Hydrocarbon Saturation Research Articles

Reservoir quality evaluation using petrophysical, well-log analysis and petrographical description: A case study from the Carboniferous-Permian Kulshill group formations, southern Bonaparte Basin, Australia

The Carboniferous – Permian Kulshill Group formations are producing reservoirs in the Petrel subbasin, Australia. The studied Keyling and Kuriyippi formations were investigated by integrating petrophysical, petrographical, sedimentological, and well-log interpretations. The petrophysical study reveals that both formations Keyling and Kuriyippi have very good porosity (max. 30.9% and 25.2% respectively) and permeability values (max. 3053 mD and 1025 mD respectively) indicating good reservoir quality. Based on petrographic descriptions, both formations comprise very fine to coarse-grained sandstone and moderate to well-sorted with abundant intergranular porosity. Many diagenetic factors acting on the reservoir quality of the Kulshill Group formations are observed. Cementation and clay minerals as well as secondary porosity is more visible in both formations while at the same time the formations still holding good enough reservoir quality.The interpreted well-log data indicate that the Kuriyippi Formation is mostly oil bearing, whereas the Keyling Formation is water bearing reservoir. The average petrophysical parameters of both formations show that porosity values reaching up to 16.5–32.3% respectively, and clay volume up to 25.2% with abundance of montmorillonite, mixed clay layers, while glauconite, micas, and illites were found in few amounts in both formations. The hydrocarbon saturation recorded higher values (up to 80.4%) in the Kuriyippi Formation while the measured values in the Keyling Formation is less and the water saturation is always playing around the cutoff values. This can be attributed to the presence of the permeability barrier Treasury shale Formation underlying the high quality Keyling sandstone reservoir blocking the upward migration of hydrocarbon.

A Review on Models for Evaluating Rock Petrophysical Properties

The evaluation of subsurface formations as applied to oil well drilling started around 50 years ago. Generally, the curent review articule includes all methods for coring, logging, testing, and sampling. Also the methods for deciphering logs and laboratory tests that are relevant to assessing formations beneath the surface, including a look at the fluids they contain are discussed. Casing is occasionally set in order to more precisely evaluate the formations; as a result, this procedure is also taken into account while evaluating the formations. The petrophysics of reservoir rocks is the branch of science interested in studying chemical and physical properties of permeable media and the components of reservoir rocks which are associated with the pore and fluid distribution. Throughout recent years, several studies have been conducted on rock properties, such as porosity, permeability, capillary pressure, hydrocarbon saturation, fluid properties, electrical resistivity, self-or natural-potential, and radioactivity of different types of rocks. These properties and their relationships are used to evaluate the presence or absence of commercial quantities of hydrocarbons in formations penetrated by, or lying near, the wellbore. A principal purpose of this paper is to review the history of development the most common techniques used to calculate petrophysics properties in the laboratory and field based primarily on the researchers and scientists own experience in this field.

ANALISIS JENIS FLUIDA RESERVOIR BERDASARKAN NILAI SW DAN LOG SUMUR DS-19, CS-21, RS-23 FORMASI AIR BENAKAT CEKUNGAN SUMATERA SELATAN

Hydrocarbon exploration currently has a variety of methods in operation to determine and identify a reservoir according to the required parameters. Well log data plays an important role in the development of hydrocarbon exploration. Hydrocarbon saturation can be known by first calculating the water saturation, so the value of Sw is the key to work to determine the type of reservoir and its fluid content at an interval or reservoir zone accompanied by crossover and separation readings on the density & neutron log curve. The research was conducted in the Jambi Sub-basin area, ANONIM field, South Sumatra, DS-19, CS-21, RS-23 wells with shaly sand lithology which produces three productive zones. Based on the results, wells DS-19, CS-21, RS-23 has a gaseous hydrocarbon fluid with Sw value in the DS-19 well of 10.5%, CS-21 well of 27.1%, and RS-23 well of 22.4%.

Assessment of the petrophysical properties and hydrocarbon potential of the Lower Miocene Nukhul Formation in the Abu Rudeis-Sidri Field, Gulf of Suez Basin, Egypt

Lower Miocene rift sediments of the Nukhul Formation are one of the prominent hydrocarbon producers in the Gulf of Suez basin. In this study, we focused on the oil producing Nukhul sandstones of the Abu Rudeis-Sidri Field, located in the east central Gulf of Suez. Nukhul Formation is characterized by the prominent low amplitude seismic reflectors and represents the youngest identified reflector (Lower Miocene) in the study area. Petrophysical assessment was carried out using wireline logs to infer the reservoir characteristics. The Nukhul sandstone reservoir exhibits lower shale volume (< 0.1 dec dominantly), 0.07–0.16 dec total porosity and effective porosity up to 0.13 dec within the Nukhul sandstone interval. Bulk density-neutron porosity cross plot infers primarily sandstone matrix with the influence of carbonates, which characterizes the studied reservoir as calcareous sandstones. Spectral gamma ray data indicates montmorillonite as the principal clay phase along with minor kaolinite and illite. The calculated water saturation of the reservoir zone in the three productive wells ranges between 0.17 and 0.34 dec (i.e., the hydrocarbon saturation equals 0.66–0.87 dec). A small range of bulk volume of water (0.011–0.03 dec) indicates superior quality of the hydrocarbon-bearing sandstone intervals. Absence of productive sands in one of the studied wells, drilled in the hanging wall implied structural control on hydrocarbon accumulation in the study area. This study provides crucial insights regarding the quantitative petrophysical characteristics, reservoir quality distribution and hydrocarbon potential of the Lower Miocene Nukhul clastic reservoir.

Automatic Multiwell Assessment of Flow-Related Petrophysical Properties of Tight-Gas Sandstones Based on the Physics of Mud-Filtrate Invasion

Summary Petrophysical interpretation of borehole geophysical measurements in the presence of deep mud-filtrate invasion remains a challenge in formation evaluation. Traditional interpretation methods often assume a piston-like radial resistivity model to estimate the radial length of invasion, resistivities in the flushed and virgin zones, and the corresponding fluid saturations from apparent resistivity logs. Such assumptions often introduce notable inaccuracies, especially when the radial distribution of formation resistivity exhibits a deep and smooth radial front. Numerical simulation of mud-filtrate invasion and well logs combined with inversion methods can improve the estimation accuracy of petrophysical properties from borehole geophysical measurements affected by the presence of mud-filtrate invasion. We develop a new method to quantify water saturation in the virgin zone, residual hydrocarbon saturation, and permeability from borehole geophysical measurements. This method combines the numerical simulation of well logs with the physics of mud-filtrate invasion to quantify the effect of petrophysical properties and drilling parameters on nuclear and resistivity logs. Our approach explicitly considers the different volumes of investigation associated with the borehole geophysical measurements included in the interpretation. The new method is successfully applied to a tight-gas sandstone formation invaded with water-base mud (WBM). Petrophysical properties were estimated in three closely spaced vertical wells that exhibited different invasion conditions (i.e., different times of invasion and different overbalance pressures). Available rock-core laboratory measurements were used to calibrate the petrophysical models and obtain realistic spatial distributions of petrophysical properties around the borehole. This approach assumes that initial water saturation is equal to irreducible water saturation. Based on the calibrated petrophysical models, thousands of invasion conditions were numerically simulated for a wide range of petrophysical properties, including porosity and permeability. Based on the large data set of numerical simulations, analytical and machine-learning (ML) models were combined to infer unknown rock properties in each well. Mean-absolute-percent errors (MAPE) of the analytical and ML models for the estimation of water saturation in the virgin zone are 5% and 2%, respectively, while the MAPE of the analytical models for the estimation of residual hydrocarbon saturation is 10%. Synthetic and field examples are examined to benchmark the successful application and verification of the new interpretation method. Estimates of water saturation in the virgin zone using the new method are in good agreement with core-based models.

Prospect Evaluation of the Cretaceous Yageliemu Clastic Reservoir Based on Geophysical Log Data: A Case Study from the Yakela Gas Condensate Field, Tarim Basin, China

This paper evaluated the oil and gas potential of the Cretaceous Yageliemu clastic reservoir within the Yakela condensed gas field lying in the Kuqa Depression, Tarim Basin, China. The petrophysical properties of the interest zones in the Kuqa area were characterized using geophysical logs from five wells. The results reveal that the gas-bearing zones are characterized by high resistivity, good permeability (K) and effective porosity (Φeff), low water saturation (Sw), and low shale concentration (Vsh), reflecting clean sand. The shale distribution model showed that these shales have no major influence on porosity and fluid saturation. The average shale volume, average effective porosity, and hydrocarbon saturation indicate that the Cretaceous Yageliemu Formation in the studied area contains prospective reservoir properties. The spatial distribution of petrophysical parameters, reservoir rock typing (RRT), and lithofacies were analyzed using the cross plots of litho saturation (volumetric analysis), iso-parametric representations of the petrophysical characteristics, cluster analysis, and self-organizing feature maps, respectively. The southeastern and northeastern regions of the research area should be ignored because of their high water and shale concentrations. The sediments in the southwest and northwest include the most potential reservoir intervals that should be considered for the future exploration and development of oil and gas fields in the study area.

Integrated Geological and Petrophysical Approaches for Characterizing the Pre-Cenomanian Nubian Sandstone Reservoirs in Ramadan Oil Field, Central Gulf of Suez, Egypt

The present study integrates multidisciplinary geological and petrophysical approaches to characterize and evaluate the potential of the pre-Cenomanian Nubian sandstone reservoirs in the Ramadan oil field, the central offshore part of the Gulf of Suez, Egypt. The different petrophysical parameters of the Nubian sandstone reservoirs (shale volume, porosity, water saturation as well as gross and net-pay thicknesses) were mapped, and 3D slicing models for the hydrocarbon phases saturation were constructed to understand the reservoir heterogeneity and the distribution of the best reservoir facies. The petrophysical results of the pre-Cenomanian Nubian succession highlight very good reservoir intervals in the Nubian C sandstones containing thick pay zones (> 120 m). On the other side, the Nubian A and B reservoir rocks are less prospective with pay zone horizons (< 10 m). Integrated reservoir models and wireline log analysis elucidate that clay volume is the most detrimental factor to the reservoir quality as the pay zone thickness and hydrocarbon saturation often increase where the clay volume decreases. Therefore, the presence of scattered pay zone intervals in Nubian A and B is mainly related to their elevated clay content which acts as barriers for fluids flowing within the reservoir facies. The Nubian C succession contains three different reservoir rock types (RRT) with variable compositional and petrophysical properties. RRTI and RRTII sandstones comprise quartzose sandstones with very low clay content (< 10%) and are characterized by an open pore system dominated by macropores. These sandstones are less impacted by overburden pressure and therefore can preserve their depositional porosity and permeability. On the other hand, RRTIII reservoir rocks are clay rich (> 10%) with abundant mesopores that are more prone to compressibility and hence reduction of the pore volume and pore throat. The present study highlights the significance of comprehensive integration between wireline logs, cores, and 3D reservoir models in directing exploration endeavors toward prospective reservoirs in mature basins.

Structural Styles and their Suitability for Hydrocarbon in Eastern Sindh Monocline, Lower Indus Basin, Pakistan

The present study is aimed to recognize the structural styles of hydrocarbon exploration and petrophysical properties of the LGF. The 2-D seismic and well log data set is composed of three seismic lines and well log data of Chak 66–1. Five horizons have been marked with the help of well to seismic tie namely tops of Ranikot, Parh, upper Goru, lower Goru, basal and top massive sands, and out of which basal and massive sands are the objective focus of the present study. Based on seismic data, the study area is characterized by normal faults showing NW–SE dipping trend. Horst and graben structural features are prominent on the seismic lines, which indicated the extensional tectonic regime. Time–depth contour maps and 3D surfaces of objective horizons depict their actual spatial distribution in this area. Wireline logging analysis revealed the physical properties of both basal and massive grains of sand, as 17% effective porosity, 25% average volume of shale (Vsh), 40% water and 60% hydrocarbon saturations for basal sands, Whereas, 16% effective porosity, 35% Vsh, 30% water and 70% hydrocarbon saturations are interpreted for massive sands. Cross–plots of Nphi–Dt and Dt–Rhob also identified that both areas of sand are clean, gas–saturated and have the potential to produce hydrocarbons.

Petrophysical Properties of Mauddud Formation in Selected Wells in Al-Ahdab Oil Field, Middle Iraq

This paper aims to calculate the petrophysical properties in the Al-Ahdab field in the middle of Iraq within the Mauddud Formation. This study was based on the information available from well logs. The interactive petrophysical software IP (V4.5) was used to calculate the porosity, hydrocarbon saturation and shale volume, divide the formation into reservoir units and buffer units, and evaluate these units in each well. The Mauddud was divided into five units, two of them were considered good reservoirs having good petrophysical properties (high porosity, Low water saturation, and low shale volume). The other three are not reservoirs because of poor petrophysical properties.

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.

Dependence of electrical conduction on pore structure in reservoir rocks from the Beibuwan and Pearl River Mouth Basins: A theoretical and experimental study

The electrical conduction of reservoir rocks is crucial for estimating hydrocarbon and water saturation. The dependence of the electrical formation factor as a key parameter of electrical conduction on pore structure is analyzed through theoretical development, petrophysical experiments, error analysis, core-scale displacement experiments, and pore-scale numerical simulations. Through the tortuous fractal capillary bundle pore model, the electric formation factor is theoretically a function of three pore structure parameters: porosity, tortuosity fractal dimension, and pore fractal dimension. Through rock-electrical experiments from 46 reservoir rocks from the Beibuwan and Pearl River Mouth Basins, Thanh’s model can give a satisfactory performance with a suitable value for the ratio of minimum to maximum pore radius. Porosity-based formation factor models, including classical Archie’s law, have an unacceptable error at high formation factor. Our formation factor model provides better predictions with an error factor of ±10. The Archie’s cementation exponent can be expressed as the average tortuous degree of electrical conduction paths. The dependences of hydraulic and electrical conductions on pore structure are distinctly different. Hydraulic conductance has obvious pore-size dependence, the dominant flow channel, and threshold pressure, which are affected by displacement order. However, the case of electrical conduction is the opposite, in which electrical conduction has no dominant channel, and does not reflect the pore-size information under the same porosity.

Evaluation of mixed organic-rich carbonate and shale rocks of Meyal oilfield using an integrated palynofacies, geochemical and petrophysical approaches

This study integrated palynological, geochemical, and petrophysical analysis that maybe used to analyze petroleum rocks. Shales and sediments rich in carbonate are essential in assessing the geological history of source rocks for the generation of petroleum. This emphasizes the important role of carbonate source rocks on a global level. This study evaluated the source and reservoir rocks of Meyal oilfield, Potwar Basin. Twenty-five well cutting samples from two wells and four fresh outcrop samples were studied. Results of TOC and Rock-Eval of Sakesar Formation samples showed fair to good TOC, Patala Formation in well had very good TOC contents in well both wells. S2 values of both formations’ samples showed fair to good generative potential. Both formations lie in the maturity window having primarily mixed Type II/III and Type III kerogen with good oil/gas-generation potential. Palynological analysis also shows Type III kerogen in productive oil/gas window and in good agreement with pyrolysis data. Three forms of kerogen assemblages were identified: Structured and Bio-structured phytoclasts, opaque phytoclasts, and AOM. Petrophysical analysis of Chorgali formation showed average porosity ∼12.01%, average water saturation ∼37.71%, and average hydrocarbon saturation ∼62.28%, indicating average to good reservoir potential. Findings of this research will help and guide exploration and production companies.

A novel approach for estimating pore size distribution and capillary pressure in hydrocarbon zone through hydraulic flow unit framework using NMR log

Nuclear magnetic resonance (NMR) logging imparts a wealth of information regarding the petrophysical characterization of rocks including pore size distribution and capillary pressure. However, the NMR data can only be comprehensively utilized when formation pores are fully water-saturated. As with hydrocarbon saturation increase in rock pores the NMR's transverse relaxation curve (T2 distribution) gets distorted and this in turn causes flawed measurement of petrophysical and fluid properties. Therefore, the estimation of representative pore structure and capillary pressure from hydrocarbon zone utilizing T2 distribution has traditionally been quite arduous. The previous correction methods in this regard mostly require expensive core data for their implementation, which makes them less desirable. In this study, a novel workflow has been introduced which does not necessitate expensive core data for its application. The new method employs the concept of hydraulic flow units (HFUs), which are zones within a reservoir having consistent petrophysical and geological properties to subdivide the reservoir rock while investigating the T2 distribution character variation through a statistical approach to determine the most optimally informed reconstruction of effected T2 distributions in hydrocarbon zone for accurate petrophysical characterization. After implementing the novel workflow on a carbonate reservoir having gas, the before and after comparative analysis of T2 distribution, pore size distribution (PSD) and capillary pressure curves show promising results. The novel workflow establishes a robust and cost-effective methodology for NMR T2 distribution correction in hydrocarbon zone for un-cored and partially cored wells.

Analyzing the seismic attributes, structural and petrophysical analyses of the Lower Goru Formation: A case study from Middle Indus Basin Pakistan

The purpose of this research is to delineate the structures of the Lower Goru Formation, investigate fluid properties, and clarify the hydrocarbon-prone areas through seismic attributes analysis. First, the acquired data was matched by the interpretation datum. Structural analysis was done by performing horizon interpretation, fault interpretation, and contour mapping on the C-Interval of the Lower Goru Formation. Hydrocarbon zones were marked with the help of attribute analysis on seismic sections and were justified by petrophysical analysis. An integrated approach such as seismic structural interpretation, seismic attribute, spectral decomposition, and petrophysical analyses was used in current research to better understand geological structure and features. This research showed that normal faults are present in the area showing negative flower structure, horst and graben, and faults oriented north-west to south-east. The contour map shows structural inclination and faults bound closure near well locations. Variance attribute and spectral decomposition attribute were used to verify horizon lineation and fault behavior. Instantaneous amplitude and instantaneous phase attributes justify hydrocarbon bearing zones, and bright spots are present on seismic sections at C–Interval of Lower Goru Formation. Petrophysical analysis of the available wells showed a number of significant hydrocarbon zones having more than 55% of hydrocarbon saturation at the C-Interval of the Lower Goru Formation. The four possible reservoir zones in Sawan-02 well, two zones in Sawan-07 well, and three zones in Sawan-09 well are identified based on well data interpretation. Based on these analyses, the area of interest has a very good reservoir potential, structural closure, and visible bright spots. The current finding of this research will be helpful for future exploration and development of the Sawan area.

RESERVOIR CHARACTERIZATION OF THE ‘SHULA FIELD’, OFFSHORE NIGER DELTA BASIN, NIGERIA: AN INTEGRATED APPROACH

This study analyzed “Shula field” offshore Niger Delta basin for it hydrocarbon bearing capacity. Well logs and seismic data were used for the analysis. Well logs consisting of gamma ray, resistivity, neutron and density logs for five different wells were used. Gamma ray logs aided lithological identification, resistivity logs were used to delineate hydrocarbon bearing zones while a combination of neutron and density logs aided in distinguishing oil and gas zones. Three hydrocarbon bearing sands (reservoirs) of varying thickness designated as RES-AA, RES-BB and RES-CC were identified. Well log correlation of the five wells revealed lateral continuity of the sand units thinning out in northwestern direction of the study field. The range values of gross thickness (GT), net-to-gross (NTG), volume of shale (VSH), effective porosity (ΦEff), permeability (K), hydrocarbon saturation (Sh) and water saturation (SW) for RES-AA reservoir are 51-74ft, 0.88-98%, 0.10-11%, 24-28%, 174-734mD, 8-80%, and 20-92% respectively. RES-BB reservoir range values of (GT), (NTG), (VSH), (ΦEff), (K), (Sh) and (SW) are 47-65ft, 83-98%, 8-14%, 24-32%, 234-1880mD, 4-78%, and 22-96% respectively while the RES-CC reservoir range values of (GT), (NTG), (VSH), (ΦEff), (K), (Sh) and (SW) are 121-191ft, 82-96%, 8-11%, 23-31%, 125-1352mD, 9-88% and 12-91% respectively. Sixteen faults were identified and interpreted comprising of nine synthetic and seven antithetic faults. The time and depth structural maps show the subsurface structural geometry and possible hydrocarbon migration and trapping potential. The probable structure trapping hydrocarbon in the study field is anticlinal structure and four-way closure. The volumetric calculation revealed that reservoir RES-AA has 951 × 106 bbl, reservoir RES-BB has 1058 × 106 bbl and reservoir RES-CC has 1688 × 106 bbl of oil originally in place (OIIP). Generally, the petrophysical results and the volumetric calculation for the field confirm an economically viable investment potential except for reservoir RES-AA, wellbore ZY-005 with 8% Sh, reservoir RES-BB, wellbore ZY-003 and ZY-005 with 4% Sh, and 7% Sh respectively and reservoir RES-CC, wellbore ZY-005 with 9% Sh. Therefore, these four reservoir units may be screen out during production to reduce the rate of water cut thereby increasing the producing life of the field.

Integrated Modelling and Reservoir Characterization of Ataga Field, Niger Delta Basin, Nigeria

Integrated modelling, well correlation and petrophysical analysis were performed to characterize the reservoirs for optimum hydrocarbon correlation using 3-D seismic reflection data and suites of well logs from Ataga 5, 7, 10 and 11 wells respectively in Ataga field, shallow offshore, Niger Delta Basin, Nigeria. The study revealed the presence of two viable hydrocarbon bearing reservoirs, AT1 and AT2 and the average values of porosity, permeability, water saturation, hydrocarbon saturation, Net to Gross (NTG) and volume of shale are in the ranges of 15% - 77%, 44.5% - 75.5%, 25.5% - 85%, 15% - 75.5%, 0.70 - 0.88 and 0.11 - 0.38 respectively which goes further to show that the both reservoirs have fair characteristics that are suggestive of the presence of hydrocarbon accumulation. It can therefore be deduced that the permeability values are reflective of fair interconnectivity of pore spaces of sands within the well areas and their ability to transmit fluids, the depth and depth structural map generated for the horizons and structures shows that the most dominant trapping mechanism in the area under study is the crescentic growth fault and the rollover anticlines trending in the Northwest-Southeast direction and from the volumetric analysis. It can be deduced that the recoverable gas for AT1 and AT2 reservoirs is 2 × 106 mscf and 6 × 106 mscf respectively.

FLUID PREDICTION THROUGH LITHOLOGICAL ANALYSIS IN ‘M’ OIL FIELD NIGER DELTA: USING ROCK PHYSICS APPROACH

3D Lithology and reservoir fluid studies based on conventional interpretation approach, such as low Vp/Vs values indicating gas presence have been used to discriminate hydrocarbon fluids. This work was provoked by the emerging trends of noticeable uncertainties leading to drilling of dry wells in the study area. Confirming the physical indicators of hydrocarbon in the reservoirs through the employed method is worthwhile. Well log data of M oil field was investigated with the aim of identifying reservoir rocks through qualitative and quantitative interpretations of subsurface well log data of M oil field through rock properties cros-splots analysis in the select reservoir in the field (M-5000) and to derive elastic rock attributes such as Lame’s parameter terms (λρ and μρ), Vp/Vs, P-Impedance and S-Impedance from available petrophysical data. Rock attributes derived from well logs were combined to produce three major forms of crossplots, which described and characterized the reservoir in terms of fluid and lithology present. The combinations were: VP/VS versus IP, μρ against λρ and IP versus IS. These rock parameters were analyzed in cross-plots space and used to determine which of them constitutes better indicators of pore fluids and lithology. The M- oil field cross-plot analysis indicate the lowest values of VP/VS (2.05-2.40); IP (5600-6300 (m/s*(g/cc)), λρ (16-20 (GPa*g/cc)), and μρ (4-9.5 (GPa*g/cc)). However, the low values of VP/VS, IP, λρ, and μρ, perhaps IS corresponds to hydrocarbon (Gas) saturation within the M- oil field.

Integrated Prospectivity Evaluation of XYZ Field Coastal-Swamp Depobelt Niger-Delta Basin Nigeria

Five studies were conducted on the “XYZ” field to understand its reservoir properties, structural settings, and hydrocarbon-in-place. Petrophysical parameters were calculated using appropriate equations and wireline logs. 3D seismic fault models were created. A stacking pattern of the reservoir sand bodies was interpreted from a gamma-ray motif. The reservoir surface area was deduced using hydrocarbon indicators and seismic amplitude change. A seismic inline section corresponding with the reservoir zone was used for the seismic facie studies. Reservoir R1 has net-thickness of 111.71m and 117.09m, N/G ratio of 76% and 85%, effective porosity of 25% and 28%, hydrocarbon saturation of 44% and 40%, permeability of 14md and 16md, and Formation factor of 156.32 and 13.77 in well “XYZ-03” and “XYZ-05” respectively.Three-ways and two-ways fault-dependent closures with an anticlinal stratigraphic closure were delineated towards the western and middle parts of the field. Reservoir R1 generally shows an aggrading stacking pattern. R1 associated with wells "XYZ-03" and “XYZ-05” has hydrocarbon volume of 272,293.40m3 (1,712,674 bbl) and 193, 502.93m3 (1,217,097 bbl) respectively. Seismic facies showed continuous reservoir sand bodies. The field is endowed with moderate to good multiple reservoirs, and effective fault and stratigraphic closures, which support economically considerable hydrocarbon volume.

Reservoir characterisations from bouguer gravity data, Northern Western Desert, Egypt

ABSTRACT The current study is a trial for estimating the reservoir characterizations as density, effective porosity, and hydrocarbon saturation. It employs subsurface lithological data from 48 drilled wells dispersed over the area and gravity data. The study was based on applying the gravity stripping technique. The gravities of five well-defined depositional cycles (cycle I, II, III, IV, V) of diverse ages were calculated depending on each cycle's density and thickness obtained from the available well data. Maps were prepared for each cycle and the surface of basement rocks from which the characteristic structures were traced. New linear empirical relationships were concluded with a correlation coefficient of 0.9 from linear relationships. Accordingly, reservoir characterizations were calculated for the reservoir at the sites in which neither seismic nor well logging data are available. Contour maps were prepared for each parameter to reveal the areal distribution of these parameters in all study areas. Maps revealed that, at Abu Gharadig basin, the predicted density varies from 2.3 g/cm3 to 2.7 g/cm3, effective porosity from 13% to 30%, and hydrocarbon saturation from 50% to 90%. The main deep subsurface structure trends are the E-W, the WNW-ESE, the ENE-WSW, the NE-SW, the NW-SE, and the N-S trends.

Estimating Geophysical Parameters Using Petrophysical Algorithm to Enhance Hydrocarbon Recovery in Lokaka Field, Niger Delta, Nigeria

Adoption of Enhanced Oil Recovery (EOR) to boost the hydrocarbon saturation (Sh) of reservoirs has caught the interests of many researchers in Geosciences. Evidence from literature shows that both primary and secondary recovery methods have failed to account for about 60% hydrocarbon (HC) that is trapped in the reservoirs and getting to discover large productive new fields has become a herculean task. This study identified the fluid nature and boundaries of reservoirs using some relevant geophysical (petrophysical) parameters and reservoir rocks physical features such as shale volume (Vsh), permeability (K), water and hydrocarbon saturation (Sw&amp; Sh). Petrophysical data were sourced from the data bank of the Department of Geology, Obafemi Awolowo University, Ile-Ife, Nigeria. Analysis of data was done using the PETREL 2010 and OpendTect 4.6.0 versions for quality checking, delineation of identified reservoirs, fluid contacts demarcation and fluid types’ determination. The interpreted data were thereafter loaded into Microsoft Excel environment in order to adopt suitable statistical relations for the estimation of Vsh, K, Sw and Sh. Exploration of about 59.4% HC with NaOH, 64.5% HC with KOH, 69.5% HC with NH4OH and 78.5% HC with LiOH were discovered after the (EOR) flooding process. Comparison of the Vsh, K, Sw and Sh values before EOR with the values after EOR further showed that the reservoirs produced more HC with EOR. This study concluded that more hydrocarbon saturation can be achieved from reservoirs when EOR is carried out.