The Methods of Determination of Stratigraphic Boundaries and Reservoir Units for the Yamama Formation in the Ratawi Oil Field, Southern Iraq

Abstract


Introduction
The Ratawi Oil Field is located in southern Iraq, 70 kilometrs west of Basra, 12 kilometrs south of Hor .The Yamama Formation is a heterogeneous reservoir that dates back to the Valanginian-Berriasian .It was deposited at the foot of megasequence Arabian Plate 8 (AP8) (Tithonian-Early Turonian) (Jassim and Goff, 2006).This time witnessed the occurrence of complications, including the occurrence of wide and overlapping facies variation.
The Yamama Formation is laminarly underlaid by the Sulaiy Formation with transitional contact, which contains limestone, hard recrystallized limestone, and argillaceous limestone with occasional interbeds of shale.The Ratawi Formation is confined on top by clay and limestone with a significant amount of shale; see Fig. 2.
There are 28 wells in the field, nine of which penetrate the Yamama Formation.The availability of borehole sensors was adopted to select these wells, which were distributed at the crest and flanks of the field; see Fig. 3. Eight wells were selected for the current study: .The petrophysical characteristics of carbonate rocks in many Iraqi oil reservoirs have been researched by a number of researchers (Al-Majid, 2019;Al-Jawad and Kreem, 2016;Abdulrahman et al., 2018;Mamaseni, 2020).Core data is critical for accurately determining the petrophysical characteristics and stratigraphic boundaries of geological formations and improving well log information (Al-Majid, 2021).So, current studies have tended to present the essential methods to determine the stratigraphic boundaries and reservoir units using an integrated strategy that incorporates all accessible data by using well logs, petrophysical properties, and petrographic characteristics that characterize these components within the sedimentary section of the formation.and then divide them The components are then divided into several primary and secondary facies depending on Flugel (1982).Then makeing a correlation section in N-S and E-W directions.

Materials and Methods
Preliminary information was compiled and consisted of reviewing wells and research, including internal reports, geological and reservoir studies, and the archives of the Iraq Ministry of Oil and its service companies, along with information from the Oil and Gas University.
Wire-line logs were collected that cover most of the excellent section for Yamama wells, which were selected because of the availability of open-hole logs for identifying each reservoir unit in the Yamama Formation, including gamma-ray log, calliper logs, the compensated neutron log (CNL), density log, sonic log, spontaneous potential log, and resistivity logs.These logs identify the formation tops and thickness and have also been used in stratigraphic correlation.These logs are also crucial for identifying the seal and reservoir units that return to the formation.
Detailed core examinations (plate 1) and thin sections were collected for facies analysis and divided into primary and secondary facies.The steps for sampling and making a thin section are listed below: • Describing the study samples through field observations.
• Modeling the study samples, photographing and describing the samples during collection, then storing them in special bags.• Making thin slides of the selected samples.
• Examining the thin slides under a microscope and obtaining a clear picture of each important slide using a special microscope.Applying software to obtain the following aspects: • Didger 3 software was used to read the values of all the open hole logs mentioned above with depth for each meter for the study area.Additionally, the software was used to draw many graphics and maps related to the study area.• Excel was used to calculate the petrophysical properties of the reservoir.
• ArcMap was used to draw many graphics and maps related to the study area.
• The Weka-3.6 software with Excel was used to determine the values of electrofacies for the study area to obtain the intervals of facies for the study area that had no core by open hole logs.
• The Petrel 2017 software was used as follows: Tabulate the results of the petrophysical and facies analyses and make a correlation between the studied wells.
Plate 1. Description of the study samples through eye observation in the field

Well Log Determination
A well log is a valuable tool for petroleum geologists.Log analysis is used to describe the porosity, lithology, and geometry of pores as well as permeability, which is frequently used to provide an estimated interpretation of oil reservoir levels (Asquith and Krygowski, 2004).So, the stratigraphic boundaries determination by well logs will be as below:

Spontaneous potential (SP) log
The upper seam (contact) boundary of the Yamama Formation with the Ratawi Formation was determined at the inflection point of the SP curve, which deflected to the left of the shale baseline after the SP curve was very close to the shale baseline at the lower boundary of the Ratawi Formation.In contrast, the lower seam (contact) boundary of the Yamama Formation with the Sulaiy Formation was determined at the inflection point of SP curve towards the shale baseline where its reading was close to zero in Sulaiy Formation.

Gamma ray log
The gamma-ray log can be used to determine the volume of shale.(Boddy and Smith, 2009).At the upper Yamama, the readings of gamma-ray decrease, while they increase when it enters the Sulaiy Formation.

Resistivity logs
At the upper seam (contact) boundary of the Yamama Formation, the readings of the true resistivity (Rt) and the shallow resistivity (Rxo) increased (i.e., high resistivities), while their readings decreased (i.e., low resistivities) at the lower seam (contact) boundary of the Yamama Formation.

Porosity logs
Porosity is defined as the ratio of a rock's pore volume to its bulk volume.Gas, oil, or water could be contained within the pore spaces of reservoir rocks (Awadh et al., 2018;Al-Baldawi, 2021).At both the upper and lower seam (contact) boundaries of the Yamama Formation, the values of porosity decreased.Whereas, we can notice the convergence of neutron and density logs at the beginning of the Yamama Formation after they were relatively far apart in the Ratawi Formation, which confirms that the upper boundary of the Yamama Formation begins with relatively clean and porous limestone rocks, depending on the readings of the acoustic log.
It should be noted that because the Yamama Formation is considered a complex formation from lithology and reservoir characterization, the results of the reservoir properties and lithofacies properties were used to determine the internal boundaries and the upper and lower boundaries of formation for the study area.Depending on the petrophysical and reservoir results, the formation was divided into three reservoir units (YA, YB, and YC) separated by two barrier units (C1, and C2).
The depth and thickness of the Yamama Formation and its top reservoir units were determined as indicated in Tables 1, 2, and 3, according to the above-mentioned log data, which were used to determine the stratigraphic boundaries of formation.

Petrophysical and Reservoir Properties
The present study depicted an interpretation of open hole logs responses such as Gamma-ray logs (GR), spontaneous potential logs (SP), and caliper logs were used for the correlation of depth and to determine the boundaries of the studied formation and identification of permeable zones, in addition to identifying the same lithofacies in the wells, which have a lack of core data with helping of porosity logs (density logs, neutron logs, and sonic logs) were used to calculate total and effective porosity after correcting its values at each point by knowing and calculating the ratio of shale volume (Vsh) to get more accurate results.
Resistivity logs were used to obtain water saturation.After obtaining water saturation, hydrocarbon saturation can be calculated.Then, permeable zone identified by using porosity and water saturation.To get more reliable results, these calculations were compared and corrected with core data, and thus will help to evaluate the reservoir units in the study wells of the Ratawi field.Calculating the petrophysical methods will be as below:

Porosity
It can be expressed as the ratio of the volume of voids to the total volume of the rock as a percentage and denoted by the Greek letter (Ф) (Asquith and Krygowski, 2004;Bowen, 2003), as shown in the following equation: (1) The equation above represents the total porosity (interconnected and isolated pores), measured by Neutron & Density logs.Porosity is an important rock property because it measures the potential storage volume for hydrocarbons or indicates the rock's ability to store fluids (Peters, 2008).

Permeability
It is the ability of a rock to transmit fluids (Asquith and Krygowski, 2004), or it is a measure of the rock`s ability to flow fluids (oil, gas, and water) (Maute, 2003).It is defined through Darcy's law (Peters, 2008).Permeability is important because it is a rock property related to the rate at which hydrocarbons can be recovered (Ahr and Wayne, 2008).Permeability can sometimes be estimated from log values.The permeability of a rock relies on its effective porosity, so it is affected by the rock grain shape, grain packing, sorting, grain size, and type of clay, cementation and degree of consolidation (Djebbar and Donaldson, 2004).Highly productive reservoirs commonly have permeability values in the millidarcy range (MD) (Lucia, 2007).

Saturation
Saturation (S) is defined as the ratio of the pore volume occupied by a fluid, typically water (Vw), oil(Vo), or gas (Vg), to the total pore volume of the reservoir rock (Vp) such that Ahr and Wayne (2008).
The water saturation represents the ratio of the volume of voids filled with formation water to the total volume of the rock voids, and it is measured as a percentage and denoted by the symbol Sw (Bowen, 2003;Asquith and Krygowski, 2004). (3) The water saturation of the invaded and uninvaded zone for wells of the study area was calculated according to the following two equations (Archie, 1942): (4) Rmf: resistivity of mud filtrate at formation temperature (.m), Corrected using plotters (Schlumberger, 1972).
n: the power of saturation and its value equal to (2) for limestone.
In this study, gamma-ray was used for correlation and estimate of shale content (Vsh), according to the following equation: Then, Shale Volume (Vsh) is calculated using the equation appropriate for the age of the studied rocks, which is represented in this case (the equation of the oldest solidified rocks in the Lower Cretaceous period) and according to (Dresser Atlas, 1979), as this is done by entering (IGR ) values that were previously calculated with this equation is, and as below: The results of the Shale Volume (Vsh) calculation showed an increase of 10% in most of the intervals depths of the study wells.
The porosity can be calculated if the matrix density and the liquid density within the pores are known using (Wyllie et al., 1958), which was used at the depths at which the ratio (Vsh) was less than (10%) (For clean depth intervals (Vsh≤0.1) in the study wells are as follows: (8) As for the depths in which the percentage of (Vsh) exceeded 10% (for dirty depth intervals (Vsh>0.1) in the wells of the study area, the equation (Dresser Atlas, 1979) was used to remove the effect of shale and correct it as follows: (9) Whereas: ФD: porosity calculated from the density log (density derived porosity).
In this study, the neutron log was used to measure porosity directly, but this porosity value must be corrected for periods in which the ratio of Vsh is greater than 10%.In (dirty intervals, the porosity corrected for shale effect) by using an equation (Tiab and Donaldson, 1996) and identifying the lithology by comparing it with the density log for the wells of the study area.The acoustic porosity is calculated using the equation (Wyllie et al., 1958) for the depths at which the percentage of (Vsh) was less than 10% (clean depth intervals) in the wells of the study area as follows: (11) As for the depths periods in which the percentage of Vsh exceeds 10%( dirty depth intervals), the time of transmission of the wave (∆t Log) within these periods is longer compared to the time of transmission of the wave to the clean depths that have the same amount of porosity according to (Al-Saadouni, 1988).The porosity in the presence of the shale effect will be as follows using (dresser Atlas equation, 1979):

Estimate of Shale Volume content (Vsh)
The estimation of this value is very important due to the effect of shale on the different log types of equipment.(Hilchie, 1978;Basseoni, 1994) indicated that the presence of an increase in the shale percentage over 10% of the total volume of the rock has a significant effect on the water saturation value and the calculated porosity from the log.The volume of shale can be calculated through several methods, including the gamma-ray log, the resistivity log, and the spontaneous potential log (SP).It is also derived from the cross plot of (Density-Sonic) (Neutron, Sonic) (Schumberger, 1970).In this study, the value of shale volume has been calculated from the gamma-ray log (GR), as in equation 5 to find the value of IGR and then equation 6 to find the value of Vsh.

Calculation of total and secondary porosity
After knowing the values of both the density and the neutron porosity, the total porosity, which represents the total porosity within the volume of the rock, is measured from the combined neutrondensity logs (Asquith and Krygowski, 2004), according to the following equation (Schlumberger, 1997): (13) Whereas: N.D: total porosity calculated from the density and neutron combined logs.
N: porosity calculated from the neutron log.D: porosity calculated from the density log (RHOB).
After calculating the total porosity and record acoustic porosity, the secondary porosity can be estimated using the equation (Schlumberger, 1997) as follows: (14) SPI: Secondary Porosity Index.
The above formulas for clean interval depths (Vsh less than 10%), while the dirty interval depths (Vsh more than 10%) should use the corrected porosity from shale volume for each one of them.The appendix shows ∅N.D, SPI values with depth for shale-corrected porosities (corrected from Vsh) (dirty interval depths) and for clean interval depths.

Calculation of water saturation and hydrocarbon saturation
Saturation is the proportion of the pore space filled with fluid (water or hydrocarbons) to the total rock volume (Schlumberger, 1987).The determination of saturation is one of a reservoir's most important petrophysical properties.There are many techniques to estimate this parameter, and some of them are based on indirect measurements by using logging devices.This study estimated water saturation in uninvaded and flashed zones using resistivity logs (Archie, 1942).
Whereas, in the current study, the water saturation of the study area wells was calculated for the invaded and uninvaded zones(Sw) for clean depth intervals (Vsh less than 10 %) by using equations 4 and 5 (Archie, 1942).
While, increasing the ratio of Shale Volume (Vsh) more than (10%) in the reservoir gives false values that are not real for water saturation, so in order for the values to be reasonable and true for water saturation, we must eliminate the effect of shale for the depth periods affected by it by correcting the values of (Sw).Which is worth noting is there are many equations to calculate this value if the ratio of Vsh is more than 10% ( dirty interval depths), and the most accurate ones by the oil industry will be as the following equation.The equation of Simandoux (1963) as follows: (15) of the permeability to the depths intervals that do not contain the permeability data from cores for the depths in the case of Swirr for the wells of the study area.

Petrophysical interpretation for Yamama formation reservoir (CPI)
Before entering an interpretation of the reservoir characteristics of each unit, it should be noted that ffective porosity values have been calculated and found its correspond to the values of the total corrected porosity (which includes the total porosity of the clean interval depths, i.e. those in which the ratio of Vsh is less than 10% plus the total corrected porosity from the effect of the shale volume of the dirty interval depths which are having Vsh more than 10% for all wells in the study area and for all units. The formation is divided into three reservoir units from top to bottom: YA at the top, YB in the middle, and YC at the bottom of the formation.The following is the petrophysical interpretation of the reservoir units of Yamama formation from top to bottom according to the arrangement and according to the location of each well of the study area in the Ratawi field: a. Petrophysical interpretation for reservoir unit -YA According to the locations of the distribution of the study wells in the Ratawi field.Whereas the wells are located near the center of the field (near crest); RT-3, RT-13, RT-14, and RT-15 have good reservoir characteristics at this unit where they have good hydrocarbon saturation (Sh), porosity, and permeability, but the ratio of shale volume (Vsh) increases at the bottom of YA unit.The reservoir characteristics worsen as we head towards the east of the field at the RT-4 well.It has a high water saturation rate, fair to poor porosity and almost negligible permeability of the Vsh ratio increases at the bottom of this unit for this well.
The reservoir properties improve towards the west of the field at well RT-6, where the ratio of hydrocarbon saturation, porosity and permeability is somewhat better than the reservoir characteristics in the east of the field, but the percentage of Vsh increases in the lower part of YA than the upper part of it.
As for the north of the field at RT-5, it has lower reservoir characteristics than it is in the wells located near the center of the field and has high water saturation and a high Vsh ratio in the lower part of this unit, while in the south of the field represented here by RT-7 well, it has poor reservoir characteristics and very high shale volume ratio in almost all of the unit compared to the ratio in the rest wells of the field for YA unit.
Accordingly, it can be said that the reservoir characteristics of the first reservoir unit, which YA is better near the center of the field and toward the west, and the characteristics deteriorate more we head towards the east of the field.
b. Petrophysical interpretation for reservoir unit -YB This reservoir unit (YB) can be considered to have the best petrophysical properties in the Yamama formation, whereas the wells are located near the center of the field (near crest); RT-14 and RT-15 have very good reservoir characteristics in this unit where they have very good hydrocarbon saturation (Sh), porosity, and permeability, low ratio of shale volume (Vsh) compared with YA unit.While RT-3 has fewer petrophysical properties than Rt-14 and RT-15, whereas the best characterization is Rt-14.RT-13 has the lowest ratio of petrophysical properties for the wells are located near the crest or center of the field, where it has lower hydrocarbon saturation (Sh) and a higher proportion of water saturation (Sw) with good porosity and less permeability compared with other wells near the crest, and the percentage of shale volume increases in the lower part of this unit; and this is evidence that Yamama formation was deposited during several small sedimentary cycles (multiple transgression-regression stages) associated by clastics and mud deposits that transported from the basin's adjacent positive areas and eventually caused to variation in petrophysical properties for the formation.
The reservoir characteristics worsen as we head toward the east of the field at RT-4 well, where it has a very high water saturation rate, poor porosity, and almost negligible permeability.The reservoir properties improve towards the west of the field at RT-6 well, where hydrocarbon saturation, porosity, and permeability ratio are very good.
As the north of the field at RT-5 has good reservoir characteristics in the upper part of this unit (YB), the properties become worse in the lower part with high water saturation and a high Vsh ratio in the lower part of this unit.
The south of the field represented here by the RT-7 well has very good reservoir characteristics compared with the YA unit ratio for this well.
As a summary of reservoir properties in this unit (YB), it can be said it is better near the center of the field and towards the southern part of it at RT-14, and RT-15, and toward the west at RT-6, while the deteriorate towards the north at RT-5 and the wells of the near center of the field toward the north at RT-13; while the properties become worse we head toward the east of the field at RT-4. c. Petrophysical interpretation for reservoir unit -YC For the petrophysical properties in Yamama formation of reservoir unit (YC), the wells are located near the center of the field (near Crest); RT-14 and RT-15 have good reservoir characteristics at this unit but less compared with the properties in the unit YB, where they have good hydrocarbon saturation (Sh), porosity, and permeability, low ratio of shale volume (Vsh).While RT-3 has good petrophysical properties but less compared with Rt-14, and RT-15, whereas the best characterization, is Rt-14.RT-13 has the lowest ratio of petrophysical properties for the wells located near the crest or center of the field, where it has good hydrocarbon saturation (Sh), porosity, and permeability just in the lower part of this unit (YC); this is because of the multiple transgression -regression stages of the Yamama Formation (the type of deposition during several small sedimentary cycles).
The reservoir characteristics worsen as we head towards the east of the field at the RT-4 well.It has a low hydrocarbon saturation rate and poor to almost negligible porosity and permeability.The reservoir properties towards the west of the field at RT-6 well as a low ratio of hydrocarbon saturation, and inadequate to almost little porosity and permeability, but in general, the properties of the west part of the field are better than the east part of the field.The north part of the field at RT-5 has terrible reservoir characteristics and a high Vsh ratio in this unit.The characteristics improved in the south part of the field represented here by RT-7 compared with the field's northern and eastern parts.
The summary for reservoir properties in this unit (YC) can be said to be better near the center of the field and towards the south part of it at RT-14, and RT-15, and in the south of the field at RT-7 and toward the west at RT-6, while the characteristics deteriorate towards the north at RT-5 and the wells of the near center of the field toward the north at RT-13; while the properties become worse we head toward the east of the field at RT-4.An example for petrophysical properties and their reservoir units as in Fig. 4.

The Yamama Formation lithological units
The Yamama Formation is characterized by porous limestone interspersed with thin layers of argillaceous and compact limestone.Some shale strata revert to barrier units.They end in dense, compact limestone with a shally layer in some wells and a uniform, gradient surface.The rarity and absence of fossils in the research wells set this limit.The lack of integrated core sections in the study area formation, the difficulty of studying cuttings due to challenges in obtaining particular or significant fossils compared to finer facies, the fear of mud contamination from drilling, and inaccuracies in determining model depths have made determining this limit by well logs onerous.To compare them with petrophysical parameters (porosity and permeability).The Yamama Formation was split into three primary reservoir rock units (YA, YB, and YC), C1, C2 as barrier units (Al-Siddiki, 1978;Folk, 1965;Folk, 1959); see Figs. 5 and 6.Each unit's lithology description is listed below: YA unit: This unit shows remarkable stability in thickness, as the average thicknesses were 118.00,126.87, 125.09, 116.93, 117.02, 124.00, 118.50 and 106.63 meters in Rt-3, Rt-4, Rt-5, Rt-6, Rt-7, RT-13, RT-14, and RT-15.An examination of two well cores (Rt-5 and Rt-7) showed that it consists of grey limestone exchanged with a thin area of light brown limestone that contains some stylolite and little oil steaming, as well as interspersed with some thin layers from shale and compacted limestone.
YB unit: This unit is considered one of the most critical units of the Yamama Formation in terms of reservoir properties, and the average thicknesses are 86.00, 87.80, 88.01, 83.27, 81.97, 84.00, 82.50, and 102.77meters in Rt-3, Rt-4, Rt-5, Rt-6, Rt-7, RT-13, RT-14, and RT-15.It can be divided into two parts, upper and lower: the upper part composed of light brown limestone contains a little bit of show oil, along with some stylolite lines, while the lower part has less important reservoir quality specifications than the previous one, as it is noted that the percentage of shale (Vsh) has increased more than the upper part within this unit.
C2 unit: Depending on the examination of the available core, this unit represents the second main insulating layer between the two reservoir units YB and YC, as it is composed of argillaceous limestone exchanged with layers of shale.The average thicknesses in 11.57,16.39,10.73,12.06,10.50,15.50,and 13.94 meters,respectively.YC unit: Consists of grey limestone containing some stylolite and some oil shows, and the average thicknesses in 65.38,76.00,67.36,73.97,53.92,64.58,and 46.04 meters,respectively.This formation lies between the Sulaiy Formation in the bottom withtransitional contact, containing argillaceous limestone with some shale, and the Ratawi Formation, bounded on top by clay and limestone with a high percentage of shale.
This means that the Yamama Formation is divided into three main lithofacies zones, the first representing rocks of wacky and pellet packstone and grainstone of limestone with good porosity and permeability at the lower parts of wells located on the crest of the field, the second representing a mix of packstone, oolitic, and peloidal grainstone of limestone with some intervals of wacky limestone deposits in the middle of the formation, whereas the third lithofacies deposits at the upper part of the formation represent a mix of oolitic and grained limestone and different kinds of wacky limestone, with some intervals of layers containing clay limestone in some wells towards the southern area of the field.

Petrographic constituents of microfacies
There are numerous limestone facies classes, each with distinct properties.In the current study, Dunham's categorization (Dunham, 1962) was used to classify the microfacies based on the sedimentary environment, rock texture, grain quality, and agglomeration.This categorization divides limestone rocks into two basic types: grain supported and mud supported.These petrographic components (grains, groundmass, or matrix) are described as follows: a. Matrix or groundmass The groundmass is one of the essential indicators of depositional energy intensity and is made up of micrite and sparite depending on the particle size (Folk, 1959).The groundmass in this investigation was micrite partially converted into microsparite by cementation or neomorphism.Micrite is the substance that fills the gaps and compartments of fossils.In some research regions, the micrite partially transformed into sparite, leaving pores within the ground as a result of exposure to dissolving processes.Dolomitization altered the groundmass, as seen in the Yamama Formation rocks by the diffusion of rhomboid dolomite crystals in some microfacies.b.Grains Grains are particles that are precipitated mechanically and originate before sedimentation or through it.Grains in carbonate (limestone) rocks divide into two types: skeletal grains and nonskeletal grains (Flugel, 1982).The following is a review of the essential grain constituents observed in the limestone of the Yamama Formation.

• Skeletal grains
It was found by examining the thin sections that the wells in the Yamama Formation contained a percentage of skeletal grains, which include calcareous algae, some larger benthonic foraminifera such as Everticyclamina eccentric and Pseudocyclammina littus, some smaller benthonic foraminifera such as Cyclammina greige, Nautiloculina Politica, and Trocholina Alpina, echinoids, and a few sponge spicules and molluscs, which can distinguish the study area by containing an abundance of these skeletal grains.

• Nonskeletal grains
The nonskeletal grains that were distinguished in the facies of the study area were represented by oolites, pseudoolites, and peloids, and some pellets were also observed very rarely.

The Microfacies Analysis
Many studies have used different definitions of microfacies, but Flugel (2004) used a simplified and straightforward definition, which is the sum of sedimentary and fossil features that may be defined and classified through the thin section.According to Kendall (2007), sedimentary deposits' textural, structural, and compositional features result from deposition and change in a specific sedimentary environment (Kendall, 2007).More than 250 thin sections of the Yamama Formation were studied in three Ratawi oilfield wells Rt-3, Rt-5, and Rt-7 from north to south.The facies for the intervals that do not have cores was electrofacies utilizing well logs (GR, ∅N, RHOB, ∆t, and SP); thus, seven types of main microfacies were identified based on the existence of grains to the groundmass, and the critical diagenesis effect on those rocks was defined based on Dunham (1962).Secondary microfacies (submicrofacies) are defined by the fossils and grains that indicate the sedimentary settings.The microfacies were compared to Wilson standard microfacies (SMF) (Wilson, 1975) and the environment to environmental facies zones (EFZs) (Flugel, 1982).
a. Lime mudstone main microfacies At the base of the micritic facies, (Dunham, 1962) classified lime mudstone as a form of limestone whose primary structure is composed of microcrystalline calcite, which corresponds to the name (micrite) coined by (Folk ,1965).This facies was affected by many diagenesis processes, mainly dolomitization and recrystallization, followed by compaction, micritization, dissolution, and plate formation (2-1, 2-2, and 2-3).c.Wackestone main microfacies These major facies are found in several of the current study wells.The skeletal grains found are benthonic foraminifera, echinoids, mollusca, and algae.Peloids and some bioclastic detritus are nonskeletal grains.These principal facies have been impacted by diagenesis processes such as dissolution, micritization, compaction, dolomitization, and cementation to varying degrees, depending on the environmental circumstances at the time of sedimentation.Porosity decreased at some depth intervals due to cementation and void filling; see Plates (2-5, 2-6, 3-1 and 3-2 d.Wackestonepackstone main microfacies This main facies is characterized by an increase in the percentage of skeletal grains, and it consists of bioclastic algae debris with a small percentage of mollusc shells and echinodermata, very little coral debris, and some benthonic foraminifera pieces such as miliolipids, where the percentage of grains in this main facies ranges from 40-70% compared to groundmass.Grains appeared in different parts of the study formation and at different rates from one well to another; see Plate (3-3).
e. Packstone main microfacies These main microfacies are characterized by a granular ratio of 70-90% represented by peloidal, pseudoolitic, oolitic, some pellets, and some different kinds of bioclastic debris and fragments within micrite groundmass.They were wholly or partially transformed into microsparite or pseudosparite by neomorphism process compartments of some fossils, voids, and solution microchannels filled with spary cement by dissolution and cementation processes.The dolomitization process also affects them, consisting of acceptable to medium-sized rhomboid crystals distributed in different ways from one well to another within the groundmass of these main facies.This main facies appeared in most of the study wells and in all parts of the formation.It varies from one well to another and is divided according to the type of granules prevailing in them; see Plates (3-4, 3-5 and 3-6).
f. Peloidal packstonegrainstone main microfacies These main facies consists of a clear overlap between peloidal packstone microfacies, along with some benthonic foraminifera and echinoids, and grainstone microfacies.This main facies is characterized by the abundance of grains in terms of quantity and size.They may reach the size of small pebbles with sculpted edges (abraded) due to the high energy for the sedimentation environment with a percentage of micrite groundmass remaining.It was noted that it was affected by the washing process, or dissolution, consisting of vuggy, mouldic, and intergranular porosity.However, the cementation process led to the filling of voids and reduced the percentage of porosity.For the dolomitization process, its effect is small, as dolomite appears in a small percentage in this main facies.These main facies can be located between a biostrome environment or the so-called shallow barrier environment.Additionally, an open shallow lagoon environment is roughly part of the standard facies (SMF-15) of the facies zone (FZ-6) and the standard facies (SMF-17) from the facies zone (FZ-8) according to Wilson (1975) for standard facies; see Plate (4-1).g.Grainstone main microfacies In total, skeletal grains and nonskeletal grains make up more than 90% of the basic structure of these main facies, along with less than 10% of the groundmass, which is often composed of microsparite or pseudosparite.These main facies are affected by different diagenesis processes, such as cementation, neomorphism, and the dolomitization process; see Plates (4-2 and 4-3).

Discussion
The Yamama Formation was divided into three central reservoir units (YA, YB, and YC) and two central barrier units (C1 and C2).The boundary of the contact between the upper and lower Yamama Formation of the Ratawi field was redefined using well logs, facies, and petrophysical data.Thus, the various reservoir data and new limits were given according to the data of the previous results, and these limits came very close to the results obtained from the studies of the oil service company (JOGMEC, 2010;Shell, 2006).
Those at noncore depths could be monitored by matching them with their corresponding well logs to obtain their electrofacies.The main facies were distinguished depending on whether they were grain supported or mud supported and on the appearance of the configuration facies through microscopy and after comparison.

Conclusions
The lower and upper boundaries of the Yamama Formation in the Ratawi Field, as well as the internal boundaries, have been redefined using well log data, facies data, and various reservoir data, and new limits were given according to the results mentioned earlier.
Seven primary facies and several subsidiary facies were found, deposited in various settings and modified by diagenesis.Facies at noncore depths could be checked by comparing them to their well logs.After comparing the microscopy results with the well logs, the following main limestone facies were identified: mudstone, mudstone-wackestone, wackestone, wackestone-packstone, packstone, packstone-grainstone, and grainstone facies.

Fig. 2 .
Fig. 2. The generalized stratigraphic columnar section observed in the study area (generalized by using Didger 3 software)

Fig. 3 .
Fig. 3. Contour map of the top of YB of the formation and distribution of studied wells of flow A = the cross-sectional area of the sample.K = permeability ΔP / L = the potential drop across a horizontal sample μ = fluid viscosity saturation of uninvaded range (percent).F: formation resistivity factor.Rw: resistivity of the formation water (.m).Rt: the true resistivity of the formation (resistivity of the uninvaded zone) (.m).
ray index GRlog = gamma ray reading of formation GRmin = minimum gamma ray (clean sand or carbonate) GRmax = maximum gamma ray (shale) The porosity of the neutron log is corrected by the shale effect (Shale-corrected density porosity).ØNsh = neutron porosity of nearby shale Vsh = shale volume.
-derived porosity.Øscorr.= The porosity calculated from the acoustic log corrected from the shale effect (μsec/ft) (Shalecorrected sonic porosity).Δtlog = the interval transit time in the formation measured by the log (μsec/ft).Δt ma = the interval transit time in the rock matrix (47.6 μsec/ft for limestone, 43.5 μsec/ft for dolomite, 55.5 μsec/ft for sandstone).Δtf = the interval transit time through the fluid (189, 185 μsec/ft) for fresh and salty fluids, respectively.Δtsh = the interval transit time in nearby shale.

Table 1 .
The thicknesses and stratigraphic boundaries of the Yamama Formation units in the study area according to the current study

Table 2 .
The thicknesses and stratigraphic boundaries of the Yamama formation units in the study area according toShell company study (2006)

Table 3 .
shows The thicknesses and stratigraphic boundaries of Yamama formation units in the study area according to JOGMEC company study(2010)