Complementary Core Information

Learning Objectives After completing this topic "Core Information", you will be able to: Describe the different types of data and core information obtained as a complement to routine, special core analysis (SCAL) and the standard core description. State the purpose of each type of complementary core information. Describe the methods used for determining each type of complementary core information. Grain Density The grain density of a rock is defined as the weight of the rock (exclusive of the weight of the fluids contained within the pore spaces) divided by the volume of the solid rock material (exclusive of the pore spaces). The grain density primarily varies with the mineral composition of the rock and the state of hydration of the minerals. In complex lithologies containing intermixed limestone, dolomite, sandstones and heavy minerals, the grain density will vary both vertically and horizontally. Even in formations described as homogeneous (Figure 1), the measured grain densities often vary considerably from the published values for the pure components (Table 1). Figure 1: Homogenous sandstone ComponentApproximate grain density ([latex]\tfrac{g}{cm^{3}}[/latex])Sandstone2.65Limestone2.71Dolomite2.85-2.87Anhydrite2.98Gypsum2.3Pyrite5.0Siderite3.9Clays2.2 - 2.9Table 1: Grain Densities of Pure Rock or Mineral Components Minor amounts of secondary cement, such as calcite or siderite (Figure 2), will cause the grain densities to vary from the values shown in the table. Figure 2: Calcite (left), and siderite (right) An example of the variance in inter-well and intra-well differences recorded in one study is shown in Figure 3. Figure 3: Grain density variations Grain density is important complementary core information for two main reasons. First, it can be used as a quality control check of the core analysis measurements. Second, a value for grain density is a required input to the equation used to calculate the porosity from the bulk density value sensed by the wireline and/or LWD logging tools. The equation takes the form: [latex]\phi =\dfrac{GD-BD}{GD - FD}[/latex] Where: GD = Grain Density, ([latex]\tfrac{g}{cm^{3}}[/latex]) (assumed or measured) BD = Bulk Density, ([latex]\tfrac{g}{cm^{3}}[/latex]) (from downhole log) FD = Fluid Density, ([latex]\tfrac{g}{cm^{3}}[/latex]) (assumed) ϕ = Porosity, fractional The general rule is that impurities in the rock increase its grain density. Grain density values that exceed the estimated values for the pure components occur when carbonate cements are present, or when relatively heavy impurities such as pyrite (Figure 4) or siderite are present within the pore spaces. Values can occasionally exceed 3.0 ([latex]\tfrac{g}{cm^{3}}[/latex]). In these cases, using erroneously low grain densities will generate calculated values of well log porosity that are too low. This potential error is most critical when evaluating low porosity rock, as even small errors result in significantly lower porosity estimates. When an erroneously low porosity value is substituted into water saturation equations that use the well log resistivity data, the calculated water saturations are too high. A combination of such underestimated porosity and overestimated water saturations can cause the calculated oil-in-place to be underestimated by up to 25%. Figure 4: Pyrite An exception to the general rule that impurities in the rock increase its grain density is with core samples that contain large quantities of hydratable clays (Figure 5). When such a sample is dried in a humidity oven, the two molecular layers of water are maintained on the clay surfaces, and the calculated grain density has a lower value than the rock itself. Removal of this water, which can occur when the sample is dried in a non-humidity oven, increases the grain density. Figure 5: Hydratable clay When core analysis grain densities are reported, it is important to know how the samples were prepared (Actlabs, 2014). In some analyses, the grain density is measured with all the bound water removed from the clay surfaces of the samples; in other analyses, the grain densities and porosities are measured with this water still in place. After the core has been cleaned and dried to specifications, the measured grain density is accurate to ±0.01([latex]\tfrac{g}{cm^{3}}[/latex]). Core Photography Core photography options range from black and white photographs, to color photography under natural light, to pictures taken under ultra-violet light (Figure 1). Photographs are often taken of the core before it is slabbed, with any residual hydrocarbons still in place. The color and ultra-violet light photographs tend to complement one another, the color recording what the eye sees and the ultra-violet revealing oil fluorescence and, hence, the location of hydrocarbons. Figure 1: Left to right: Black and white core photograph, color core photograph, and core photographed under ultra-violet light In reservoirs that are fractured (Figure 2), enhancement of the fracture pattern is sometimes observed using the ultra-violet light photographs. Figure 2: Fractured core Photographs are often taken at 1 ft (30 cm) intervals along the core. In other cases, the cores are grouped into lengths of 15 or 20 ft (4.5 or 6.1 m), and a single photograph is made of the entire sequence. Some detail of the core may be lost in the multiple footage shots, but changes in facies and lithology as well as core structures are sometimes observed better this way. While laminations and other core structures are often visible on non-slabbed core, they are normally easier to study on a core that has been cleaned and slabbed before being photographed (Vinci, 2014). Multiple footage photos, such as those shown in Figure 3, are helpful for seeing changes in the core bedding and structures that indicate differences in permeability, porosity and the depositional environment. Thomas (2011) describes a process for deriving lithology from core photographs. Figure 3: Core photograph illustrating structure and depositional environment Photographs form a permanent record of the core's appearance and can be easily sent to coventurers and other interested parties. A photographic record is invaluable in reservoir studies when the physical rock is no longer available. Written lithological descriptions are important, but they are well complemented by the photographic record, revealing zonal transitions, stained sections, minerals, fractures, dips, stylolites, shale partings and other critical formation indicators. Geological interpretations may change as additional wells are drilled and new data becomes available. In such cases, a permanent record of the core's appearance is a very helpful tool. Core Gamma Ray Log The natural gamma ray radiation of the core may be sensed in the laboratory with instrumentation (Figure 1) similar to that used in the LWD and wireline well log tools. This radiation is generally attributed to the presence of uranium minerals, thorium or the potassium isotope K-40. Shales typically have high gamma ray activity, carbonate rock activity is normally low in general (except with intense dolomitization and mineralization), and sandstone radiation frequently falls between these two levels. Anhydrite and halite evaporites often have very low gamma ray readings. The gamma ray radiation tool is used for discerning the broad lithological changes, bed boundaries and for correlation. The data it generates are referred to as the core gamma ray log. Figure 1: Core gamma ray equipment In the laboratory, the core sample is placed on a motor-driven conveyer belt and travels through a lead-shielded tunnel containing a scintillation gamma ray detector. Impulses from the detector are electronically integrated, and the output is recorded on a log at the same scale as that used for the downhole gamma ray logs to facilitate correlation between them. Gamma ray measurements in the laboratory are generally performed on continuous, full diameter cores, not sidewall core samples. Data are recorded in chart form for comparison with the visual assessment of the core lithology, and for depth correlation with the downhole logs. By aligning the peaks and troughs of the laboratory-measured gamma ray radiation profile with those of the LWD and/or wireline gamma ray logs (Figure 2), the depth recorded on the core can be shifted to the depth on the downhole logs. Figure 2: Correlating core gamma ray with a well log gamma ray Because natural radioactivity has a statistical element and the two gamma ray logs are acquired at different logging speeds, good interpretation judgment is needed to make the optimal correlation. The convention is to adjust the core analysis depth profile to correct it to the downhole log depths. Core depths are computed by counting the pipe joints recovered from the borehole on tripping out the bottomhole assembly. In some cases, a joint (30 ft, or 9 m) or stand (90 ft, or 27 m) may be missed in the pipe tally. It is common to find depth discrepancies of 3 to 7 ft (1 to 2 m) between the log depths and the core depths. When no correlation is initially found between the two, it is advisable to shift the depth in intervals of 30 ft (9 m), being the length of one joint of drill pipe, to see if a good correlation can be found. If cores are jumbled during their assembly and transport, or boxed in inverted order, the core gamma ray can help to rectify the situation. The output of the natural gamma ray radiation tool is in a digital format and stored for later use. The data can be re-plotted at various depth scales for various correlations and interpretations, or presented in a tabular printed report. Usually the surface measurements of gamma ray radiation can be completed within an hour, and are ready for immediate comparison with the physical characteristics of the core and for correlation with downhole LWD and wireline logs from the same, or nearby, wells. These data are usually reproduced on a log of the core, along with other basic laboratory information. Cores that were not originally measured for gamma ray radiation and that have been stored for periods of time can still be suitable for this measurement. Samples that were previously analyzed, cleaned and dried are also suitable candidates. Samples that have been preserved with CoreSealTM can be tested without removal of the preservative material. It is recommended that cores not be tested within closed wooden or cardboard boxes because this inhibits proper fitting of the core prior to sensing its gamma ray activity. When rubber sleeves are within the unopened boxes, for example, zones where the sleeve has collapsed because of sand washout will not be identified. Spectral gamma ray analysis presents not only the total gamma activity, but also separates the individual components contributed by uranium, potassium and thorium (Figure 3). Figure 3: Spectral gamma ray In some depositional environments, the presence of significant quantities of mica and clays within the pore structure or rock fabric has caused hydrocarbon productive zones to be highly radioactive and, thus, superficially to appear to be shales. The use of the spectral gamma ray log assists in identifying such zones of higher radioactivity, indicated by the relevant log curve deflecting to the right. Figure 4 illustrates a core gamma ray surface log (traditional laboratory gamma ray radiation test) and the associated core spectral gamma ray log. Figure 4: Core gamma ray surface log and core spectral log Directional Permeability The permeability of rocks normally varies in different directions (Figure 1 ) because rocks generally have some anisotropy. Figure 1: Directional permeability terminology Figure 2 illustrates a reservoir model with horizontal permeability channels. Figure 2: Reservoir model with horizontal permeability channels For effective dynamic reservoir modeling, differences in the horizontal and vertical permeabilities of reservoirs must be well understood. Figure 3 shows a geostatistical permeability realization used for numerical simulation. Figure 3: 3-D realization of a field’s reservoir architecture from which the horizontal and vertical permeabilities are derived In both sandstone and carbonate reservoirs, it is common to find low permeability zones that may sometimes be only millimeters thick yet serve as effective barriers to vertical flow (Mavor, 2014). In such a case, the vertical permeability of a formation is only a small fraction of the horizontal permeability. A lack of data on horizontal and vertical permeabilities can result in inappropriate completion practices, or the installation of an enhanced recovery scheme that does not work well, or both. In one example, a crestal injection of liquefied petroleum gas was used to improve the displacement efficiency from pinnacle reef reservoirs. However, in some instances, vertical flow barriers extending over large horizontal distances (Figure 4) caused a holdup of the downward advancing liquefied hydrocarbon fluids and unanticipated high residual oil saturation in the non-contacted zones. Figure 4: Vertical flow barriers (associated with flooding surface shales) In formations where differences in the vertical and horizontal permeability may not be significant, there may still be a preferred permeability direction in the horizontal plane. Many rocks are made up of grains that were transported by, and deposited in, water currents (Figure 5). If the grains were not spherical, they acted like weather vanes they came to rest with their long axis parallel to the current and their largest cross-sectional areas parallel to the earth's surface. Such preferred grain orientation gives rise to directional permeability. Figure 5: Current direction affecting the directional permeabilities Laboratory analyses to establish the directional permeability can be made on core plugs cut in different orientations around the core periphery or by conducting directional permeability analysis of full diameter cores. In either case, these data are very informative, especially when they are obtained for oriented cores and reported at 30º to 45° increments around the circumference of the rock. Directional permeability tests are a natural adjunct to oriented core analysis. They can be complemented by studying thin sections cut in specific orientations to explore and explain directional permeability differences. Cation Exchange Capacity The cation exchange capacity (CEC) is a measure of the ability of clays, such as montmorillonite, chlorite, illite, and kaolinite (Figure 1), to exchange ions between the clay surfaces and surrounding water. It is normally expressed as milliequivalents per 100 grams of dry rock. Its magnitude is a function of the clay type and amount, and may be determined using wet chemistry techniques that utilize an ammonium or a barium exchange. This technique originated within the soil science discipline. A newer technique establishes the CEC through a correlation with the adsorbed water content of test samples. Figure 1: From upper left: montmorillonite, chlorite, illite, and kaolinite CEC is a mechanism related to the stripping of ions from injection fluids, trace element accumulation and over-pressuring of the formation. These data have also been used to identify environmental changes resulting from changes in climate, sediment source and erosion rate. A primary use of these data in the petroleum industry is in the Waxman and Smits (1968) and Waxman and Thomas (1974) equations, where they are used to calculate water saturation in clay-bearing formations. The CEC is converted to an exchange capacity per unit pore volume prior to use in calculation of the water saturation using well logs. Table 1 shows the cation exchange capacities for various clays. Table 1: Cation Exchange Capacities (CEC) of Various Clays Clay CEC (mEq/100 grams)* * Units are milliequivalents/100 grams of dry rock.** In some studies, the CEC for chlorite has been reported as below 1. Montmorillonite 80-150 Illite 10-40 Chlorite 10-40** Kaolinite 3-15 Application of the Waxman-Smits equation and its influence on the calculated water saturations was demonstrated in a paper by Keelan and McGinley (1979). Ignoring the CEC will result in calculated water saturations that are erroneously high. This may cause the oil-in-place of the hydrocarbon productive zones to be underestimated, at best, or even overlooked. Grain Size Distribution The grain size distribution (Figure 1), affects both porosity and permeability, and is an important indicator of reservoir quality. Generally, the more uniform the grain size, the higher the porosity and permeability. However, porosity is actually independent of grain size. Studies have shown that both silt-sized and coarse-grained sands may exhibit essentially the same porosity, but the coarser-grained rock will have much higher permeability. Figure 1: Grain size variation of sands and silts The grain size distribution of sandstones is often determined by grain size analysis. These data are one of the indicators of the depositional environment. The particle size analyzer often used in sidewall core analysis provides a rapid measure of grain size distribution and, with it, a better estimate of the permeabilities on these small samples. Grain size data are also used for sizing the gravel packs that are installed in well completions to prevent sand flow into the wellbore. Two basic analytical techniques for estimating grain size distribution are sieve analysis and sedimentation analysis based on Stokes’ Law. Sieve Analysis Technique This method involves sieving a disaggregated core sample through a series of dry screens with increasingly finer mesh (Figure 2). Figure 2: Sieve analysis Difficulties occur in this technique because the electrical attraction between disaggregated clay particles causes them to clump and not pass properly through dry screens. This can be remedied by using a wet technique in which the finer clay particles can be washed through a 230 mesh sieve (0.0625 mm) to remove the clay (Figure 3). The remaining portion of the sample is then passed through a nest of variously sized screens, and the portion remaining on each screen is weighed. Figure 3: Wet sieve technique It is common to present the grain size distribution as a function of cumulative weight percent of the total sample, as shown in Figure 4, normally an S-shaped curve. The farther to the left on the horizontal axis that the distribution curve falls, the coarser the material. The more uniform the sample, the more vertical the S shape. A completely uniform sample would result in a vertical line. Figure 4: Grain size distribution using sieve analysis Sedimentation Technique The second analytical technique for measuring the grain size distribution utilizes the principles of Stokes' law on the settling time of free-falling grains in a liquid column. The sample is carefully disaggregated and weighed, and then placed in a holder where ultrasonic agitation completely disperses the particles and detaches clay from any sand-sized grains. The dispersed sample is then spread evenly and simultaneously over the surface of the solution in the settling tube. Particles falling to the bottom of the tube collect on a balance as a function of time. Weights are monitored electronically and transmitted to a computer. The analyzed results generate both tabular and graphical data similar to that illustrated in Figure 4. A sample may be characterized mathematically by: (1) its standard deviation, which indicates the degree of sorting, and (2) the median grain diameter. A grain size distribution that is not symmetrical around the mean grain size is said to be skewed. The coefficients of skewness are calculated, as well as the relationship of the total height of the distribution to its base width. This is referred to as the peakedness, or kurtosis, of the distribution. The Trask (1932) sorting coefficient is an indicator of the degree of sorting, with the value of 1.0 representing a well-sorted sample. The Trask sorting coefficient is defined as "the square root of the ratio of the 75th and 25th percentiles". This ratio works well as a sorting indicator because it can be interpreted as an estimate of the spread. Firmly cemented samples pose problems in measuring grain size distribution. The two most common types of cement are carbonate and silica. Carbonate cement can be removed by washing the core with dilute hydrochloric acid. If the sample is cemented by silica, it may be impossible to disaggregate it without crushing the grains; the only available technique for determining grain size distribution would then be the use of thin sections. Even in cemented sandstones, the grain size distribution is a helpful indicator of the rock quality and has been used successfully in studies of both ditch cuttings and cores. While grain size distribution is an indicator of the depositional environment in general and its energy in particular, it should be supplemented with lithology and biostratigraphy data to be more definitive. Laser Diffraction Technique Some laboratories use the laser diffraction technique to establish the grain size distribution. Laser diffraction measures the particle size distributions by measuring the angular variation in the intensity of light scattered as a laser beam passes through a dispersed particulate sample. Large particles scatter light at small angles relative to the laser beam, and small particles scatter light at large angles. The angular scattering intensity data is then analyzed to calculate the size of the particles responsible for creating the scattering pattern, using the Mie theory of light scattering (Figure 5). The particle size is normally reported as a volume equivalent sphere diameter. Figure 5: Mie scattering Detailed Fracture Studies The objective of detailed, natural fracture studies is to carefully describe the nature and degree of natural fractures in recovered full diameter cores (Figure 1). Figure 1: Fitting fractured core together and marking it These data are subsequently used to: Locate development wells with favorable fracture permeability. Determine the optimal direction of horizontal and multi-lateral development wells in unconventional reservoirs requiring fracking (Sonnenberg, 2012). Assist in the planning of well completion and stimulation by identifying fracture intervals. Evaluate fracture-finding well logs and correlate them with actual rock fracture conditions. Assist in the structural analysis of hydrocarbon accumulations as they relate to fault orientation and location. Assist in the calculation of the theoretical block height and cross-sectional area of matrix fracture blocks for mathematical modeling. To obtain valid fracture data, good core handling procedures (London Petrophysical Society, 2012) must be used at the wellsite. Care should be taken to avoid breaking the rock excessively and to fit it properly together prior to marking (Figure 1). The core must be spatially oriented to be of maximum benefit to the study. This can be accomplished by coring with an orientation tool (Devico, 2014), or by aligning the visible core bedding dip with the formation dip as identified either by a dipmeter or by regional geological information. After the core is properly orientated, both the dip and strike of the observed fractures are recorded. An example of such a recording is the rose diagram shown in Figure 2, which shows a well with a major fracture trend striking in a northwest to southeast direction, with a secondary trend at right angles to it. Figure 2: Distribution of measured fracture strike in a core Figure 3 is a histogram demonstrating that a large majority of the fractures found in this well occur at dip angles of 50º or greater. Figure 3: Histogram of fracture dip It is common practice to record all the observed fracture data on a core fracture log. Such a log displays the fracture depth, length, frequency, density per foot and dip, together with the lithology and rock hardness, on a foot-by-foot basis. In addition, the log records the core porosity and matrix oil saturation. The latter data are of particular importance in thick carbonates that display wide variations in their rock properties and whose zones of oil saturation are sporadic, appearing and disappearing at different depths. Calcimetry Measurements It is useful to know the percentages of limestone, dolomite and insolubles present within the core. These data aid in typing rocks, and are often helpful in correlating various information about rock properties. Calcimetry measurements are sometimes made using a titration technique known as a versenate, or EDTA, analysis (Figure 1). Figure 1: Versenate analysis Another rapid, practical and low-cost method for determining the ratios of limestone and dolomite and the total amount of acid-soluble material in small samples is to use an automated calcimeter. A one-half gram sample is crushed and placed in a chamber to which acid is added. The reaction of the acid with the rock releases carbon dioxide, which builds up pressure within the chamber. This rise in pressure is related to the rate of reaction and, when monitored, can be used to differentiate between limestones and dolomites, as well as to measure the total solubility of the rock. Pyrochromatography and Fluorescence Spectroscopy Two methods for distinguishing gas productive, oil productive and non-productive zones are pyrochromatography and fluorescence spectroscopy. Pyrochromatography Pyrochromatography, sometimes called thermal extraction chromatography, is derived from the process in which heat is applied in a controlled manner to small hydrocarbon-saturated rock samples, which causes the fluids to leave the core sample and be swept into a chromatograph for "fingerprinting." These data are helpful in providing a distinction between gas productive, oil productive and non-productive zones. An important application of this procedure is in evaluating reef formations. Its application requires the use of production as well as other conventional well evaluation data to establish working correlations. Figure 1 displays chromatographic fingerprints for both a non-productive and an oil productive formation. Figure 1: Chromatographic fingerprints for productive and nonproductive formations The oil productive formation is characterized by high percentages of C15 through C19, and significant percentages of C20 and above. It can be noted that essentially all of the hydrocarbons lower than C8 are missing. This indicates that the rock has permeability and that these light components vaporized and escaped on the trip up to the surface. Another important indicator is the total hydrocarbon quantity in the sample (the area under the curve), which is sufficient in this case to indicate oil production. The non-productive example shown in Figure 1 has less total hydrocarbon in the core and a high percentage of C8 and lower. This indicates that the rock contained little residual hydrocarbons and was of such poor quality that the lighter hydrocarbons could not readily escape as the core moved to the surface. The thermal extraction chromatography technique is also used in the analysis of drill cuttings to evaluate the source rock quality. Fluorescence Spectroscopy Another method for distinguishing gas productive, oil productive and non-productive zones is fluorescence spectroscopy. Portions of the rock are placed in a chemical solvent to leach out the residual hydrocarbons. Fluorescence measurements of the leached solution are taken at predetermined time intervals with a fluorescence spectrometer, or fluorimeter, to determine the relative levels of fluorescence. This provides an indication of how rapidly the available hydrocarbons are extracted from the rock, which in turn is an indication of the permeability of the samples. Fluorescence data can then be plotted by depth to identify those wellbore intervals that do and do not exhibit fluorescence. Figure 2 is an example of a comparison between fluorescence and chromatographic analysis and includes a prediction of the gas, oil and water zones. Figure 2: Comparison of hydrocarbon profile by relative fluorescence and chromatographic analysis Salinity of Pore Water It is important to know the salinity, and thus the resistivity, of the formation water present within a reservoir rock, especially to enable accurate water saturation calculations using LWD and wireline well logs. With knowledge about the salinity/resistivity of both the formation water and the coring fluid, measurement of the salinity of the water recovered in the core will indicate the extent of filtrate flushing. Analysis of the water salinity can be applied only to cores cut with oil-base mud. In core samples acquired with oil-base mud, where usually no extraneous water has been added to the core, the salinity of water in the sample should represent that in the reservoir. Bloys (2011) described low invasion coring techniques. In situations where the formation has not been previously penetrated by wells and no water production has occurred, the salinity of the formation water may be initially unknown. This salinity can sometimes be estimated from regional studies or calculated from the spontaneous potential (SP) log if a sufficient salinity differential exists between the coring fluid and the in-place formation water. Even in this case, further verification of the calculated salinity is desirable. A relatively rapid laboratory technique for estimating the water salinity uses a sample of core taken adjacent to those samples used for the Dean-Stark or summation-of-fluids analysis (University of Liverpool, 2014). If it is assumed that the porosity and water saturation present in the adjacent sample are the same as that in the summation or Dean-Stark (Royal Society of Chemistry, 2010) sample previously analyzed, the quantity of water in the salinity sample can be estimated. The sample can then be crushed and washed with a known volume of distilled water, leaching the salt from the sample. This solution can then be titrated to generate a measure of water salinity. This technique is documented in API RP 40 (1998). Salinity measurements on cores have also been used to estimate the vertical sweep efficiency, an important input into the hydrocarbon recovery efficiency calculation. In those reservoirs where the salinity of the injection water varies sufficiently from that of the formation water, determination of the core salinity on a foot-by-foot basis will establish that portion of the formation that has been contacted by the injected water and, thus, has been swept. There are practical limitations to making these calculations on low porosity formations that contain moderate water saturations. In such cases, the quantity of water present in the test plug may be quite small and a small error in estimating its volume will generate a large error in the calculated water salinity. Water derived from a drill stem test, or sometimes from a formation tester if conditions are ideal, will generally be more definitive for determining the resistivity of the formation water, [latex]R_{w}[/latex]. Oil API Gravity Knowledge of the oil API gravity is helpful in the interpretation of SCAL data and core photographs taken under ultra-violet light, and estimates of its value may be useful before the well is completed. Laboratory estimates of the in-place oil gravity can be made using one of several techniques. A common method requires the collection of oil samples, either from a drill stem test or a wireline formation tester fluid sample, from the zone of interest. The API gravity is determined on these oil samples, which are then retorted. The API gravity is then determined on the oil recovered in the retorting process, and correlations are made between the retorted oil gravity and the initial, non-retorted oil gravity. Retort oil from the core analysis can be used with the correlations in subsequent wells. Data included on the core analysis report represent a non-retorted oil gravity. Alternatively, oil samples may be obtained from wireline formation testers. In cases involving the analysis of heavy oil and tar sands, where no produced oil is available or likely to be initially available, oil is actually recovered from the core. Sufficient oil can sometimes be recovered by centrifuging the core. In other cases, solvents such as methylene chloride have successfully removed the oil from the core. The solvent is subsequently vaporized and measurements are made on the remaining oil. Application of heat and agitation is necessary to remove the solvent from the oil, and some uncertainty exists as to how representative the gravity of the remaining fluid actually is. Nevertheless, this measurement has sometimes proved useful in those cases where no other source of oil gravity was available. Methods for Determining Oil API Gravity Three basic techniques exist for the determination of oil gravity. The first technique involves filling and weighing a capillary of small volume with water, and then filling and weighing the capillary with the sample of oil. Comparison of the two weights establishes the specific oil gravity, from which the oil’s API gravity is calculated. The second technique involves the suspension of an oil droplet in a water-alcohol mixture. The mixture is adjusted by water or alcohol addition to cause the oil droplet to float. When this adjustment has been completed, a hydrometer is inserted into the mixture and the specific gravity of both the oil and the mixture is read. The third technique, mentioned previously, is commonly used in sidewall core analysis. The refractive index of the retorted oil is measured, and through the use of correlations, the API gravity of the non-retorted oil is estimated. This is a relatively rapid measurement technique. It requires previously developed correlations between non-retorted oil API gravity and retorted oil refractive index. The following equations express the relationship between specific gravity and API gravity. [latex]API {^{o}}= \dfrac{141.5}{SG} - 131.5[/latex] [latex]SG=\dfrac{141.5}{131.5 + API {^{o}}}[/latex] Assignment Core Information You are the project geologist responsible for a well in which some full diameter core has been acquired. Summarize the various options and formats for core photographs, briefly describing some of the main interpretation applications. Solution Options for core photography range from black and white to color photography, as well as photographs taken under ultraviolet light. Photographs are often taken of the core before it is slabbed, with any residual hydrocarbons still in place, as well as of the slabbed core. The color and ultraviolet light photographs tend to complement one another, the former recording what the eye sees and the latter revealing oil fluorescence indicating hydrocarbons. In reservoirs that are fractured, enhancement of the fracture pattern can sometimes be observed in the color and ultraviolet light photographs. Photographs are often taken at 1 ft (30 cm) intervals along the core. In other cases, the cores are grouped into lengths of 15 or 20 ft (4.5 or 6.1 m) and a single photograph is made of the entire sequence. Multiple footage pictures can enable visualization of changes in the core bedding and structures that indicate differences in permeability, porosity and the depositional environment. Assessment Core Information 1. The data derived from detailed, natural fracture studies in recovered cores are subsequently used to do what? (Select all that apply.) A .Assist in the planning of well completion and stimulation by identifying fractured intervals. Correct ✔B .Determine the optimal direction of horizontal development wells in unconventional reservoirs requiring fracking. Correct ✔C .Locate development wells with favorable fracture permeability. Correct ✔D .Assist in the structural analysis of hydrocarbon accumulations as they relate to fault orientation and location. Correct ✔ 2. Which of the following describe the pyrochromatography method? (Select all that apply.) A .Provides a distinction between gas productive, oil productive and non-productive zones. Correct ✔B .Can only be used for offshore hydrocarbon accumulations. C .Is useful for evaluating reef formations. Correct ✔D .Causes the fluids to leave the core sample and be swept into a chromatograph for fingerprinting. Correct ✔ 3. By what processes are oil fluid samples obtained for the analysis of their API gravity? (Select all that apply.) A .From the core by centrifuging Correct ✔B .Drill stem tests Correct ✔C .Wireline formation tester fluid samples Correct ✔D .Ditch cuttings 4. What minerals can cause high gamma ray readings in a core gamma ray log? (Select all that apply.) A .ZincB .Thorium Correct ✔C .Potassium Correct ✔D .Uranium Correct ✔ 5. In the cation exchange process, cations are exchanged between what two elements? A .Sandstones and limestonesB .Sandstones and claysC .Coring fluids and clastic rocksD .Clay surfaces and surrounding water Correct ✔ 6. What types of secondary cement, when in significant quantities in sandstones, can cause the grain densities to vary from standard values? (Select all that apply.) A .Siderite Correct ✔B .Calcite Correct ✔C .QuartzD .Silica 7. A good understanding of the differences in the horizontal and vertical permeabilities of reservoirs is extremely important for what subsurface interpretation activity? A .Time to depth seismic data conversionB .Seismic fault interpretationC .Dynamic reservoir modeling Correct ✔D .Basin modeling 8. What are the advantages of knowing the salinity of the pore waters? (Select all that apply.) A .Indicate the extent of coring filtrate flushing. Correct ✔B .Determine if the pore water is drinkable.C .Enable accurate water saturation calculations using well logs. Correct ✔D .Estimate the vertical sweep efficiency of reservoirs. Correct ✔ 9. Under what conditions are cores normally photographed? (Select all that apply.) A .Color photographs under ultra-violet light Correct ✔B .Black and white photographs under natural light Correct ✔C .Color photographs under natural light Correct ✔D .Black and white photographs under infra-red light Recommended for You Special Core Analysis (SCAL) Core Reports | What is a core report? Core Description