bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhancing Design-by-Analogy Procedure of Injection-Well Gel Treatment Sizes by an Integrated Survey of Case Histories
Authors: Aldhaheri Munqith , Almansour Abdullah , Zhang Na , Wei Mingzhen , Bai Baojun 
Published: February 2022

Abstract
The drive to mitigat water production continues to increase the interest in applying conformance-control gel treatments in mature oil fields. Practically, designs of new gel treatments are adopted from previous case histories conducted in analogous reservoirs. This design-by-analogy procedure requires reservoir engineers to have a thorough knowledge about how gel treatments should be designed and have been mostly applied for each reservoir type.
This paper presents comprehensive design guidelines for sizes of injection-well gel treatments based on an integrated survey of worldwide field projects. It also provides the typical and most-applied treatment volumes per reservoir type to be used as a starting point in planning of new jobs. The survey includes 61 gel projects compiled from SPE papers and conducted in 11 different countries between 1985 and 2014. Summaries and distributions of five gel-volume parameters were evaluated using the univariate descriptive analysis and stacked histograms. Scatterplots were used to determine effects of the formation temperature and the treatment timing on treatment volumes. The unsuccessful pilots were compared with productive gel projects to indicate the causes of pilots’ failure.
The survey showed that the typical treatment size is 10,700 barrels, 310 barrel per perforated foot, or 19% of the moveable-pore-volume (MPV) of problem zones. Overall, gel volumes are greatly affected by the formation type and larger treatment volumes are placed in sandstones than carbonates and in matrix-rock than other formation types. Frequently, matrix-rock formations are treated with gel volumes &gt;100 bbl/ft while treatment sizes &lt;100 bbl/ft are used to treat naturally-fractured and unconsolidated formations. Gel volumes &lt;3000 or even &lt;1000 barrels are used to treat pipe-like channels in unconsolidated sandstones, treat matrix-rock formations without crossflow, or in economically-designed gel treatments. We have found that increasing the gel volume improves all treatment performances, not just the oil production response, and for all formation types, not just for the matrix-rock reservoirs. Hence, the ‘bigger is better’ rule of the gel volume is also recommended for fractured and unconsolidated formations as for the matrix-rock reservoirs. Instead of searching the literature for few analogs, the new survey provides conformance specialists with a complete overview of gel treatment sizes for all reservoir types. This would markedly facilitate designing of gel treatments and save time needed to identify the analogs for a given candidate reservoir.
Machine Learning Assisted Reservoir Properties Prediction in a Brownfield Offshore Malaysia
Authors: Kasim Fadzlin Hasani , W. Muhd Zainudin W Nur Safawati , Kantaatmadja Budi Priyatna , Ahmed Siddiqui Numair , Sidek Akhmal , Yahaya Nur Aqilah Nabila 
Published: February 2022

Abstract
Accurate prediction of porosity and permeability are crucial to the understanding of fluid distribution and hydrocarbon potential within targeted reservoir. However, increasing reservoir heterogeneity always possess a challenge to conventional method that simplify these complexities, while the high cost of coring acquisition makes it more difficult to validate the result. This paper describes an innovative technique for reservoir properties prediction that combines well logs, core analysis and machine learning tested at 5 wells located in a brownfield offshore Malaysia.
Standard well logs of gamma ray, bulk density and neutron porosity were used as main inputs with routine core analysis as targeted outputs. The inputs data were checked and corrected for any light hydrocarbon or borehole washout effect that may affect the learning process. Due to nonlinear relationship between the variables, classification machine learning method of Random Forest was chosen for the study. The ratio of training and blind test was set at 70:30. The algorithm then tested at 100% of the data and benchmarked with core porosity, core permeability and human evaluation judgment based on well logs response at uncored interval.
Both porosity and permeability prediction showed R2 of 85% and 80% during blind test which indicated high reliability on training model algorithm. In general, prediction result has a very good correlation with core data at good and thick sand. While at shaly sand, the correlation quality was reduced. At uncored interval, the prediction quality showed a realistic reading when comparing with well logs data response. This further proved the confident in the machine learning algorithm away from core interval. The R2 for porosity prediction was observed higher compare to permeability with average of possibly due to smaller scale ranges.
The study showed another perspective to predict reservoir properties using a data driven approach and indicated a very promising result. No constant was used as compared to empirical calculation which introduced less uncertainty into the model. With reduce dependability in core data, the saved cost can be utilized in another multidiscipline task to increase the hydrocarbon recovery.
First Metal to Metal Dual Auto Switch ESP
Authors: AlOlaywat Ali 
Published: February 2022

Abstract
Electrical submersible pump providers are always collaborating with client to overcome the challenges of costly ESP change out by offshore workover rigs and the conventional well intervention by offshore barges, in addition to the harsh reservoir environments due to high H2S and high temperature. Accordingly, operating companies are keen to minimize the number of ESP failures and avoid costly offshore workovers especially in high producers and when the demand of production is high. In effort to improve the ESP reliability and ensure continuous production, several recent technologies were combined to boost the run life of the overall completion.
The combination of these technologies improved the run life and the reliability of the system and resulted in massive financial impact as it saves rig cost, Barge cost, wireline cost, operations cost and more importantly the deferred production.
This paper will elaborate in details about the technologies utilized in this completion and how it caused considerable financial impact on both vendor and client.
Innovative Retrofit Straddle Deep Gas Lift Technology for Enhancing Oil Production
Authors: Tyagi Himanshu 
Published: February 2022

Abstract
This paper outlines an approach to enhance production from a deep, moderate bottomhole-pressure (BHP) reservoir in a mature offshore oilfield by using deep gas-lift technology. Enhanced software-based analysis, design and optimization has proved to be effective in enhancing the production rate from an existing gas-lifted well.
The deep gas lift system (DGLS) incorporates tubing directly above the packer and straddles the lowest gas-lift mandrel, using thru-tubing packers, with a two-piece straddle/crossover assembly and a dip tube extending to the desired depth. This system directs lift gas from the casing-tubing annulus via a special crossover assembly to the desired depth, with the resultant production returning via the dip tube annulus through the crossover to the tubing above. This assembly facilitates the deepest point of gas injection without applying additional backpressure on the formation.
A pilot project on four wells demonstrated a significant improvement in well performance with an incremental gain of 3,000 bpd. This system was installed in a well with 5.0 in. tubing to provide lift gas 2,800 ft. below the production packer and resulted in 700 bpd augmentation of production from the well. A conventional gas-lift installation cannot reach any deeper than the production packer and, in most cases, significant depth above the lowest perforation remains sheltered. A distinctive retrofit straddle-deep gas-lift system (DGLS) was designed for a major operator to enable lift gas to reach the lowest perforations. It provides an efficient means of lowering the flowing bottom-hole pressure beyond the capability of a standard gas-lift system.
This paper considers multiple scenarios that help revive and elevate a potential hydrocarbon source and recommends suitable actions that allow production engineers to analyze performance of an oil well. With the increased complexity of mature fields, each next step to improve recovery comes with increased cost. Therefore, novel horizons of affordable technology will play a pivotal role to maximize economic recovery and meet rising demand in the current business environment.
Joint Implementation of Ensemble and Deep Learning Regression Techniques to Predict Missing Density Logs
Authors: Dabi Shubham , Vishwakarma Anmol , Maiti Saumen 
Published: February 2022

Summary
This paper shows the study of the construction of a few models based on machine learning regression techniques with various applications. Fulfilling the need of missing well log data, here density log, by training the model from other wells is one of those applications that helps in proper analysis of the reservoir properties. The predictions are based on two regression approaches, Ensemble Learning and Deep Learning. Followed by the necessary preprocessing steps, the models were trained on the twenty wells and assessed for their density predictions on the two new wells. The neural network model based on the deep learning approach was tested for the different numbers of hidden layers, neurons, batch size, epochs, etc. The other two algorithms, namely Gradient Boosting and Random Forest, are based on Ensemble Machine learning approaches which were also assessed for the prediction based on their specific variables. The predictions were plotted for all three algorithms and confronted with the actual data. The accuracy of the models was known by determining the Root Mean Square Error (RMSE) for each prediction. All the predicted results by our three models follow the original trend even at the layer interfaces. Finally, the results were matched with those obtained from Gardner's relation (Gardner et al., 1974), which correlates the layer density with its seismic compressional velocity. The models can be improved in efficiency through the training from the wells selected from the identical lithology. However, this approach proves to be a reliable and valuable tool as it helps in predicting missing logs, which saves the high measurement costs. Also, they can predict the missing logs for the undrilled future wells locations, which eliminates both the expensive cost and extensive time of the drilling and core sample measurements.
Three-Phase Saturation Evaluation Using Advanced Pulsed Neutron Measurement
Authors: Mostefai Ilies , Van Steene Marie , Al-Mulla Ali 
Published: February 2022

Abstract
Accurately monitoring saturation change mechanisms requires adequate surveillance methods and techniques. We present a methodology to evaluate three-phase saturation using an advanced pulsed neutron measurement. This is a complex reservoir monitoring situation, where gas saturation must be monitored in addition to oil saturation, in a variable water salinity environment.
An advanced pulsed neutron logging tool provided robust thermal neutron measurement (hydrogen index) for gas quantification. Formation capture cross section (sigma) was not used for water saturation because of its sensitivity to water salinity, which changes vertically and laterally in the subject field. The apparent volume of oil from the tool's improved-precision carbon/oxygen (C/O) method provided a salinity-independent indicator of oil saturation. Since this C/O apparent oil volume combines the carbon contributions from oil and gas, elemental modeling provided the apparent oil volume response to gas. Lithology information and porosity from initial formation evaluation were also entered in a linear solver to resolve water, oil, and gas volumes.
This methodology was applied in wells where all three fluid saturations (water, oil, and gas) were expected to change over time. Surveys were taken at regular intervals over a span of several years. With the improved precision of the advanced pulsed neutron measurement, it was possible to precisely map the saturation changes with time in the field and identify variations in the fluids’ volumes down to a few porosity units. This information was critical in understanding fluid movements inside the reservoir.
This is the first implementation of this technique. The precision brought by the advanced pulsed neutron tool provides superior results for monitoring a complex fluid mixture.
Acoustic Telemetry Enhances the Safety and Efficiency of MPD Operations
Authors: Groves Duncan 
Published: February 2022

Abstract
Managed Pressure Drilling (MPD), along with variations such as Controlled Mud Level (CML), underbalanced drilling, mud cap drilling and drilling with losses, which will all collectively be referred to as MPD for brevity, is widely used to access reservoirs that cannot be safely or efficiently drilled into by using conventional mud pressure and circulating pressure to manage overbalance, well bore stability and a range of other concerns that are well known.
MPD surface systems, of which there are many types and more detailed informationon on their functionality can be found in other papers, in conjunction with mud pulse based MWD systems transmitting downhole pressure are used to calibrate the whole wellbore system in a process known as finger printing, which is primarily used to calculate the frictional pressure drops around the entire system. These includes the surface pressure pumping equipment, the drillstring, annulus and back pressure system and chokes. The results of the finger printing are used as inputs to the MPD control systems to manage back pressures during the drilling of the well and these can be updated by using the MWD annular pressure measurements.
This can be time consuming, but when combined with high accuracy flow meters has resulted in being able to successfully drill many wells.
A Novel Technique on Microseismic - EDFM Fracture Modeling and Calibration for Complex Fractures in Unconventional Reservoirs
Authors: Mahmoud Salah El din Ragab , Alshmakhy Ahmed , Leines-Artieda Joseph Alexander , Al-Jabery Fatema , Liu Chuxi , AlHarthi Amena , Yu Wei , Fiallos-Torres Mauricio Xavier , Miao Jijun , Sepehrnoori Kamy 
Published: February 2022

Abstract
Hydraulic fracture models are useful mechanisms to understand reservoir properties and performance in unconventional reservoirs. The inclusion of field measurements can further refine hydraulic fracture models by providing key information to optimize field development planning. Microseismic data remains as one of the most accessible types of field data, which can help understanding reservoir extension. Additionally, microseismic data is useful to assess well interference and extracting average hydraulic fracture geometry. However, an efficient method to extract cluster-based hydraulic fracture models from microseismic data is absent due to loss of spatial accuracy of current techniques when used in reservoir simulations. Moreover, accessibility to hydraulic fracture propagation simulators may add up to the challenge of producing reliable and fast estimates of fracture geometry.
In this paper, our main objective is to efficiently reconstruct a hydraulic fracture model using microseismic data and combine it with a history matching workflow in order to optimize field development planning in a shale gas well. We created a fast and efficient cluster-based hydraulic fracture reconstruction tool, which uses microseismic events’ spatial distribution to create hydraulic fracture models represented by the embedded discrete fracture model (EDFM). Our workflow can include different sets of discrete fracture network (DFN) models, in order to assess their interactions with hydraulic fractures. We used two different DFN models: original DFN model and DFN represented by the activation of natural fractures during well stimulation. Finally, we calibrated our hydraulic fracture and DFN models to production data. We efficiently modeled the effective hydraulic fracture geometry that contributes to production by including spatial cut-off coefficients, which reduce fracture geometry in the history matching process.
The results of this novel workflow produce not only efficiently calibrated hydraulic fracture models, but provides valuable insights regarding hydraulic fracture geometry and their interaction with natural fractures. Additionally, the inclusion of cut-off coefficients allows to model the effective contribution of hydraulic fractures after calibrating fracture geometry with production data.
Integrated Approach for Formation Water Salinity Determination
Authors: Alshaikhmubarak Tariq , Mira Laila , Ghadiry Sherif , Mattar Tariq 
Published: February 2022

Abstract
In exploration areas formation water salinity is often unknown. Several log-based techniques can be used to estimate the water resistivity, which can be used to calculate the equivalent formation water salinity, such as the Pickett's plot technique or spontaneous potential (SP log) but remain subjected to some uncertainties. Although captured down hole samples can accurately determine salinity, it can take a long time to receive the laboratory analysis results, delaying the Field Development Plan (FDP) studies and affecting current logging operations decisions.
In this paper, we tested two methodologies. First, we utilized a novel dry weight chlorine (DWCL) measurement from an advanced spectroscopy tool to estimate the formation salinity at the depth of investigation of the device. This newly introduced methodology can be used in areas where formation salinity is unknown. The second methodology uses a new downhole induction resistivity cell in the formation tester tool. This cell gives a calibrated direct measurement of the water resistivity in the flowline, which can be converted into an equivalent water salinity if temperature is provided, and cross-checked with the DWCL values from the spectroscopy tool.
The new chlorine measurement, along with the flowline induction resistivity measurement, provides a robust workflow to estimate the formation water salinity, enhancing the quality of the saturation evaluation for quick decision-making during logging operations, and accelerating the evaluation studies rather than waiting on laboratory results.
Definition of Well Operating Envelope for Floating Rig During Well Testing Operations
Authors: Zinzani Giacomo , Stocchi Donatella , Vanoli Antonio , Carfora Luca , Arcelloni Alberto , Mastrocola Carlo , Leo Giuseppe , Pasquali Paolo Giovanni , Borra Simone , Sala Gianluigi 
Published: February 2022

Abstract
The purpose of this document is the definition of the operational areas for floating rig during well testing operations, depending on the depth of water and meteorological conditions.
The main problem for a floating system is the station keeping. In order to operate, in fact, the rig must be located around the well.
Considering the Rig-Riser-BOP system, the latter is fixed to the bottom, while the rig is subject to the forces of the wind, waves and currents that cause it to move from the vertical of the well.
As the rig moves, the riser tilts and lowers relative to sea level. At the same time, the telescopic joint and the tensioners extend up to their maximum available.
Once these limits have been exceeded, the riser-rig connection is no longer guaranteed because either the telescopic joint goes out of travel, or the tension cables break.
In the Well Testing phase, this situation is aggravated by the presence of the string inside the riser.
Its position is fixed; therefore, a lowering of the riser corresponds to a lowering of the string at the end of which is the flowhead. It must be ensured that the lowering of the riser is less than the maximum distance flowhead – rig floor.
Therefore, while the operational limits of a rig are dictated by the telescopic joint and by the tensioners, the operational limits for the test phase are dictated by the flowhead-rig floor distance.
In order to avoid reaching these limits and endangering the safety of the system, areas are defined in which it is possible to operate, carry out the test, or areas where it is necessary to disconnect the riser and make the system safe.
Applications of Computer Vision and Deep Learning in Visual Features Extraction of Drill Bits
Authors: Lu Baoping , Xu Ting , Huang Yuebin , Tao Xingang , Zhang Hongbao , Yang Shunhui , Jiang Jun , Hou Xutian , Rached Rached , Wang Zhifa 
Published: February 2022

Abstract
Drill bit dull grading provides basic information for bit performance evaluation, drilling parameters optimization and BHA optimization. Traditional dull grading standard from IADC depends on visual inspection, which is subjective, low accuracy & efficiency and of lower information dimension. Computer vision is one of the most mature applications of artificial intelligence. In petroleum engineering, researchers started to use image processing to evaluate bit damage. But there are technical challenges for wider usage of this technology due to accuracy of object detection and image classification in complex environments, integrative description of 3D objects, various bit profiles, cutter structures and dull shapes, etc.
More than 3000 images of bits before and after drilling are collected and pre-processed for the research. A workflow to detect objects (bit, blades, cutters, nozzles, etc.) in images are designed, and the performance of several front-edge algorithms are compared, such as Faster RCNN, Yolo, etc. and several methods are used to improve detection performance in complex light environment. Multi view images fusion was conducted for an integrative view of bit picture for integrative bit dull grading report. Structured light camera is tested to improve the accuracy of 3D cutting features.
It's shown that the accuracy of object detection in wellsite environment is over 90% and Faster RCNN performs with more robustness. It's possible to generate 3D structures with multi view images or videos and the image resolution is critical to the definition of 3D images. Compared with common camera in mobile phone, structured light imaging features with higher accuracy in 3D structure mapping. The results helped to push the application of computer vision and AI in PDC bits evaluation at the well sites.