Net-pay Thickness Research Articles

تقدير السمك المساهم في الإنتاج بإستخدام طريقه جنسن ـ منك الآحصائيه في حساب القيمة الفاصلة: دراسة تطبيقيه عن الحجر الرملي الجلايكونيت في حقل بلاكفوت، البرتا، كندا

Cut-offs are required to exclude the reservoir portion that does not contribute significantly to evaluating hydrocarbon in situ or reserve estimation. There is no universally accepted set of definitions, but it is necessary to have a firm grasp on the fundamental terms and expressions used in volumetric analysis employing core, well-log data. Oil and gas are trapped in the Blackfoot Field's multiple fluvial and valley-fill reservoirs of the Glauconitic sandstone. Two wells, A-08-023-23W4 and B-08-023-23W4, were chosen to quantify parameters needed to estimate net pay thickness (NPT) and net-to-gross ratio from the cores data in both wells. Understanding charts, which show how average parameters change with a cut-off value, are used to determine the final cut-off. Using the statistical criterion for the assessed wells, an appropriate porosity limit for the net-to-gross ratio (NTG) estimate is being sought. A perspective on choosing porosity cut-off values from a statistical and core data perspective is provided. The cores used in this investigation were analyzed for permeability and porosity under controlled laboratory settings. It is possible to make inaccurate predictions when using least-squares regression to determine porosity (or permeability) cut-off values. Using a probabilistic method, Jensen and Menke assessed the precision and inaccuracy of various porosity cut-off values. To accomplish this, the line indicating the porosity cut-off values (Øc) was fine-tuned to minimize error and produce the most precise estimate possible. In this case study, we apply the tasks of estimating different porosity cut-off values to identify NPT and NTG and reduce the errors. A-8-23-23W4's Øc is 0.3 porosity unit (pu) off the best estimate ØBE values when using the least squares regression line fitted to the porosity and permeability, and the regression line cut-off errors are 2.7% higher. ØBE matches the least squares regression's NPT cut-off values for well B-8-23-23W4. The least regression line has a lower error rate than the best estimate for NTG, which is a 2.1 pu difference. According to the results, the NTG for well A-8-23-23W4 and well B-8-23-23W4 are predicted to be 0.9 and 0.8, respectively. The application of the Jensen and Menke statistical cut-off is contingent upon the reservoir type, and the optimal statistical method for assessing net pay should be combined with all relevant data and analyzed by geologists and engineers. Key Words: Glauconitic sandstone, core data, Porosity cut-off, least square regression, Net pay thickness.

Integrated seismic, petrophysical, and geochemical studies for evaluating the petroleum system of the Upper Bahariya-Abu Roash G sequence in the Karama Field, Abu Gharadig Basin, North Western Desert, Egypt

The main aim of this study is to delineate the hydrocarbon potential and evaluate the petroleum system elements of the Cenomanian Abu Roash G (AR/G) and the Upper Bahariya Members in the Karama Field. It lies at the southeast borders of the Abu Gharadig Basin, a well-known basin in the W.D. to the NE of Africa. We accomplish this study by analyzing a total of thirty 2D seismic profiles, a complete data set of well logs for five wells, and their geochemical data. The workflow starts with illustrating the dominant subsurface structural features, defining the main potential reservoirs and their parameters, and checking the maturity of the probable source rocks. The seismic interpretation indicated that the research area had been influenced by a NE-SW anticlinal structure accompanied by a set of WNW-ESE and NW-SE normal faults that are controlled by the positive compression inversion process that dominated during the Late Cretaceous. Analyzing and processing the well log data sets suggest that the reservoirs of the Abu Roash G (AR/G) and the Upper Bahariya Members are characterized by poor to good reservoir settings with net-pay thickness reaching up to 13–50 feet in the different wells (av. Effective porosity (∅eff) = 17.7 % and 15.6% for the AR/G and the Upper Bahariya Members, av. Shale volume (Vsh) = 17.4 % and 13.6 %, av. Water saturation (Sw) = 38.9 % and 39.8 %, while av. Hydrocarbon saturation values (So) = 60.2 % and 61.1%, respectively). The geochemical and maturity analyses assisted in determining the potential mature source rocks of the Jurassic Khatatba Shale (TOC = 0.70–5.67%; S1+S2 = 0.43–5.97 mg/g, Ro = 0.54–1.06 %) with some contribution from the Cretaceous sources (Alam El-Bueib and Bahariya Formations). Studying elements of the petroleum regime of the Karama Field indicates that the trapped hydrocarbons are structurally controlled by three-way dip closures, horst blocks, sealing faults, and vertical sealing by impervious shale and limestone beds. This case study could be applied to similar analogs in other oil fields in the Egyptian Western Desert to delineate their hydrocarbon potential and structural setting.

Structural assessment and petrophysical evaluation of the pre-Cenomanian Nubian sandstone in the October Oil Field, central Gulf of Suez, Egypt

The low quality of the seismic resolution of the studied Cambrian Pre-Cenomanian formations, which rest directly on the basement in the October Field in the Gulf of Suez, requires study, and the structure pattern controlling these formations is uncertain. The poor quality of the seismic data resolution in the Gulf of Suez is due to the presence of thick sequences of evaporites represented by the South Gharib and Zeit formations. Therefore, the current study used seismic reflection data integrated with well-log data to define the structural-stratigraphic setting of the pre-Cretaceous Nubian reservoir sequence. The study aims at locating and delineating zones having excellent reservoir potential within the Nubian sequence horizons (Nubian Transition, main Nubian, Nubian marker-1, and Nubia marker-2, referred to as NT, MN, M1 and M2, respectively) through the integration of the 3D static modelling and the petrophysical parameters deduced from the well-log data processing. A detailed petrophysical analysis, based on the wireline logs of some wells, was performed to determine the lithological units using two types of cross plots (Neutron-Density and M-N plots), and the different petrophysical parameters that characterize the various Nubian horizons were also computed. 3D modelling was used to visualise the lateral and vertical changes of the reservoir characteristics. The seismic mapping reveals that the Nubian structure is controlled by an NW-SE trending (Clysmic trend) of an NE-plunging asymmetrical anticlinal feature unconformably resting on a basement horst. The main structure is affected by two major normal faults, which trend NW, andis cut by two smaller sub-parallel faults that disturb the core of the structure, which is unaffected by the easterly oriented faults of the Aqaba trend. The petrophysical analyses indicate that the Nubian sandstones have intervals of good reservoir quality, with a total net-pay thickness of about 500 m, net sand ratios (60–90 %), effective porosity (10–25 %), and hydrocarbon saturation (85%), which may encourage further drilling, especially in the southeast portion. The result of this study can be extended to the other Nubia sandstones resting on the basement complex in the Gulf of Suez.

Właściwości złoża jurajskiej formacji Khatatba: Pole naftowe Tut, Pustynia Północno-Zachodnia, Egipt

The Tut oil field is in the North-western part of the Western Desert. This work aims to study the reservoir characteristics, to evaluate the hydrocarbon potentiality of the Upper and Lower Safa Members based on the available subsurface data obtained from open-hole well log records of four wells distributed in the study area. Numerous isopach and lithofacies maps have been constructed. The petrophysical evaluation, in terms of determining reservoir net-pay thickness, shale content (Vsh), effective porosity (∅eff), water saturation (Sw) and hydrocarbon saturation (Sh), were estimated. The vertical and the lateral distribution of the reservoir characteristics, in the form of litho-saturation cross-plots, iso-parametric maps and lithologic-matrix cross-plots were constructed. Three hydrocarbon charged zones in the Khatatba Formation were defined and represented by the Upper Safa-Top, Upper Safa-Bottom and Lower Safa-Top. The upper most part of Upper Safa Member (Upper Safa-Top) reservoir represents an oil producing zone where it consists of shallow marine to alluvial sediments. The Lower most part of Upper Safa Member (Upper Safa-Bottom) reservoir represents gas producing zone where it consists of a thick alluvial sand body. Finally, the upper most part of Lower Safa Member (Lower Safa-Top) reservoir represents an oil-gas producing zone consisting of shallow marine sediments with high terrestrial input. The iso-parametric maps show that Northern and central parts of the study area are the most favorable parts for hydrocarbon accumulation due to the increase in net-pay thickness and average effective porosity and decrease in water saturation toward these parts.

Seismic interpretation and sequence stratigraphic analysis of the Bahariya Formation in the South Umbaraka oilfields (Western Desert, Egypt): insights into reservoir distribution, architecture, and evaluation

The integration of multiscale datasets, including seismic, well-logs and stratigraphy, is providing a precise picture about reservoir evaluation and spatial distribution. This study focuses on the seismic interpretation and sequence stratigraphic analysis of the Bahariya Formation in the South Umbaraka oilfields (Selkit, Khepri, and Sethos), located in the Western Desert of Egypt. Seismic interpretations reveal various structural closures, including anticlinal domes and faulted anticlines in different fields. The study area is divided into northern and southern blocks separated by a major fault, and structural cross sections provide valuable information on reservoir zones regarding lateral extension, thickness variation, and fault distribution. The Bahariya Formation is subdivided into two depositional sequences: Lower Bahariya sequence (BAH.SQ-1) and Upper Bahariya sequence (BAH.SQ-2) with distinct wireline-log characteristics, seismic reflections, and lithofacies variations. BAH.SQ-1 comprises mixed siliciclastic-dominated units with some carbonate units, while BAH.SQ-2 consists of mixed siliciclastic and carbonate units. Multiple sequence boundaries, depositional surfaces, and systems tracts are identified within BAH.SQ-1 and BAH.SQ-2, indicating changes in sedimentary environments and sea-level fluctuations. The petrophysical evaluation reveals promising reservoir zones in both the Lower and Upper Bahariya sequences. However, the Lower Bahariya sequence exhibits superior reservoir characteristics in terms of net-pay thickness, shale volume, effective porosity, and water saturation. Particularly, the sandstone-dominated LST-1 within the Lower Bahariya Formation is identified as a favorable reservoir zone. Conversely, the Upper Bahariya Formation has limited reservoir potential. This study underscores the significance of sequence stratigraphy and reservoir architecture, emphasizing the role of faulting, folding, and depositional environments in the distribution and quality of reservoir zones. The findings contribute valuable insights into the structural and stratigraphic characteristics of the Bahariya Formation, enhancing understanding of hydrocarbon plays and reservoir distribution in the studied area.

Implication of the micro- and lithofacies types on the quality of a gas-bearing deltaic reservoir in the Nile Delta, Egypt

The Messinian Qawasim sequence, as one of the most important reservoirs in the Egyptian Nile Delta, represents a typical gas-bearing deltaic reservoir sequence. It aims at delineating the implication of the litho- and microfacies associations on the reservoir characteristics of the different stages of the fluvial deltas including the prodelta, proximal/distal delta front, and the delta plain depositional sequences. The studied reservoir sequence was divided into two units; upper and lower clastic units. The petrophysical properties of these two units were studied on the borehole scale using the gamma-ray, caliper, sonic, density, neutron, and resistivity logs to estimate the reservoir parameters including the total and effective porosities, water saturation, shale volume, and the net-pay thickness. For more details, they are also examined on the plug-scale using the core dataset including helium porosity, density, permeability, and fluids saturations, where the flow zone indicator, the reservoir potentiality index, the reservoir quality index, and the average reservoir pore radius were then estimated. The entire sequence is divided into five reservoir rock types (RRT1-RRT5) where, the best quality is assigned to the first RRT (the upper reservoir unit), and the lowest quality is assigned to the RRT5 of the lower reservoir unit. Based on core description and the petrographical studies five lithofacies and four microfacies have been identified. The lithofacies are (1) laminated mudstones/siltstones, (2) ripple laminated sandstones, (3) cross-laminated sandstones, (4) cross-bedded sandstones, and (5) pebbly massive sandstones. These lithofacies are primarily composed of four microfacies; sublithic arenites, subarkose arenite, glauconitic quartz wacke, and sandy mudstone/siltstone. Based on this study, the pebbly massive and the cross-bedded sandstones of the upper unit which is composed of the sublithic and subarkose arenites (RRT1-RRT2) have the best reservoir quality. On the other hand, the lowest quality is assigned to the RRT5 (sandy mudstone/siltstone microfacies) which is represented on the macro scale by the laminated mudstones/siltstones lithofacies. The integration between multi-scale datasets (core-well, petrography, well logs, and seismic) gives a precise picture of the deltaic Qawasim reservoir rock units in the Nile Delta. This workflow has never been applied to the deltaic system in the onshore Nile delta and North Africa. Thereby, this study is considered a standard case study for the deltaic sequences and its proposed workflow is applicable to the Nile Delta elsewhere and worldwide for similar reservoir sequences.

A new hydrocarbon prospect determination using the seismic interpretation and petrophysical evaluation of Bahariya reservoir in Nader field, north Western Desert, Egypt

The goal of this research is to assess the hydrocarbon potential of Bahariya reservoirs in Nader Field of Khalda Ridge concession in the northern part of Western Desert, which had never been addressed before. This study is based on using a complete set of well-logs of four wells and twenty 2D seismic lines, where both the Upper and Lower Bahariya members were evaluated as hydrocarbon-bearing sandstone reservoirs in the Nader Field. Seismic interpretations were used to clarify the structural settings of the tops of these members. These members' time-and-depth-structure maps reveal a variety of structural features which aid in hydrocarbon prospect identification in the area. The interpretation of the depth structure contour maps clearly defines NW-SE fault trend. The petrophysical evaluation includes lithology identification and determinations of petrophysical parameters such as effective porosity (PHIE), net-pay thickness, water saturation (Sw), shale content (Vsh), and hydrocarbon saturation (Sh). The computed petrophysical parameters of the Upper Bahariya reservoir reveal that it has a PHIE range of 13–24%, Sw of 53.7–92%, and Vsh of 12.5–23%. On the other hand, the computed petrophysical parameters of the Lower Bahariya reservoir reveal that it has a PHIE range of 14–23%, Sw of 35–89%, and Vsh of 12.1–18%. The Sh averages 46.3% for the Upper Bahariya and 65% for the Lower Bahariya. The maximum net-pay thickness is 33 foot in the Lower Bahariya reservoir and is 11 foot in the Upper Bahariya reservoir. The results of this study revealed three new proposed locations to the southeast and north of the investigated Nader Field. These locations lie on four- or three-way dip structural closures that are suitable for petroleum accumulations. These potential locations also exhibit decreasing in Vsh and Sw, and increasing in net pay, PHIE, and Sh in both Upper and Lower Bahariya reservoirs. As a result, it is advised to pay more attention to exploration efforts on new promising locations for more economical petroleum discoveries.

Delineating the main structural outlines and the petrophysical properties of the Albian-upper Cretaceous Reservoirs using seismic and well log data, Shushan Basin, north Western Desert, Egypt

This study concerns with delineating and analyzing the subsurface structural setting of Khalda Oil Field at Shushan Basin as a key factor for evaluating the petrophysical properties and the deliverability of the Bahariya Formation. Shushan Basin is considered one of the most prospective basins in the Western Desert. The oil is trapped within a gentle seismically defined anticline that contains a series of coastal sandstone reservoirs interbedded with a neritic and tidal flat mudstone and a few carbonate interbeds of the Albian-Cenomanian Bahariya Formation forming multiple oil-bearing sandstone reservoirs. A set of borehole logging and seismic data were available, tied, processed, and mapped to delineate the predominant structures in the study area. Results show the implication of the NW–SE, NE–SW, and E–W gravity faulting on the Bahariya and the overlying Abu Roash formations. This set of gravity faults is attributed to the Mesozoic tensional stresses. The depth structure contour maps on the upper surfaces of the Lower and Upper Bahariya members reveal the presence of some NE–SW gravity faults that dissected the Khalda Field into some slightly tilted blocks, shallowing in depth to the south as deepening to the north. Besides, the study area has been affected later in the Jurassic by E–W gravity faults during the Atlantic Ocean opening. This faulting trend was changed later into the NE–SW direction as a result of the movement of North Africa against Laurasia. The petrophysical analysis indicated that the Lower Bahariya sandstone reservoir has a good reservoir quality (16 ≤ ∅ ≤ 25%, 53 ≤ Sw ≤ 59%, 6.0 ≤ Vsh ≤ 32.2%, and good net-pay thickness 18.0–38.0 ft). It is revealed that the drilled wells penetrating the crest of the anticline are prospective while that located in the anticline flanks are water-bearing recommending exploration away from the anticline flanks. By applying this workflow, it is possible to explore for the similar subsurface hydrocarbons-bearing sequences in the Western Desert and North Africa in future exploitation plans.

Formation evaluation and reservoir quality assessment of the Albian clastic sequence in the SWM Oilfield, Southwest the Mesopotamian Basin, Iraq

This work intends to delineate the petrophysical properties and the reservoir quality of the Albian sequence in the Mesopotamian Basin which has been deposited as a siliciclastic sequence. The well log data (including the caliper, gamma-ray, density, photoelectric factor 'PEF', neutron, sonic, and resistivity logs), derived from eight wells in the SWM (Southwest Mesopotamian) Oilfield, was studied and interpreted using the appropriate software (IP3.6). These borehole data indicate the necessity to divide the sequence into five reservoir rock units (U1, U2, M, L1, and L2 units). This enabled depicting the porosity, shale volume, water saturation, and net-pay thickness in the vertical and horizontal directions. It is indicated that the M and L1 units are the most promising units with good to very good porosity (∅ ≥ 17.2%), low water saturation (Sw ≤ 28.0%), and acceptable shale volume (Vsh ≤ 8.4%). The net-pay thickness varies between 32.8 and 77.4 m in the different wells of the SWM Oilfield. The well log data were supported by more detailed conventional core data including porosity (∅He) and permeability (k), from which the reservoir quality parameters were estimated precisely. In the present study, reservoir quality assessment based on conventional core data is considered for the first time for evaluating and discriminating the Albian–Aptian sequence in the Southwest Mesopotamian field into reservoir zones and hydraulic flow units. The estimated reservoir parameters include the Flow Zone Indicator (FZI), the Reservoir Quality Index (RQI), and the effective pore radius (R35). Based on the available core data and the estimated reservoir quality parameters, the studied sequence was divided into three reservoir rock types (RRT1–3). The best petrophysical properties have been assigned for the medium-grained sandstone of the RRT1 that dominates in the L1 and the M units (av. ∅He = 23.0%, av. k = 1581 mD, av. R35 = 23.7 μm, av. FZI = 7.368 μm, and av. RQI = 2.304 μm). On the other side, the fine-grained sandstone of the RRT3 is characterized by the lowest petrophysical properties and reservoir quality parameters (av. ∅He = 17.1%, av. k = 5.49 mD, av. R35 = 0.92 μm, av. FZI = 0.603 μm, and av. RQI = 0.136 μm). The integration between the well log and core data of the studied Albian sequence stated that the M and L1 units are the most promising reservoir units. They are predominated by medium-grained and fine to medium-grained sandstones of the RRT1 and the RRT2, respectively. This well log-core data integration is applicable to the different oilfields in the different fields in the Mesopotamian Basin and other basins in south Iraq and elsewhere.

Petrophysical Evaluation of the Lower Rudeis Formation in Shukheir Bay Field, Gulf of Suez, Egypt Using Open-Hole Well-Logs

The Shukheir Bay Field is located in the northern part of the Shukheir Marine Concession towards the southern part of the Gulf of Suez, about 300 km southeast of Cairo. It covers a shallow offshore water area of 5 km2 with a total area of 22.5 km2. The Rudeis sands in the Miocene sequence, which are widely distributed in the area, represent the main reservoir in the Shukheir Bay field. This study focuses on the clastic unit in the Lower Rudeis Formation usually referred to as the Lower Rudeis Sandstone. The petrophysical evaluation of this sand zone was conducted using a complete set of open-hole well-logs in three wells penetrating the formation. The lithologic composition is distinguished and identified as sand intercalated with shale, using tri and dia porosity cross plots. The shale distribution has been studied in both ways, amount and type. The amount is found to be relatively low to moderate, and the type is found to be mainly dispersed shale as indicated by the Thomas-Stieber model and the dispersed-laminated plot. The net-pay thickness also has a good value ranging from 39 m to about 42 m with high porosity (21%) and good oil saturation (76-94%). Both the vertical and lateral distributions of the petrophysical parameters are clarified, using the proper types of graphs. This research recommends drilling development wells in the central part of the study area, in addition to increase the exploration process towards the southwestern part.

Petrophysical analysis of well logs and core samples for reservoir evaluation: a case study of southern Issaran Field, Gulf of Suez province, Egypt

Understanding basic petrophysical properties may enhance the recovery of residual oil saturation and help in reservoir management. Reservoir oil saturation is the fraction of the porosity of a zone occupied by oil. The trapping may increase with the increase of porosity. Oil reservoirs represent a significant fraction of the reservoirs in the world-wide. We try to make a reservoir evaluation using petrophysical analysis of well logs and core samples at Issaran Field, South Gharib Formation, West of the Gulf of Suez, southeast Egypt. This area was heavily influenced by the structural setting of the Gulf of Suez’s central province, which is characterized by major SW dipping faults with a regional stratigraphic dip toward the NE. The high structural blocks are located in the center of the research area, and the low structural region is located in the southwest. South Gharib Formation is primarily composed of carbonates with few sulfates that grade upwards into sulfate-rich beds in the upper part. Laminated dolomitic limestone, with evaporites grades, changes downward into laminated dolomitic limestone and marly limestone, in the lower part. The anhydrite and dolomite units near the bottom have spotty oil stains. The structural setup is continued by the spread and deposition of this formation. We try to make analytical examination, of some reservoirs, accomplished by analyzing both well log data and core rock samples, vertically and laterally. According to the study of the horizontal permeability to vertical permeability ratio (Permeability anisotropy; lambda_{k}), the reservoir is laminated rock (lambda_{k} = 1.1 - 5), with a few data samples nearly isotropic (lambda_{k} = {1 mathord{left/ {vphantom {1 {1.1}}} right. kern-nulldelimiterspace} {1.1}}–1.1) and fractured (lambda_{k} = {1 mathord{left/ {vphantom {1 {2.5}}} right. kern-nulldelimiterspace} {2.5}}–1/1.1). Reservoir data histograms show that the most typical values of the data are 20–30% oil saturation and 7–10% porosity. The net-pay zone varies from four to 71 feet at different depths (897–1414 feet). Due to low shale content, water saturation, high effective porosity values, hydrocarbon saturation, may show higher net-pay thickness. These results may help to enhance the oil recovery. The area in the middle of the research area is suggested for future hydrocarbon development and using more petrophysical analysis.

GEOLOGICAL PETROPHYSICAL EVALUATION OF YAMAMA FORMATION SUBBA FIELD

The main purpose of this study is to estimate hydrocarbon potentialities of Yamama Formation (Valanginian–Early Hauterivian) by using assessment technique links up between gamma ray spectrometry logs and other conventional open hole logs for determining the petrophysical properties of Yamama units in Subba oil-field and oil water contact as well. The Lower Yamama (YB); is considered the main reservoir unit, aptly composed of shallow high depositional energy levels of oolitic to bioclastic grainstone facies reflecting low clay-content, thus these properties had gave a fruitful chance as for immigrated oil to accumulate in the porous bodies of this reservoir units. The non-improved petrophysical properties of upper Yamama member (YA) due to far-deep depositional conditions reflected by well-developed dense-compact sub-tidal open-shelf lagoonal benthic foram / algal wackestone facies and sparse-fossiliferous lime mudstone intercalated with bioclastic wackestone facies, are clearly displayed sedimentary intervals of high clay-content that is, the reduction potential depositional conditions are highly affected on these facies.YB-unit have attained (22-29m) net pay thickness with porosity (9.35-10.9%) and water saturation ranged (40-40.6%),whereas the YA-unit net-pay thickness is reached to (7.5-16.5 m) with (6 % phi) and (35.3%Sw). The oil water contact at the lower Yamama member may assign at depth 3573m (MSL) of southern dome on basis of electrical logs monitoring, well log interpretation and test results carried out the formation units.

Impact of diagenetic processes on the petrophysical properties and quality of the Miocene “Reefal limestone” reservoir in Al-Hamd field, Gulf of Suez, Egypt

Unconventional reservoirs have burst with a great force in the oil and gas worldwide production. Reefal limestone reservoir is one of them. The present study deals with the reefal carbonate Hammam Faraun Member in Al-Hamd oil field. This study focus on the interpretation of sedimentological and petrophysical data to show the effect of diagenetic processes on middle and lower Miocene reefal carbonate reservoirs in Al-Hamd oil field. Comprehensive petrophysical analysis for Hammam Faraun Member was performed using wireline logs and core data to determine the proper petrophysical parameters. Of the reservoir intervals. The analytical reservoir rock achieving the main reservoir parameters as shale content (Vsh), effective porosity (Oeff), water and hydrocarbon saturation (SW and Shr) as well as the net-pay thickness. The Formation Micro Imager (FMI) was also applied to detect the variation, types, and directions of the fracture systems that present in the lower and middle Miocene reefal limestone reservoir. Petrographic analysis was done, indicating the presence of a clear effect of diagenetic factors on the quality, productivity, and efficiency of the reefal limestone reservoirs behavior. The diagenetic factors include dolomitization, slicification, recrystallization, and solution process which affect greatly the petrophysical characteristics of the reefal carbonate Hammam Faraun reservoir in the study area. The core analyses were also used to detect the paleo environment, associated textural/ lithological and sedimentological characteristics to gain and understand the factors responsible for the productivity behavior of the reservoir in the Al-Hamd oil field. Rock facies have been divided as specific characteristics and were further described considering their color, texture, grain-size characteristics, and the depositional and biogenic sedimentary structures.

Evaluation of Petrophysical and Hydrocarbon Potentiality for the Nubia A, Ras Burden oil field, Gulf of Suez, Egypt.

The present study deals with the Petrophysical Evaluation of Nubia A of Lower Cretaceous age in Nubia Formation, Ras Budran oil field, Gulf of Suez, Egypt. The petrophysical parameters results of Nubia A in Nubia Formation is represented laterally (Iso-parametric maps, such as effective porosity, shale content, net-pay thickness and hydrocarbon saturation maps).A set of well logs has been run for the selected four wells. These wells named (RB-A1, RB-B1, RB-B11 and RB-C1). The minimum suite of logs consisted of gamma ray, density, neutron, and resistivity logs, all the log data are in the form of LAS files. Nubia Formation is very good reservoir rock in most intervals, where the interpretation of the well logging data indicates that the total porosity ranges from 13.8% to 15%, effective porosity ranges from 13.2% to 15%, shale content ranges between 0.3% to about 2.1%, water saturation from 15.4% to about 52.1%, hydrocarbon saturation ranges from 47.9% to 84.6% and Netpay thickness ranges between 21 ft toabout137.25ft. From Lithological Identification Techniques for Nubia A indicates the presence of mixed lithology has sandstone, shale, dolomite and limestone. The developments in Ras Budran field for Nubia A towards the central part around RB-B1 well and northwest- southeast, this shown by the increasing of effective porosity and hydrocarbon saturation respectively. There is a good opportunity to drill other Exploratory and development wells to enhance the productivity of the study area because it is containing valuable amount of hydrocarbon accumulation. The best well for this study is RB-A1 has high hydrocarbon saturation 76.2%, effective porosity 13.7% and Net pay thickness137.25 ft.

Petrophysical evaluation of reservoir in a selected well (Z) in an onshore oil field (X) in the Niger Delta Basin, Nigeria using wireline logs

: The petrophysical properties of a well selected from among the onshore oil fields in the Niger Delta Basin, Nigeria was evaluated using gamma ray log, resistivity log and neutron-density overlay log to analyze for the hydrocarbon potential of the well. Some petrophysical properties of the reservoir rocks and fluid characters such as porosity, shale volume, effective porosity, permeability, and formation resistivity factor, resistivity of water, hydrocarbon saturation, water saturation, and net pay thickness were evaluated. The results show that the volume of shale in each reservoir zone directly affects the effective porosity and the zones. The volume of shale is inversely proportional to the effective porosity, as an increase in the volume of shale will bring about a decrease in effective porosity. On the other hand, permeability is dependent on the effective porosity. Facies type identification of the reservoir sands were also carried out using the wireline log - Gamma Ray Log. Results of the work revealed the presence of hydrocarbon in 10 reservoirs across the well, and the hydrocarbon type was observed to be only oil. Oil/Water contacts occurred at 2288m, 2518mm, and 2989m, and the Net Pay Thickness was calculated to be 238m, that is the total thickness of the hydrocarbon reservoirs.Keywords: Petrophysics, Wireline logs, Facies, Reservoir rocks, Pay thickness.

Integrated of Sequences Seismic Stratigraphy, Accoustic Impedance Invertion, and Petrophysical for Resources Exploration in Offshore Southern Ardjuna Northwest Java Basin, Indonesia

This thesis discusses the uses of the integration of the Stratigraphic Seismic Sequence method, AI Inversion, Petrophysical Evaluation for Exploration Resource Analysis in more detail and more accurately which will produce information on contingent structures ranging from Play concepts, petroleum systems, and properties from reservoir characteristics, to prospect mapping. and evaluation of the risk of exploration findings. Understanding of seismic internal characteristics helps draw stratigraphic sequential seismic markers in seismic cross sections. The Seismic AI invasion will help in the determination of the spread of lithofasies, porosity, fluid in seismic sections. Distribution Map of AI Inversion of Structure Overlays The depth of the interval TST 2 provides trap area parameters for Sand DST 4 located on the Tidal System. Petrophysics will help provide porosity properties, netpay thickness, formation water saturation. The use of this integration method will prove if the evaluation of subsurface data is assessed by Integration of Seismic and Geophysical Methods (Seismic Inversion, Seismic Attribute Analysis, Seismic Stratigraphy Analysis) and Wells Data (DST test data, Fossil Index Catalog, and mud log well) very helpful for evaluating the Half Graben Exploration Resources in an integrated manner.

3D Geological Modeling for Yamama Reservoir in Subba, Luhias and Ratawi Oil Fields, South of Iraq

3D geological model for each reservoir unit comprising the Yamama Formation revealed to that the formation is composed of alternating reservoirs and barriers. In Subba and Luhais fields the formation began with barrier YB-1 and four more barriers (YB-2, YB-3, YB-4, YB-5), separated five reservoirs (YR-A, YR-B, YR-C, YR-D, YR-E) ranging in thickness from 70 to 80 m for each of them deposited by five sedimentary cycles. In the Ratawi field the formation was divided into three reservoir units (YR-A, YR-B, and YR-C) separated by two barrier units (YB-2 and YB-3), the first cycle is missing in Ratawi field. 
 The study involves 1 well in Luhais field (Lu-12), 3 wells in Subba field (Su-7, Su-8, and Su-9), and 5 wells in Ratawi field (Rt-3, Rt-4, Rt-5, Rt-6 and Rt-7), the Luhais, Subba, and Ratawi fields located in the Mesopotamia zone (Zubair subzone).
 The reservoir units (YR-C and YR-D) in Subba oil field, and YR-B in Ratawi oil field represent the major reservoir units that characterized by the best Petrophysical properties (the highest porosity, the lowest water saturation, and the best Net Pay Thickness), Luhais oil field has poor to moderate Petrophysical properties and low oil bearing in YR-A, YR-B and YR-C units, and produce heavy oil and salt water from YR-D and YR-E as indicated by low resistivity log reading, and according to the Drill Steam Test (DST) with the description of cutting in final geological reports.

Demarcation of hydrocarbon potential zones for Qishn clastic member, Masila oil field, Yemen

The present study makes an attempt to utilize reservoir parameters which have been integrated into Arc GIS to delineate hydrocarbon potential zones in Masila oil field, Yemen. Petrophysical analysis has been carried out for a set of well logs data using Schlumberger Techlog software. Reservoir parameters calculated from well logs analysis include effective porosity (PHIE), permeability (K), Net-Pay thickness (N-PTh), hydrocarbon saturation (Sh), water saturation (Swe), the volume of shale (Vsh), and fault system (Fs). Petrophysical parameters prepared as contour maps, converted into raster format, classified and visualized as 2D/3D on GIS platform. Frequency ration model has been used to assess weighting score for each parameter with the help of existing wells location. Themes of reservoir parameters are reclassified by using weightage score of frequency ratio model. The result obtained from analyses of reservoir properties concluded that total effective porosity ranges between 17 and 38%, permeability between 108.89 and 903.30 mD, net-pay thickness 25–189.30 m, volume of shale 9–27%, water saturation 14–77%, and hydrocarbon saturation 73–86%, which is mostly concentrated in NW and SW in the study area. These parts of oil field reveal promising reservoir characteristics and have more hydrocarbon potential due to high values of permeability, porosity, and hydrocarbon saturation and less values of water saturation and volume of shale. The area is categorized into five potential zones, viz., very high, high, moderate, low, and very low. Reservoir cross plots of hydrocarbon occurrence have been used to validate the new potential zones. The result of overlay has shown very good correlation with the present ground situation. The outcome of this research will contribute to the development of the existing oil fields; besides, it will provide a superior database and will lead to improvement in decision-making to achieve higher hydrocarbon exploration and production.

Hydrocarbon potential of Upper Bahariya member in Um Baraka oil field, North Western Desert, Egypt

ABSTRACTThe present study deals with the hydrocarbon potential evaluation of the Upper Bahariya Member (Upper Cretaceous) in Um Baraka field, North Western Desert. The Upper Bahariya Member is characterised by sandy shale facies in the UMB-152 well, calcareous shale facies in the UMB-89 well and calcareous sand facies in the UMB-108 and UMB-130 wells, these facies reflect to fluvio-marine environment changing to shallow marine environment. The petrophysical parameters results of Upper Bahariya Member are represented laterally (Iso-parametric maps, such as effective porosity, shale content, net-pay thickness and hydrocarbon saturation variation maps) and vertically (Litho-saturation cross-plots). The Iso-parametric maps revealed that the promising hydrocarbon-bearing zones are characterised by their clay content range from 1.7% to 21.4%, effective porosity ranges from 13.2% to 19.7%, net pay thickness range from 7.5 ft to 15.5 ft, and hydrocarbon saturations range from 39.3% to 68.3%. The log analysis and petrophysical parameters results indicate that the Upper Bahariya Member is considered to be the main potential reservoir in Um Baraka field. The petrophysical parameters of the Upper Bahariya reservoir illustrated the improvement of the reservoir properties of Upper Bahariya Member towards the north and northwest and northeast directions, due to increasing of total porosity, effective porosity and hydrocarbon saturation.

Use of Well Logs for Petrophysical Evaluation of Abu Madi Reservoir in Abu Madi-ElQara-Nidoco Area, Northern Nile Delta, Egypt

The open-hole wire line log data of seven wells are used to study the petrophysical characteristics of the Late Miocene Abu Madi Formation (levels II and III) in Abu Madi-El-Qara-Nidoco area, northern Nile Delta, Egypt. The vertical variation of the petrophysical characteristics is presented as lithosaturation cross-plots. The parameters distribution maps (shale volume, effective porosity, fluid saturation, net pay thickness and hydrocarbon saturation) are used to represent the lateral variation of petrophysical characteristics. Cross plots show that the main reservoir lithology is shaly sandstone with laminated to dispersed shale in level II and dispersed shale and minor laminated shale in level III. The shale volume ranges from 0.19 to 0.71 for level II and from 0.19 to 0.47 for level III. The effective porosity ranges from 0.03 to 0.22 for level II and from 0.06 to 0.19 for level III. The hydrocarbon saturation reaches up to 0.88 for level II and up to 0.81 for level III. The net-reservoir thickness ranges from 50 to 101 m for level II and from 30 to 153 m for level III. The net-pay thickness ranges from 75 to 90 m for level II and from 22 to 110 m for level III. Maps show that the most favorable places for hydrocarbon reservoirs occupy southwestern part for Abu Madi level II reservoir and in the middle, the middle-west, the middle-east and the southeastern parts for Abu Madi level III reservoir.