bluuebunny/crossref_metadata_2025 huggingface dataset:
Scrutinizing Wells Integrity for Determining Long-Term Fate of a CO2 Sequestration Project: An Improved and Rigorous Risk Assessment Strategy
Authors: Patil Parimal Arjun , Hamimi Asyraf M , Abu Bakar M Azuan B , Das Debasis Priyadarshan , Tiwari Pankaj Kumar , Chidambaram Prasanna , B. A. Jalil M Azran
Published: February 2022

Depleted hydrocarbon reservoirs are considered inherently safe for carbon sequestration, but high well density penetrating the CO2 storage reservoir could compromise the containment performance in a carbon, capture & sequestration (CCS) project. Based on the available well data, it is crucial to understand the age of the well, materials used for wellbore construction, cement quality, barriers performance, and well integrity. A risk management methodology can be incorporated to evaluate primary and secondary barriers in existing plugged and abandoned (P&A) and development wells to ensure long-term fate of CO2 sequestration project.

Existing P&A wells and development wells in a depleted field were drilled 3–5 decades ago. The wellbore construction utilized non-corrosive resistant materials. Health of all wells that ever penetrated the CO2 storage reservoir need to be analyzed from long term perspective of storing CO2. Throughout the lifespan of wells, subsurface barriers should maintain hydraulic isolation to prevent leakage happening from subsurface to environment of reservoir fluids and injected CO2. Deterioration of strength of wellbore construction material due to corrosion, induced by downhole pressure and temperature conditions, should be considered. This study investigated 3 exploration and 21 development wells. Risk register was developed for each well describing causes and CO2 leakage risks, impacts and consequences. Metrics were defined for parameters such as well age, well head materials, wellhead functional test and leak test, sustained casing pressures for risk determination. Wells were risk rated individually based on the assessment. Wells with low risk can be utilized for well conversion. While for high-risk wells, an opportunity risk matrix was developed to mitigate risks in all the wells.

This study evaluates the well integrity and CO2 leakage risk along the wells that penetrated the CO2 storage reservoir. The improved rigorous risk assessment exercise evaluates well barrier failure causes and impacts along with estimating the risk number per well. The well risk assessment score calculated was between 9.24 and 13.35 for 21 development wells. Out of these 21 wells, 4 wells with risk score <10 can be utilized for wells conversion. Specific barrier restoration process by additional scope of work such as lower completion removal including packer milling, intermediate casing removal, or installation of downhole permanent barriers with remedial cement is discussed for designing the well abandonment process to minimize leak potential of high-risk wells for ensuring long-term containment security. Improved rigorous well integrity risk assessment for CO2 storage field is decisive for any CCS project economics that utilizes barrier identification process and remedial actions.
Innovative Technical Strategies in Natural Fracture Characterization for Well Placement: Case Study from Darajat Field, Indonesia
Authors: Joonnekindt Jean Pierre , Diaz Francisco , Davies Russell , Hultzsch Paul , Mulyani Sri , Intani Rindu , Putra Fanji , Meiyanto Meiyanto , Nordquist Gregg , Golla Glenn , Gunderson Rich
Published: February 2022

The Darajat geothermal field, located in West Java, Indonesia and operated by Star Energy Geothermal, has a long history of production with about 30 wells in which image log data are available. The subsurface geometry of the field was characterized initially from remote sensing methods and surface geology to locate the intrusions, faults and rock units comprising the reservoir, and later validated by well data. Reducing the uncertainty in future well locations depends on models of natural fractures applied and used successfully in oil and gas reservoirs, and associated permeability sweet spot maps. The modeling of natural fractures is determined by results from "drivers" calibrated to fractures interpreted in borehole image logs. These drivers most typically include distance-to-fault as in a damage zone, but also geomechanical methods that model fractures in the perturbed stress field around mapped faults. We modified the drivers to include the effects of the pressurized volcanic intrusions and their cooling for this geothermal field. These drivers were applied in sequential steps and fractures generated from the driver-specific constraints were compared against those observed in the well log images to define an intensity. In this paper we describe novel methods to characterize fractures to generate sweet spot maps for drilling locations in the Darajat geothermal field.
A Novel Portland Cement for CO2 Sequestration by Nanoparticles
Authors: Tiong Michelle , Gholami Raoof , Li Yisong
Published: February 2022

Global warming is a critical issue that has garnered significant attention during the last few decades. This temperature increase results from the emission of greenhouse gases into the atmosphere, most notably CO2. Carbon Capture and Storage (CCS) technology has been established as one of the most successful ways to store CO2 in underground layers and prevent it from being released into the atmosphere. However, CO2 is difficult to contain in subterranean layers subjected to high-pressure, high temperature (HPHT) conditions due to the degradation of Portland cement caused by chemical interaction with wet/dry CO2. Numerous studies have been conducted to increase the cement's resistance to CO2 attack, but limited effectiveness has been found when these methods have been evaluated under various settings. Given the distinctive properties of nanomaterials, such as high surface areas, quick contact, and resilience to heat, Nano Glass Flake (NGF) and Multiwall Carbon Nano Tube (MWCNT) were deemed to be suitable additional materials for increasing cement efficiency.

On cement samples treated with NGFs and MWCNTs, a number of pre-carbonation and post-carbonation tests were performed. The pre-carbonation tests revealed that the density of NGFs-based cement remained constant with that of neat cement while the plastic viscosity increased. Additionally, it was recommended not to add more than 1wt% NGFs to the cement, as this would result in a high viscosity paste, which would negatively affect the pumping operation. On the other hand, this threshold for the viscosity of MWCNTs was roughly 0.25wt%. It was found that by using nanoparticles and employing a proper dispersion process, the cement's overall physical performance can be improved, and a lower amount of Portlandite is formed, which is critical for increased resistance to CO2 attack.

In a static reactor, samples with the best pre-carbonation performance were subjected to water saturated supercritical CO2 for 56 days. It was then discovered that CO2 diffuses into cement and increases cement decomposition in the post-carbonation stage of the experiment. Samples weighing more than 0.5wt %. NGFs and 0.05 wt% MWCNTs had the smallest carbonated regions, indicating carbonated cement. However, the number of nanoparticles added to each sample resulted in a variable level of carbonation. Cement made using MWCNTs has a higher compressive strength due to its ability to manipulate CaCO3 crystal shape. NGFs-based cement, on the other hand, could be a better solution in terms of CO2 resistance. Due to their substantially lower cost than MWCNTs, it is possible to increase cement performance in CCS operations without imposing a high cost on projects.
Optimizing Hydrogen Kinetics for Zero-Carbon Emission Transport Technologies
Authors: Park Ji-Woong , Pei Yuanjiang , Zhang Yu , Zhang Anqi , Som Sibendu
Published: February 2022

To achieve carbon neutral ambition, hydrogen (H2) has recently received significant attention as a zerocarbon fuel for internal combustion engines (ICEs) across transportation sectors. As a critical element in the analysis-led design process, a hydrogen kinetic mechanism needs to be thoroughly evaluated to support the development of high-efficiency H2-ICE combustion system concepts. In this study, recently published H2 kinetic mechanisms were reviewed and down-selected for evaluations against available laboratory data in ignition delay time (IDT) and laminar flame speed (LFS) measurements. The examination was subsequently extended to high-fidelity three-dimensional (3-D) computational fluid dynamics (CFD), spark-ignited, H2 engine simulations. Discrepancies identified at engine-relevant conditions led to a kinetics tailoring campaign based on the H2 mechanism developed by Burke et al. (2012). Selected reactions identified via global sensitivity analysis were optimized under the engine-relevant pressure-temperature conditions. The reaction rate coefficients were adjusted within the experimental and theoretical uncertainty limits by adopting a Monte-Carlo sampling approach as a searching algorithm to generate candidate mechanisms. Finally, the optimized mechanism was validated sequentially from low-dimensional (0-D and 1-D) to high-fidelity 3D CFD engine simulations. Overall, the optimized H2 kinetic model led to significantly improved predictions on capturing engine in-cylinder pressure trace and heat release rate.
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

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 >100 bbl/ft while treatment sizes <100 bbl/ft are used to treat naturally-fractured and unconsolidated formations. Gel volumes <3000 or even <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

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

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

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

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

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

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

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

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

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

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.
Breakthrough Innovative Solutions and Technologies for Greenhouse Gases Reduction
Authors: Al-Mahmood Moaath
Published: February 2022

Khurais Producing Department, as one of Saudi Aramco's producing facilities, is sharing this paper to highlight implemented breakthrough innovative solutions and technologies with massive positive impact on the environment. These technologies were introduced to increase the operation reliability, reduce the Greenhouse Gases (GHG) emissions and carbon footprint, and promote circular economy by optimizing power consumption, generating clean power, and eliminating daily routine flaring towards Saudi Aramco's ambition of achieving net-zero Scope 1 and Scope 2 greenhouse gases emissions by 2050, which is a step towards achieving Saudi Arabia's commitment to net-zero by 2060.

Driven by the commitment of Khurais managements toward the Saudi Aramco defined environmental protection policies through Khurais Environmental Management System (EMS) that meets the requirements of ISO 14001:2015 and strives for continual improvement, Khurais has set its objectives for protecting the environment and reducing the impact of its day-to-day operation on the surrounding environment. To achieve these objectives, Khurais has developed different plans, such as the Flare Minimization Plan and GHG Assurance Plan, and established key performance indicators (KPIs) through the Operational Excellence (OE) system to track and enhance the environmental performance of the facility.

To achieve the objectives identified by Khurais managements and to support their commitment plan for protecting the environment, different initiatives and technologies were deployed at Khurais facility which have significantly contributed to GHG emission reduction. The implemented initiatives include: a) construction of steam turbine generator (STG) part of the combined cycle cogeneration plant to generate clean power, b) installing flare gas recovery system to recover daily routine flaring from the facility, c) deploying the first worldwide Advanced Process Control (APC) for oil production wells for conventional oilfield for optimizing energy consumption, d) installing a swing line connecting all five oil trains’ HP Compressor suction lines to share the feed gas, e) flare minimization during running Oil Train-4 with bypassing damaged stabilizer which was a patented solution deployed to achieve the facility MSC post the attack on Khurais facilities, f) deployment of nonmetallic resin thermal pipe (RTP) material technology for over 60% of the massive crude pipeline network, and g) full deployment of closed draining systems through the construction of WOSEP blowdown system and automatic crude tank dewatering system.

This paper will share Khurais efforts in implementing these initiatives and technologies, which touch base on different sources for GHG emission from the facility such as power consumption, flared gas, and material release to the atmosphere. Identifying a plan and implementing these initiatives have contributed to reducing the GHG emissions from Khurais facility.
Rig Move Safety Optimization
Authors: Mahmood Tariq , Khan Zubair
Published: February 2022

The safety ofourRigmoves isofparamountimportance inour roleofexecuting this taskwithahigh KPI score.Our rigmoves must beperformed after properplanningwithmaximum safetyprotocols andwithin the target time frame from the old to new location.
Practicing Sustainability in Remote Location
Authors: Al Awadhi Ibrahim , Sharma Ashok , Karim Twana
Published: February 2022

Objective/Scope

Effective electrical and instrument control system is required for efficient operation of pipeline network. These equipment are kept in unmanned shelter with necessary cooling, as ambient temperature can go upto 54°C vs designed of 40°C. Pipelines and supply network often run through remote areas where usually no power supply is available. This puts heavy challenges to cooling inside shelters. This paper presents a unique approach adopted to enhance the shelter cooling performance in remote locations.

Methods, Procedures, Process

Conventionally shelter in remote area are Passive cooled shelter (PCS) where water in the exchanger is cooled by using lowest night ambient air. This water is circulated inside the shelter in closed circuit which cools the space by natural convection. High inside temperature (45°C) was recorded in some existing PCS. To assess reasons for high temperature, performance of PCS and heat dissipations of installed equipment against design values were evaluated. Furthermore, survey was performed for ambient and inside temperature during summer peak time instead of assuming ambient temperature of 54°C. Accordingly, the impact of maximum temperature on instrument was evaluated.

Results, Observations & Conclusions

Study concluded high inside temperature in PCS was due to high heat dissipation and external opening for ventilation in battery room.

Conventionally reduction in maximum temperature inside PCS can be carried out by increasing the capacity of installed external exchangers from existing 300 W/C to 600 W/C. Further benefits can be achieved by installing small fans next to the internal water tank and installing breather diaphragms with filter in external openings to reduce the heat input from outside. However, study concluded that with all this, minimum temperature inside PCS can be reduced to 42°C vs required 40°C as all installed equipment are designed to operate at max 40°C. This is due to high lowest ambient temperature during peak summer (36°C)

Due to remote location and non-availability of electric power, unique approach of additional cooling using Solar Hybrid A/C system was proposed without battery charger. Study concluded installing Hybrid Solar A/C system without battery charger can be operated during the summer peak time for period of 6 hours per day can bring down the inside temperature below 35°C throughout the year. Proposed solution is now successfully implemented in existing PCS and performance is found satisfactory during peak summer condition.

Novel/Additive Information

There is several PCS with similar issues and this unique approach of installing 24V DC Hybrid Solar A/C system is now being adopted in other PCS shelter which will support ADNOC Way by sustaining safe network operation and 100% HSE. There are large network of pipeline running in remote locations across the world where power availability is a concern and limit were above approach can be followed to realize larger benefits.
Merging Buoyancy Technology and Low Friction Centralizers in Deploying a Long 9-5/8" Casing String: Case History of an Ultra Extended Reach Well
Authors: Hussain Sajid , Harthi Fahad , Shaikh Alaa , Missiaen Francois Missiaen
Published: February 2022

Drilling into the fields with the presence of communities, will limit closer surface well placement and eliminate the option of conventional well design. With the continuous advancement of Extended Reach Drilling (ERD) technologies, it is possible to drill in such areas; although this approach does present numerous challenges in particular while casing deployment.

The project began by preparing a surface location which required a long stretch of the planned well to penetrate the reservoir target(s), thereby, placing it in the ultra-extended reach well category. Due to the shallow TVD and long well departure, the frictional forces developed in the horizontal sections were of significant magnitude. As a result of this, torque and drag were major challenges to overcome during casing running operations.

This paper will examine the planning, design, simulation and practices implemented during the (1) drilling of a 12.25 in. horizontal hole section with a stepout of over 16,000 ft., and (2) the deployment of a long 9.5/8 in. casing string with partial flotation and low friction centralizers technologies. Effectively deploying such a long 9.5/8 in. casing string to the bottom of this uniquely challenging wellbore, requires significant engineering and close operational scrutiny. This involves managing frictional and drag losses through effective hole cleaning practices and fluids performance. This study documents using both partial flotation technology and low friction polymer centralization where drag and torque limits, along with potential casing lock up were considered to allow for successful casing running operations. The casing flotation is allowed by employing a buoyant chamber length over 8,800 ft., thus effectively reducing drag in the lateral section as well as the required force to deploy the casing into the extended horizontal section. This results in complete buckling elimination and significant torque reductions. Tailoring the buoyant chamber length/capacity proves to be a critical factor to allow for extended formation exposure and/or reach for casing deployment.

A detailed pre-job planning methodology and modeling technique are provided to demonstrate the technical limits and improvement achieved with such technologies to effectively run the 9.5/8 in casing. Expected vs. actual friction factors will be defined and evaluated in order to enhance the assessments and predictions of the computational tools. A tailored methodology to tackle ERD challenges is also presented herein based on the combination of real time data vs. designed simulations.
Comprehensive Speed-Up Technology for Safe and Efficient Drilling Through Ultra-HTHP Huge Mudstone Formation in the South China Sea
Authors: Chen Haodong , Liu Hexing , Luo Ming , Jin Yan , Han Xu , Liang Jiwen , Wang Shiguo , Lu Yunhu
Published: February 2022

How to drill through the huge mudstone formation safely and quickly in the Ying-Qiong basin, western South China Sea has always been a significant problem in deep-water drilling. Under the action of the hydrostatic pressure of high-density drilling fluid and confining pressure of deep strata, ultra-HTHP huge mudstone presents viscoelastic and severe plastic characteristics. It is difficult for the bit to penetration the strata and slow down the rate of penetration. Although the thickness of mudstone is less than 30% of the total footage, the pure drilling time accounts for more than 75% of the total drilling time, which is difficult to meet the demand for economic and efficient drilling. In order to solve the problem of low ROP, the deformation and failure characteristics of huge plastic mudstone are found through the experimental test. The critical confining pressure of brittle plastic transition of mudstone is analyzed. The evaluation method of brittle plastic transition of mudstone and its influence on drillability is proposed. The personalized design and selection template of drill bits for plastic mudstone is established, and the personalized bits and drilling acceleration tools are optimized. The design scheme of safe drilling fluid density is put forward, which considers both wellbore safety and elimination of chip hold down effect. Considering the engineering and geological characteristics, the integrated drilling speed-up technology with high-efficiency rock breaking and wellbore stability is formed. Compared with field drilling, the ROP is increased by 82.6%. This technology can improve the drilling efficiency and significantly reduce the drilling cost, which provides a reference for speeding up drilling in similar formations.
Fatores que dificultam a aplicação do processo de enfermagem pelos enfermeiros da atenção primária à saúde
Authors: Macedo Evelin Reis , Basílio Ana Carolina Mendonça , Silva Bárbara Jordânia Rodrigues , Santos Brenda Domingos Vitorino , Andrade Clara Rodrigues de , Souza Gilberto de , Pardini Rafaela Dias
Published: February 2022

Objetivo: Identificar os motivos pelos quais os profissionais de enfermagem da Atenção Primária à Saúde (APS) não aplicam o Processo de Enfermagem (PE) adequadamente. Métodos: Trata-se de uma revisão integrativa da literatura que visou analisar os fatores que interferem na execução do PE. Para o estudo, utilizou-se artigos publicados nos anos de 2016 a 2020, coletados na BVS, a qual abrange bases de dados como LILACS, MEDLINE, SCIELO e BDENF, que estivessem em língua portuguesa e disponíveis eletronicamente na íntegra. Após as buscas nas bases selecionadas e atendendo os descritores e critérios pré-definidos pelos autores, foram selecionados 15 artigos para a amostra final. Resultados: As dificuldades que se apresentaram com maiores frequências foram as seguintes: falta de capacitação para aplicação do PE (30,7%), sobrecarga de trabalho (26,8%), falta de espaços físicos para realizar a consulta de enfermagem (CE) (11,4%) e desvalorização do profissional enfermeiro (7,7%). Os resultados do presente artigo evidenciaram diversos aspectos que dificultam a aplicação do PE pelos enfermeiros na APS. Considerações finais: Diante dessas informações, é possível traçar planos e estratégias para solucionar tais adversidades, a fim de estimular o uso dessa ferramenta tão importante para o desenvolvimento científico da profissão.
Mulheres Primigestas: um olhar sobre o desempenho ocupacional e o novo papel social de mãe
Authors: Lourenço Priscila Barros , Araújo Renilce Machado dos Santos , Pantoja Jorgeane Pedrosa , Toda Lívia Sue Saito de Oliveira , Costa Elson Ferreira , Oliveira Luísa Sousa Monteiro
Published: February 2022

Objetivo: Analisar o desempenho ocupacional e o novo papel social de mãe de mulheres primigestas. Métodos: Trata-se de um estudo transversal, descritivo, exploratório, quanti-qualitativo, com 10 mulheres primigestas, na faixa etáriaentre17 e 37 anos (com média de idade = 26,7), atendidas em um Centro de Saúde Escola, no período de julho e agosto de 2021. Resultados: No desempenho ocupacional as categorias que apresentaram diferenças nas médias foram: vestuário, sistema urinário e transferência. Quanto desempenhar o papel social de mãe, a maioria apresentou dúvidas relacionadas à futura rotina de cuidados com o bebê. Conclusão: Pode-se observar que o desempenho ocupacional da mulher primigesta tem comprometimento em pelo menos uma área de AVD e que o papel social de mãe ainda é visto como complexo, uma vez que o pré-natal ainda está focado mais no processo de gestação em si, assim pretende-se reforçar que a mulher primigesta receba orientações para melhor desempenhar suas tarefas ocupacionais e de seu bebê ainda durante o pré-natal.