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Reservoir quality is one of the important geological factors controlling the development of tight oil in the Honghe oilfield, Ordos Basin, northwestern China. Analyses of core, well logging, mud logging and geophysical data as well as thin sections (casting and fluorescence) were combined with testing methods (such as grain size analysis, constant-rate mercury injection, and scanning electron microscopy) to characterize the micropore–throat development in reservoirs of the eighth member of Yanchang Formation in the oilfield. From the perspective of sedimentation and diagenesis, the mechanisms causing reservoir quality difference were explored and a method for characterizing reservoir quality difference and distribution was proposed. The results show that complex and diverse pore–throat configurations and multi-scale throat development are the microscale manifestations of reservoir quality differences in the member. Three types of pore–throat combinations are recognized, including intergranular pore-wide lamellar throat, intergranular and intragranular pore-wide lamellar throat, and intergranular/clustered micropore-wide lamellar throat. Different diagenesis processes and intensities under the control of sedimentary conditions determine the differential development of the reservoirs. Diagenetic facies are the indicators of reservoir quality. Diagenetic facies with chlorite cementation-moderate dissolution indicates reservoirs with the most ideal physical properties for hydrocarbon accumulation, while that with moderate calcite and kaolinite cementations are usually observed in reservoirs with less ideal physical properties. Reservoirs with the worst physical properties often correlate with diagenetic facies with strong calcite cementation and compaction facies. A multi-level constrained method under the control of sedimentation and diagenetic facies is proposed for characterizing tight reservoir quality difference in the member. The spatial distribution of sedimentary elements is analyzed through sedimentary configurations, the diagenetic facies distribution is constrained by sedimentary elements and the reservoir quality distribution is predicted with constraint of diagenetic facies. It suggests that the high-quality reservoirs in the member occur vertically in the middle of thick channel sandstone, while poor reservoirs occur in the upper or lower parts of the channel sandstone due to intensive compaction and cementation. Laterally, the quality of reservoirs enhances along the channels with a change in shape to lens or strips along the middle and downstream sections.

Effect of depletion rate on wellbore stability due to production of oil from hydrocarbon-bearing reservoirs is important and can result in a reduction of the reservoir pore pressure. A reduction in the reservoir pressure, in turn, results in a change in the stresses acting within the reservoir. If these changes are not well analyzed and applied in future calculations, we may be unsuccessful in some cases such as drilling infill wells or extended wells, forecast of sand production and optimum flow rate, preventing of casing collapse, etc. Therefore, knowing the stresses around the well at every stage of production is fundamental to the next calculations. In this paper, we recognized these changes in near-wellbore stresses using data from logging (image log, dipole sonic, full set log, mud log), production data, information from kick, blow out, loss etc. and determined it using Techlog software and theoretical calculations. Three wells of two huge oilfields of SW Iran were investigated after depletion or production for long years. In each well, state of stresses were calculated in cases of safe drilling mud weight using log data and theoretical equations. At the end effect of depletion rate on wellbore stability was investigated in these three wells.

The fracturing of naturally fractured volcanic rocks has a significant impact on the logging due to the high degree of volcanic fracture development and the complex distribution of fractures. Such impact ultimately leads to the difficulty in determining the location of fracturing perforations and the increase in engineering costs. This article proposed a method of analyzing cuttings for geologging that return to the ground when drilling. After cleaning and further processing of the cuttings, samples at every depth are formed. Then, an electron microscope and supporting processing software are used to calculate the parameters of the sample at each depth and the rock mechanical parameters in the target well section based on the mineral content. Compared with mud logging data, the mineral analysis method of rock cuttings costs less time, and the materials are easier to obtain, thereby providing richer data. This method has an important guiding role for the selection of perforation positions in large-scale hydraulic fracturing.

The overall development of the top of the gas reservoir of the Dengying Formation, Upper Sinian in the Anyue Gas Field of the Sichuan Basin, has been deployed, and the inner Dengying Formation is the next potential succession layer. However, the high-quality reservoirs of inner Dengying Formation are undeveloped and cannot be identified on the seismic profiles, which restricts its deepened understanding, exploration and development. In this paper, the logging and seismic response characteristics of high-quality reservoirs were analyzed using the mud logging and well logging data of the Anyue Gas Field, and a seismic response model for high-quality reservoir was established by means of seismic forward modeling. Then, the target processing was carried out for the problem of weak effective signals. Finally, the plane distribution of high-quality reservoirs of inner Dengying Formation and the favorable exploration areas were predicted. And the following research results were obtained. First, there are two types of high-quality reservoirs inside the Dengying Formation, i.e., concentrated vug type and independent cave type. Vertically, the independent cave reservoirs are mainly distributed within 100 m above the mudstone floor of the third Member of Dengying Formation. Horizontally, karst zones are developed along the bed. Laterally, they are scattered and beaded. And the scale is small. Second, seismic response of high-quality reservoirs inside the carbonate rocks is characterized by single-peak concealed “beaded” reflection, whose peak energy is relatively weak and can be easily covered by the noise of seismic data. Third, deep-seated weak signal recovery and processing technology can be used to deal with the weak seismic response of high-quality cave reservoirs, improve the amplitude preservation and S/N ratio of seismic data, and obtain the beaded reflections on seismic profiles so as to realize effective identification of high-quality cave reservoirs. In conclusion, the deep-seated weak signal recovery and processing technology is proved to be operable because the achieved results conform to the drilling data and the seismic forward modeling conclusions. In addition, high-quality cave reservoirs are developed at the bottom of the fourth Member of Dengying Formation, and they are locally distributed in a large scale. Therefore, it's one of the favorable succession layers for the following natural gas exploration and development of the Anyue Gas Field. Keywords: Sichuan Basin, Anyue Gas Field, Late Sinian, Inner Dengying Formation, High-quality reservoirs, Cave, Beaded reflection, Multiple wave, Weak signal recovery, Succession layer series

The Early Jurassic rock of Alan Formation in Barda Rash field has been examined using petrophysical wireline log analysis, drilling stem test, mud logging reports, drilling cutting and core samples for evaluation of reservoir potentiality and fluid production throughout heterogeneous rocks intervals in three exploration and appraisal wells. The Alan Formation consists of intercalation of light, chalky and argillaceous limestone beds with shale layers in the upper part and dominantly anhydrite layers from the middle to the lower parts of the formation. Qualitatively, weak oil shows of light brown to dark brown and blackish heavy oil have been observed while drilling. Furthermore, light brown trace oil has been recorded in the fracture surfaces of the core samples. The wireline log analysis provided an overestimated result for the hydrocarbon bearing interval identification and fluid movability index as the anhydrite layers confused the fluid distribution detection in the drilled interval. However, the combined results achieved from the mud logging reports and drilling stem tests were operated within the drilled intervals shown a limited productivity levels from the limestone beds of the Early Jurassic Alan Formation. The oil production from the studied interval does not exceed 10% and the entire production rates were composed of formation water with a trace amount of gases. As a result, the Early Jurassic Alan Formation can be considered as a tight carbonate reservoir rocks in the Barda Rash field.

Rock typing is an extremely critical step in the estimation of carbonate reservoir quality and reserves in the Middle East. In order to recognize the rock types of carbonate reservoirs in the Mishrif Formation better, classify the reservoirs accurately, and establish the permeability model in line with the study area precisely, it is necessary to study the recognition method conforming to the actual situation of the study area. The practice shows that the current recognition methods based on capillary pressure curve, flow unit and NMR logging data can effectively distinguish rock types, but a large number of accurate experimental data are required, which can only be applied in a few cored well, however, cannot be applied in the whole oil field. In this study, based on core, thin section, logging data, the sedimentary characteristics of carbonate reservoir, logging response of four rock types as well as porosity and permeability characteristics of Mishrif Formation in W are comprehensively studied. Based on Bayesian stepwise discriminant theory in multivariate statistics, the Bayesian discrimination model based on conventional logging data is established. The examining results showed that, compared with the description of logging and coring, the accuracy of Bayesian discriminant model and cross confirmation rate have achieved more than 80% for the original sample. Reliability verification showed that the matching degree of the rock type recognized in the non-cored well with the core and mud logging was as high as 90%, which matched the depositional environment of the entire region. The study results confirm the validity and generalizability of the Bayesian method to identify and predict rock types, which can be applied to the entire Middle East region to solve the problem of the lack of core data to accurately evaluate the quality of non-cored wells and accurately predict production, meeting the needs of actual reservoir evaluation and production development in the Middle East.

The Tertiary rocks of Khurmala Formation in the Taq Taq oil field have been studied using wireline log analysis, drilling cutting descriptions with integration of mud logging report, and test results for understanding reservoir potentiality and fluid distribution. The formation comprised dolostone and dolomitic limestone with an intercalation of clay layers between the recognized beds. The formation has variable thickness throughout the field, 99.8 m from the northeastern limb and 109 m in the southeastern plunge. The calculated shale volume in the studied interval shows a high rate of the clay contents which in some points the gamma ray has 100% of shale. The corrected log-derived bulk porosity subdivided the Khurmala Formation into 5 porosity units from the top to the bottom including (Kh-1, Kh-2, Kh-3, Kh-4, and Kh-5). The first (Kh-1), third (Kh-3), and fifth (Kh-5) porosity units have the average porosity ≥0.10 (10%) that can be considered as good reservoir unit in terms of porosity, whereas the shale contents reduced the reservoir quality of these units. However, well hydrocarbon entrapment through interconnected fractures and fault in the other Tertiary reservoir was recorded in Taq Taq field , but the weak connectivity of the pores in the Khurmala Formation caused this rock interval remains as water bearing zone.

The rate of penetration (ROP) plays a major role in drilling optimization, which makes it an important area of investigation. In this work, sensitivity and statistical analysis were carried out using a big set of data gathered from over 800 wells in the Basra oil fields, Iraq. The main objective of this investigation is to assess the effect of mud weight (MW) on ROP and to provide a method for estimating the recommended range for operational mud weight based on the rock hardness. The collected data for the drilling intervals from the drilling reports for over 800 wells in the Basra oil fields, Iraq, were categorized as weak, medium, hard, and very hard, based on the unconfined compressive strength (UCS), depth, and lithology. Statistical and sensitivity analyses were conducted and correlation coefficients (CC) were developed to describe relationships between rock hardness, ROP, and MW from field data. This methodology combines data from mud logging, daily drilling reports, and geological information to investigate the relationship between ROP and MW for different rock types and strengths. Several previous studies focused directly on MW, where the effect of MW on bit conditions, and thus the ROP was clearly demonstrated. However, these studies did not take into consideration the rock hardness or lithology. There is also a strong discrepancy between results from different studies, where some studies showed an inverse relationship between MW and ROP, while other studies showed it was a direct relationship. In this study, field data have been gathered (more than 800 wells) to further investigate the relationship between MW and ROP, and how it varies with rock hardness. The results showed that MW has an inverse relationship with ROP for the weak formation with a CC of −0.57, suggesting that the MW should be maintained as minimum as possible when drilling through the weak formation. On the other hand, MW showed a direct relationship with ROP for medium, hard, and very hard formations with CC of 0.31, 0.4, and 0.42 respectively. Hence, MW has to be maintained as high as possible to maximize ROP for medium, hard, and very hard formations. Large-scale collection and interpretation of field data were collected to demonstrate the effects of MW on ROP with varying rock hardness and lithology. While field data of this scale is inherent of interest, this analysis also investigates relationships previously unexplored and extends understanding of how MW effects ROP.

The BZ19-6 deep buried-hill structural belt in the southwest of Bozhong Sag, Bohai Bay Basin, is a newly discovered super-giant oil and gas bearing area. The study on its reservoirs is still in the early stage, and the characteristics and control factors of reservoir development are not understood deeply. In this paper, cores, sidewall cores, rock sections were analyzed and described. Then, based on regional structural setting, mud logging and logging data, the buried-hill reservoirs in this area were analyzed from the aspects of petrological characteristics, reservoir space types and physical properties, the inherent factors influencing the development of the reservoirs were discussed, and distribution laws of the reservoirs were investigated. And the following research results were obtained. First, the deep buried-hill reservoirs of this belt are a pan-buried hill reservoir system composed of the Palaeocene–Eocene Kongdian Fm glutenite in the upper part and the Archean buried-hill metamorphic granite in the lower part. A multi-layer reservoir structure of glutenite pore zone, weathering crust dissolution fracture zone and inner fracture zone is formed. These reservoirs are complex in genesis and diverse in type. Second, the Archean buried-hill metamorphic granite reservoir can be vertically divided into weathering crust, inner fracture zone and tight zone, and it presents the dual characteristics of porous and fractured media. Third, the buried-hill weathering crust is mainly affected by strong dissolution and leaching superimposed with fracturing, forming fractured-porous reservoir space. The reservoir of inner fracture zone is mainly controlled by the superimposition of three-phrase fractures, which forms the main development period of buried-hill fractures since the Yanshanian. Fourth, the glutenite of Kongdian Fm is a typical sieve deposit and it is mainly controlled by the late dissolution. Fifth, migmatization and supercritical fluid cryptoexplosion play a constructive role in the development of the reservoirs. In conclusion, the understanding of buried-hill glutenite and metamorphic reservoir system developed in this belt is conductive to determining the target and direction of next oil and gas exploration in this area. Keywords: Bohai bay basin, Bohai sea area, BZ19-6 deep buried-hill structural belt, Archean, Deep metamorphic granite reservoir, Paleogene, Glutenite reservoir, Dissolution, Structural fracture

Strong heterogeneity, poor pay reservoir connectivity, and complex micro-pore structure are the reasons behind the high difficulty and low accuracy in the productivity evaluation of tight sandstone gas reservoirs. This paper utilized various well logging and mud logging curve data, summarizes the typical curve type, and made use of a mathematical method to form quantitative characterization. Additionally, a logging curve evaluation method is proposed based on the test of production capacity. The total hydrocarbon curve can be divided into six types as shown by the results: box shape, half box shape, upright triangle, inverted triangle, sawtooth shape, single peak, etc. The above is closely related to the level of oil and gas in the reservoir layer. Six types of total hydrocarbon curve can be quantified by amplitude, relative centroid, relative sawtooth, variance, and the parameter value of the autocorrelation function. The box-shaped total hydrocarbon gas logging curve is full and has a large scale. The half box-shaped total hydrocarbon gas logging curve peak scale is significantly smaller than that of the reservoir thickness. The triangularly-shaped total hydrocarbon gas logging curve may either be an upright or inverted triangle. The sawtooth-shaped total hydrocarbon gas logging curve has high and low tendencies that show a number of spikes. Single peak-shaped total hydrocarbon gas logging curve is small with a single peak. There is a good relationship between the six kinds of total hydrocarbon gas logging curve and the tight sandstone gas reservoir production capacity. The high and middle gas pay layers are mainly box-shaped and triangular, whereas the lower production layer is half box-shaped, triangular, and has a zigzag pattern. However, the low gas pay layers mainly possess a sawtooth pattern, while the non-production layer is mainly single peak in shape. The comprehensive interpretation of the total hydrocarbon gas logging curve and log resistivity curve can more accurately distinguish the production capacity of tight sandstone gas reservoirs. Finally, the quantitative model is used for automatic interpretation. Through data verification and analysis, it is found that the coincidence rate of the production gas pay layer is 80.95%, whereas the coincidence rate of production capacity is 78.05%. It is proven by practice that the gas formation capacity of tight sandstone gas reservoirs can be predicted based on the logging and mud logging well curve shapes. Keywords: Method of total hydrocarbon gas mud logging curve, Tight sandstone gas, Reservoir, Fracturing production well capacity

The Chang 81 Member, Yanchang Formation in Huanxian area, Ordos Basin, China, is a tight sandstone dominated reservoir with low porosity and low permeability. The contribution of pore fluid to well logging response is greatly reduced, and the resistivity of oil layer and water layer are close, which bring great difficulties to the fluid identification and logs interpretation. In this paper, we first analyzed the genetic mechanism of the low-resistivity oil pay layer in terms of reservoir petrological characteristics, irreducible water saturation and formation water salinity. The high content of clay and complex pore structure resulting in high irreducible saturation which leads to additional conductivity; and the formation water salinity has great difference in this area. In order to reduce the influence of the formation water salinity difference on the fluid identification, we separated the study area into normal oil pay region and low-resistivity oil pay region based on the relationship between formation water salinity and formation resistivity. Then, double apparent formation water resistivity difference method, fluid identification factor cross-plot method, full hydrocarbon mud logging and well logging hybrid method and the normal distribution method were established in two different regions, respectively. The comparison of different fluid identification methods show that full hydrocarbon mud logging and well logging hybrid method is the best method for fluid typing of oil layer, oil-water layer and water layer. Double apparent formation water resistivity difference method is not effective to distinguish the oil-water layers from the water layers and oil layers, and the normal distribution method is not applicable for distinguishing the low-resistivity oil pay. In the case study, the above methods are together used to identify the fluids of the reservoirs, and the application result indicates that comprehensive analysis of multiple methods can effectively improve the accuracy of fluid typing.

Determination of petrophysical parameters from surface measurements of drill cuttings, rather than well logs, has long been a subject of interest in the petroleum industry. Analysis of cuttings is presently included in mud logging workflows, although the methods employed tend to be labor-intensive and inefficient with an emphasis on qualitative lithological and mineralogical descriptors. Nuclear magnetic resonance (NMR) has the potential to deliver rapid formation evaluation at the rig site for near-real-time completion decisions. Despite numerous efforts to demonstrate NMR cuttings analysis, dating back to the 1980s, the technique has yet to achieve commercial success. We suggest this failure is due not to the physics of the measurement, which is understood, but rather to inadequate sample preparation. By centrifuging brine-saturated cuttings from conventional formations under a per-fluorinated oil, and using multinuclear NMR to measure liquid volumes, we obtain accurate porosity and permeability values independent of other measurements. Our robust workflow removes the inconsistencies associated with manual sample preparation. We present two case studies and the important requirements for handling actual drill cuttings.

The Sinian Doushantuo Formation is the oldest shale gas reservoir discovered in the world, which contains good shale gas shows as the Eyangye-1 and Zidi-1 wells in the Yichang Region of western Hubei province, China. The shales in the Doushantuo Formation feature considerable thickness (135 m), high gas content (4.83 m3/t) and high fragile mineral content (up to 75%). Due to the influences of the sedimentary environment, the shale reservoirs here have high dolomitic content (54%) and abruptly changes in vertical lithofacies. Moreover, the characteristics of the shale sweet-spot differ significantly from that in the Wufeng Formation and Longmaxi Formation in southeast Sichuan Basin. A high-resolution sequence stratigraphic correlation was performed on the shales of the Doushantuo Formation at the Eyangye-1 well, Zidi-1 well, Zidi-2 well and some outcrop profiles in Yichang area for the identification of their sedimentary microfacies characteristics. A comprehensive comparative analysis was made by incorporating the elemental geochemistry, wireline and mud logging data of the well to further identify the sweet-spot interval therein. With the analysis of Eyangye-1 well, the sweet-spot interval of the Doushantuo Formation is 3360−3408 m, of which sedimentary microfacies is deepwater reduced environment with many pyrite laminaes, and the TOC is high to 3.42%, the Ro is 3.3%, the organic and matrix pore are well developed and the aperture more than 50 nm, the porosity is 2.7%, the desorption gas content average is 2.16%, and the main mineral is dolomitic (54%) and siliceous quartz (21%). Additionally, these parameters combined with previous studies will shed light on evaluating and characterizing the layers therein, also provide referential geological data for the following exploration and development activities of this shale system.

Underground strata are reflected in various information sources in petroleum exploration, including good logging and drilling data. Real-time measurement parameters obtained from mud logging can provide data support for the early discovery of oil and gas resources and the prevention of safety accidents. It plays a forward-looking role in the drilling process. In this paper, we aim at the defection of fuzzy and random characteristics of the big data of drilling element parameters in the current drilling process. A new method named grey wolf optimization-support vector machine (GWO-SVM) is proposed by analyzing the relationship between logging data and formation to solve the serious problem of formation misjudgment. Using element content and Gamma-ray value, data mining is performed by a large number of real-time data obtained from the drilling site. The obtained information is used for comprehensive estimation and prediction of strata. First, the data is normalized, and then, the best $\zeta $ and $\sigma $ values are found through the optimization of gray wolf algorithm, next the SVM training is carried out, finally, the formation prediction model is established, and the error analysis of the results was conducted. In the paper, the algorithm model is subsequently applied to three actual wells. The GWO-SVM model based on drilling data is used to predict the formation, and the error analysis showed that the error range of the GWO-SVM algorithm is within 10%. Compared with the GWO-SVM, the model accuracy of SVM, Particle Swarm Optimization-Support Vector Machine (PSO-SVM) algorithm is lower 53% and 23%, respectively. The GWO-SVM has higher robustness, reliability, and achieves faster convergence speed, stronger generalization effect, and improves the identification accuracy of elements for the formation. The average accuracy of the GWO-SVM in stratum dynamic identification is 93.5%. This model is implemented to support the logging system to improve application strength.

Prediction of penetration rate (ROP) is important process in optimization of drilling due to its crucial role in lowering drilling operation costs. This process has complex nature due to too many interrelated factors that affected the rate of penetration, which make difficult predicting process. This paper shows a new technique of rate of penetration prediction by using artificial neural network technique. A three layers model composed of two hidden layers and output layer has built by using drilling parameters data extracted from mud logging and wire line log for Alhalfaya oil field. These drilling parameters includes mechanical (WOB, RPM), hydraulic (HIS), and travel transit time (DT). Five data set represented five formations gathered from five drilled wells were involved in modeling process.Approximatlly,85 % of these data were used for training the ANN models, and 15% to assess their accuracy and direction of stability. The results of the simulation showed good matching between the raw data and the predicted values of ROP by Artificial Neural Network (ANN) model. In addition, a good fitness was obtained in the estimation of drilling cost from ANN method when compared to the raw data.

By means of chemical combination between the Polydimethylsiloxane (PDMS) layer and Polyethersulfone (PES) layer, a kind of PDMS/PES composite membrane was prepared for separation of the light hydrocarbon components from the drilling mud. Meanwhile, its separation performance of the light-hydrocarbon components from the drilling mud was investigated and evaluated quantitatively. Results showed that the prepared PDMS/PES composite membrane had good mechanical performance, and it was resistant to corrosion of the water-based drilling mud. The PDMS/PES composite membrane can work stably at 5 MPa and 393 K. The responding time of the membrane to sudden change of the hydrocarbon gas content was less than one minute. For either single phase flow or gas-liquid two-phase flow, a high flow rate was recommended to avoid non-ideal flow patterns and to increase mass transfer in the feed channel of the membrane cell. Results in this work could be helpful for further application of the membrane technology in geological mud logging.

The coal measure of Middle Jurassic Walloon Subgroup is the main reservoir of coalbed methane (CBM) reservoirs in the Surat Basin, Australia, and it is a set of typical low-rank, high-yield coal measure. To figure out the CBM accumulation conditions and enrichment models of this coal measure, its distribution characteristics, source rock characteristics, reservoir characteristics and preservation conditions were investigated based on mud logging, experimental and testing data. Then, based on the analysis results of gas origin and gas bearing property of this coal measure, 3 CBM development areas in northeastern Surat Basin were analyzed and compared in terms of its gas enrichment model, and favorable conditions for CBM accumulation and enrichment of Walloon coal measure (WCM) was summarized. It is indicated that tectonic movements, groundwater conditions and macerals provide favorable conditions for gas generation of Walloon coal. The roof, floor and interbed of this coal measure are lithologically tight, presenting a good sealing capacity. Besides, the Walloon CBM reservoir is a mixed origin gas reservoir with the secondary biogenic methane as the dominant component formed in a monocline structure jointly sealed by hydrodynamic force and lithology. CBM enrichment is controlled by 3 factors, i.e., local structure, methane generating capacity of coal bed and underground hydrodynamic force, and it can be divided into 3 models, i.e., anticline model, syncline model and slope model, among which, the CBM enrichment degree of the former two models is higher. Finally, different from other CBM reservoirs, the Walloon CBM reservoir satisfies four favorable conditions in CBM accumulation and enrichment, including dual-carbon source, efficient methane generation, moderate hydrodynamic force and double sealing. Keywords: Australia, Surat Basin, Jurassic, Walloon coal measure, CBM, CBM accumulation condition, CBM enrichment model

Rate of penetration (ROP) enhancement serves as a key factor in reducing drilling time and hence drilling costs. ROP enhancement requires identification of the parameters affecting this rate. However, the large number of effective parameters, which are further immersed in noise, makes it difficult to present a highly accurate and comprehensive model. In the present research, in order to predict the drilling ROP in one of the vertical wells drilled into the Karanj Oilfield, a hybrid model composed of a multilayer perceptron (MLP) neural network together with either a particle swarm optimization (PSO) algorithm or a cuckoo optimization algorithm (COA) was used. For this purpose, first petrophysical logs and drilling data were denoised using the Savitzky–Golay filter. Then, the 'plus-l-take-r' method was used to select superior features. Feature selection results indicated that an increase in the number of input parameters tends to reduce the error associated with the estimator model; however, the error reduction rate was seen to be negligible for models with five or more input parameters. Therefore, five parameters were considered as input parameters in MLP-COA and MLP-PSO hybrid models: rotary speed, weight on bit, shear wave slowness, compressional wave slowness, and flow rate. A comparison of errors and coefficients of determination in the training phase of the two models indicated that MLP-COA model tended to converge way faster and more accurately. The small difference in generated error using this model between training and testing phases indicated the high reliability and generalizability of the model. Comparing the results of the model trained with raw and denoised data against the same set of selected features clearly showed the positive effect of the denoising step on the accuracy of the model. Validation of the proposed model via the multilinear regression method was indicative of the superior performance of the MLP-COA model, so that it could be confidently stipulated that this model can be used to estimate the ROP at other vertical wells near the studied well. Further, provided the required information is available, this method can predict the ROP to high accuracy in vertical oil and gas wells.

To control the human factor risk for oil and gas drilling industry, the types of work activities involved in drilling were identified, the major accident risk types of human errors were selected, the probability and severity levels of the risks associated with each activity were quantified, and the human factor risk levels of major work activities involved in drilling processes were calculated. Quantitative results demonstrate that the highest risks during the drilling process include being struck by an object, injury by machine, and overexertion; conversely, the lowest risks include exposure to harmful substances or environments and fire and explosion. The highest risk activities are associated with, for instance, penetration drilling, the trip in and out, and the hoisting and lifting operations. Conversely, the relative lowest risk activities include auxiliary operations, well logging and mud logging, equipment inspection and maintenance. The total risk value of all main drilling activities is 11.3947 S/w-h. Twelve risk control measures were selected, and the Delphi method was taken to quantify the human factor risk mitigation capacity resulting from the selected risk control measures. The results demonstrate that the human risk control measures exist in three tiers of effectiveness, with each tier being separated by nearly an order of magnitude. The types of most risk mitigation are risk codes, such as injury by machine, fall from height, and contact with harmful material. The most minimal risk mitigation types include muscle strain and fire and explosion. Finally, these data will be valuable for drilling companies to strategically allocate limited resources to their safety management plan, and they can evaluate the expected effectiveness resulting from risk control measures.

During the past ten years an enormous development in mud logging technology has been made. Traditional mud logging was only qualitative in nature, and mudlogs could not be used for the petrophysical well evaluations which form the basis for all subsequent activities on wells and fields. AML however can provide quantitative information, logs with a reliability, trueness and precision like LWD and WLL. Hence for well evaluation programmes there are now three different logging methods available, each with its own pros and cons on specific aspects: AML, LWD and WLL. The largest improvements have been made in mud gas analysis and elemental analysis of cuttings. Mud gas analysis can yield hydrocarbon fluid composition for some components with a quality like PVT analysis, hence not only revolutionising the sampling programme so far done with only LWD/WLL, but also making it possible to geosteer on fluid properties. Elemental analysis of cuttings, e.g. with XRF, with an ability well beyond the capabilities of the spectroscopy measurements possible earlier with LWD/WLL tools, is opening up improved ways to evaluate formations, especially of course where the traditional methods are falling short of requirements, such as in unconventional reservoirs. An overview and specific examples of these AML logs is given, from which it may be concluded that AML now ought to be considered as “first among its equals”.

The present work is devoted to study the geologic setting, reservoir characterization and hydrocarbon detection with conventional and advanced well log methods for Kafr El-Sheikh Formation at Sapphire field, Offshore Nile Delta, Egypt. The used wells are Sapphire-Da, Db, Dc, De, Dh and Dq. By using open hole logging tools, advanced logging tool like Modular dynamic tester (MDT), Mud log during drilling and conventional core that analyzed carefully, to detect the clean sandstone and thin bedded sandstone of the study Location. These basic well log tools (Gamma Ray, Resistivity, Density and Neutron) reflectclean sandstone reservoir with good way, but can’t detectthin bedded sandstone reservoir, as a result of their low vertical resolution, this may miss several intervals charged with hydrocarbons during perforation and production from the field.So, we should run advanced tool like the Modular Dynamic Tester (MDT) and analyze conventional core, if found, and the hydrocarbons in Mud log to detect these missed intervals. Also by using the conventional cores and mud logging while drilling. The results had showed clean sandstone and thin bedded sandstone reservoirsthroughthe advanced well log tools, which identify more than 68% deep water reserve didn’t use beforethis should be takeninto consideration in the future wells, workover wells, excellent distribution of facies in both the static and dynamic models, to increase the hydrocarbon production and life time of producible wells. . The optimum location for forthcoming wells is south west of the field, because it has the best petrophysical parameters. It has high porosity, hydrocarbon saturation, and net to gross, in addition to low shale volume.

High-yield gas layers, low-yield gas layers and (gas bearing) water layers of Upper Paleozoic coexist in the Shilijiahan zone in the northern Ordos Basin, but gas–water distribution characteristics, laws and influence factors are not understood well, so the exploration and development of natural gas in this zone are restricted. In this paper, statistical analysis was carried out on the data of Upper Paleozoic formation water in this zone, e.g. salinity, pH value and ion concentration. It is shown that the formation water in this zone is of CaCl 2 type. Then, the origin, types, controlling factors and spatial distribution characteristics of formation water were figured out by using core, mud logging, well logging and testing data, combined with the classification and evaluation results of geochemical characteristics of formation water. Besides, the logging identification chart of gas, water and dry layers in this zone was established. Finally, the occurrence and distribution laws of reservoir fluids were defined. The formation water of CaCl 2 type indicates a good sealing capacity in this zone, which is favorable for natural gas accumulation. It is indicated that the reservoir fluids in this zone exist in the state of free water, capillary water and irreducible water. Free water is mainly distributed in the west of this zone, irreducible water in the east, and capillary water in the whole zone. The logging identification chart has been applied in many wells in this zone like Well Jin 86. The identification result is basically accordant with the gas testing result. It is verified that gas and water layers can be identified effectively based on this logging identification chart.

The Wu 2 section of the Ke017 well block is a low-resistance gas reservoir with ultralow porosity and low permeability. The comprehensive analysis of rock lithology, physical properties, sedimentary characteristics, and gas content demonstrated that the development of micropores in illite/smectite dominated clay minerals together with the resulted additional conductivity capability and complex reservoir pore structures, as well as the enrichment of self-generating conductivity minerals like zeolites and pyrite which were the formation mechanisms of low-resistance gas layers in the Wu 2 section. A low-resistance gas reservoir has poor physical property, and it is difficult to distinguish the oil layer from the dry, gas, or water layers. In this paper, based on well/mud logging data and laboratory data, by taking advantages of the “excavation effect” of neutron gas and the dual-lateral resistivity difference between different depths, we successfully established a set of low-contrast log response methods for the identification and evaluation of oil layer and formation fluids. For a gas layer, the difference between neutron porosity and acoustic (or density) porosity is smaller than 0 and the difference in dual-lateral resistivity is greater than 0. For a water layer, the neutron porosity is similar to the acoustic (or density) porosity and the dual-lateral resistivity difference will be less than 0. While for a dry layer or a layer with both gas and water, the difference in porosity as well as dual-lateral resistivity is very small. The proposed method effectively solves the technical problem of oil layer and formation fluid identification in low-resistance gas reservoirs.

This study presents the log analysis results of a suite of conventional wireline logs including gamma ray, density, neutron, and resistivity from two wells in ‘Ictorian’ Field located in the Niger delta with the aim of evaluating hydrocarbon prospect of the field. Results obtained showed presence of hydrocarbon in eleven (11) reservoirs from well 1, and four (4) reservoirs from well 2. Well 1 and 2 both had hydrocarbon reservoir bearing gas. Well 1 had Gas Water contact at 2497m and 2964m, while well 2 had Gas water Contacts at 1739m and 2510m. Effective porosities had values ranging from 26-16% in well 1. In well 2, effective porosities had values ranging from 22-17%.The values obtained show that the analysed reservoirs have good permeability. The calculated values indicate that porosity, permeability values from the hydrocarbon bearing reservoirs are good enough for commercial accumulation in the Niger Delta. It is recommended that for field optimization mud logging data and core data analysis should be integrated as part of the evaluation exercise. Keywords: Reservoir, petrophysical properties, reservoir quality, wireline logs

Petrophysical evaluation from laboratory and well logging data, such as gamma ray, Nuclear Magnetic Resonance (NMR) and resistivity has been used to identify and evaluate oil zones in reservoirs. Gamma ray log is able to predict lithologies along the well, and X-ray Diffraction (XRD) and X-ray Fluorescence (XRF) techniques also provide important lithological laboratory information. The NMR log directly estimates the porosity of the rock. Resistivity log identifies the water region, but cannot provide information about oil saturation. However, the application of unconventional techniques, such as Electron Spin Resonance (ESR), can be of great relevance in the well logging, adding information about lithologies, oil quality and saturation. The ESR technique, which can directly estimate the oil saturation inside the rock, can also provide important information about the origin and formation of rocks. This technique could be an advance for the oil industry, helping to understand the geothermal processes suffered by the rocks and identifying important regions of the reservoir. Thus, in this work, we studied carbonate rock (limestone and dolomite) samples with and without oil, by ESR technique. Firstly, the effectiveness of ESR in the differentiation of carbonates (calcitic and dolomitic) without oil was tested, through the analysis of manganese ion impurity, which promotes the replacement of calcium and magnesium ions in calcites and dolomites. The samples had a typical manganese ESR signature. The hyperfine parameter, A, was homogeneous for both limestone and dolomites. The zero-field split parameter, D, showed variability, as reported in the literature. The studies were carried out at X-band frequency. The analysis by XRF and XRD provided information on the chemical and mineralogical composition of the carbonates, which were added to the ESR data for application in a correlation matrix, by which it was identified that the components CaO and MgO were directly related to the intensity of the ESR signal and the concentration of CaO was inversely related to the concentration of Al2O3 and SiO2. In one limestone rock sample was incorporated oil, with 25° API and moderate biodegradation level, to identify by ESR, the oil presence inside this rock. The technique was able to identify the oil and its saturation in the rock through the detection of free radical signal, g = 1.9951. The innovative application of the ESR technique to identify oil in varying saturation, in carbonate rock samples from the Illinois Basin (USA), was successful. These results demonstrated that this technique in addition to being accurate, non-destructive and relatively low cost, could be used in mud logging operations providing results for lithological characterization, oil identification and its saturation inside the reservoirs.

The problem of lost circulation is a direct consequence of the presence of fractures or high permeability. Lost circulation material (LCM) is used to treat the loss that occurs or proactively strengthen the wellbore of the potential loss zones. The polyacrylamide (PAM)/Polyethylenimine (PEI) cross-linkable polymer gel is proven to work best in zone-sealing and plugging applications. In addition to their thermal stability, the fact that these gels are flexible gives them the advantage of deforming and sealing-off multiple and complex near wellbore fractures. The primary objective of this study is to investigate the gelation kinetics of the PAM/PEI cross-linkable polymer to be used in drilling fluids formulations to enhance wellbore stability and strength. Different combinations of polymers and crosslinkers were evaluated; potential polymers were screened for gelation kinetics and gel strength in typical drilling mud formulations. The gelation time of the polymer-based drilling mud formulation is determined in salt-free and in saline systems. The results on rheological properties and gelation kinetics were used to prepare a gelling mud formulation using PAM/PEI cross-linkable polymer as LCM. The produced gel was thermally stable under high-temperature-high-pressure reservoir conditions, which will result in enhanced wellbore strengthening. This paper was made possible by an NPRP Grant # NPRP10-0125-170240 from the Qatar National Research Fund (a member of Qatar Foundation ). The statements made herein are solely the responsibility of the authors. Scopus

Biostratigraphy is a key upstream activity. Drilling operations use biostratigraphic data derived from core samples extracted via boreholes (mud logging) in order to guide drilling processes and verify models of basin geology. Current manual data analysis relies on the existence of sufficient numbers of biostratigraphers to be available to fulfil industry needs. However, due to factors such as retirement, and that the number of people being trained in the requisite taxonomic skills has declined sharply over the last couple of decades; the available pool of expertise is dwindling. It is clear that if the high cost of drilling operations is taken into account, the current situation is untenable and in many ways represents a perfect storm. This pessimistic situation can be radically changed by augmenting human expertise using automated species identification tools based on artificial neural network technology. DAISY [Digital Automated Identification System], a proven system of this sort, could revolutionise commercial biostratigraphy operations by enabling microfossil identification to be undertaken by technicians. This would yield immediate benefits for the industry as it would permit routine work to be performed quickly and accurately by less skilful, cheaper and therefore more available staff; freeing biostratigraphers to concentrate on non-routine, more complex tasks. The feasibility study presented here indicates that DAISY can consistently identify microfossils to species, with repeatable, high levels of accuracy. Crucially, it can also act as a permanent repository for taxonomic knowledge, which is currently lost when experienced personnel retire. There might also be additional environmental and social benefits if this technology is widely adopted within the oil and gas sector: as DAISY technology is generic, it can easily be re-targeted to interpret seismic data or even to estimate the impact of upstream exploration activities on abutting ecosystems.

Located in the Sichuan Basin, the Yuanba Gasfield is the deepest marine sour gas field among those developed in China so far. Its biohermal gas reservoir of the Upper Permian Changxing Fm is characterized by ultra depth, high content of hydrogen sulfide, medium–low porosity and permeability, and small reservoir thickness. Economic evaluation on it shows that horizontal well drilling is the only way to develop this gas reservoir efficiently and to reduce the total development investment. At present, the petroleum engineering technology for this type of ultra-deep sour gas reservoir is less applied in the world, so an ultra-deep horizontal well is subject to a series of petroleum engineering technology difficulties, such as safe and fast well drilling and completion, mud logging, well logging, downhole operation, safety and environmental protection. Based on the successful development experience of the Puguang Gasfield, therefore, Sinopec Southwest Petroleum Engineering Co., Ltd. took the advantage of integrated engineering geology method to carry out specific technical research and perform practice diligently for 7 years. As a result, 18 key items of technologies for ultra-deep sour gas reservoirs were developed, including horizontal-well drilling speed increasing technology, horizontal-well mud logging and well logging technology, downhole operation technology, and safety and environmental protection technology. These technologies were applied in 40 wells during the first and second phases of productivity construction of the Yuanba Gasfield. All the 40 wells have been built into commercial gas wells, and the productivity construction goal of 3.4 billion m 3 purified gas has also been achieved. These petroleum engineering technologies for ultra-deep sour gas fields play a reference role in exploring and developing similar gas reservoirs at home and abroad.

The Yuanba giant gas field in the Sichuan Basin produces from Upper Permian Changxing heterogeneous reef-shoal reservoirs. It is an ultradeep tight gas reservoir with burial depth of 7000 m. This paper proposes an integrated methodology incorporating the reservoir geology description, petrophysics characterization, seismic response analysis, forward seismic modeling, pseudo-acoustic inversion, and reservoir architecture imaging to identify the geologically complex reef-shoal reservoirs and predict the distribution of the producible reservoirs. The facies of reef cap, reef core, reef base and shoal are first identified based on observations and interpretations of cores, thin sections, mud logging, wireline logs, and formation microscanner images (FMIs). High-energy shoals, reef cores, and reef caps are the most favorable reservoir microfacies. Seismic responses of reef-shoal reservoirs are then investigated through forward modeling and well-seismic calibration. Four reef belts are identified based on seismic reflections and edge detection by seismic paleogeomorphologic features. Reservoir distribution and quantitative properties are predicted using the facies-controlled postattack seismic inversion technique through the correlation between reservoir properties and seismic attributes, which is aided by pseudo-gamma acoustic inversion to exclude the shale-bearing non-reservoir and pseudo-neutron acoustic inversion based on its good relationship with porosity. The reef reservoir thicknesses range from 10 m to 130 m, and the thickest reservoir is located in the northwestern Yuanba gas field. Finally, 3-D visualization is used to characterize the spatial variation of the interior architecture, connectivity, and distribution of a good reservoir in the reef system. The accuracy rate of prediction for reservoirs and non-reservoirs reaches 88% using this method. The technique has also been successfully used for the deployment of development wells and well trajectory optimization, and the rate of encountering the predicted reservoirs is 100%. This study provides a practical approach to identify and predict the tight carbonate gas reservoir with similar petrophysical responses of density and acoustic to non-reservoirs in the complex carbonate system.

MPFM (Multi Phase Flow Meter) is an on field tools to measure the flow and compotition of crude oil during mud logging process. This tool unit operated beside logging well area so the result can be obtained directly on site. Because of remote access in mining location, a small and lighter measuring unit tools required in order to have easy transportation, storaging and installing of the unit. The MPFM Single line unit then developed to answer this problems VDI 2221 design methode is using to design this new unit where the primary data gathered from litercy study, interview with the company’s management staffs and operators. This design methode obtain 4 product variations where 1st Varian was choosed as the best design. Keywords: MPFM, VDI 2221, Design Methode, Mechanical Design.

Recently, people are increasingly interested in horizontal directional drilling (HDD) to construct oil and gas pipeline and utility pipeline in the urban area as one of trenchless methods. One of major issues during the HDD is the collapse of borehole, which may be the potential causes of ground collapse. This study investigated the effect of mud pressure on the borehole stability, using finite element analysis. Since the borehole is being drilled with a certain angle, three dimensional analysis should be performed. The borehole stability was examined by applying two different types of mud pressures, i.e., uniform and non-uniform, to the exterior surface of borehole. The results show that the high mud pressure at the beginning of drilling, i.e., at shallow depth, causes the borehole collapse, whereas the borehole was stable even at high mud pressure as the drilling depth increases. It can be said that the determination of maximum mud pressure is strongly related to the drilling depth.

Resistivity logging is one of the most important ways of identifying and estimating the saturation level of gas hydrates in permafrost and ocean regions. in practical drilling operations, resistivity loggings, especially shallow lateral resistivity logging in gas hydrate bearing sediments (ghbs), are likely to be affected by drilling mud invasions. here, we use available data from site measurements to construct a two-dimensional model for hydrate reservoirs around the borehole sh2, a hole that was drilled during the first expedition in shenhu area of south china sea to examine and drill into gas hydrates. we then use this model to investigate the characteristics of drilling mud invasions and the effect of drilling mud properties (e.g., temperature, density, and salinity) on resistivity logging using a numerical simulation. this simulation and associated calculations indicate that shallow lateral resistivity logging is significantly affected by variations in drilling mud temperature, which leads to hydrate dissociation and the formation of secondary hydrates. increasing drilling mud salinity accelerates hydrate dissociation, and has a greater effect on shallow lateral resistivity logging than the free gas produced during drilling and any potential mud density influence, which is generally dependent on the depth at which the drilling mud invasion occurred. this means that future drilling operations should focus on ensuring that the temperature, salinity, and density of drilling muds remain within a reasonable range in order to minimize the effect of mud invasions on resistivity logging data. (c) 2014 elsevier b.v. all rights reserved.