Petrophysical Properties Estimation by Using Well Log and Core Data Interpretation for Tertiary Reservoir in Ajeel Oil Field

Abstract


Introduction
Understanding and estimating the hydrocarbon potential in the reservoir is significantly dependent on the interpretation and assessment of subsurface petrophysical rock properties.Well logging, coring, and well testing are principal methods for obtaining petrophysical parameters directly (Aswad et al., 2024).The main aim of the analysis and interpretation of well logging is to reveal the petrophysical properties of reservoirs, such as shale volume, effective porosity, lithology, water saturation, movable hydrocarbons, and net pay thickness (Senosy et al., 2020).This helps understand various types of hydrocarbon traps; therefore, an estimate could be made of how much oil can be extracted from them (Farouk et al., 2023).
Heterogeneity in carbonate reservoirs is easily observed because it has several features, such as porosity and permeability, that result from sedimentation and digenesis processes (Jassam et al., 2023).
The heterogeneity and interactions in the carbonate reservoir and there effects on the permeability, oil accumulations and migration is constructed by Awadh et al. (2019).Such petrophysical characteristics are important in predicting the behavior of the reservoirs, thus underpinning accurate geological modeling (Amin & Al-haleem, 2024).Therefore, it is advisable to use basic analytical methods on borehole samples so as to completely understand composition, porosity and permeability (Mohammed, 2018).
The tertiary reservoir in Ajeel oilfield lies in the northern part of Iraq, in a region characterized by instability resulting from the convergence of the Arabian and Eurasian tectonic plates; this belt contains folded strata and normal faults (Al-Ameri et al., 2013).Furthermore, a variety of digenetic characteristics, such as microfractures, dissolution, recrystallization, cementation, and dolomitization, suggest that the formations under investigation were deposited in a marine environment.Tertiary reservoir rocks are primarily made up of limestone, dolomitic limestone, and thin anhydrite beds based on cross-plots of many well-logging data sets (Gharib & Özkan, 2022).Consists of three geological formations: Jeribe, Dhiban, and Euphrates.The primary type of carbonate rock in the tertiary reservoir is dolomite.The top layer of the reservoir is Jeribe, which is made up of a dolomite carbonate unit that is muddy and has many anhydrite nodules.The underlying Dhiban formation is the same as Jeribe but includes a high concentration of anhydrite nodules, chiefly towards its base, which makes it fundamentally a poor reservoir unit.Euphrates is mainly dolomite with some anhydrite and has the best reservoir quality (Deabl et al., 2021).
Numerous techniques and methodologies for determining the petrophysical properties of heterogeneous carbonate reservoirs have been described in the literature.Evaluation of petrophysical properties is conducted utilizing the IP program to delineate the reservoir and explore hydrocarbon potential (Hashim & Farman, 2023).Existing well logs and core data unveil the rock's porosity, permeability, and water saturation after identifying unidentified aquifer and reservoir parameters using nonlinear regression methods (Tawfeeq & Aziz, 2023).To explore the mineralogical and geological elements of the shale formations, M-N cross plots are utilized, providing an understanding of lithology and reservoir characteristics (Hamzah et al., 2022).Consequently, by using this approach, one can get indispensable information about such petrophysical parameters as porosity, fluid saturation and formation density, hence increasing our knowledge of the behavior of reservoirs (Bassiouni, 1994).
The variability of Archie parameters ascertained from different wells by using the Pickett method reflects the presence of substantial inhomogeneity in the reservoir rock properties (Tuaimah, 2017).Analysis of well logs and core data yields tortuosity factor values indicating the existence of multiple fractures in the reservoir (Ashour, 2016).Precise estimation of the total volume of oil shale is essential, as it has a significant effect on fluid content, pore space, and permeability.Various techniques, including Gamma-ray, are employed for measuring shale volume, offering accurate and indispensable insights (Khamees et al., 2022).Net pay, denoting the specific section of a reservoir with favorable petrophysical characteristics and hydrocarbon deposits economically extractable, is determined by estimating the limiting (cut-off) values of petrophysical features such as permeability, porosity, water saturation, and shale volume.Net pay serves as a critical metric for estimating the initial hydrocarbon in place (Al Jawad & Tariq, 2019).Identification of oil-bearing zones relies on their favorable characteristics of high porosity and low water saturation to medium, distinguishing them from other units characterized by low porosity and highwater saturation (Al-Baldawi, 2021).
This study aims to estimate and delineate the petrophysical properties of the Jeribe, Dhiban, and Euphrates formations within the Tertiary reservoir of the Ajeel oil field.By leveraging core data analysis (routine and special core) and well log interpretations (GR, Density, Neutron, Sonic, Deep, and Shallow Resistivity) for well AJ-25, this research endeavors to enhance understanding of effective porosity within the reservoir, the influence of shale on reservoir formations, and water saturation for identifying the oil-bearing formation.

The Study Area
Like most carbonate oil fields in Northern Iraq, the Ajeel oil field has multiple produce layers.The Ajeel oil field is situated in the Iraqi provinces of Kirkuk and Tikrit, some 30 kilometers northeast of Tikrit City.It generally stretches parallel to the "Alnikhila" dome in the "Hemreen" Oil Field and toward the (North-East)-(South-West) direction (Al-Yassery & Al-Zaidy, 2023).Fig. 1 shows the location map of the Ajeel Oilfield in northern Iraq.The Ajeel Field was first discovered in 1977 by drilling the AJ-1 well, which targeted the highest point of a seismic map (Mahammed & Nasser, 2018).Ajeel oil field consists of three hydrocarbon formations in the Tertiary age reservoir: Jeribe Formation, Dhiban Formation, and Euphrates Formation.
The produce drive mechanism in the Tertiary Reservoir of Ajeel oil field combines a gas cup drive, water drive, and fluid expansion.The Jeribe, Dhiban, and Euphrates formations, all of which belong to the Middle Miocene.The Tertiary reservoir in this field covers transitional layers of the Lower Fars (Fatha) Formation of the Miocene age (Al-Yassery & Al-Zaidy, 2023); these layers consist of several thin layers of carbonate, separated by a continuous accumulation of anhydrite.The thickness of these transitional layers is about 120 m (Deabl et al., 2020).Tertiary reservoir formations are unconformably found above the base of the anhydrite, which belongs to the Oligocene age).Fig. 2 shows the stratigraphic sequence of the Ajeel oil field and Table 1 shows the top of the tertiary reservoir in the Ajeel field in well AJ-25.

Materials and Methods
The Interactive Petrophysics software (IP V2018) was utilized to correct environmental variables and generate CPI results from a Las file of log data (including GR log, porosity logs, and resistivity logs).Determine the requirements (porosity cutoff, water saturation cutoff) by utilizing a Microsoft Excel worksheet based on data obtained from Routine Core analysis (porosity and permeability) and special core analysis (effective porosity and water saturation).The Formation Water Resistivity (R W ) can be determined by conducting a Dissolved Solids Total (DST) test, which takes into account the salinity and sodium chloride measurements provided in the Final Well Report (FWR).

Environmental Correction
Most well log records require adjustment to conform to the standard requirements of log tool processing due to potential variations in the state of the wellbore and the conditions under which the log tools were described or calibrated (Jassim & Goff, 2006).The IP V, (2018) application incorporates many environmental correction models supplied by diverse agencies.The well logs from a subset of wells in the Ajeel field were analyzed using the Schlumberger Corrections model, given that Schlumberger originally recorded the majority of the logs.The environmental adjustments for well AJ-25 are illustrated in Fig. 3.

Determining Formation Temperature
The geothermal gradient (GG) is the term used to describe the rate at which temperature increases with depth below the surface.It is commonly measured in degrees Fahrenheit per 100 meters (°F/100m).The formation's temperature greatly impacts the formation assessment, as the resistivity data completely relies on temperature.To determine the geothermal gradient of a region with an unknown value (Eq. 1) can be employed for calculation (Djebbar & Donaldson, 2012). (1) (2) Where: GG: Geothermal gradient (°F/100m).T f : Formation temperature °F.T s : Surface temperature °F.∆D: Absolute distance between two depths.When the geothermal gradient is known, the formation temperature can be calculated by flowing from using Eq.2.The temperature curve generated in well AJ-25 using the temperature model in IP V2018 is depicted in Fig. 4.

Determining Petrophysical Properties
Petrophysical properties Interpretation is critical to understanding the factors controlling the quality of the reservoir and production wells (Al-Baldawi, 2021).

Lithology and Mineralogy Identification
The M-N cross plot is a valuable method for identifying complex lithology.It allows for the identification of mixtures of minerals by plotting M values against N values on a chart.This chart includes single points representing particular minerals such as calcite, dolomite, sandstone, gypsum, sulphur, and gas and areas indicating secondary porosity.By locating where the data point falls on the chart, the predominant lithology or mineralogy present in the formation can be identified (Fertl, 1981).
(3) (4) Where: ∆t log : The variable represents the transit trip time from the sonic log, measured in microseconds/foot.∆t f : The transit travel time of the formation fluid, ∆t f =189 microseconds/foot.ρ b : The bulk density obtained from the density log is expressed in grams per cubic centimeter.
∅ Nlog : refers to the porosity obtained from a neutron log.∅ Nlog : refers to the porosity obtained from a neutron log.∅ Nf : represents the porosity of the formation fluid, which is equal to 1.

Shale Volume Determination
The shale volume of the Ajeel field is determined using the Gamma Ray (GR) approach.The GR approach requires the first determination of the GR index (Bassiouni, 1994).Then apply the Larionov equation for young rocks.
Gamma-ray techniques detect and quantify natural gamma radiation emitted by shale formations, revealing subsurface geology and reservoir features.Shale has more naturally occurring radioactive elements like uranium, thorium, and potassium than other rocks.Specialized logging methods can identify gamma rays from these radioactive materials (Mohammadinia et al., 2023).
The volumetric content of shale is less than 10% of the bulk volume of the reservoir, indicating that the rocks present in the formation are clean reservoir rocks (Khamees, 2021).
: Density porosity from density log (%).: Sonic porosity from sonic log (%).SPI: The Secondary Porosity Index For the water-saturated zone (Sw =100%), the above equation reduces to: (13) A linear trend can be derived by fitting a line through the log R t values for the water-saturated zones, passing through the lowest possible values, and intersecting at ∅=1 of the log a×R W . From the intercept (a×Rw), determining a value of a is possible with knowledge of Rw (via records or fluid samples).Where -m denotes the inclination value of a linear trend in the water saturation zone.
Previous studies have noted that areas of a formation known as irreducible water saturation (Swi) retain a stable bulk volume fraction of water (Holmes et al., 2009).
For irreducible water saturation zones, substitute Swi for Sw in equation (Eq.12), and the expression is transformed.

(14)
Where: C: Constant When Rt versus Ø is plotted on log-log paper, the points representing zones of irreducible water saturation define a linear trend with a slope of n-m and an intercept of the log at ∅=1 on log-log paper, which is illustrated by the equation above.
Archie's parameters a, m, and n for the tertiary reservoir were estimated using IP v. ( 2018) and were supplemented with the Pickett method.The Archie parameters (a, and m) were obtained from the water zone and n from the irreducible water saturation zone (Jumaah, 2021).These values also were derived through special core analysis (Bennion et al., 1996).
• Determination of Water Saturation (Sw) Initial reservoir fluid saturation, a critical factor in estimating the quantity of initial oil in position, denotes a pore space system comprising gas, water, and oil.The regulation of the reservoir's flow properties was determined by the effect observed on the relative permeability (Bennion et al., 1996).Water saturation was calculated in the Ajeel field's tertiary reservoir using the Archie equation (Eq.15) (Asquith & Gibosn, 1982). (15) The water saturation in the flushed zone, denoted as Sxo, can be calculated using the Archie equation, as expressed in Eq. ( 16) (Asquith & Gibosn, 1982).The bulk volume of fluids signifies the smooth dispersion of the fluid volume throughout the pore space of the rock formation (Tonietto et al., 2014).The CPI for well AJ-25 selected for examination in the tertiary reservoir has been performed.

Reservoir Quality
• Cutoffs porosity and water saturation • Net to Gross Historically, the determination of net pay zones has been predicated on particular criteria established using petrophysical data (Cosentino, 2001).
The net to gross ratio refers to the percentage of reservoir rock utilized in the production process.This ratio is ascertained by applying cutoffs to the log curves, which are subsequently utilized to compute the producible intervals by the overall thickness of the formation.The cutoff is a preestablished value employed to classify reservoir characteristics to differentiate productive regions from unproductive ones within the formation.The prevailing approach to ascertain the porosity cutoff value, defined as 1md for permeability, involves employing core permeability-porosity cross plots (Dutton et al., 1999).
The determination of the saturation cutoff can be achieved through the utilization of the relative permeability ratio, provided that specialized core analysis is available (May, 2009).
The Tertiary Reservoir's porosity cutoff was determined through the utilization of the traditional permeability porosity cross plot from routine core analysis data.
The permeability cutoff value= 1md was used depending on lithology (carbonate) and the type of hydrocarbon (oil) to give more realistic results (Al Jawad & Tariq, 2019).

Results and Discussion
Before estimating the petrophysical properties, an environmental correction was applied to the well logs.It was noted that the difference between the initial and modified log readings in Fig. 3 is negligible, except when the cavity collapses significantly or bleaching occurs.The geothermal gradient for the Al-Ajeel field is 4.18°F per 100 m, using equation (3-1).Using the parameter temperature curve, this gradient was utilized to calibrate the resistivity logs for all wells within the Al-Ajeel field.The temperature curve produced in well AJ-25, based on the temperature model in IP v., 2018, is shown in Fig. 4.

Lithology and Mineralogy Identification
The M-N diagrams depicting the AJ-25/ Jeribe, AJ-25/ Dhiban, and AJ-25/ Euphrates formations in Fig. 5 a, b, and c, respectively, indicate that the Jeribe Formation has most of the values concentrated within the dolomite zone, and a few anhydrite nodules and thin slices of limestone.The Dhiban Formation has many points lying on limestone and dolomite rock with many anhydrite nodules, and the Euphrates Formation is similar to the Dhiban Formation but contains a smaller amount of anhydrite.Illustrated in Fig. 5. Thus, the type of rock affects the flow of fluids.However, fluids are expected to flow in rocks with low porosity in the presence of fractures (good permeability), and the primary rock in the reservoir is dolomite, which is characterized by many fractures.The presence of dolomite, limestone, anhydrite, and shale in a reservoir significantly impacts its quality and fluid flow behavior.A comprehensive comprehension of their characteristics and distribution is imperative for the efficient management of reservoirs.Dolomite and limestone typically have higher porosity and permeability than anhydrite, promoting efficient fluid flow and hydrocarbon production.
The M-N diagram shows that the Tertiary reservoir mainly consists of dolomite with secondary porosity.Furthermore, it indicates that the reservoir is a lithic mixture of anhydrite nodules and dolomitic limestone.

Shale Volume Determination
The evaluation of shale volume in well AJ-25 is depicted in Fig. 6 (a).The Jeribe Formation has a shale volume of about 18%.In contrast, the Dibane Formation has about 6% shale volume, while the Euphrates Formation includes about 9%.The histogram in Fig. 6 (b) illustrates the distribution of shale volume across all formations for the tertiary reservoir in well AJ-25.The data indicates that the mean volume of shale in the tertiary reservoir is roughly 10%.Gamma rays were preferred over other techniques because gamma rays are potent radiations that are explicitly designed for this purpose, and due to the low radioactivity of the formation rocks (dolomite, limestone and anhydrite), the naturally occurring radioactive elements in the shale formation were identified and counted.The Larionov equation was selected as the suitable model for categorizing tertiary rocks according to their geological age in the field of young rock classification.The study by Deable (2021), which was conducted on 12 wells, showed that the effective porosity of the Jeribe, Dhiban, and Euphrates formations is 24%, 18%, and 24%.Likewise, according to the study by Gharib and Ozkan (2022) on 48 samples taken from the Tertiary reservoir, the total porosity was 32%, and the effective porosity was 30%.These two studies confirm that the effective porosity is good in the tertiary reservoir.

Determination of Formation Water Resistivity (R w )
The Total Dissolved Solid (TDS) measurements at well AJ-25 in the Tertiary Reservoir produce a formation water sample for analysis.The laboratory report stated that the concentration of salinity, represented by NaCl, in well AJ-25, was 114,000 ppm.Equation (3) can be used to calculate the value of Rw at a temperature of 75°F, resulting in an approximate value of 0.066 Ω.m.The Rw value for each well is calculated using equation (4) with the downhole temperature Rw=0.041Ω.m.Mud filtrate (Rmf) values were obtained from the vertical reports of well logs and then corrected to downhole temperature using Eq.4 (Rmf = 0.0873 Ω.m) at depth (RTKB)=1178m.

Calculation of Archie's parameters (a, m, and n)
Archie's parameters (a, m, and n) for the tertiary reservoir were estimated using IP v. ( 2018) and were supplemented with the Pickett method.Figure 9 illustrates the correlation between effective porosity and actual formation resistivity for well AJ-25.The Archie parameters (a, and m) were obtained a b from the water zone.A linear trend can be derived by fitting a line through the log Rt values for the water-saturated zones, passing through the lowest possible values, and intersecting at (∅=1), declaring the intercept as (a × Rw=0.0514)where Rw=0.041, the inclination value denotes -m.The value of (n) can be found from the inclination value for the irreducible water saturation region (n-m), where m=1.82.2021) calculated the Archi parameters values to be a=1, m=1.72, and n=1.9.
The Computer Processed Interpretation (CPI) values for well AJ-25 are depicted in Fig. 11.The CPI findings from well AJ-25 showed that the highest proportion of movable hydrocarbons was effectively extracted from the optimal porosity zone in the Jeribe Formation of the Tertiary Reservoir.Furthermore, the presence of water was discernible within the Dhiban and Euphrates Formations.

Cutoffs of porosity and water saturation
The Tertiary Reservoir's porosity cutoff was determined through the utilization of the traditional permeability porosity cross plot from routine core analysis data.
The cross-sectional analysis revealed the plot of porosity at 1md permeability as shown in Fig. 12 (a), (b), and (c).The results showed a clear scattering around each fit curve.This can be attributed to the heterogeneity of carbonate formations, which are mixed of dolomite intercalated with argillaceous dolomite and locally anhydrite argillaceous (Jeribe Formation).After the best straight line was drawn in the point concentration area, using the Permeability cutoff value =1md gave more realistic results for porosity cutoff because the reservoir is a carbonate reservoir that contains oil.
The porosity cut-off for the Jeribe Formation is equivalent to approximately 10%, for Dhiban Formation is equivalent to 12%, and for the Euphrates Formation is equivalent to 10%.
A cross plot was created using the spatial core analysis data to compare the effective permeability ratio (Krw/Kro) with the water saturation (Sw) for six samples.The purpose was to determine the water saturation cutoff value, which is represented by the intersecting point of 1 value Krw/Kro with the average water saturation of the samples (Fig. 13 a and b).
The water saturation cutoff was ascertained by averaging the relative permeability values of six samples acquired through accessible special core analysis (Fig. 13.a) (Fig. 13.b).The water saturation cutoff average is 60%.

Net to Gross
The precise cutoffs were established utilizing the IP v.2018 application.The application produced the gross interval represented by the flag for the reservoir."Pay flag" is the designation given to the net productive interval.The reservoir interval and productive interval for well AJ-25 are depicted in Fig. 14.

Fig. 4 .
Fig.4.Computed thermal profile for well AJ-25 3.3.4.Evaluation of Fluid and Reservoir Formation• Determination of Formation Water Resistivity ( ) Equation (10) can be used to calculate the value of at a temperature of 75°F.Consequently, the Rw value for each well is computed by utilizing equation 11 with the bottom hole temperature (W75 : formation water resistivity (Ω.m) at 75 °F.R WFT : formation water resistivity (Ω.m) at formation temperature °F.CSP: NaCl concentration in ppm, ppm: Part per million.T F : Formation temperature °F.• Calculation of Archie's Parameters a, m, and n.Pickett (1973)  presented graphical solutions for Archie's equation, which can be used to quickly estimate water saturation or anticipate the parameters of Archie's equation, which are used in interpretation approaches(Krygowski & Cluff, 2012).(12)Where: S w : Water saturation (decimal).R t : Deep resistivity log (Ωm).Rw: Resistivity of the connate water (Ωm).m: Cementation exponent.a: Tortuosity factor.n: Saturation exponents.

Fig. 6 .
Fig.6.Shale volume for a specific formation in a tertiary reservoir in well AJ-25.(a) Well AJ-25's Shale volume log (b) Shale volume histograms

Fig. 7 Fig. 7 .
Fig.7 (a)  shows the primary, secondary, effective, and secondary porosity index (SPI) for well AJ-25.Certain intervals of the Tertiary reservoir show a relatively high proportion of secondary porosity.Fig.7(b) displays a graph representing the effective porosity of the Tertiary reservoir formations.The Jeribe Formation has an average effective porosity of 15.41%, the Dhiban Formation has an average effective porosity of 4.65%, and the Euphrates Formation has an average effective porosity of 9.85%.The average effective porosity of the Tertiary reservoir is 10.32%.The high value of secondary porosity indicates that the tertiary formations are fractured reservoirs, which makes the permeability good.

Fig. 13 .
Fig. 13.Water Saturation cutoff cross plot from core data of tertiary reservoir in Ajeel oilfield, (a)Jeribe Formation and (b) Euphrates Formation

Table 3 .
Archie parameter tertiary reservoir