Characterizing Hydrocarbon Reservoirs in Kenya’s Lamu Basin Leveraging Petrophysical and Rock Physics Approaches

This paper is concerned with geological and petrophysical characteristics of the Abu Roash “D” resesvoir in the G.P.T. Field, Abu Sennan area, using primarily the well log data. The subsurface geological studies were accomplished through the study of the lithostratigraphy, the regional structural deformations and the tectonic implications in the field area in addition to petrographic analysis. Computer-assisted log analyses were used to evaluate petrophysical parameters such as the shale content, effective porosity, water saturation, hydrocarbon saturation, flushed zone saturation and true resistivity. Litho-saturation crossplots of the studied wells, and isoparametric maps of the weighted petrophysical parameters of the investigated rock unit (shale content, effective porosity, water saturation and net pay thickness of hydrocarbon saturation) have been constructed to illustrate the spatial variation of petrophysical parameters and to show their relationships with the geologic setting of the study area. Based on the obtained results, the oil potential and the development of the Abu Roash “D” Member in the G.P.T. Field should be taken into consideration. The reservoir rock analysis revealed that Abu Roash “D” Member may be considered as a good reservoir and the better chances for more hydrocarbon reserves in the field area may exist in the central parts that have high effective porosity, low shale content and low water saturation.

Summary Our study applied a geophysical well log analysis, rock physics diagnostics and rock physics modelling to an exploration well log data from a shale gas exploration area in the Sichuan Basin o f South China. The study established an unconsolidated model (80% quartz plus 20% clay in the shale gas for mation) transform between the acoustic and elastic impedance on the one hand and lithology, porosity, water saturation, clay content, quartz content, and TOC content on the other hand. Through our geophysical well log anal ysis, we calculated mineral volumes using best available data, total and effective porosity, water saturation, and bu lk density and VS prediction where it was missing. For rock physics modeling, the shale gas formation matr ix substitution (Clay, Quartz and TOC) and porosity modeling were performed in this exploration well. Crossplots ar e also used to analyze the elastic properties of the shale gas formation including VP velocity vs density, Acoustic Impedance ( AI) vs total porosity (ΦT), AI vs Poisson’s Ratio (P R), and VP vs VS. The results were quality controlled by core sample laboratory analysis data. T o understand seismic effect as a result of rock physics modeling, ray tr aced synthetic modelling has been applied. The Ray-traced synthetics have been generated for the in situ and modeled scen arios for AVA analysis. These transforms will be upscaled and applied to acoustic and elastic impedance inversion volum es to map lithology, porosity, and TOC distribution in the shale gas exploration area.

Our study applied a geophysical well log analysis, rock physics diagnostics and rock physics modelling to an exploration well log data from a shale gas exploration area in the Sichuan Basin of South China. The study established an unconsolidated model (80% quartz plus 20% clay in the shale gas formation) transform between the acoustic and elastic impedance on the one hand and lithology, porosity, water saturation, clay content, quartz content, and TOC content on the other hand. Through our geophysical well log analysis, we calculated mineral volumes using best available data, total and effective porosity, water saturation, and bulk density and VS prediction where it was missing. For rock physics modeling, the shale gas formation matrix substitution (Clay, Quarzt and TOC) and porosity modeling were performed in this exploration well. Crossplots are also used to analyse the elastic properties of the shale gas formation including VP velocity vs density, Acoustic Impedance (AI) vs total porosity (ΦT), AI vs Poisson's Ratio (PR), and VP vs VS. The results were quality controlled by core sample laboratory analysis data. To understand seismic effect as a result of rock physics modeling, ray traced synthetic modelling will be applied. The Ray-traced synthetics will be generated for the in situ and modeled scenarios for future AVA analysis. These transforms will be upscaled and applied to acoustic and elastic impedance inversion volumes to map lithology, porosity, and TOC distribution in the shale gas exploration area.

Seismic reservoir property is one of the most important components of the seismic interpretation analysis. The research describes a successful use of a model-based seismic inversion tool and probabilistic neural network (PNN) to post-stack 3D seismic data for the identification of hydrocarbon reservoir zones within the Mishrif Formation. It represents an important formation in Iraq geologically and economically. The objective of this work is to evaluate reservoir characterization and increase the method to obtain better information about reservoir characterization by enhancement and assessment of petrophysical properties of Mishrif Formation such as (P-wave, effective porosity, density, and water saturation). Well logging data, well tops and 3D seismic were used as input to achieve the goal of this along with Petrel and Hampson Russel (The strata and emerge modules). Two horizons were picked in the Two-Way Travel Time (TWT) domain and converted to depth maps by using average velocity of wells. The TWT and depth maps of the Mishrif and near Ahmadi formations show highly developed structures in the southwest and southeast, with a N-S axis, and generally dipping toward the NW. The results of the acoustic impedance horizon units within the Mishrif Formation showed low acoustic impedance values, with higher values observed at the crest and on the northern sides of the N–S anticline axis, as well as in the southwestern part. The final results of the merged and horizon slices of P-wave data showed low velocity, high effective porosity, low water saturation, and low density within the reservoir units of the Mishrif Formation, with improved values observed at the crest, on the northern sides of the N–S anticline axis, and in the southwestern part. Two carbonate buildups within the Mishrif Formation were identified, and seismic attribute analysis was used to determine the boundaries of these buildups and to estimate their reservoir characteristics. The findings from the carbonate buildups and horizon slices revealed low acoustic impedance, low density, low P-wave velocity, high effective porosity, and low water saturation values. Based on all results and attribute analyses, it is recommended to drill an exploration well targeting the stratigraphic carbonate buildup located in the southwestern part of the 3D seismic survey area of the X Oilfield.

Reservoir fluid discrimination is an important part in seismic exploration. Reliable fluid indicators help to reduce the risk of exploration and increase the rationality of drilling plans. Rock physics models are essential in converting elastic parameters from inversion data to reservoir parameters. In combination with seismic AVO inversion data, we propose an alternative physics attribute for fluid discrimination based on the analysis of rock physics templates (RPT). This attribute is built based on the distribution feature of fluid trends in Vp/Vs versus acoustic impedance (AI) domain and it is fluid saturation sensitive and can reflect the consolidation degree of reservoir rocks simultaneously. We demonstrate the use of this attribute on well logs and seismic inversion data from the Sichuan Basin and successfully screen out high-porosity reservoir rocks with low water saturation. Presentation Date: Thursday, October 20, 2016 Start Time: 10:35:00 AM Location: 156 Presentation Type: ORAL

Rock Physics Modelling and Seismic Inversion were carried out in an Onshore Niger Delta Field for the purpose of characterizing a hydrocarbon reservoir. The aim of the study was to integrate rock physics models and seismic inversion to improve the characterization of a selected reservoir using well-log and 3D seismic data sets. Seven reservoir sands were delineated using suite of logs from three wells. In this study, the sand 4 reservoir was selected for analysis. The result of petrophysical evaluation shows that the sand 4 reservoir is relatively thick (62 ft) with low water saturation (0.33), shale volume (0.11) and high porosity (0.32). These results indicate reservoir of good quality and producibility. Cross-plot of property pairs (acoustic impedance (Ip) vs. lambda-rho (λρ) and mu-rho (μρ) vs. lambda-rho (λρ) color-coded with reservoir properties reveals three distinct probable zones: hydrocarbon sand, brine sand and shale. Results show that low Ip, λρ and μρ associated with hydrocarbon charged sands correspond to low Sw and Vsh and high &#216. The integration of rock physics models and inverted rock attributes effectively delineated and improved understanding of already producing reservoirs, as well as other hydrocarbon charged sands of low Sw, Vsh, and high &#216 to the east of existing well locations, which indicate possible by-passed hydrocarbon pays. The results of this work can assist in forecasting hydrocarbon prospectivity and lessen chances of drilling dry holes in MUN onshore Niger delta field.

The Eocene rock units of the Qadirpur field, Central Indus Basin (Pakistan), are investigated petrophysically for their detailed reservoir characterization. The different petrophysical parameters determined include the following: true resistivity, shale volume, total porosity, effective porosity, density and neutron porosity, water and hydrocarbon saturation, bulk volume of water, lithology, gas effect, P-wave velocity, movable hydrocarbon index and irreducible water saturation and integrated with different cross-plots. The Eocene reservoirs are excellent with high effective porosity (2–32 %) and hydrocarbon saturation (10–93 %). Among these, the Sui Upper Limestone is an overall a poor reservoir; however, it has some hydrocarbon-rich intervals with high effective porosity and better net pay. All the net pay zones identified show low and variable shale volume (5–30 %). The secondary porosity has added to the total and effective porosities in these reservoirs. The main contributors to the porosity are the chalky, intercrystalline and vuggy/fracture types. The thickness of the reservoirs zones ranges from 4.5 to 62 m. These reservoirs are gas-producing carbonates with almost irreducible water saturation (0.002–0.01) and are likely to produce water-free hydrocarbons. The lower values of moveable hydrocarbon index (0.07–0.9) show that the hydrocarbons are moveable spontaneously to the well bore. The proposed correlation model shows that the reservoirs have an inclined geometry and are a part of an anticlinal trap.

The presalt section of the Santos Basin is responsible for around 73% of Brazil’s oil production. Previous studies have identified the significant presence of fine grains negatively affecting the petrophysical properties of the Barra Velha Formation in the Buzios Field. With the help of well and rock data, these studies highlight the impact of magnesian clays on the quality of reservoir rocks. These Mg clays are prone to dissolution during diagenesis and can result in regions with high-porosity values. However, they can also occur and be distributed as laminated structures associated with the carbonates of Barra Velha Formation. As they do not contain radioactive elements, it is a challenge to identify them using conventional petrophysical evaluation methods. In this research, we propose the petrophysical evaluation of carbonate rocks in the presalt section of the Sepia Field, Santos Basin, with a view to identifying the best reservoir zones in two neighboring wells and correlating them to obtain a more robust characterization of the reservoir, in addition to verifying the influence of magnesian clays and understanding the relationship between the preservation of these clays in the rocks and the impact of reservoir properties such as porosity and permeability. The evaluation of Barra Velha Formation made it possible to estimate the petrophysical properties, interpret the lithotypes, and obtain the associated elastic parameters using data from well logs. From well data, it is possible to analyze the sensitivity for a possible quantitative seismic interpretation. Rock physics crossplots allow us to correlate elastic parameters with reservoir properties, helping to reduce uncertainties. At this stage, the effective porosity (PHIE) and density (DENS) curves were obtained from the well logs, as well as the vagarosity curves used to calculate the compressional wave velocity (VP), shear wave velocity (VS), and acoustic impedance (AI) curves. The AI vs. PHIE (Fig.1a) and AI vs. DENS (Fig. 1c) crossplots made it possible to identify three distinct main trends: reservoir carbonates, muddy carbonates, and tight carbonates. In contrast, the attempt to visualize the same separation using the VP/VS ratio vs. AI crossplot (Fig. 1b) was unsuccessful. In the main trend, the increase in AI is related to the decrease in PHIE in both wells. The best reservoir zones are associated with lower AI values and medium to high porosities. The tight carbonates stand out for their high values of AI and a considerable decrease in porosity due to the influence of diagenetic processes of cementation and compaction. Muddy facies are associated with the lowest AI values, while porosity remains slightly altered. The VP/VS ratio vs. AI crossplot shows that the muddy zones have high VP/VS values, higher than in the tight zones, but not enough to separate them from the reservoir zones. As an option, the AI vs. DENS crossplot shows good separation between the three lithotypes, indicating an increase in impedance related to denser zones with lower reservoir quality. The fact that the muddy carbonates exhibit porosity may contribute to relatively lower DENS values than the tight carbonates but still higher than the reservoir zones. Therefore, ranges of close AI values derived from acoustic inversion can lead to misinterpretations about high porosities in both wells. Therefore, using these crossplots (AI vs. PHIE, VP/VS ratio vs. AI, AI vs. DENS) together is essential to visualize the influence of magnesian clays and understand the heterogeneities of the carbonates in the Barra Velha Formation.

Petrophysical parameters of a petroleum reservoir rock, used in formation evaluation, are generally estimated from wireline logs and core plugs. However, uncertainty or percentage error in quantitative interpretation of wireline logs and petrophysical parameters is generally not well quantified. Formation evaluation analysis and rock physics modeling are very useful techniques to link physical properties of reservoir interval extracted from wireline logs at well location with petrophysical, elastic and seismic properties of the reservoir interval far away from the well location. However, several types of uncertainty in the estimation of these parameters can affect this link seriously. In this work, a complete workflow is proposed to find out various petrophysical and rock physics parameters and to estimate percentage error in the extraction of these parameters. This work flow is based on traditional wireline log interpretation and is successfully applied on Basal sands of four wells drilled in the lower Indus Basin of Pakistan. An uncertainty analysis using statistical techniques is performed on different petrophysical parameters such as volume of shale, porosity, permeability estimated from wireline logs of these wells. Based on our statistical approach, linear and nonlinear regression relationships are developed between different petrophysical parameters. Furthermore, these parameters are used as input in rock physics model to predict elastic moduli and seismic velocities of the reservoir interval. The rock physics parameters such as velocities, densities and elastic moduli derived from well data are in close agreement to those predicted from rock physics model.

Sa'ar–Nayfa reservoir is mainly made up of carbonate sediments with bands of shale that contain a substantial amount of proven oil in the Hiswah Oilfield, Sayun–Masila Basin, eastern Yemen. Several vertical wells have been drilled and penetrated these sequences. This study is concerned on the petrophysical evaluation and well log analysis of the Lower Cretaceous of 11 wells at the Hiswah Oilfield, Hadramawt Governorate, eastern Yemen. Computer-assisted log analyses were used to evaluate the petrophysical parameters such as shale volume, total porosity, effective porosity, water saturation, hydrocarbon saturation, flushed zone saturation and reservoir and pay flags. Cross-plots of the petrophysical parameters versus depth were illustrated. The Lower Cretaceous Sa'ar–Nayfa reservoir reflects that the matrix components are mainly carbonates and shales. Moreover, the lithological-geologic model reflected that these shales are strongly affecting the porosity and, consequently, the fluid saturation in the Sa'ar–Nayfa reservoir. In this study, the thickness of the Sa'ar–Nayfa reservoir increases from central toward north-eastern and north-western parts within the Hiswah Oilfield. The porosities analyses of the investigation of the Sa'ar–Nayfa reservoir for the 11 studied wells concluded that the average total porosity ranges from 5.4 % to 16.8 % while the effective porosity ranges from 5.2 % to 14.8 %. Water saturation of the Sa'ar–Nayfa reservoir ranges from 6.9 % to 75.8 %. On the other hand, hydrocarbon saturation matches with water saturation in a reverse relationship. Sa'ar–Nayfa reservoir is interpreted as good quality reservoir rocks with high average effective porosity reaching to 20 % and high hydrocarbon saturation exceeding 93 %. The Sa'ar–Nayfa reservoir reveals promising reservoir characteristics especially the upper reservoir unit, which should be taken into consideration during future development of the oilfields area. The hydrocarbon saturation map of the Sa'ar–Nayfa reservoir shows a regular pattern of distribution with a general increasing to the northeast, northwest and east directions while decreasing southwest wards, recording the maximum value of 93.1 % at the Hiswah-21 well.

Evaluation of Nubia sandstone reservoir as inferred from well logging data interpretation for Rabeh East-25 well, Southwest Gulf of suez, Egypt

Summary Our study applied a geophysical well log analysis, rock physics diagnostics and rock physics modelling to an exploration well log data from a shale gas exploration area in the Sichuan Basin of South China. The study established an unconsolidated model (80% quartz plus 20% clay in the shale gas formation) transform between the acoustic and elastic impedance on the one hand and lithology, porosity, water saturation, clay content, quartz content, and TOC content on the other hand. Through our geophysical well log analysis, we calculated mineral volumes using best available data, total and effective porosity, water saturation, and bulk density and VS prediction where it was missing. For rock physics modeling, the shale gas formation matrix substitution (Clay, Quarzt and TOC) and porosity modeling were performed in this exploration well. Crossplots are also used to analyse the elastic properties of the shale gas formation including VP velocity vs density, Acoustic Impedance (AI) vs total porosity (ΦT), AI vs Poisson's Ratio (PR), and VP vs VS. The results were quality controlled by core sample laboratory analysis data. To understand seismic effect as a result of rock physics modeling, ray traced synthetic modelling will be applied. The Ray-traced synthetics will be generated for the in situ and modeled scenarios for future AVA analysis. These transforms will be upscaled and applied to acoustic and elastic impedance inversion volumes to map lithology, porosity, and TOC distribution in the shale gas exploration area.

Our study applied a geophysical well log analysis, rock physics diagnostics and rock physics modelling to an exploration well log data from a shale gas exploration area in the Sichuan Basin of South China. The study established an unconsolidated model (80% quartz plus 20% clay in the shale gas formation) transform between the acoustic and elastic impedance on the one hand and lithology, porosity, water saturation, clay content, quartz content, and TOC content on the other hand. Through our geophysical well log analysis, we calculated mineral volumes using best available data, total and effective porosity, water saturation, and bulk density and VS prediction where it was missing. For rock physics modeling, the shale gas formation matrix substitution (Clay, Quartz and TOC) and porosity modeling were performed in this exploration well. Crossplots are also used to analyze the elastic properties of the shale gas formation including VP velocity vs density, Acoustic Impedance (AI) vs total porosity (ΦT), AI vs Poisson’s Ratio (PR), and VP vs VS. The results were quality controlled by core sample laboratory analysis data. To understand seismic effect as a result of rock physics modeling, ray traced synthetic modelling has been applied. The Ray-traced synthetics have been generated for the in situ and modeled scenarios for AVA analysis. These transforms will be upscaled and applied to acoustic and elastic impedance inversion volumes to map lithology, porosity, and TOC distribution in the shale gas exploration area

Rock physics modeling and quantitative seismic interpretation workflow for organic-rich mudrocks

One type of reservoir that has a large enough potential is the carbonate reservoir. Carbonate reservoir has heterogeneity in relation to pore shape, so it is necessary to apply a specific rock physics approach and seismic inversion which takes into account the elastic parameters of the rock in order to know the prospect zone of the carbonate reservoir. The rock physics approach taken is to estimate the modulus of the matrix and the estimation of the aspect ratio shows that the prospect carbonate has an aspect ratio range of 0.10 - 0.30 dominated by the pore shape of the Stiff Pore. Seismic inversion shows using extended elastic impedance shows carbonate porous (Mu-Rho < 33 GPa*g/cc) and saturated hydrocarbons (Lambda-Rho < 40 GPa*g/cc) are in the middle area (around the well) where the lateral spread is getting thinner with a thickness of up to 10 ms. The prospect zone analysis from rock physics modeling and extended elastic impedance shows that reef Baturaja Formation carbonate is a zone that has a good reservoir quality dominated by a pore shape that develops is stiff pore.