Evaluation of the Shale Impact on Reservoir Characterization, the Jeribe Carbonate Reservoir in an Oilfield Northern Iraq as a Case Study

Abstract


Introduction
The sedimentary rock type known as "shale" is composed of a mixture of clay-sized particles (mostly clay minerals), silt-sized particles (quartz, feldspar, and calcite), and sometimes some sand-sized particles, such as quartz, feldspar, and calcite on occasion (Jorden & Campbell, 1984) (Jorden & Campbell, 1984).All well logging measurements are somewhat impacted by shale.The information in the wireline logs can be used to identify the existence of shale in a formation.Moreover, shale kinds, shale volume, and effective porosity can be calculated analytically using natural gamma ray or spectral gamma ray logs or graphically (cross-plotting).The presence of clay minerals in a reservoir rock has a negative impact on the petrophysical characteristics of the reservoir, reducing its effective and total porosities as well as its permeability.
Generally, the presence of shale in any reservoir causes reduced porosity and permeability, increased water saturation, anisotropy in the reservoir's properties, and problems for the interpretation of the wireline log data, which are thus misleading in estimating reserves and calculating N/G reservoir and pay ratios.Shale content in reservoirs has a variety of consequences, and the severity of those effects is largely influenced by the volume, composition, and distribution of the shale the reservoir rock.Shale also presents significant challenges when evalauating formations and conducting drilling operations.
Shale is scattered in reservoir formations in three fundamental ways: structurally, laminarly, or dispersedly (Thomas & Stieber, 1975).The most important object of this paper is to evaluate the impact of the shale content and distribution on the log measurements and reservoir quality of the Lower Miocene Jeribe Formation in two selected wells of an oilfield in Salahaddin Governorate, Northern Iraq.

The Study Area
The studied oilfield has been located approximately 30 km to the northeast of Tikrit City, and it lies just to the southwest of the Hamrin Anticline within the Zagros Foreland Low Folds Zone (Fig. 1).The structure of the studied field consists of an asymmetrical longitudinal anticline of NW-SE axis direction.The anticline contains two domes separated by a small saddle.The structure's length is around 30 km, and its width is approximately 5 km., with a structural closure of about 350 m at the top of the Jeribe Formation.The first or southern dome contains a gas column of about 270 meters in height.Light oil exists at the margins of the mentioned dome within the Jeribe, Euphrates, and Kirkuk Group formations as mentioned in an internal report of the Iraqi Oil Exploration Company (IOEC, 1994).The two selected wells for this study are located at the southwestern limb of the southern dome.

Jeribe Formation
Bellen introduced the Jeribe Formation in 1957 from Sinjar Mountain near Jaddala Village (Bellen, et al., 1959).The formation in its type locality is composed of massive limestone that has been recrystallized and dolomitized, with beds of 0.3-2.6 m in thickness.In the type locality, the Jeribe Formation is underlain unconformably by the Serikagni Formation (Bellen, et al., 1959), whereas in other areas, such as the Khabbaz anticline, it is conformably underlain by the Dhiban Formation (Baban & Hussein, 2016).
The Jeribe Formation is homogenous in lithology and faunal assemblage content.It reflects the marine platform's constrained environment, which is predominantly made up of lagoonal facies, calm, warm water, and a relatively high salinity (Bellen, et al., 1959;Jassim and Buday, 2006).In the studied field, the Jeribe Formation is an interval of carbonate that is sandwiched between the carbonate-evaporite units of the Transition Beds of the Middle Miocene Fatha Formation above and the Burdigalian Dhiban Formation below.

Data and Methodology
The Jeribe Formation is penetrated by the first well of the study NET-10 between depths of 1024.5m and 1067.5m(43m thick) and by the second well of the study NET-12 between depths of 1074m and 1122.5m(48.5m thick).The two chosen wells' available wireline logs for the Jeribe Formation served as the primary source of data for this study's objectives.The data came from the Gamma ray and Natural Gamma Ray Spectrometry (NGS) logs along with the Sonic, Density, and Neutron porosity logs.Data from the Micro Resistivity and Deep Resistivity logs was also used in this investigation.
In this study, the following technique stages are followed: • Digitizing the log plots.
• Predicting the lithology of the studied Jeribe Formation depending on the porosity log data and using special charts.
• Calculating shale volume using Gamma ray data.
• Determining the type of clay minerals within the Jeribe Formation using data from the NGS and special charts.
• Predicting the environmental depositional condition of the formation depending on the data from the Natural Gamma Ray Spectrometry (NGS).
• Determining shale distribution modes and effective porosity using data of the Density and Neutron porosity.
• Employing precise formulae to convert the data from the Acoustic and Density logs to porosity measurements.
• Removing the impacts of the shale component from the estimated porosities.

Lithology determination
Lithology determination is among the main applications of wireline logging.The response of some logs, like the gamma-ray and porosity logs, is affected intensively by the matrix types and shale content and is of great assistance in predicting the type of lithology.

Neutron-Density (NØ-ρb) Method
Although Neutron and Density logs are challenging to utilize independently for identifying lithology in its whole, they become one of the most effective lithology markers when combined.Figures 2 and 3 show that the common lithology of the Jeribe Formation is dolostone, limedolostone, limestone, and dolomitic limestone.The deviation of the sample points towards the right side of the cross plot (shale region), especially in the well NET-10 (Fig. 2), and is mostly due to the shale effect.The sample points mentioned are those that show high gamma-ray records.Although the well NET-12's Jeribe Formation shale composition is lower than that of the well NET-10's, the sample's deviation is more pronounced in the shale region.(Fig. 3).

M-N method
Another method of determining the lithology is to combine the information from the three porosity logs (Neutron, Density, and Sonic) within a cross plot called the M-N crossplot .The two factors M and N are conventionally calculated by applying the two equations 1 and 2. As the data of the sonic porosity (∆t) is also contributed to this cross plot, the effect of the possible secondary porosities (fractures or vugs) may be more obvious and lead to deviance in the sample points towards the region of the secondary porosity at the upper part of the cross plot (Figs. 4 and 5).
Thus, firstly; the apparent limestone lithology of the formation is dolomitic limestone or dolomite (dolostone), and secondly; the deviation of the sample points towards the shale region at the lower part of the cross plot is again noticeable, especially in the well NET-10 (Fig. 4), although the effect of the secondary porosities (and maybe the gas also) diminishes the effect of the shale in deviating the locations of the sample points.

DTMAA & RHOMAA method
An additional cross plot of the matrix transit time (DTMAA) versus the matrix density (RHOMAA) is used to support the previously determined lithology for the Jeribe Formation (Figs. 6 and 7).In this cross plot, the effect of the shale generally pushes the sample points towards the left side of the cross plot.This can be seen in Figure 6 for NET-10 beside the more obvious effect of the gas, whereas no such effect of shale content or gas appeared in the well for NET-12 (Fig. 7).The formation is concluded to have the same dominant dolomite and dolomitic limestone lithology using this cross-plot.

Computing shale volume from data of the Gamma ray log:
One of the greatest methods for identifying and measuring the amount of shale material is the Gamma ray log (Schlumberger, 1972).This is mostly because of its responsiveness to radioactive substances, which typically concentrate in Shaley rocks.
Calculation of the shale volume for the studied Jeribe Formation started with calculating the Gamma Ray Index (GRI) by applying the equation 3.

GRI = (GRlog − GRmin)/(GRmax − GRmin)
(3) Where: GRI: gamma ray index.GR log: gamma ray log reading in the zone of interest, API units.GRmin: minimum gamma ray reading in a clean zone, API units.GR max : maximum gamma ray reading in shale zone, API units.The equation 3 proposed by Larionov (1969) for calculating shale volume in unconsolidated rocks of Tertiary age is applied.
Figs. 8 and 9 display the gamma ray data and calculated shale volume for the Jeribe Formation in the two investigated wells.
Jeribe formation in both wells is more than 10% shale, with the NET-10 well having a higher shale content.The middle of the formation in this well has the highest proportions of shale, and it exceeds 30% in multiple horizons (Fig. 8).

Computing effective porosity
Using Schlumberger Techlog642015.3 software, the total porosity for the Jeribe Formation is computed from Sonic, Density, and Neutron logs.A correction for the shale impact is then made, which resulted in a reduction in the overestimated calculated porosity.
It's worth mentioning that not always the decrease in porosity is due to high shale content because, as noticed from the calculated porosities in Figures 8 and 9, in some horizons porosity is very low and shale content is low too (1035 m, 1052.5 m, and 1056 m in NET-10; 1114.5 m in NET-12).Such a condition is mostly due to the existence of dense lithologies such as dense dolomite or anhydritic horizons.

Clay typing
The Natural Gamma Ray Spectrometry (NGS) logging tool has been used to show the amount of the radioctive elements of Thorium, Uranium, and Potassium for both research wells (Fig. 10).

Thorium Vs Potassium
Schlumberger (2009) suggested using the Thorium vs. Potassium chart (also known as the Lith-2 chart) to compare concentrations obtained using the Natural Gamma Ray Spectrometry (NGS) log to the types of minerals present in a shale deposit.The chart aids in identifying the kind of radioactive minerals that make up the majority of the clay in the formation being studied.Figures 11 and 12 show the distribution of intersected Thorium and Potassium value points for the Jeribe Formations in the studied wells.The relatively low concentrations of both elements and the locations of the sample points refer clearly to the existence of a mixed type of clay minerals consisting mainly of Illite, Chlorite, and Montmorillonite.Heavy thorium-containing minerals may be found in some of the Jeribe Formation's horizons in well NET-10 (Fig. 11), whereas a higher concentration of Feldspar is forming the formation's clays in well NET-12 (Fig. 12).Almost the same group of clay minerals was identified by Qadir and Ali (2022)    The feldspar line is the path from the origin through the feldspar point, and the clay line connects the two clay points.By linearly interpolating between the clay and feldspar lines, WCl is obtained.Schlumberger (1989) used the equations 5 to 8 to represent the four-mineral natural gamma ray spectrum interpretation model: (5) Th = ThCl 1 WCl 1 + ThCl 2 WCl 2 + ThMatWMat + ThFelWFel (6) K = KCl 1 WCl 1 + KCl 2 WCl 2 + KMatWMat + KFelWFel (7) 1.0 = WCl 1 + WCl 2 + WMat + WFel (8) (With WCl as a known function of Th and K).Schlumberger (1989) claims that it is simple to convert the final mineral weight fractions acquired using this method to volume fractions.The application of this model is shown in Figures 13-16.The concentration of the feldspar minerals in the Jeribe Formation in the wells of the study is less than 5 wt%.The low Potassium clay is the dominant type, with weight percentages ranging between 0 and about 20 (being higher in the well NET -10; Fig. 13).As a weight percentage of clay, the Jeribe Formation in the well NET -10 is composed of about 0 to 20 wt% of clay, which is mostly of the low potassium type (Fig. 15), whereas the formation is composed of less than 10 wt% of clay, which is also dominated by low potassium type clay minerals (Fig. 16).

Thorium -Uranium ratio
The identification of "geochemical facies" has been made easier with the use of the Thorium-Uranium ratio (Th/U).Redox potential is shown by the Th/U ratio.Under reducing circumstances, the insoluble tetravalent state of uranium is fixed and changes into the soluble hexavalent state, which can be mobilized into solution.Contrarily, thorium is a suitable benchmark for comparison since it possesses a single insoluble tetravalent state that is geochemically connected to uranium.(Doveton, 1994).Practically, Th/U ratios of less than 2.0 indicate deposition in a reduced environment, between 2.0 and 7.0 can be considered neutral, whereas a Th/U ratio greater than 7.0 indicates an oxidized depositional environment (Adams and Weaver, 1958;in Doveton, 1994).The calculated Th/U ratio values for the Jeribe Formation in the study wells (Fig. 17) clearly indicate a reduced condition of deposition, with the exception of about 2-3 m of the upper part of the formation in well NET-10, which appears to have precipitated in a more natural depositional environment.Thus, the suggested lagoon paleo-depositional environment for the formation (Bellen, et al., 1959;Jassim and Buday, 2006) and restricted marine carbonates (Aqrawi, et al., 2010) looks to have occurred under a reduced condition, and accordingly, well-preserved organic matters (in case of their existence) are expected to be seen in the formation.Its worth mentioning that the studied wells are located at the western margin of the depositional environment suggested generally by Jassim and Buday (2006) as lagoons.Iraqi Geological Journal Baban et al. 2023, 56 (2E), 185-207 200

Modes of clay distribution
Certain log measures are influenced by the distribution of clay in formations.As a result, three forms of distribution (laminated, structural, and dispersed) have been discovered by log analyzers (Ellis & Singer, 2008).Thomas & Stieber (1975) used both ØN and ØD values to differentiate between the three types of shale distribution within sandstone rocks.In order to determine the three forms of shale distribution in carbonate reservoir rocks, Yang (2015) assumed two end members of clean carbonate and pure shale and determined their appropriate values from the logs of Density and Gamma-ray.
Using density porosity (ØD) and neutron porosity (ØN) values for the same purpose of defining shale distribution modes in carbonate rocks is applied by different authors based on the proposed method by Thomas & Stieber (1975) for sandstone rocks (e.g., Yang, 2015;Moradi, et al., 2016;Baban, et al., 2020;Baban & Ahmed, 2021).In addition to identifying the mode of shale distribution, this method also assists in estimating the shale volume and the effective porosity value.
To apply this method, a triangle connecting matrix (M, zero porosity), fluid (F, 100% porosity), and shale (Sh, zero effective porosity) endpoints should be identified on a ØD-ØN cross plot.The M-F line will represent the clean formation of zero shale volume, whereas the line M-Sh represents zero effective porosity (Øe).The proposed value for a clean limestone matrix (Lst) is 25%, thus the line Lst-Sh will represent the zero to 100% shale content.For each point in the triangle, Vsh may be calculated along lines parallel to the clean formation line (MF), and Øe value can be established along lines parallel to the M-Sh line.
Although the dispersed type of shale distribution is generally the most common in carbonate reservoirs, the three different modes of shale distribution were observed in the Jeribe Formation in the two wells of the (Figs.18 and 19).
As the impact of each of the three types of shale distribution on reducing porosity and permeability differs, reservoir zones with structural shale distribution will not suffer from a reduction in porosity and permeability because of the shale content.The most effective reduction in reservoir properties occurs in zones where the shale content is dispersed between the grains.
In conclusion, the reservoir properties of only selected zones from the Jeribe Formation will be seriously affected by the shale content in both wells (NET-10 and NET-12), while the porosity and permeability of the other zones of the formation are either partially affected or remain outside of the negative impact of the shale content.

Shale impact on porosity and resistivity
The porosity values calculated through the Density log and recorded by the Neutron log are considered to be a total and well-representative reservoir porosity.However, because the two logging tools react to some reservoir rocks, borehole conditions, and fluid conditions differently, Neutron-Density Porosity (ØND) is typically measured as a combination (which is almost the average of the two porosity values after correction for shale, gas, and other effects).
The corrected ØND values are more reliable and can be considered an effective porosity, which is mostly dependent on when reservoirs are evaluated.
Figs. 20 and 21 show the calculated corrected Neutron-Density porosity (NDcorr) from the shale effect for the Jeribe Formation in wells NET-10 and NET-12.The presence of shale in a reservoir rock affects the processes of reservoir evaluation and reserve estimation in different ways.According to O'Brien (1996), any formal application of Archie's equation results in an overestimate of water saturation because the presence of shale reduces the reservoir quality (porosity and permeability) and adds an additional electrical conductivity component.
Thus, the calculated water saturation values in shale and shaley zones will be unreliable due to two main reasons that act in opposition to each other.Firstly, the record of the low values of true resistivity (Rt) and flushed zone resistivity (Rxo) is due to the shale materials being less dense than other carbonate materials (like dolomite and limestone) and also due to the increase of the conductivity component caused by the shale materials, which finally leads to an overestimate of water saturation calculation when Archie's equation is applied.Secondly, applying the equation without removing the effect of the shale on the porosity will result in an underestimated water saturation (due to mistakenly calculating low values for the Formation Factor, F).
The fluctuations in the resistivity record, along with the porosity, shale content, and mode of shale distribution for the Jeribe Formation in the wells NET-10 and NET-12, are shown in Figures 20 and 21.
Among the observations about the relationship between the parameters in the two mentioned figures is that not always the high gamma ray record or high shale content calculation means the existence of a zone of low porosity, but but it is important to look into the type of shale dispersion.
Different zones in the Jeribe Formation in both wells are of relatively high shale content, but because the shale is distributed in a structural (or even laminated) mode, the porosity is still high (e.g., 1040 m-1050 m in NET-10, Fig. 20, and1093 m-1102 m in NET-12, Fig. 21).
It is important to note that the trend in resistivity fluctuation does not always coincide with the trend in porosity fluctuation (ignore the nature of the fluid content); for example, the obvious increase and decrease in porosity in the relatively high shaley content depth interval from 1035 m to 1057 m in the well NET-10 meet with a continuous decrease in Rxo values.This indicates that the nature of the matrix (including the shale content) has a greater effect on resisting the flow of the electrical current than the volume of the pore spaces and their fluid content.
Another example is the zone of very low porosity at the depth interval 1105.5-1106.5 m in the well NET-12 (Fig. 21); the zone of only 5% porosity doesn't meet a high Rxo record to distinguish it from the adjacent zone or some other zones having about 20% porosity.The only reason for this is that this is a shalecontent zone, so the less dense nature of the shale compensates for the porosity and keeps the zone's resistivity low, just like the other more porous zones.
On the other side, the mode of shale distribution has also an obvious effect of permeability.Highest reduction in permeability occurs when the shale is dispersed between the grains.This can be seen obviously in the zones where shale is dispersed in the lower part of the Jeribe Formation in both wells of the study and specially the well NET-10 (Fig. 20).Shale dispersion in a structural mode has no discernible impact on permeability reduction, for example, the depth interval 1040 -1050m in the well NET-10 and 1093m -1100m in the well NET-12.The distribution of the shale as lamina causes most the time a horizontal reduction in permeability (vertical anisotropy in permeability).The intensity of the mentioned permeability anisotropy depends on the type of shale lamina.Several forms of shale lamination are produced by various diagenetic processes and depositional locations.According to O'Brien (1996), shale can take the form of thin lamination from suspension settling, thick lamination from bottom-flowing current deposition, or wavy lamination from benthic microbial mats.
To show the impact of the shale content on the calculated porosities by the Density and Neutron logging tools, an average uncorrected ØND porosity is calculated for the Jeribe Formation (Fig. 22) and was equal to 24% and 23% for the NET-10 and NET-12 wells, respectively, whereas the average corrected ØND porosity was equal to 19% for both wells.Thus, about 4%-5% of overestimated porosities will be mistakenly calculated in the case of the non-removal of the shale effect.
The average of the calculated water saturations done by the authors for the Jeribe Formation through applying Archie's equation and using the uncorrected ØND values from the shale effect is equal to 36% and 40% for NET-10 and NET-12 wells, respectively, whereas the average of the water saturation values calculated in the same way using corrected ØND values is equal to 45% and 47% for NET-10 and NET-12 wells, respectively.So, an underestimation of about 9% and 7% water saturation will be done for the Jeribe Formation in NET-10 and NET-12 wells, respectively, in the case of an unremoved shale effect (as shown in Figure 22).In other words, the mistakenly estimated 64% hydrocarbon saturation for the Jeribe Formation in the well NET-10 is only equal to 55%, and the estimated 60% hydrocarbon saturation for the formation in the well NET-12 is only 53% in reality.
It's worth mentioning that the calculation of bulk volume water (BVW) doesn't show a significant difference when uncorrected or corrected values of porosity and water saturation are used (Fig. 22).The reason behind that is because both porosity and water saturation are affected in opposite ways when corrected or uncorrected for the shale effect, and thus when the formula of BVW is applied (Ø x Sw) the effect of the shale will be diminished to a large degree.

Conclusions
The Jeribe Formation in the wells NET-10 and NET-12 of the oilfield is lithologically composed mainly of dolostone and dolomitic limestone with more than 10% shale content and is higher in well NET-10, especially in the middle part of the formation where more than one zone of greater than 30% shale content exists.The formation has good porosity, particularly in its middle part.The shale within the formation consists of low-concentration Thorium and Potassium clay minerals such as Illite, Chlorite, and Montmorillonite.The low Th/U ratio of the formation indicates deposition of the formation in a reduced-condition environment.The shale within the formation has different modes of distribution (dispersed, laminated, and structural).As an average, the shale content in the formation has an impact on the porosity calculation by overestimating it by about 4-5% and subsequently underestimating the water saturation by 9% in the well NET-10 and 7% in the well NET-12.Vertical anisotropy in the permeability exists in different depth intervals of the formation as a result of laminated shale distribution.

Fig. 1 .
Fig.1.Location map for the studied Oilfield.The map is after (modified from Al-Ameri, et al., 2011).

Fig. 2 .
Fig.2.Neutron-Density cross plot for lithology identification of Jeribe Formation in the well NET-10.

Fig. 4 .
Fig.4.M-N cross plot for lithology identification of Jeribe Formation in the well NET-10.

Fig. 5 .
Fig.5.M-N cross plot for lithology identification of Jeribe Formation in the well NET-12.

Fig. 10 .
Fig.10.The record of the Natural Gamma Ray Spectrometry (NGS) showing the amount the Thorium, Uranium, and Potassium for the Jeribe Formation in the wells NET -10 and NET -12.
during their study of the Tertiary reservoir formations (including the Jeribe Formation) in Kor More Oilfield.By noting the relatively near closeness of the 100% Kaolinite, Montmorillonite, and Chlorite clay points on Schlumberger Company's Chart CP-19, the typical scenario of two clays and feldspar may be modeled.Thus, it is suggested to define four points: (1) a low potassium clay point (Cl1); (2) a high potassium clay point (Cl2),

Fig. 11 .
Fig.11.Thor-Pota cross plot for determining the clay mineral types in Jeribe Formation in the well NET -10.

Fig. 12 .
Fig.12.Thor-Pota cross plot for determining the clay mineral types in Jeribe Formation in the well NET -12.which is typically Illite; (3) a low thorium, high potassium point, or Feldspar (Fel); and (4) a clean matrix point (Mat).The feldspar line is the path from the origin through the feldspar point, and the clay line connects the two clay points.By linearly interpolating between the clay and feldspar lines, WCl is obtained.

Fig. 13 .
Fig.13.Four-mineral spectral model for estimating clay rich K, and feldspar minerals in Jeribe Formation in the well NET-10.

Fig. 14 .
Fig.14.Four-mineral spectral model for estimating clay rich K, and feldspar minerals in Jeribe Formation in the well NET -12.

Fig. 15 .
Fig.15.Estimation of total clay percentage using Th-K ratios for Jeribe Formation in the well NET -10.

Fig. 16 .
Fig.16.Estimation of total clay percentage using Th-K ratios for Jeribe Formation in well NET -12

Fig. 17 .
Fig.17.Th/U ratio for identifying the paleo-depositional condition of Jeribe Formation in the wells NET -10 and NET -12.

Fig. 18 .
Fig.18.Neutron-Density porosity crossplot to identify mode of shale distribution for the Jeribe Formation in the well NET-10.

Fig. 19 .
Fig.19.Neutron-Density porosity crossplot to identify mode of shale distribution for the Jeribe Formation in the well NET-12.

Fig. 20 .
Fig.20.Gamma Ray, Vsh, total and effective ND porosity, resistivity logs, and the calculated Sw, BVW, and permeability for the Jeribe Formation in the well NET-10