Log Interpretation Research Articles

Study on optimal selection of porosity logging interpretation methods for Chang 73 segment of the Yanchang Formation in the southwestern Ordos Basin, China

The physical properties of tight shale reservoirs have always been a hot topic of discussion, and the tuff reservoirs have also attracted more and more attention. Log predicting of the porosity is also important for the exploration and development of tight oil. Tight oil resources have been found in tight shale and tuff reservoirs in the Chang 7 Member of the Upper Triassic Yanchang Formation in the Ordos Basin, China. However, the logging method that effectively predicting porosity of the Chang 7 Member is lacking, and few people have discussed how to optimize the log interpretation methods. In this study, the characteristics of shale and tuff reservoirs were summarized by microscope and scanning electron microscope observation, X-ray diffraction, pore and permeability experiment, and the logging data. In order to find the optimal method of porosity prediction, four methods were performed: multiple regression fitting, multi-component volume model, porosity logging formula, and back propagation neural network method.The “Zhangjiatan Shale” of the Chang 7 Member is characterized by abundant sandy lamina and tuff lamina, compared with the tuff reservoir, the enrichment of pyrite (average 22.7 wt%) and total organic matter (>6%) increase the content of intercrystalline pores and organic matter related pores, the logging response is characterized by high natural gamma ray, low spontaneous potential and high acoustic. The tuff reservoir is mainly composed of vitric tuff and crystal-vitric tuff, hence, the rich in intergranular pore and micro-fracture can be explained by the dissolution and devitrification of vitric and crystal fragments, and the logging characteristic is opposite to that of the “Zhangjiatan Shale”. Four methods for predicting porosity are established. First, appropriate logging parameters are selected for regression fitting in the “Zhangjiatan Shale” (e.g., gamma ray, deep lateral logging resistivity, density and spontaneous potential) and tuff reservoir (e.g., acoustic, density, compensated neutron logging). Then, the rock multi-component volume model was established as rock skeleton, clay or tuff matter, organic matter, and pores. The logging parameters of the skeleton, clay and organic matter were obtained by intersection graphs, which were applied in the improved porosity logging formulas. The effect of organic matter on logging was considered into the traditional porosity prediction formula, a third prediction method was established. Finally, the BP method was introduced into the porosity prediction work, and the neural network parameters were adjusted according to the log and porosity data. The learning rate and the learning accuracy were set as 0.1 and 10−6 in the study area. The error analysis between the result predicted and measured shows that the multi-component volume model is suitable for the “Zhangjiatan Shale” (the correlative coefficient R>80%), while the back propagation neural network is the best method for the tuff reservoir (the correlative coefficient R>90%).

Reservoir Model and Production Strategy of Mishrif Reservoir-Nasryia Oil Field Southern Iraq

Nasryia oil field is located about 38 Km to the north-west of Nasryia city. The field was discovered in 1975 after doing seismic by Iraqi national oil company. Mishrif formation is a carbonate rock (Limestone and Dolomite) and its thickness reach to 170m. The main reservoir is the lower Mishrif (MB) layer which has medium permeability (3.5-100) md and good porosity (10-25) %.
 Form well logging interpretation, it has been confirmed the rock type of Mishrif formation as carbonate rock. A ten meter shale layer is separating the MA from MB layer. Environmental corrections had been applied on well logs to use the corrected one in the analysis. The combination of Neutron-Density porosity has been chosen for interpretation as it is close to core porosity. Archie equation had been used to calculate water saturation using corrected porosity from shale effect and Archie parameters which are determined using Picket plot.
 Using core analysis with log data lead to establish equations to estimate permeability and porosity for non-cored wells. Water saturation form Archie was used to determine the oil-water contact which is very important in oil in place calculation. PVT software was used to choose the best fit PVT correlation that describes reservoir PVT properties which will be used in reservoir and well modeling.
 Numerical software was used to generate reservoir model using all geological and petrophysical properties. Using production data to do history matching and determine the aquifer affect as weak water drive. Reservoir model calculate 6.9 MMMSTB of oil as initial oil in place, this value is very close to that measured by Chevron study on same reservoir which was 7.1 MMMSTB. [1]
 Field production strategy had been applied to predict the reservoir behavior and production rate for 34 years. The development strategy used water injection to support reservoir pressure and to improve oil recovery. The result shows that the reservoir has the ability to produce oil at apparently stable rate equal to 85 Kbbl/d, also the recovery factor is about 14%.

Comparison between Rafidhiya and Shuaiba Domes within the properties of Mishrif Formation in Zubair Field; the implication of structural Geology and petrophysical analyses

The current study combined both concepts of structural geology and petrophysical to understand the structural feature of Mishrif Formation and its implication on the petrophysical characterization of the formation in Shuaiba and Rafidhiya Domes (or culminations) in Zubair Field. Shuaiba and Rafidhiya are adjacent domes and these domes belong to the same Field but the domes separated by saddle may related to Basra – Zubair basement fault.
 The domes have different petrophysical properties of Mishrif Formation; consequently, influenced in water and oil saturation. Therefore, the study tries to understand the structural and petrophysical position of Mishrif Formation of the domes. The structural analysis included geometric and genetic analysis, whereas petrophysical analysis used open hole logs interpretation to determine the petrophysical characteristics (especially the distribution of porosity, permeability, and water saturation.
 It was concluded that may a variation in porosity and permeability of Mishrif Formation for Shuaiba and Rafidhiya domes because each dome was formed by a different folding mechanism effected on the petrophysical properties. The structural geology analysis detects that may be Shuaiba dome formed by bending fold mechanism (vertical force of salt structure), while Rafidhiya dome by buckling fold mechanism (parallel force of collision of Arabian and Eurasian plate). These mechanisms may directly be affected in permeability distribution, and consequently on oil and water saturation of Mishrif Formation. Thus, Shuaiba Dome has thinning in hinge area and extensional force leads to create fractures and karst phenomena, and as a result, high permeability in upper Mishrif. On the contrary, Rafidhiya Dome has a thickening feature and there is no indication of karst phenomena and low permeability. Therefore, the Mishrif of Shuaiba dome permeable and oil-saturated, while, it flooded with water in Rafidhiya Dome. The disconnection in reservoir pressure confirmed by difference in initial reservoir pressure of Mishrif Formation of Shuaiba Dome and recent reservoir pressure of Mishrif Formation of Rafidhiya Dome

Estimation of Oil-Water Contact Level Using Different Approaches: A Case Study for an Iraqi Carbonate Reservoir

In petroleum industry, an accurate description and estimation of the Oil-Water Contact(OWC) is very important in quantifying the resources (i.e. original oil in place (OIIP)), andoptimizing production techniques, rates and overall management of the reservoir. Thus,OWC accurate estimation is crucial step for optimum reservoir characterization andexploration. This paper presents a comparison of three different methods (i.e. open holewell logging, MDT test and capillary pressure drainage data) to determine the oil watercontact of a carbonate reservoir (Main Mishrif) in an Iraqi oil field "BG”. A total of threewells from "BG" oil field were evaluated by using interactive petrophysics software "IPv3.6". The results show that using the well logging interpretations leads to predict OWCdepth of -3881 mssl. However, it shows variance in the estimated depth (WELL X; -3939,WELL Y; -3844, WELL Z; -3860) mssl, which is considered as an acceptable variationrange due to the fact that OWC height level in reality is not constant and its elevation isusually changed laterally due to the complicated heterogeneity nature of the reservoirs.Furthermore, the results indicate that the MDT test can predict a depth of OWC at -3889mssl, while the capillary drainage data results in a OWC depth of -3879 mssl. The properMDT data and SCAL data are necessary to reduce the uncertainty in the estimationprocess. Accordingly, the best approach for estimating OWC is the combination of MDTand capillary pressure due to the field data obtained are more reliable than open hole welllogs with many measurement uncertainties due to the fact of frequent borehole conditions.

Fundamentals of well logging data interpretation for determining prospective Frasnian-Famennian Domanik deposits

Background. In the process of studying productive Domanik deposits of the Frasnian-Famennian, numerous uncertainties arise in identifying their effective thickness. Although several approaches have been recently proposed for identifying promising intervals in Domanik sediments, e.g. determination of the effective thickness using gas logging during geological and technical studies, the use of the interpretation method presented in the article and other methods continue to develop. Therefore, studies aimed at increasing their efficiency remain to be relevant.Aim. To develop basic methodological approaches to interpretation of well logging data with the purpose of identifying promising Domanik deposits rich in mobile hydrocarbons.Materials and methods. Geological and geophysical data obtained when investigating the wells of the according to published data of geological and geophysical resources of drilled wells in the Buzuluk depression were used to build the main well logging dependencies. In addition, the materials of core and geophysical studies of wells in the Volga-Ural oil and gas basin conducted by Gazprom Neft (PJSC) were used. Extended well logging data were collected for the wells under consideration. A number of tests and core studies, including geochemical experiments, which were carried out in deposits of Fran age, the density of resources of 5—10 samples per 1 meter of core.Results. For the first time, basic methodological approaches for identifying effective oil-saturated strata in Domanik sediments according to well logging data were developed. The developed approaches are based on the integration of geological-geophysical and geochemical data characterizing the material and mineralogical composition of rocks, the content of organic matter, the group composition of hydrocarbons and the genesis of reservoirs. In the section under study, rocks saturated with hydrocarbons were identified. The hydrocarbons were different in terms of group composition, which determined their mobility. Boundary values were obtained when interpreting data obtained by well logging methods for Domanik rocks containing mobile and stationary hydrocarbons. The proposed methodological approaches were tested on other wells in the Domanik deposits in the Orenburg region. As a result of repeated practical application and testing of the developed methodology, its effectiveness was confirmed.Conclusions. The proposed basic methodological approaches for interpretation of well logging data when identifying effective oil-saturated strata were substantiated by the geological-geophysical and geochemical properties of Domanik deposits.

Radial resistivity measurement method for cylindrical core samples

Electrical resistivity is one of the fundamental physical properties of rocks, and its relationship with fluid saturation is widely used in reservoir evaluation. The interpretation of electrical logs usually relies on the results of rock resistivity tests of cores in the laboratory. In the laboratory, core samples are commonly cut into cylinders, and the resistivity is measured along the axial direction. To determine the rock resistivity along different directions, samples are cut into cubes and tested along three perpendicular directions to obtain resistivity data. The expensive and complicated preparation process of cubic samples and the custom holder requirements limit the use of these tests. We have analyzed the advantages and disadvantages of rock resistivity measurements of cylindrical and cubic samples. To overcome the abovementioned difficulties, we develop a core holder for radial resistivity measurements and a radial resistivity measurement method for cylindrical samples. Based on the conformal transformation of the complex variable function theory, we establish a mathematical model of radial resistivity. We develop a measurement method of radial resistivity according to the mathematical model and verify this approach with isotropic cores. The theoretical calculation results agree with the experimental results. With the radial resistivity measurement method, we effectively test the resistivity anisotropy of shale. This method has more advantages than existing methods in terms of the sample preparation and realization of various displacement levels and angles. Hence, the proposed method can be widely used.

Cementation exponent estimate in carbonate reservoirs: A new method

There are two approaches for measuring hydrocarbon saturation: well log interpretation and usually developed formulas. Archie’s equation is one of the most fundamental equations used for water saturation calculation. Archie’s equation includes three factors: cementation factor, tortuosity and saturation exponent. Archie determines these factors based on lab results in sandstone and provides fixed value for them. Carbonate reservoirs have a variety of textures, shapes and distribution of pores; therefore, the mentioned factors, especially cementation are not considered constant. In this study, the relationship between cementation factor and density log was examined because cementation factor is defined as a parameter that has a close relationship with density. By calculating the matrix density and accordance factor between the matrix density and cementation factor from core’s analysis, a log will be generated that can estimate the variation of cementation factor around the borehole. This method is useable for calculating the cementation factor in carbonate rocks. Keywords: Cementation factor, carbonate reservoir, density, new method, exponents.

INTERPRETASI LINGKUNGAN PENGENDAPAN SUMUR R-2 BERDASARKAN ANALISIS ELEKTROFASIES

INTERPRETASI LINGKUNGAN PENGENDAPAN SUMUR R-2 BERDASARKAN ANALISIS ELEKTROFASIES

A New Ensemble Machine-Learning Framework for Searching Sweet Spots in Shale Reservoirs

Summary Knowing the location of sweet spots benefits the horizontal well drilling and the selection of perforation clusters. Generally, geoscientists determine sweet spots from the well-logging interpretation. In this paper, a group of prevalent classifiers [extreme gradient boosting (XGBoost), unbiased boosting with categorical features (CatBoost), and light gradient boosting machine (LightGBM)] based on gradient-boosting decision trees (GBDTs) are introduced to automatically determine sweet spots based on well-log data sets. Compared with linear support vector machines (SVMs), these robust algorithms can deal with comparative scales of features and learn nonlinear decision boundaries. Moreover, they are less influenced by the presence of outliers. Another prevailing approach, named generative adversarial networks (GANs), is implemented to augment the training data set by using a small number of training samples. An extensive application has been built for the field cases in a certain oilfield. We randomly select 73 horizontal wells for training, and 13 features are chosen from well-log data sets. Compared with conventional SVMs, the agreement rates of interpretation by XGBoost and CatBoost are significantly improved. Without special preprocessing of the input data sets and conditional tabular GAN (CTGAN) model fine tuning, the fake data set could still bring a relatively low agreement rate for all detections. Finally, we propose an ensemble-learning framework concatenating multilevels of classifiers and improve agreement rate. In this paper, we illustrate a new tool for categorizing the reservoir quality by using GBDTs and ensemble models, which further helps search and identify sweet spots automatically. This tool enables us to integrate experts’ knowledge to the developed model, identify logging curves more efficiently, and cover more sweet spots during the drilling and completion treatment, which immensely decrease the cost of log interpretation.

Application of nuclear magnetic resonance logging in the low-resistivity reservoir — Taking the XP area as an example

With the deepening of exploration and development, many low-resistivity reservoirs have been found in the XP area. We have found that the genesis of these low-resistivity reservoirs is that they contain a lot of very fine sand, which leads to the high content of bound water in the reservoirs and reduces resistivity. Compared with normal oil reservoirs, these reservoirs show low resistivity and high natural gamma, which makes it difficult to identify reservoirs qualitatively and calculate parameters quantitatively. Using conventional logging interpretation methods, the wrong shale content and porosity will be obtained, and such reservoirs may even be judged as mudstones. To solve this problem, we extract a characteristic parameter from the T2 spectrum of nuclear magnetic resonance (NMR) logging, which can effectively identify such reservoirs. In addition, we have innovatively adopted an optimized logging interpretation method for integrated NMR logging and conventional logging, which has effectively improved the parameter calculation accuracy of this type of reservoir and achieved a good application effect in the XP area.

Reservoir properties of drill cutting by the nuclear magnetic resonance relaxometry and dielectric spectroscopy data

The purpose of the study is to extend the use of nuclear magnetic resonance relaxometry and dielectric spectrometry methods. This is realized through a complex interpretation of the data by the above methods to timely provide additional petrophysical information about the drill cuttings pore space properties and structure. The relevance of the study is that the data on the drill cuttings obtained by the NMR method can be used as prior information in the logging data interpretation before a detailed petrophysical study of the core sample or in case of the core absence in the sampling interval. The objects of study are the drill cuttings samples from the fields of the West Siberian oil-and-gas province. The samples are saturated with different fluids, and their reservoir properties are determined by the nuclear magnetic resonance and dielectric spectrometry methods. As part of the experimental research, nuclear magnetic resonance investigations of the core samples of different discretization degrees have been carried out to determine the reservoir properties of the samples depending on the degree of their particle size reduction. It has been shown that the obtained results do not depend on the particle size of the measured sample and are consistent with the results of the standard petrophysical studies. The relationship between the porosity and the saturating fluid type has been established. Based on the data obtained by the dielectric spectroscopy method, the study has determined the value of the complex dielectric constant that shows how the degree of saturation changes depending on the fluid, and what happens in the pore space. The complex interpretation of the results obtained by the two methods provides additional information on the drill cuttings reservoir properties that can be used as a priori information on the formation properties.

A new method for predicting formation lithology while drilling at horizontal well bit

The identification of lithology while drilling with horizontal well bit is a difficult problem to solve in geosteering. However, due to the existence of “zero length” (the distance between the logging tool and the bit), the lithology at the horizontal well bit cannot be accurately interpreted in real time, which creates a lag in geosteering. Based on logging while drilling (LWD) technology, this paper uses supervised learning in machine learning methods, conventional logging interpretation technology and big data idea in modern computer science, through interdisciplinary theories and methods to research lithology prediction for horizontal well bits in reservoirs. First, a measurement point and vertical reservoir boundary distance (D-MP-VRB) database is built according to different step size categories. Second, based on the D-MP-VRB database, D-MP-VRB prediction models are established using one-versus-one support vector machines (OVO SVMs), random forest (RF), neural networks (NN), and extreme gradient boosting tree (XGBoost) algorithms. To reduce the dimensions of the input data, the feature parameters of the samples are obtained by a correlation analysis of the logging data. The optimal parameter values of each algorithm are determined by grid search and 10-fold cross-validation methods. Finally, the prediction formula of the bit and vertical reservoir boundary distance based on the D-MP-VRB prediction model is established. A case study is performed with data from a sandstone reservoir in Changqing oilfield, Ordos Basin, China. On this basis, the lithology predictions at the bit in real time are carried out by using four models. Considering the principle of model prediction accuracy, through 1320 experiments, only the XGBoost prediction model can be selected, and the step size of the target category is 2 m, however, this model takes the longest time to train. Therefore, the reliable prediction model trained by the sample data of the original training set is used to predict the reservoir information encountered by horizontal well. After the newly drilled reservoir information has accumulated to a certain amount and accurately explained, it is added to the original training set sample data, and the prediction model is retrained to improve the accuracy and adaptability of the model. Based on the prediction results of the XGBoost model and the prediction formula, the distance prediction between the horizontal well bit and the vertical reservoir boundary is realized, real-time lithology correction at the bit is realized, and the adverse effect of the “zero length” on the lithology prediction at the bit is reduced. The research results provide not only a new method for the real-time prediction of lithology in horizontal well bits but also a theoretical basis for the geosteering of oilfield development and valuable information for future research.

Characteristics of sand content and facial changes in the autochthonous Miocene formations of the central part of the Carpathian Foredeep based on well log interpretation

Characteristics of sand content and facial changes in the autochthonous Miocene formations of the central part of the Carpathian Foredeep based on well log interpretation

Hydraulic characterization of fault F31 at the Xinchang underground research laboratory site for geological disposal of high-level radioactive waste

As part of the suitability evaluation of the underground research laboratory (URL) candidate sites, the hydrogeological investigation activity was conducted at the Xinchang site in Beishan area from 2016 to 2019. A previous study discovered that the rock masses at the Xinchang URL site, which is surrounded by north–east trend and east–west faults, have low permeability and shortage of water-bearing structures. This article aimed to describe the hydraulic properties of fault F31, which is located on the west boundary of the Xinchang URL site, and evaluate the fault hydraulic characterization methodology for site characterization of the URL and repository sites.The surface hydrology monitoring activity at the Xinchang site showed that the water flow occurring through the gully where fault F31 is located after precipitation is the main recharge resource of groundwater. Accompanied with hydraulic monitoring during the drilling period of inclined boreholes (BSQ04–BSQ06, BS35, and BS36) crossing fault F31, the survey revealed that groundwater was stored in the weathered zones of the middle and north parts along fault 31. Single-hole and interference tests were performed later with the Heavy-Duty Double Packer system. The hydraulic conductivity (K) and storativity (S) were interpreted from the test data using analytical solutions. Diagnostic plots were also used in determining the reliability of results and identifying the flow regime. By considering the interpretation of borehole acoustic television logging as reference, the spatial morphological statistics of the structures are mainly parallel with the fault plane, wherein K is lower than 1 × 10−9 m/s depth to −250 m below the surface. Thus, the strike-dip parameter of the water resistance structures can be roughly confirmed. Six sections were selected for the evaluation of the water-conductive structures; these sections exhibited depths of more than −250 m below the surface and K values of equal to or more than 1 × 10−9 m/s. After the structures with a strike-dip similar to that in the water-resistant sections were removed, the remaining structural planes were used to build a flow model path during the hydraulic test. Compared with flow regime derived from the diagnostic plots, the structural planes fitting the real flow regime were identified as water-conductive structures.The results showed the following: (1) K and S increased from the south to the north in the shallow zone along fault F31, where water-conductive structures were surrounded by water-resistant structures; (2) the section located −250 m below the surface of F31 was water resistant, and no-flow channel existed in the deformation zone along fault F31; and (3) the fault hydraulic characterization methodology combining hydraulic test, hydrological survey, and geophysical logging is suitable for the site characterization of URL and repository.

Mechanical properties of organic-rich shales based on nanoindentation: A case study of deep shale gas reservoirs in Zigong area, Sichuan Basin

The deep shale gas in the Zigong area of the Sichuan Basin has a wide distribution and has good prospects for exploration, which has become an important replacement area for shale gas exploration and development. In this area, the burial depth of Longmaxi Formation Shale is generally >3500 m. One of the most challenging tasks in the development of this type of reservoir is the accurate prediction of the mechanical properties of organic-rich shale. The application of the mechanical properties of shale is important to the success in multiple aspects of drilling, hydraulic fracturing, and production. Methods such as unconfined/triaxial compression tests with the use of core plugs and logging data interpretation are commonly used to obtain mechanical properties. However, these methods have their own limitations. Thus, to address the difficulty in the measurement of the mechanical properties of shale, the advanced nanoindentation test is introduced and used. Nanoindentation is a technique based on a hard tip, which is pressed into the surface of a sample. The advantage of this test is the use of a sample with a small volume, such as drill cuttings or fragments, which are easily obtained during drilling. The mechanical properties at the nanoscale level, including the hardness, Young’s modulus, and fracture toughness, are measured in the nanoindentation. Moreover, this technique can be used to evaluate the creep behavior of shale. In this study, grid nanoindentation is used to investigate the mechanical properties of drill cutting samples from the Longmaxi Formation Shale in Zigong area, Sichuan Basin. Subsequently, these mechanical parameters are used to evaluate the heterogeneous properties of shale at the nanoscale level. The results can help in analyzing the correlation between rock mechanical properties and shale constituents. This suggests that the nanoindentation test is a useful approach of estimating the elastic and mechanical properties of shale in situations where conventional rock mechanics test data cannot be measured.

Petrophysical Properties of Nahr Umar Formation in Nasiriya Oil Field

Petrophysical characterization is the most important stage in reservoir management. The main purpose of this study is to evaluate reservoir properties and lithological identification of Nahr Umar Formation in Nasiriya oil field. The available well logs are (sonic, density, neutron, gamma-ray, SP, and resistivity logs). The petrophysical parameters such as the volume of clay, porosity, permeability, water saturation, were computed and interpreted using IP4.4 software. The lithology prediction of Nahr Umar formation was carried out by sonic -density cross plot technique. Nahr Umar Formation was divided into five units based on well logs interpretation and petrophysical Analysis: Nu-1 to Nu-5. The formation lithology is mainly composed of sandstone interlaminated with shale according to the interpretation of density, sonic, and gamma-ray logs. Interpretation of formation lithology and petrophysical parameters shows that Nu-1 is characterized by low shale content with high porosity and low water saturation whereas Nu-2 and Nu-4 consist mainly of high laminated shale with low porosity and permeability. Nu-3 is high porosity and water saturation and Nu-5 consists mainly of limestone layer that represents the water zone.

A new multifractal analysis-based for identifying the reservoir fluid nature

This work introduces a relevant non-linear approach to well log data processing and interpretation. The suggested method studies the behavior of fractal dimension values together with singularity spectrum attributes. It aims to delimit the hydrocarbon zones, including the detection of fluids' nature.The analysis was carried out on different datasets of 1085 well logging records related to 93 wells drilled in various geological contexts, located in different sedimentary basins in southern Algeria, both box and regularization dimensions have been calculated, and a multifractal analysis using wavelet transform allowed us to compute the singularity spectrum from which we could extract the main attributes, namely width, right height, left height, αpeak, αmin, αmax, f(αpeak), f(αmin), f(αmax) and C value. Based on the obtained values and attributes, an analytical investigation using descriptive statistics, Agglomeration Hierarchical Clustering (AHC), cross plots and scatter plots, has been performed.The obtained results illustrate that the fractal dimensions and singularity spectrum attributes can effectively characterize reservoir fluids, and are importantly affected by the fluid change, resulting in important differences and meaningful discrimination between oil and gas. It should be noted that the oil and gas widths which are significantly different from zero confirm that well logs exhibit multifractal behavior and can, therefore, be suitably investigated to explain such behavior related to physical properties and fluid qualities of reservoirs.The attained results show the oil has the broader range that manifests remarkably in all values and attributes as compared to the gas. Our findings exhibit the gas occupies high regularization dimensions, low box dimensions, low width, low right heights, low left heights which means high sets of fractal dimension, low α peak, low α max, and usually high α min as compared to oil. In addition, the widths are affected by the strength of singularity, with lower widths in gas, the gas known by strong singularities as compared to the oil which represents high widths. It is worth noting that these values and attributes should be used in combination to provide more precision in the analysis, and enhance the interpretation process of gas and oil detection.In conclusion, the obtained results demonstrate the relevance of the suggested method in detecting the nature of the fluid; it might be very interesting to examine the multiscale characteristics of the well log data and enrich the conventional analysis. However, additional investigations using multiple mathematical and statistical tools are needed to confirm these findings, obtain more results as well as improve our analysis and interpretation process.

An Interpretation Model for the Production Profile on the Same Angle of a Horizontal Well Trajectory

An accurate interpretation of the fluid production profile is the essential scientific step required for the dynamic monitoring and management of the reservoir. Currently, the accurate interpretation of conventional logging is generally available for vertical wells. However, high-accuracy interpretation is still a blank for horizontal wells, especially for those wells with low production. Therefore, it is of great importance to develop a new model which can efficiently improve the interpretation accuracy of horizontal wells’ production profiles. Practically, it was observed from experiments that for multi-phase flow in the horizontal well, the flow pattern changes significantly with the varied inclination angle along well trajectory. This is because the flow pattern is critically related with the flow rate and the measured phase flow data (i.e., the production data of oil, gas and water), which varies with the inclination angle along the horizontal well trajectory. Based on the above observations, a new methodology is proposed to interpret horizontal wells’ production profile with the same inclination angle. The comparison between the measured data and numerically calculated results indicated that the newly established method can significantly improve the interpretation accuracy of horizontal wells’ production fluid profile. The interpretation method is therefore enriched of production logging for different types of wells. By comparing the experimentally measured data and the calculated results, the newly established method is indicated capable of significantly improving the interpretation accuracy of horizontal wells’ fluid production profile. The interpretation method is further extended to production logging for different well types. By applying this new methodology, the main water-producing layer can be precisely identified to prevent and control the water burst from the horizontal wells as well as the formation of water plugging. Consequently, the oil and gas recovery can be effectively enhanced.

Natural fault and fracture network characterization for the southern Ekofisk field: A case study integrating seismic attribute analysis with image log interpretation

Production from the Ekofisk Chalk Field in the North Sea is believed to be significantly influenced by the presence of a connected fault and fracture network. In the current study, we create a 3D seismic discontinuity cube which is representative of this network within the southern part of the Ekofisk Field. This is done using a multiscale workflow which integrates seismic fault and fracture detection with borehole image log interpretation from three horizontal well sections. The results show that faults and fractures are prevalent in the Ekofisk Formations. Within the study area, faults are mainly organised in three orientations: 1) WNW-ESE, 2) NNE-SSW and 3) NNW-SSE. Smaller E-W striking faults are also observed. The interpreted fractures show a similar pattern and are organized in four orientation groups: NW-SE, WNW-ESE, ENE-WSW and NE-SW. The analysis of seismic discontinuity data (i.e. faults and fractures detectable on seismic) indicates that most small-scale discontinuities occur in proximity to large faults, and that the Lower Ekofisk Formation is characterized by more widespread – and a higher intensity of small-scale seismic discontinuities. It is also demonstrated that along each studied well section, the extracted seismic discontinuities show a qualitative correlation with the image log interpretation. This correlation suggests that the 3D seismic discontinuity cube can serve as a proxy for the fault and fracture network in the southern part of the Ekofisk Chalk Field. Following from our key findings, we conclude that the presented workflow and results could provide a starting point for future studies assessing the impact of natural fractures in the Ekofisk – and other complex reservoirs.

FischerLab: An Application for Generating Fischer Plots and Dynamic Fischer Plots from Wireline Well-Logs and Stratigraphic Data

Fischer plots are a technique that is used to graph changes in accommodation in cyclic carbonate successions. They typically depict the cumulative departure from the average cycle thickness as a function of the cycle number or stratigraphic depth. Many applications of Fischer plots focus on their construction from exposed cyclic carbonate successions. No published programs allow the direct construction of Fischer plots from digital wireline well-logs or dynamic presentations of Fischer plots. Here, we introduce a program known as FischerLab, which facilitates the generation and analysis of Fischer plots. In addition to accepting interpreted stratigraphic data input, FischerLab facilitates the interpretation of digital wireline logs for the generation of Fischer plots in cycle and depth domains, as well as in a dynamic evolving cycle and relative depth domain from an easy-to-use interface. The dynamic construction facilitates the correlation of specific stratigraphic packages to parts of the accommodation cycle while simultaneously tracking the locus of the mean subsidence vector. We demonstrate the use of FischerLab on data derived from the carbonate succession outcrops of the Al-Athrun Formation, Libya, and the Glen Rose Formation, Central Texas, USA, as well as on wireline well-log data from the Western Great Bahama Bank, the Bahamas.