and Amott wettability indexes. Water-WetNeutrally-WetOil-WetContact angle (Degree)Minimum060-75105-120Maximum60-75105-120180USBM Wettability IndexW near 1W near 0W near -1Amott Wettability IndexDisplacement-by-water ratioPositiveZeroZeroDisplacement-by-oil-ratioZeroZeroPositiveAmott-Harvey wettability index0.3 to 1.0-0.3 to 0.3-1.0 to -0.3Table 1: Approximate Relationship between Wettability, Contact Angle and the USBM and Amott Wettability Indexes Rocks in their initial state are normally water-wet. Many remain in this state permanently, while some become neutral or oil-wet over geological time when contacted by oil that contains surface-active (polar) compounds that are adsorbed on the rock surfaces. Samples of given original reservoir wettability have been shown to change (Figure 3) because of contact with coring fluids, temperature and pressure effects, core storage and packaging, core exposure and core cleaning activities. In other instances, however, rocks were found to be virtually insensitive to these same factors, indicating that valid results can be obtained in many cases with less than optimum conditions prior to special core analysis. Figure 3: Changing rock wettability For the determination of a set of representative SCAL data, the wettability state of the core sample in the laboratory should approach as closely as possible the wettability state of the reservoir. Kokkedee et al. (1996) noted that state-of-the-art SCAL measurements at representative wettability conditions, taking account of both relative permeability and capillary pressure artefacts in the interpretation, systematically indicate lower residual oil saturations for a number of reservoirs worldwide. The reduction in residual oil saturation can amount to 10-15 saturation percent compared to the previous estimates. Much of the usually limited amount of SCAL data in the databases of very mature oilfields is based on experiments conducted in the 1980s, when reservoirs were often assumed to be water-wet (Kokkedee et al., 1996). It is now understood that a significant number of reservoirs tend towards either neutral wettability, or a state of preferential oil wetness (Figure 4). Figure 4: Schematic of water-wet and oil-wet rock A number of studies have found that significant percentages of both carbonate and sandstone formations appear to be other than strongly water-wet. When the rock is neutral or oil-wet, the laboratory capillary pressure data are likely not to be suitable for the calculation of reservoir water saturations. Masalmeh et al. (2008) demonstrated the importance of SCAL, particularly the drainage and imbibition capillary pressure and relative permeability measurements for the predominant rock types, in modeling the remaining oil saturation in oil-wet carbonate reservoirs under waterflooding. (adsbygoogle = window.adsbygoogle || []).push({}); Water-oil relative permeability (Figure 5) can be measured on extracted cores from water-wet formations. Where the formation is believed to be either intermediate or oil-wet in nature, these tests should be made on samples recovered with oil base coring fluids to which no extraneous water has been added. A native state core is one taken so as to preserve the in-situ water saturation of the rock. Consequently, a native state core is usually drilled with oil base mud, or crude oil from the same reservoir. The assumptions in this case are that the water saturation present in the sample in the laboratory is equal to that in the reservoir, that it is in the proper pore spaces, and that the wettability of the laboratory rock sample mirrors the reservoir wettability. When the formation is oil-wet, the electrical properties may also need to be measured on native state cores. Figure 5: Water-oil relative permeability Ma et al. (1999) reviewed methods of interpreting spontaneous imbibition. Imbibition is a key to success in water drive reservoirs, as it can affect the rate of water movement and its areal sweep. These methods can, in certain circumstances such as very strongly water-wet reservoirs and systems that achieve residual oil saturation by spontaneous imbibition, supplement the more commonly used Amott and USBM tests. (adsbygoogle = window.adsbygoogle || []).push({}); Capillary Pressure Tests (adsbygoogle = window.adsbygoogle || []).push({}); Water is retained in the reservoir’s pore space by capillary forces as hydrocarbons migrate and form an accumulation (Figure 1). Capillary action is the movement of a liquid along the surface of a solid caused by the attraction of molecules of the liquid to the molecules of the solid. Figure 1: Hydrocarbons migrate to form an accumulation In water-wet reservoirs, this interstitial water adheres to the sandstone or carbonate surfaces (Figure 2). The retentive forces are proportional to the water-hydrocarbon interfacial tension and the affinity of water for the rock (its degree of wetting preference), and inversely proportional to the pore size. Figure 2: Interstitial water This implies that low permeability formations that are composed of very small pore spaces (Figure 3) have high water retentive forces, and hence generally have high immobile water saturations. Figure 3: Low permeability formation composed of very small pore spaces The measurement of capillary pressure requires that core samples be selected so that the pore radii distribution of the sample is representative of the reservoir. The data obtained in the test are used to define the initial water saturation distribution in the reservoir as a function of the height above the hydrocarbon-water contact, and to generate pore throat size and distribution data that are helpful in identifying the various rock types present in the formation. Measurement Techniques (adsbygoogle = window.adsbygoogle || []).push({}); Three commonly used techniques for measuring capillary pressure data are the: restored state cell technique (Bruce and Welge, 1947) centrifugal technique (Slobod, Chambers and Prehn, 1951) mercury injection technique (Purcell, 1949) All three techniques generate multiple saturation values so as to define water saturation as a function of the capillary pressure. The restored state technique has one advantage over the other two: water is present in the core samples, which allows their electrical properties to be measured along with the capillary pressure. The centrifugal technique is the most rapid analysis process and is the best method for poorly consolidated rocks, provided they have been mounted in sleeves with screens over the sample ends. The mercury injection technique generates the maximum number of data points. It is the best process for obtaining the pore throat distribution data, but the sample will be filled with mercury at the conclusion of the test and, therefore, will have no further value. Figure 4 is a schematic of the restored state capillary pressure cell. Figure 4: Schematic of restored state capillary pressure cell Clean, dry samples are weighed, evacuated, pressure-saturated with simulated formation brine, and then again weighed. Multiple samples of varying permeability can be run in one cell. The non-wetting phase is introduced at a low and constant pressure. This low pressure injection, which acts as a driving force to remove the water, is counterbalanced by the capillary retentive forces. When no further water is moving from the core at the imposed pressure level, the sample is removed and weighed. The water saturation remaining in the core is then determined gravimetrically. The pressure imposed on the sample in the laboratory is equivalent to the pressure difference that exists between the wetting and non-wetting fluid phases. This, in turn, is proportional to the pressure difference between the wetting and non-wetting phase in the reservoir, which is related to the height of a given saturation above the original water-oil level and the oil and water hydrostatic gradients. Figure 5 illustrates this concept. Figure 5: Pressure differential (Pc) between water and hydrocarbon versus height and water saturation As the hydrocarbon column increases in height, the buoyant force of the hydrocarbon column increases. Water saturation is, therefore, pushed from the pore space and reduced to lower values as the height above the free water surface increases. Figure 6 shows examples of capillary pressure data for rocks representative of three different depositional environments. Figure 6: Capillary pressure data for rocks representative of three different depositional environments The higher permeability rocks have the lowest water saturation at any given capillary pressure, resulting in a shorter transition zone. The capillary pressure that yields a given water saturation is a function of the rock-wetting characteristics. Typically, this contact angle varies between the laboratory and the reservoir. Capillary pressure is also a function of the interfacial tension between the fluids in the core at the time of testing, which may differ from the reservoir value. One of the major uses of capillary pressure data is to define the initial water saturation of the reservoir. Dernaika et al. (2013) compared multi-scale measurements on whole cores and adjacent core plugs to assess the effect of heterogeneity on the capillary pressure curves within a carbonate reservoir in the Middle East. The measurements were conducted at the reservoir temperature and net confining stress. The whole core primary drainage capillary curve averaged the variability seen from core plugs. For rock types with higher degrees of heterogeneity, whole core imbibition capillary pressure data were found to deviate from individual plug capillary pressure curves and to be a function of the relative presence of intermediate pore throats. (adsbygoogle = window.adsbygoogle || []).push({}); Water Saturation versus Height (adsbygoogle = window.adsbygoogle || []).push({}); The laboratory measured capillary pressure can be corrected to an equivalent height above the free water level in the reservoir. The free water level is defined as the depth where the capillary pressure is zero. For practical purposes, it is the depth at which a high permeability and high porosity reservoir rock would show no residual oil saturation as the zone of 100% water saturation is approached. The zero capillary pressure point in the reservoir is at the intersection of the oil and water continuous phase pressure lines on a pressure versus vertical depth plot derived from vertically distributed wireline formation pressure points (Figure 1). Figure 2 shows a schematic relationship between a capillary pressure curve and oil accumulation. Figure 1: Intersection of the gas and water continuous phase pressure lines on a pressure versus depth plot Figure 2: Capillary pressure from the free water level through the transition zone to the zone of irreducible water saturation The equations used to correct the laboratory measured capillary pressure to an equivalent height above the free water level in the reservoir require knowledge of the interfacial tension of the fluids, both in the laboratory and in the reservoir. Some estimate must also be made of the contact angle in the reservoir. For water-wet systems, the values reported in Table 1 may be used as an approximation for those two variables if no further information is available. Table 1. Typical Interfacial Tension and Contact Angle Values for a Water-wet System System Contactangle, θ \theta |Cosine θ \theta | InterfacialTension, T T⋅ \cdot Cosine θ \theta Laboratory Air-water 0 1.0 72 72 Oil-water 30 0.866 48 42 Air-mercury 140 0.765 480 367 Air-oil 0 1.0 24 24 Reservoir Water-oil 30 0.866 30 26 Water-gas 0 1.0 50 50 (adsbygoogle = window.adsbygoogle || []).push({}); [latex]\textrm{1.}\quad \dfrac{P_{c_{L}}}{P_{c_{R}}}=\dfrac{(\sigma \ \cos \theta)_L}{(\sigma \ \cos \theta)_R}[/latex] or [latex]P_{c_{R}}=P_{c_{L}} \dfrac{(\sigma \ \cos \theta)_R}{(\sigma \ \cos \theta)_L}[/latex] But [latex]\textrm{2.}\quad P_{c_{R}}= (\rho _w - \rho _h)\, g\, h[/latex] Therefore [latex]\textrm{3.}\quad h=\dfrac{P_{c_{R}}}{(\rho w - \rho _h)\, g}= \dfrac{P{c_{L}}}{(\rho _w - \rho _h)\, g}\dfrac{(\sigma \ \cos \theta)_R}{(\sigma \ \cos \theta)_L}[/latex] Where: [latex]h[/latex] = height above free water table [latex]P_{c}[/latex] = capillary pressure [latex]\sigma[/latex] = interfacial tension [latex]\theta[/latex] = contact angle [latex]\rho _{w}[/latex] = density of brine [latex]\rho _{h}[/latex] = density of hydrocarbon [latex]g[/latex] = gravity term used to convert density to fluid gradient [latex]R[/latex] = subscript used to indicate initial reservoir conditions [latex]L[/latex] = subscript used to indicate laboratory conditions Schowalter (1976) discusses the importance of capillary pressure and presents data that may be used for estimating the parameters required in the three equations. Examples of conversions of capillary pressure to reservoir height have also been presented by Keelan in the manual published by Core Laboratories, Inc., Special Core Analysis. Pore Throat Distribution (adsbygoogle = window.adsbygoogle || []).push({}); Capillary pressure data obtained from mercury injection tests can be converted to equivalent pore radii. Figure 3 illustrates plots of the pore entry radius developed from capillary pressure curves. These data have been helpful in rock typing and in the selection of net pay. Figure 3: Cumulative pore throat distribution for different depositional environments (adsbygoogle = window.adsbygoogle || []).push({}); Electrical Properties (adsbygoogle = window.adsbygoogle || []).push({}); Electrical measurements made on core samples in the laboratory define, for any given formation, the parameters that are used in the LWD and wireline log calculations of water saturation. The measured properties include the resistivity of the core at 100% water saturation ([latex]R_{o}[/latex]), at native state ([latex]R_{t}[/latex]), and the resistivity of the formation water ([latex]R_{w}[/latex]). The relationship between rock properties and water saturation is as follows: 1. [latex]S_w = \left (\dfrac{F\cdot R_w }{R_t} \right )^{\frac{1}{n}}[/latex] 2. [latex]S_w = \left (\dfrac{R_o }{R_t} \right )^{\frac{1}{n}}[/latex] or 3. [latex]S_w = \left (\dfrac{a }{\phi ^{m}}\cdot R_w \right )^{\frac{1}{n}}\cdot \dfrac{1}{R_t}[/latex] Where: [latex]S_{w}[/latex] = formation brine saturation, fraction [latex]R_{w}[/latex] = formation brine resistivity, ohmmeters [latex]R_{t}[/latex] = true formation resistivity, ohmmeters [latex]R_{o}[/latex] = true resistivity of 100% brine-saturated rock, ohmmeters [latex]F[/latex] = formation resistivity factor [latex]\frac{R_o}{R_w}[/latex] [latex]\phi[/latex] = measured porosity, fraction [latex]a[/latex] = intercept on [latex]F[/latex] versus [latex]\phi[/latex] plot [latex]n[/latex] = saturation exponent, slope of [latex]RI^*[/latex] versus [latex]S_{w}[/latex] plot [latex]m[/latex] = cementation exponent (slope of [latex]F[/latex] versus [latex]\phi[/latex] plot) * The resistivity index ([latex]RI[/latex]) is defined as the true formation resistivity ([latex]R_{t}[/latex]) at any saturation divided by the resistivity at 100% saturation ([latex]R_{o}[/latex]). By using these equations we can refine log calculations and no longer need to rely on estimates presented in the literature. Formation Factor versus Porosity (adsbygoogle = window.adsbygoogle || []).push({}); The formation factor ([latex]F[/latex]) has been defined Archie, (1942) as the resistivity of a 100% water saturated rock ([latex]R_{o}[/latex]) divided by the resistivity of the saturating formation water ([latex]R_{w}[/latex]). When the measured formation factor is plotted against the measured porosity, the slope of the resulting line establishes the cementation exponent ([latex]m[/latex]). This is illustrated in Figure 1 along with limits observed in laboratory tests. Dernaika et al. (2013) observed that the cementation exponent ([latex]m[/latex]) was systematically reported to be lower in the measured whole core samples than in the 1.5 inch core plugs. Figure 1: Plot of formation factor versus porosity, illustrating variation in intercept (a) Most carbonate reservoirs are characterized by multiple-porosity systems that impart petrophysical heterogeneity to the gross reservoir interval. Resistivity Index versus Water Saturation As the water saturation decreases in a given sample, the true formation resistivity rises. This occurs because less water, and subsequently fewer ions, are available to conduct electricity. As mentioned previously the resistivity index ([latex]RI[/latex]) is defined as the true formation resistivity ([latex]R_{t}[/latex]) at any saturation divided by the resistivity at 100% saturation ([latex]R_{o}[/latex]). Figure 2 shows a typical plot of the resistivity index versus water saturation over a range of laboratory-measured data. Figure 2: Plot of resistivity index versus water saturation for range of measured values of the slope (n) The saturation exponent ([latex]n[/latex]) is the slope of the resistivity index versus water saturation line. In very rare cases, both the [latex]m[/latex] and [latex]n[/latex] values exceed the limits illustrated in Figure 1 and Figure 2. For example, if the rock matrix contains conductive matrix components, the n value can fall outside the illustrated limits. The calculation of water saturation is very sensitive to m as the porosity decreases, and use of an incorrect m value can generate water saturation errors of up to 50% pore space. In their study of multi-scale SCAL measurements in a giant carbonate oil field, Dernaika et al. (2013) found that whole core resistivity index ([latex]RI[/latex]) measurements were on the lower end of values from the core plug measurements, especially when large variations were recorded from the plug data. Clay Effects The presence of clay often suppresses the rock resistivity, and generates lower m and variable n values. The water saturation equation that was developed to accommodate the presence of clays that conduct electricity becomes more complex than that given in Equation 3. Water saturation equations that incorporate the measured cation exchange capacity effects caused by clays are the Waxman-Smits and Waxman-Thomas equations (1968, 1974): 4. [latex]S_w=\left [\dfrac{F^*\cdot R_w}{R_t\left (1+ \dfrac{R_w\cdot B\cdot Q_v}{S_w} \right )} \right ]^{\tfrac{1}{n^*}}[/latex] where: 5. [latex]F^* = F_a(R_w\cdot B\cdot Q_v)[/latex] 6. [latex]Q_v = \dfrac{CEC\cdot (1-\phi )\cdot \rho_{ma}}{100\cdot \phi}[/latex] Where the following apply: [latex]F^*[/latex] = formation resistivity factor independent of clay conductivity = [latex]\frac{a^*}{m^*}[/latex] [latex]n^*[/latex] = saturation exponent independent of clay conductivity [latex]B[/latex] = specific cation conductance, [latex](\mathit{1}/\textit{ohm-m})/( \mathit{meq}/\mathit{mL })[/latex] [latex]Q_{v}[/latex] = quantity of cation exchangeable clay present, [latex]\tfrac{meq}{ml}[/latex] of pore space [latex]CEC[/latex] = cation exchange capacity, [latex]\frac{meq}{100\ ml}[/latex] [latex]\rho _{ma}[/latex] = grain density of rock matrix, [latex]\tfrac{g}{cm^{3}}[/latex] [latex]a[/latex] = equation coefficient associated with [latex]m^*[/latex] [latex]m^*[/latex] = cementation exponent (slope of [latex]F^*[/latex] vs [latex]\phi[/latex] plot) (adsbygoogle = window.adsbygoogle || []).push({}); Neglecting the cation exchange capacity (using Equation 4 rather than 5) results in pessimistic estimates of the hydrocarbons in place (Koerperich 1975; Keelan and McGinley 1979). The cation exchange capacity can only be reliably determined on rock samples from the specific formation being evaluated. The Waxman-Smits and Waxman-Thomas equations require a trial and error solution, as the water saturation ([latex]S_w[/latex]) appears on both sides of Equation 4. Keelan and McGinley (1979) have shown how the measured laboratory values of m and n may be modified to establish the [latex]m^*[/latex] and [latex]n^*[/latex] values required for the Waxman-Smits and Waxman-Thomas equations. Table 1 displays the differences in the calculated water saturation that may occur when using [latex]m[/latex] and [latex]n[/latex] values for clean sand versus values developed for use in the Waxman-Smits and Waxman-Thomas equations. Note the pessimistic estimate of hydrocarbons in place that will result if the clean sandstone is used rather than the equations for shaly sandstone. Table 1: Comparative values of calculated water saturation, using clean sand and shaly sand equations, for a shaly formation (Keelan and McGurley, 1979. Reprinted with permission of SPWLA.) Waxman-Smits-Thomas Laboratory Data Clean Sand (1) Laboratory data correctly adjusted to *values (equation 2)(2) Laboratory values used as reported(3) Clean sand values assumed correct and ignoring clay and shale effects (equation 4) a= a = 1.0 a∗ a^* = 1.0 a= a = 1.0 a= a = 1.0 m= m = 1.63 m∗= m^* = 51.92 m= m = 1.63 m= m = 2.0 n= n = 2.38 n∗= n^* = 2.87 n= n = 2.38 n= n = 2.0 (1) (2) (3) No. Porosity Sw S_w : % PV Sw S_w : % PV Sw S_w : % PV 1 20.4 47 55 66 2 17.8 56 68 87 3 16.3 57 72 95 4 20.1 54 64 79 5 14.3 61 80 111 6 25.2 59 59 69 7 25.4 55 51 58 8 27.3 57 51 57 9 17.5 74 73 95 10 20.0 60 70 88 11 17.4 68 75 99 12 14.4 74 86 119 (adsbygoogle = window.adsbygoogle || []).push({}); Relative Permeability (adsbygoogle = window.adsbygoogle || []).push({}); Hydrocarbon reservoirs contain water, gas and/or oil in variable quantities. Each phase interferes with, and impedes the flow of, the others. Relative permeability is a dimensionless term that has great importance when two of the fluids, such as oil and water, move through the pore spaces. Specific, or absolute, permeability is the permeability of a porous medium to one fluid at 100% saturation. For example, in the aquifer the reservoir contains water as a single phase at 100% water saturation. Effective permeability is the permeability to a given phase when more than one phase saturates the porous medium. The effective permeability, then, is a function of the fluid saturation. Relative permeability to a given phase is defined as the ratio of the effective permeability to the absolute, or in some cases, the base permeability. Relative permeability, then, is also a function of the saturation and can be expressed as a number between 0 and 1, or as a percentage. The pore type and the rock wettability affect the relative permeability. In core analysis data that were generated prior to 1973, the specific permeability to air was often used as the base permeability. Since that time, the common base has been the hydrocarbon permeability in the presence of irreducible water. For an oil-water reservoir, this would mean the base permeability would be the effective permeability to oil at irreducible water saturation. For a gas reservoir, the base permeability would be the permeability to gas in the presence of irreducible water. Figure 1 illustrates gas-water relative permeability data when water displaces gas. Figure 1: Gas-water relative permeability curves Imbibition and Drainage Processes (adsbygoogle = window.adsbygoogle || []).push({}); The terms imbibition and drainage are also employed when discussing relative permeability tests. Their meanings imply what is happening in the pore space to the wetting phase as the relative permeability tests are measured. If the wetting phase is decreasing, that phase is draining and the curve is called a drainage curve. If the wetting phase is increasing or being imbibed during the test, the curve is referred to as an imbibition curve (Figure 2). Figure 2: Drainage and imbibition curves For a water-wet reservoir, the drainage curves apply during the time that water is draining from the reservoir and hydrocarbons are accumulating. Once the reservoir rock or laboratory sample has attained an equilibrium water saturation value and the water is subsequently increased by natural water influx or the introduction of coring or test fluids, the imbibition curves apply. In oil-wet rock, a reduction in the oil phase by water flooding would be referred to as a drainage curve. These data are required in many reservoir engineering calculations, and the laboratory tests that develop them should follow the same saturation history as that in the reservoir. Laboratory Methods for Measuring Relative Permeability Two major laboratory methods have evolved to measure relative permeability (Figure 3). These are referred to as the steady-state and nonsteady-state techniques. Figure 3: Laboratory equipment for measuring relative permeability with both steady-state and nonsteady-state methods Steady-state: The steady-state test, the older of the two methods, is made at low flow rates, and the test apparatus contains upstream and downstream mixer heads to remove capillary end effects. Many organizations prefer data obtained from the steady-state test. Two fluids are injected simultaneously into a core sample and the water saturation is increased slowly. This simulates the slow increase in water saturation that would occur in the formation between the water injection and hydrocarbon producing wells. Saturation increase is monitored by measuring the gain in weight occurring in the sample, or by X-ray technique. Nonsteady-state: The nonsteady-state technique uses a viscous oil and is normally made at a higher flow rate than that present in the reservoir. It is this higher rate that sometimes yields pessimistic estimates of hydrocarbon recovery from rocks of intermediate wettability. Heaviside and Black (1983) analyzed the two techniques and presented recommendations on the most appropriate way to measure water-oil relative permeability depending upon the wetting characteristics of the rock. Wettability Effects (adsbygoogle = window.adsbygoogle || []).push({}); The natural preference of a porous medium, which causes one fluid to adhere to its surfaces rather than another, is referred to as its wettability. A water-wet porous medium causes water to adhere to its surfaces. The wettability of a rock has a dramatic influence on the relative permeability curves. It is, therefore, essential that the core samples tested in the laboratory reflect the actual formation wettability, and that the initial water saturation in the test sample be of the same magnitude and have the same spatial location as it has in the reservoir. This requirement has led to the acquisition of "native state" cores. These are cores taken with crude oil or with other oil-base fluids that do not alter the wettability or water saturation present in the recovered core. Figure 4 illustrates the effects of core wettability on water-oil relative permeability measurements (Owens and Archer, 1971). Figure 4: Effects of wettability on water-oil relative permeability: imbibition data for Torpedo sandstone These data indicate that as the rock becomes more oil-wet, the relative permeability to oil decreases and the relative permeability to water increases at any given saturation. This results in unfavorable recovery efficiency. It also indicates that the residual oil saturation in intermediate to oil-wet rocks is a function of the volume of water that flows through the core sample, and that the relative permeability to water existing at floodout will be much higher for the oil-wet formation. An interesting observation is that the reduction of capillary retentive forces in the oil-wet rock allows a lower residual oil saturation to be achieved in the oil-wet rock if the project’s economics would support continued water injection. Wettability may be estimated from the shapes of relative permeability curves. However, it should be remembered that a similar shift in the relative permeability curves can also be caused by changes in other rock properties (Morgan and Gordon, 1970). Critical Water Saturation Critical water saturation (sometimes called the irreducible water saturation) is the point where the water saturation is sufficiently low that there is no measurable water cut. Water, although present, is held in place by capillary forces and will not flow. If the actual water saturation is higher than this critical saturation level, then both water and hydrocarbon flow during production. As the water saturation further increases, there will come a point at high water saturation at which only water flows. The critical water saturation varies depending mainly on the rock type, composition, porosity and permeability (Hartmann et al., 2014). Critical water saturations are usually determined through special core analysis. (adsbygoogle = window.adsbygoogle || []).push({}); Petrographic Studies (adsbygoogle = window.adsbygoogle || []).push({}); Petrography is a branch of petrology that focuses on the detailed descriptions of rocks. Sidewall cores and conventional cores, as well as ditch cuttings the cuttings of rock (Figure 1) brought to the surface by the circulating drilling medium (normally a drilling mud) recovered from wells can be used for petrographic studies. The mineral content and the textural relationships within the rock are described in detail. Figure 1: Ditch cuttings Progress in instrumentation now allows the core analysts to look into the pore spaces and examine samples at magnifications of 50,000 times or greater. These various microscopic measurements are complementary in nature, and all may be made on a single sample that is representative of a given depth. Figure 2 shows several types of microscopes that may be used in petrographic studies. Figure 2: Scanning electron microscope (A), X-ray microscope (B), laser microscope (C), and stereo microscope (D) Petrographic studies include thin section analysis, scanning electron microscopy (SEM), X-ray diffraction and cathodoluminescence. Thin Section Analysis In thin section analysis, samples are mounted on glass and ground to a uniform thickness of 0.03 mm. They are studied with a petrographic microscope under both normal and polarized light (Figure 3). The minerals that are present are identified, and the estimated porosity, median grain diameter, and the degree of rounding and sorting are recorded. The accumulation of minerals can be ascertained, and the changes in composition, texture and cementation that have occurred after deposition can be determined. These studies use magnifications of up to 600 times normal size. Figure 3: Thin sections under normal light (left), and under polarized light (right) Thin section analysis is a less successful method for identifying clays, but there may be cases where a particular clay is abundant enough to be seen and identified (Figure 4). Figure 4: Thin section microscope display An example of the core description made from this type of analysis might be: (adsbygoogle = window.adsbygoogle || []).push({}); Sample depth: 4640 feet Color: Medium gray Name: Fine-grained sandstone Sorting: Well Lithification: Well Texture: Massive Grain size: Minimum: 0.06 mm Maximum: 0.51 mm Average: 0.24 mm Angularity and shape: Angular to sub rounded Grain contacts: Concavo-convex Table 1 displays an example of thin section data. Table 1: Thin Section Data Detrital grains(%) Cements(%) Matrix(%) Visible porosity(%) Quartz: 69 Secondary Detrital: 2 Intergranular: 5 Chert: 3 Quartz Authigenic: 4 Grain-moldic: 2 Alkali Feldspar: 1 Secondary Quartz Overgrowths: 7 Dissolution: 1 Plagioclase Feldspar: 1 Calcite: — Microporosity: 1 Lithic Fragments: 4 Pyrite: Trace Fracture: — Scanning Electron Microscopy (SEM) Scanning electron microscope photographs provide a three-dimensional view of a pore space with a magnification of up to approximately 40,000 times normal. Both the distribution and the morphology of clays within the pore spaces can be studied with this type of display. Normally, samples for analysis are first coated with a thin film of conductive material and then bombarded with electrons. This causes a secondary electron emission that yields a visual image, such as that shown in Figure 5, plus X-ray photons that are then available for elemental analysis. Figure 5: Electron microscope display The elemental analysis assists in defining the clay type and chemistry. Clays influence core analysis procedures, permeability and porosity magnitude, well completion techniques and the responses of the downhole LWD and wireline logs. The ability to identify clay types and to observe the microporosity present in both clay linings and in carbonates are two of the most important uses of SEM information. X-ray Diffraction All crystalline materials reflect X-rays from atomic planes within the crystal that generate a unique diffraction pattern. This allows the identification of minerals, including those too small to be identified by thin section studies. Improved clay mineral identification results when clay-sized particles of four microns or less are separated from large sand grain particles and X-rayed as a unit. Table 2 is an example of such data. Table 2: X-ray Diffraction Data Mineral Bulk sample Net clay fraction(4.2% of bulk sample) Sample depth: 4640 ft. Quartz 91 Feldspars 5 Calcite — Kaolinite 3 70 Chlorite — — Illite/Mica 1 30 Total 100% 100% Cathodoluminescence Thin sections of rock that are placed within a vacuum chamber will glow with color when hit with electrons. If the electron emitter is mounted on a petrographic microscope, immediate comparison of samples by polarized light and luminescence is possible, and growth rings similar to those of trees may be observed in individual crystals. Some authors suggest that these rings have proved to be correlatable over large distances, and that their color pattern reflects trace elements present in formation waters at various stages of the crystal history. The color pattern, then, offers insight into water temperature and chemistry during the history of the rocks. Tung-Hau et al. (2012) investigated the controlled growth density and patterning of silica nanorings and nanowires with enhanced ultraviolet cathodoluminescence peak. Alimuddin et al. (2011) discussed hydrocarbon and mineral exploration using cathodoluminescence. Doane et al. (1995) noted the use of a combination of petrographic and special core analysis techniques to evaluate the potential effectiveness of proposed drilling fluids and procedures, prior to the actual cost and risk of implementation. This minimizes invasive formation damage of a mechanical, chemical or biological nature during the subsequent drilling of wells. (adsbygoogle = window.adsbygoogle || []).push({}); Micropalaeontology and Palynology (adsbygoogle = window.adsbygoogle || []).push({}); Micropalaeontology is the study of microfossils which are not identifiable with the naked eye (Figure 1 ). Both the petrographic microscope and scanning electron microscope are essential tools for these studies. Palynology is a specialized area of micropalaeontology that deals with acid-insoluble organic plant fossils. Included in this classification are plant spores and pollen, which are associated with terrestrial environments. These data, when observed in core samples and related to sedimentary structures, texture and lithologic characteristics, help in the classification of environments of deposition. Figure 1 presents some examples of terrestrial and marine microfossils. Jones (2014) provides a state-of-the-art overview of all aspects of applied foraminifera studies and their applications in palaeoecology, biostratigraphy and sequence stratigraphy. Figure 1: Terrestrial and marine microfossils Trace Element Identification (adsbygoogle = window.adsbygoogle || []).push({}); Trace elements (an element in a sample that has an average concentration of less than 100 parts per million measured in atomic count, or less than 100 micrograms per gram) present in shales have been used successfully as a guide to major variations in the water salinity, and hence serve to differentiate between fresh water and marine sediments. The presence of trace elements is related to the cation exchange capacity of clay minerals located within the shales. Clays have very large surface areas and are often electrically imbalanced. Trace elements are adsorbed on clay surfaces, and many trace metals survive at these adsorptions points. Boron, chromium, copper, nickel, vanadium, rubidium and lithium are generally found in higher percentages in marine clay sediments deposited in salty water. Some studies have indicated lead associated with fresh water sediments. Insoluble Residues Tests for insoluble residues are conducted to determine the materials remaining after rock samples have been dissolved in hydrochloric, formic or acetic acid. Quartz, chert, pyrite and clay are common residues. The reporting of data may simply identify residues or may document their weight percentages as well. The techniques for such studies was discussed by Swanson (1981). Residue identification helps to specify the rock’s depositional environment. Pwa et al. (1999) discuss geochemical exploration using acid insoluble residues. (adsbygoogle = window.adsbygoogle || []).push({}); Computer-Assisted Tomography (CAT) Scanning (adsbygoogle = window.adsbygoogle || []).push({}); A computer-assisted tomography, or CAT scan, produces an image of the internal structure of a cross-sectional slice through an object by reconstructing a matrix of x-ray attenuation coefficients (Figure 1). CAT scanning is a non-destructive x-ray technology that is most familiar through its use in medicine, but which has been found to have oil industry applications as well. Applications relating to core analysis include: Visualizing the extent of mud filtrate invasion Detecting fractures (Figure 2) Characterizing the lithology of cores contained in opaque preservation material and stainless steel pressure vessels Screening cores prior to flow tests Correlating scan data to porosity, permeability and lithology Waterflooding studies A good technique for observing the actual progressive movement of fluids inside rocks is to use computer tomography (CT) scanning at successive time intervals to record the displacement or flooding process. Figure 1: CAT scan image of core (adsbygoogle = window.adsbygoogle || []).push({}); Figure 2: CAT scan of fractures Lopez et al. (2012) documented an integrated multiscale imaging and modeling method for determining petrophysical and multiphase flow properties of reservoir rocks at the core pore, sub-plug, plug and whole core scale. The method is based on the integration of multi-scale X-ray computed micro-tomography (MCT) imaging and numerical 3D rock modeling to characterize heterogeneity, pore classes and porosity types at different scales. (adsbygoogle = window.adsbygoogle || []).push({}); Nuclear Magnetic Resonance (NMR) Logging (adsbygoogle = window.adsbygoogle || []).push({}); The nuclear magnetic resonance (NMR) logging tool is used to measure in-situ rock properties such as porosity, permeability and residual oil saturation. NMR technology is also applied as a tool for special core analysis. NMR imaging enables the analyst to visualize fluids in a porous medium in three dimensions on a sub-millimeter scale, and thus to study porosity and fluid saturation distributions, along with fractures and drilling mud invasion. NMR images only the mobile fluids within the pore structure. Figure 1 shows an NMR image of the petrophysical simulation of pore-scale Darcy flow in sandstone. Figure 2 shows a comparison of NMR porosity with the core porosity. Figure 1: Petrophysical simulation for NMR: pore scale Darcy flow in sandstone (adsbygoogle = window.adsbygoogle || []).push({}); Figure 2: Comparison of core and NMR porosity (adsbygoogle = window.adsbygoogle || []).push({}); Assignment Special Core Analysis (SCAL) (adsbygoogle = window.adsbygoogle || []).push({}); You are the geologist responsible for core analysis for your company and have been asked to summarize what is involved in special core analysis (SCAL) studies for your colleagues. Solution Special core analysis (commonly abbreviated to "SCAL") comprises a number of laboratory procedures, which conduct flow experiments and other specialist analyses on core plugs, which are usually cut from an interval of full diameter core. SCAL often includes the measurement of two-phase flow properties to determine the relative permeability, as well as capillary pressure and wettability. Special core analysis establishes a number of electrical properties of the formation which can then be used for the analysis of LWD and wireline well logs, in particular determining the water saturation. SCAL often includes a number of specialist studies such as petrographic, micropalaeontology and palynology, trace element identification and insoluble residue studies, as well as computer-assisted tomography (CAT) scanning and nuclear magnetic resonance logging. Assessment Special Core Analysis (SCAL) (adsbygoogle = window.adsbygoogle || []).push({}); 1. What are the features of micropalaeontological studies? (Select all that apply.) A .Micropalaeontology is the study of microfossils. Correct ✔B .Micropalaeontological studies require the use of a petrographic microscope. Correct ✔C .Micropalaeontological studies require the use of a scanning electron microscope. Correct ✔D .Micropalaeontological studies involve organisms visible to the naked eye. 2. Which of the following are features of trace elements? (Select all that apply.) A .A trace element is the mark left by an organism moving through unconsolidated sediments.B .A trace element is an element in a sample that has an average concentration of less than 100 parts per million measured in atomic count. Correct ✔C .Trace elements in shales have been used successfully as guides to major variations in the water salinity. Correct ✔D .The presence of trace elements is related to the cation exchange capacity of clay minerals located within the shales. Correct ✔ 3. What level of immobile water saturations are typically found in low permeability formations that are composed of very small pore spaces? A .Intermediate immobile water saturationsB .Very low immobile water saturationsC .Low immobile water saturationsD .High immobile water saturations Correct ✔ (adsbygoogle = window.adsbygoogle || []).push({}); 4. What types of wettability can be determined during special core analysis? (Select all that apply.) A .Oil-wet Correct ✔B .Non-wetC .Water-wet Correct ✔D .Neutral-wet Correct ✔ 5. What attribute of a rock does the identification of the insoluble residues help to determine? A .AgeB .Depositional environment Correct ✔C .Hydrocarbon contentD .Color 6. Relative permeability has which of the following attributes? (Select all that apply.) A .Relative permeability is the same as the absolute permeability.B .Relative permeability is a result of each phase interfering with, and impeding the flow of the others. Correct ✔C .A dimensionless term, expressed either as a number between 0 and 1, or as a percentage. Correct ✔D .Relative permeability is a function of the saturation. Correct ✔ 7. Which of the following are applications of computer-assisted tomography (CAT) scanning? (Select all that apply.) A .Establishing the relative permeabilityB .Screening cores prior to flow tests Correct ✔C .Characterizing the lithology of cores Correct ✔D .Detecting fractures Correct ✔E .Visualizing the extent of mud filtrate invasion Correct ✔ 8. What is petrography? A .Petrography is the study of petroleum.B .Petrography is the illustration of petroleum products.C .Petrography addresses the geographical distribution of rocks.D .Petrography is a branch of petrology that focuses on the detailed descriptions of rocks. Correct ✔ 9. What is the capillary pressure at the free water level? A .0 psi Correct ✔B .10 psiC .100 psiD .1000 psi 10. Nuclear magnetic resonance (NMR) logging is often used to measure which of the following rock properties? (Select all that apply.) A .Residual oil saturation Correct ✔B .Permeability Correct ✔C .Porosity Correct ✔D .Age Recommended for You Core Analysis: A Best Practice Guide (adsbygoogle = window.adsbygoogle || []).push({}); Introduction to Core Analysis Fluid Saturation Determination Permeability Measurement Porosity Measurement | What is porosity and how is it measured?