Studying the Statistical and Petrophysical of the Mishrif Formation in the Nasiriya Oilfield, Southern Iraq

Abstract


Introduction
The Nasiriya Oil-field is located in Dhi Qar Governorate, approximately 38 km northwest of Nasiriya City (Fig. 1), between latitude 61ᵒ 10´-57ᵒ 50´ and longitude 34ᵒ 80´-34ᵒ 60´.The Nasiriya Oilfield located at the stable platform Mesopotamian zone (Jassem and Goff, 2006).The Mushrif Formation deposited during the Cretaceous Period, is one of the important geological formations containing oil in southern Iraq and it represents the second formation from the economic aspect after the Zubair Formation in southern Iraq (Aqrawi et al., 1998).It is considered a major hydrocarbon reservoir in some fields (Awadeesian et al., 2018).The Mishrif Formation contains about 30% of Iraq's total oil reserves (Abdula, 2020).

Geological Setting
The Mishrif Formation is one of the formations of the Early Cenomanian -Late Turonian sedimentary cycle within the Megasequence AP8 (Late Tithonian -Early Turonian) (Jassim and Goff, 2006).The Mishrif Formation consists of carbonate rocks deposited in shallow marine environments.
The thickness of the formation in southern Iraq ranges between 150-200 m, as it increases towards the Iraqi-Iranian border until the thickness of the formation reaches more than 350 m.Its thickness in the study area is between 150-180 m.The stratigraphic seals in Nasiriya Oil-field are based on lithostratigraphic sections Bellen et al. (1959Bellen et al. ( -2005)), as illustrated in Fig. 2.

Materials and Methods
In this study, seven wells were selected in the Nasiriya Oil-field in southern Iraq , as shown in the Table .1 and the Fig. 3.The statistical analysis of the study wells was conducted by drawing a histogram of gamma-ray, density and neutron log for each of the wells using the Minitab program and representation of the relationships between logs, it is called qualitative interpretation.
Then the petrophysical properties were calculated using the Excel software and represented using the Techlog software Fig. 5, it is called the quantitative interpretation.Later, the reservoir heterogeneity was calculated using the Dykstra parson index.

Qualitative Interpretation
The qualitative interpretation was performed in two different ways: first, by the relationships between Rt & NPHI, second by drawing a statistical histogram of the GR, NPHI, RHOB logs for each well of the study wells to identify the best well in terms of shale content and porosity, the purpose of construction of histograms is to evaluate the petrophysical characteristics (Shale Volume and Porosity) of the wells (Figs. 6,7,8).Through the relationship between the neutron log NPHI and resistivity log RT, that the wells indicate that they contain of water saturation more than the hydrocarbon saturation, except for the well Ns-6, as shown in the Fig. 4.
Through the neutron and density logs, preceive that the correspondence of the density log with the porosity ØN is evidence of the presence of limestone.While positive separation, an increase in the value of the density log with porosity ØN, is evidence of the presence of shale, as explained in Fig. 5. Through the statistical histogram charts, it was found that the value of the GR log for the study wells at most depths is less than 20 or 30 API indicates clean limestone, some depths are between 30 -70 API indicates dirty limestone and depths is more than 70 API indicates shale (Fig. 6).
Based on the reading of the logs for the wells, determined the depths and thicknesses of the Mishrif Formation in the Nasiriya field (Table 2).
The total porosity or effective porosity was calculated by equation 8 in clean zones and equation 9 in shale zones (Schlumberger, 1997).

Reservoir units of Mishrif Formation
It was observed that the lithology of the Mishrif Formation in the Nasiriya oil field consists, in general, of clean limestone characterized by low gamma ray log response (Ali et al., 2022), and it was compared with the reading of the logs and the results of the petrophysical calculations, and on its basis the Mishrif Formation was divided into: • MA Unit (Upper Mishrif) : This part consists of granular carbonate and chalky carbonate rocks , and the rocks of this part are characterized by high porosity ranging between 0.13 and 0.20, The thickness of this part ranges between 58.2 m and 73.5 m, as shown in the Table .3. It does not contain oil due to the very fine grained nature of its rocks (Exploration, 1989).• MB Unit (Lower Mishrif): It is an important reservoir part of the Mishrif Formation because it contains granular limstone rocks, which are considered good reservoir rocks.This type of rock is characterized by high porosity.This part is divided into two subunits, MB1 and MB2: • MB1 subunit: It is characterized by good reservoir specifications, its thickness ranges between 12.1 m and 28.7 m, and increases towards the well Ns-14 due to an improvement in porosity as shown in Table .4.   9 showed that the effective porosity values of the Mushrif Formation ranged from good to excellent and the primary porosity was equal in all wells of the study.Due to the low influence of diagenesis processes on the formation, such as dolomitization and dissolution, the secondary porosity was observed in the study wells as low or non-existent at some depths.The movable oil saturation and the residual oil saturation were calculated for the study wells, as it was noted in the well Ns-15, Ns-16 and Ns-20 that a percentage of the residual oil saturation higher than the movable oil saturation and this indicates that the permeability is low.As for the wells Ns-6, Ns-8 and Ns-9 the movable oil saturation is higher than the residual oil saturation and this is evidence of a low permeability.As for the well Ns-14 some depths have high permeability and some depths have low permeability.

Pore Throat Radius (R35)
It can be used to support the flow unit data base as it directly comes from capillary pressure tests or is estimated from log readings (Martin et al., 1997;Gunter et al., 1997).It describes the diameter of the pore throat radius at mercury saturation 35.They discussed about the value of and method for supporting reservoir flow units using R-35.It directly calculates R-35 using Winland's equation (Kolodzie, 1980): Table 7. Classification of porous systems (Pittman, 1992).

Pore Type
Size range (µ) Mega >10 Macro 2-10 Meso 0.5-2 Micro 0.1-0.5 Nano <0.1 R35 was calculated for the MB1 and MB2 reservoir subunits for the formation of the Lower Mishrif for all the wells of the study area through the porosity and permeability that were calculated using the data of the logs, it was discovered to have very large to medium (22.3-1.7 µ) sized pores.

Permeability Calculation
The ability of a porous medium to transmit fluids is indicated by its permeability (Peters, 2006).A rock's permeability is determined by its effective porosity, which is affected by the grain size, grain shape, grain sorting, cementation, degree of consolidation, shale content, and other characteristics of the rock (Tiab and Donaldson, 2011), the equation of Willie et al.'s (1958) to calculate the permeability: K=[ * (∅  /)]  , (17) Where: K = permeability (mD), C = constant, its value equal 250 for medium oil and 79 for dry gas, Ø = porosity, Swirr = irreducible water saturation.

Dykstra Parson Coefficient Vk
Permeability heterogeneity was quantified using Coefficient of Permeability Variation of Dykstra and Parsons (1950) as explained by Jensen et al. (2000).The Dykstra-Parsons Coefficient is an excellent tool for characterizing the degree of reservoir heterogeneity.The term Vk is also called the Reservoir Heterogeneity Index (RHI).A log probability graph with the cumulative probability values shown in Fig. 10, the initial permeability values are displayed.The 50th and 84th probability percentiles are then determined from this plot's slope and intercept, which are used in equation to derive Vk for all data.The Dykstra Parsons Coefficient has the following definitions.The Dykstra-Parsons coefficient ranges from a minimum of 0 (homogeneous) to a maximum of 1.0 (heterogeneous).Abbas and Mahdi (2020) mentioned that the petrophysical heterogeneity of the reservoir units within the Mishrif Formation is due to variations in porosity, water saturation and fluid volume.50: Permeability value at the 50 percentile, K84.1: Permeability value at the 84.1 percentile.The heterogeneity in the reservoir was determined for the extension of the unit MB1 and MB2 for the wells of the study as shown in the Fig. 10.The results showed that the value of the cofficient of the unit extension MB1 is 0.57 for the study wells and the value of the coefficient of the unit MB2 is 0.64.That is, the lateral extension of the reservoir units of the study wells are heterogeneous.

Lorenz coefficient Lk
The cumulative storage capacity and the cumulative flow capacity are used to calculate Lk, a statistical measure of heterogeneity (Handhal et al., 2019).The distribution of reservoir permeability is homogeneous if LK=0, but the distribution of reservoir permeability is heterogeneous if LK = 1 (Tiab and Donaldson, 2015).Homogeneous wells for Lk< 0.5 obtained a 0 code, whereas heterogeneous wells for Lk > 0.5 obtained a 1 code.

Conclusions
The Mishrif Formation in the Nasiriya oil field is mainly composed of clean limstone, dirty and a few percentage of shale in all study wells, which was determined using well logs.It was possible to divide the Mushrif Formation into two units (MA and MB) using CPI through various petrophysical properties such as shale valume , effective porosity, water saturation and hydrocarbon saturation, the upper MA and lower MB, separated by insulating shale rocks, based on the gamma ray log, the lower unit MB was divided into two reservoir units MB1 and MB2.The wells indicate that they contain of water saturation more than the hydrocarbon saturation, except for the well Ns-6.Using the data of the logs and R35 calculated, it was discovered to have very large to medium (22.3-1.7µ)sized pores.The results showed that the value of the Dykstra-Parsons cofficient of the unit extension MB1 is 0.57 for the study wells and the value of the coefficient of the unit MB2 is 0.64, and the value of the Lorenz coefficient for (Ns-6, Ns-8, Ns-14, Ns-15 and Ns-20) wells had a heterogeneous distribution, while (Ns-9 and Ns-16) wells had a homogeneous distribution.

Fig. 3 .
Fig.3.Structure contour map of the location of the study wells of Mishrif Formation in Nasiriya Oilfield

Fig. 9 .
Fig.9.(a) It explains the petrophysical result of the study well Ns-6; (b) It explains the petrophysical result of the study well Ns-16

Fig. 10 .
Fig.10.(a) The Dykstra-Parson Coefficient of Permeability Variation (mD) for reservoir unit MB1 of the study wells; (b) The Dykstra-Parson Coefficient of Permeability Variation (mD) for reservoir unit MB2 of the wells

Table 1 .
The depths and coordinates of the study area wells

Table 2 .
The top and thickness for the reservoir units of the study area wells.

Table 3 .
The petrophysical results of the reservoir unit (MA)

Table 4 .
The petrophysical results of the reservoir unit (MB1) • MB2 subunit : This unit has good reservoir specifications in Nasiriya Oilfield wells.It is divided into two reservoir zones: 1) a reservoir zone of high hydrocarbon saturation MB2.1 (Al-Zubaidi et

Table 8 .
The values of each R35, K and Ø of the wells of the Nasiriya Oilfield

Table 9 .
The value of Dykstra-Parsons Coefficient in reservoir units of the study wells

Table 10 .
The value of Lorenz Coefficient Lk for the study wells