bluuebunny/crossref_metadata_2025_split huggingface dataset:
Research and Application of Wellbore Fixed-Point Acidification Unblocking Technology for High Temperature and High Pressure Gas Wells
Authors: Wu Hongjun , Liu Ju , Wang Xi , Sun Tao , Kong Change , Liu Jiquan , Zhang Hui 
Published: January 2020

In recent years, the high temperature and high pressure gas wells production in Kuqa mountain front zone were severely restricted due to the blockage of the wellbore, which affected the efficient development of gas field group of the Kuqa mountain front. The Dina and Keshen blocks were the main gas fields and the wellbore blockage problem was more severe. The problem in the Keshen gas field was mainly concentrated in the Keshen2 block. More than 50% gas wells had that problem, which leaded millions of square meters of production loss compared with the full production. As for Dina gas field, the problem was severer and more than 80% wells had wellbore blockage problems, which resulted in reducing the gas production by more than half, and even shutting down the production.
For the severely blocked wells, the coiled tubing tool was used to unblock and the wellbore blockage sample was finely collected. It could be drawn that the wellbore blockage distribution was partly blocked and blockage position was likely to occur at the reduced diameter throttling tool or the screen pipe. The amount of blockage was less than 30L, and the main component of the blockage was measured as scale.
Based on the understanding of the blockage, a "9%HCl+1%HF" acid unblocking liquid system was developed. The dissolution rate of the liquid system to the scale was greater than 90%, and the dissolution rate of the formation sand sample was greater than 34%. For blocked wells with flow passages available in the wellbore, the wellbore fixed acidification was used and the unblocking process was that under the condition of controlling the pump pressure not higher than the maximum allowable pressure of the wellhead, acid unblocking solution was injected at low-displacement to dissolve the wellbore blockage and to restore gas well productivity. Compared with the coiled tubing sand washing, wellbore fixed acidification had the effect of better performance, simple process and low time consumption.
A total of 14 wells had a success rate of 100%. After fixed-point wellbore acidification, the single-well oil pressure increases by 30MPa. The amount of gas production was increased by 207×104 m3/d, and the open-flow capacity of 71% wells was equal or exceeded to the capacity at the initial production stage.
Improvements in Waste Heat Recovery Units Used in Oil and Gas Facilities
Authors: Siem Nelson 
Published: January 2020

The aim of this paper is to describe significant potential risks that were identified in a typical waste-heat recovery unit (WHRU) used in a natural gas processing unit and to recommend some improvements and best practices in order to minimize those potential hazards that might lead to operational incidents, particularly during the commissioning phase. A case study of a WHRU operating in a gas processing is taken as example and where a heating coil circulating a thermal fluid recovers the waste heat from the exhaust gas of a gas turbine that serves for power generation in the processing of raw natural gas. The potential risks identified are the possibility of coking formation in the circulating thermal fluid, the surge of high backpressure in the exhaust gas from the turbine and, finally, the possibility of corrosion in the dampers and heating coil.The paper provides valuable guidelines and best practices to prevent operational problems during the startup and operation of the WHRU from gas turbines. The recommendations are intended to minimize the risks by improving the sealing airflow to the main damper with the proper dimension of the piping network and by avoiding stagnant flow of the thermal fluid. Additional recommendations include monitoring constantly the exhaust gas backpressure to prevent the pressure surge, as well as the installation of mechanical devices that can prevent the full closure of the two dampers simultaneously. Finally, the selection of the recommended construction materials can minimize the potential risks of corrosion.
First Successful Installation of Progressing Cavity Pump System in an Oil Well at the Kingdom of Saudi Arabia
Authors: Zein El Din Shoukry Ahmed , Soltys Tim Wayne , Bettenson John , Ariza Gustavo 
Published: January 2020

This paper explains the benefits of using Progressing Cavity Pump (PCP) as a reliable Artificial Lift System (ALS) to be deployed during short term drill stem testing (DST) operations in mid to shallow heavy oil wells in Kingdom of Saudi Arabia.
A screening of the available ALS's was performed based on the selected candidate well's conditions. Aspects such as flow rate, API gravity, equipment installation simplicity and equipment capability for redeployment were evaluated in order to pick the most cost-effective option for this application.
During the planning stage in the development of a new oilfield, the selection of the artificial lift system (ALS) to be install is one of the more critical decisions. Aspects such as fluid flow rate, API gravity of the fluid to be produced, equipment installation simplicity and its capability for redeployment must be evaluated in order to pick the most cost-effective option for the application. The proper selection of the ALS will rely on the parameters previously mentioned as well as others. Below is a table that contains some parameters to be considered when evaluating ALS options
ALS application screening values.
Quantifying Separator Oil Shrinkage
Authors: Carlsen Mathias Lia , Whitson Curtis Hays 
Published: January 2020

In tight unconventionals, oil and gas rates are often measured daily at separator conditions. Consequently, it is necessary to reliably convert these rates to volumes at standard conditions in cases where direct stock-tank measurements are not available. Due to changes in producing wellstream compositions and separator conditions, the separator-oil shrinkage factor (SF) can change significantly over time. This paper presents a rigorous and consistent method to convert daily separator rates into stock-tank volumes. Recommendations for developing field-specific shrinkage correlations using field test data are also proposed.
To study how separator-oil shrinkage changes through time for tight unconventional wells, four reservoir fluids have been studied using a compositional reservoir simulator: (1) black oil, (2) volatile oil, (3) near-critical oil, and (4) gas condensate. All the simulations were conducted using a common equation of state (EOS) model, such that the only difference between each of the different runs were the in-situ reservoir fluid composition. The daily simulated wellstreams were thereafter run through a set of i) constant separator conditions and ii) changing separator conditions to analyse how daily separator oil shrinkage factors (SF) change with time.
Separator oil shrinkage factor, and the associated liberated gas, change with time due to changes in producing wellstream compositions and separator conditions (zi, psep, Tsep). The variations of shrinkage factors through time are more severe for near-critical volatile oils and gas condensates, than for black- and volatile oils. This paper shows that not accounting for these changes can lead to errors in converted stock-tank oil rates of more than 20%.
To convert separator rates to stock tank volumes, the common practice is to apply one constant shrinkage factor for a well and/or region. This paper shows that this practice can lead to significant errors, especially when producing from near-critical volatile oil and gas condensate fluid systems. This paper provides a novel approach for rigorous and consistent translation of daily separator-oil rate measurements into stock-tank rates, where we believe this procedure is seldom applied and can be important to allocation, ownership royalty determination, and consistency related to forecasting.
Cement-Conveyed Technology Improves Zonal Isolation and Stimulation Efficiency
Authors: Perroni Dominic , Medvedev Anatoly , Kolchanov Petr , Makarychev-Mikhailov Sergey , Roye Justin 
Published: January 2020

Successful cement placement in horizontal wellbores requires solutions for several technical challenges. Zonal isolation provided by cement is considered an important factor for efficient stimulation. A cement system was designed and recently introduced in unconventional developments to mitigate hydraulic isolation challenges encountered when cementing horizontal wellbores. Herein, we disclose recent results that show the efficiency of the interactive cementing system (ICS) in both laboratory and field case studies. Specifically, decreased communication between stages and improved production compared to offsets.
At the 2018 SPE Annual Technical Conference, Kolchanov et al. described the ICS improving zonal isolation in wells that would otherwise contain mud channels symptomatic of the cleaning methods used in unconventional developments (SPE-191561-MS). The scaled performance tests disclosed in that publication are further evaluated to build on the relationship between the laboratory test and realistic downhole scenarios. Literature data indicate that &gt;30% of stages have communications with previously treated zones. The ICS was shown to eliminate interstage communication during stimulation operations when compared to conventional cement systems. To investigate the effect of the ICS on completion quality, five wells cemented with the ICS and stimulated by multistage hydraulic fracturing were compared with numerous offset wells drilled, cemented, and stimulated during the last 2 years in the same producing zone within a 10-mile radius. The early normalized production data have been analyzed, and they indicate a statistically significant increase of production for the ICS-treated wells. This shows the importance of an integrated approach in well construction process, especially for challenging horizontal wells.
Unique Real-Time Production Optimization Methodology for a Multilateral Well with Hydraulic and Electrical Inflow Control Valves
Authors: Shaker Wisam , Majed Shammari , Ali Alshuwaikhat , Farooq Qazi 
Published: January 2020

Productivity index is directly proportional to the total reservoir contact (RC) within the same reservoir, hence the applications of multilateral. The new generation of the smart multilateral well completions divides the lateral section into a number of segments through oil swell packers and integrated stations are placed against each segment. The integrated station consists of electrical ICVs, downhole liquid metering and WC and pressure measurements sensors.
The unique smart completion allows real-time optimization and controlling of unwanted fluids on the segment level, utilizing the fast electrical ICVs. A comprehensive methodology has been developed to establish a production balance across the segments and the laterals utilizing the real-time downhole measurements rather than the tedious trial and error procedure. The methodology is divided into two components. In the first component: a single multilateral model is constructed using a single well modelling application. The model is calibrated to match the recent production test conducted on the well. Several simulation runs are performed on the calibrated model to test different combination of the downhole and surface choke settings until the well produces the target on condition that the laterals are producing equally. In the second component: a real-time production optimization process is conducted on the well using the outcomes of the first component.
The proposed methodology was conducted on multilaterals well with hydraulic and electrical ICVs and successfully completed. A good match has been obtained between the outcomes of the calibrated modeland the actual performance of the well. The process brings the well to the target at a straightforward task and avoids the trial and error procedure that may.
Automated Steering with Real-Time Model-Based Control
Authors: Demirer Nazli , Zalluhoglu Umut , Marck Julien , Darbe Robert 
Published: January 2020

Automation of directional drilling processes has gained interest as drilling operators seek more cost-effective solutions and consistent performance. Automation and control–although a mature topic in many industries–has recently started to take place in the drilling world as well. Hence, there is a great potential for rapid and significant improvements.
Currently, directional drilling operations are primarily managed by directional drillers who make steering decisions based on available pre-job reports, real-time data and geometric calculations. The resulting performance is contingent on directional drillers’ skill set, knowledge of the drilling tool, and familiarity with the local geology. Automating this process brings the promise of standardized drilling decisions with consistent accurate well placement with improved borehole quality, and the flexibility to adapt to new technologies in drilling tools and sensors. Automation also increases safety level in operations by reducing the on-site crew size since directional drillers can remotely manage multiple wells.
This work proposes a model-based control approach for automated steering in drilling operations. Two different models are presented. First, a comprehensive wellbore propagation model which considers multiple factors, such as the geometric feedback embedded in the wellbore trajectory, the drilling tool mechanical properties and actuation principle, the bit/rock interaction laws and kinematic relations between the bit motion and the newly created borehole, then a reduced-order model tailored for control applications. The control approach presented is applicable for both rotary steerable systems (RSS) and mud motors. Testing results are presented and discussed at the end of the paper.
Modification of Redundant Filter Elements to Suit Carbonate Filter
Authors: Al Dhaheri Abdulla Mubarak , Al Shamsi Abdulla Saeed 
Published: January 2020

ADGAS Train III Acid Gas Removal Unit, removes, H2S and CO2 from the feed gas. It is a hybrid arrangement of the Benfield Carbonate unit and Amine technologies. In the Carbonate Unit, using Potassium Carbonate as solvent, the bulk of the Acid Gas is removed. After absorbing H2S & CO2, rich carbonate solution exits the absorber to the Regeneration loop for stripping the absorbed acid gases namely H2S & CO2.
Presence of liquid hydrocarbons & particulates in the carbonate systems causes foaming in the circuitry. To prevent the buildup of particulates in the circulating carbonate solution, a side stream of the lean carbonate flow passes through a filtration pump and a mechanical filter of cartridge type. The cartridge is loaded with cotton disposable filters, of 10 microns size.
In addition to the particulate filtration system, Activated Carbon Filters, 2T-308A/B are installed to remove hydrocarbon contaminants from the circulating carbonate solution.
Logistic issues delayed the arrival of fresh stock of filter elements of 10 micron size, and the available stock was consumed fast due to slippage of particulate matter from Activated Carbon Filters, 2T-308A. The alternate source of Filer elements of 50 micron size could not be mobilized due to lack of supply in the market. Foaming coupled with lack efficient filtration threatened heavy production loss.
At this juncture, a redundant, microfiber filter elements of shorter length were located in the store and a calculated strategy to alter the available filter elements to suit the requirement was made. By altering and using the Micro-clean elements the system was fast restored to normalcy ensuring a stable production I short period of time. By avoiding plant trip and restart, the in house modification of the filer element saved close to 2.5 million US$
(This paper was selected as Technical Poster for GPA-GCC Chapter Conference on March 12-14, 2019 in Kuwait)
Pore-Scale Simulation of Fluid Flow in Carbonates using Micro-CT Scan Images
Authors: Abu-Al-Saud Moataz , Gmira Ahmed , Al-Enezi Sultan , Yousef Ali 
Published: January 2020

The recent advancements in imaging techniques have allowed quantifying the transport and fluid flow inside the complex rock pores at the microscopic scale. Specifically, micro-computed tomography (micro-CT) can reconstruct the three-dimensional pore-space geometry with micron-scale resolution. In this work, a numerical investigation of single-phase fluid flow is conducted on micro-CT images of carbonate core-plug subsamples. The presented numerical model studies the fluid flow and transport inside the rock pores at the pore-scale.
The flow dynamics is modeled using the Darcy-Brinkman formulation to consider the wide pore size distribution in carbonate rock samples. The simulation model takes into account pores at the micro-CT image resolution as well as the unresolved pores (microporosity) that are smaller than the micro-CT voxel sizes. These unresolved pores are usually categorized as microporosity, which is a parameter in the simulation model. The microporosity is quantified based on the micro-CT gray-scale intensity.
Simulation results show that direct pore-scale simulation on micro-CT images can characterize the permeability, porosity, and microporosity. As a result, pore-scale simulation can supplement conventional core analysis as well as provide detailed information of the primary fluid flow paths inside the carbonate rock pores. It is also shown that the microporosity has a first order effect on the rock permeability. Neglecting the microporosity regions alters the pore connectivity, which is essential to compute the permeability and rock petrophysical properties accurately.
The novelty of this study lies in solving the Darcy-Brinkman simulation model in a finite-volume framework to capture the effect of microporosity on carbonate rock samples in full three-dimensional space. The new findings shed light on the fluid flow and transport inside highly heterogeneous carbonate formations, which becomes an important first step to understand the fundamentals of oil recovery in advanced waterflooding process at the microscopic level.
Phase-Field Modeling of Hydraulic Fracture Propagation in Mechanically Heterogeneous Formations
Authors: Alotaibi Talal E. , Landis Chad M. , AlTammar Murtadha J. 
Published: January 2020

Understanding the mechanisms behind the nucleation and propagation of cracks is of considerable interest in engineering applications and design decisions. In hydraulic fracturing treatments of unconventional formations, complex hydraulic fracture geometries and propagation behaviors are encountered. As a result, the development of modeling approaches that can capture the physics of non-planar crack evolution while also being computationally tractable is a critical challenge. The phase-field approach to fracture has been shown to be a powerful tool for simulating very complex fracture topologies, including the turning, splitting, and merging of cracks. In contrast to fracture models that explicitly track the crack surfaces, crack propagation and the evolution thereof arise out of the solution to a partial differential equation governing the evolution of a phase-field damage parameter. As such, the crack growth emerges naturally from solving the set of coupled differential equations linking the phase-field to other field quantities that can drive the fracture process. In the present model, the physics of flow through porous media and cracks is coupled with the mechanics of fracture. Darcy-type flow is modeled in the intact porous medium, which transitions to a Stokes-type flow regime within open cracks. This phase-field model is implemented to investigate how fluid-driven cracks interact with material interfaces. The problem of an induced hydraulic fracture interacting with a layer possessing contrasting mechanical properties is studied. Several factors that influence the fracture behavior when encountering such a layer are presented in the simulations. Simulation results have shown that a very tough layer has the ability to deflect the induced fracture. Interestingly, the contrast in the modulus of elasticity of the layer relative to the matrix is not sufficient to make the layer act as a barrier in the absence of a contrast in the layer toughness. Additionally, a layer with a steep orientation relative to the crack direction has less of a tendency to deflect the fracture. Also, a thicker layer has a greater tendency to deflect the induced crack than a thin layer. Finally, it appears that the distance between the injection point and the layer does not play a significant role in deflecting the fracture.
Achieving Digital-Twin Through Advanced Analytics Support: A Novelty Detection Framework to Highlight Real-Time Anomalies in Time Series
Authors: Cadei Luca , Rossi Gianmarco , Montini Marco , Fier Piero , Milana Diletta , Corneo Andrea , Lancia Lorenzo , Loffreno Danilo , Purlalli Elisabetta , Carducci Francesco , Nizzolo Riccardo , Sophia Gustavo 
Published: January 2020

As Industrial plants evolve towards massive digitalization and their "digital twin" architectures are constantly enriched with a wide range of advanced analytics solutions that are becoming part of the ordinary control operations, the quality of the input data becomes of paramount importance. But as the number of variables, KPIs and processes monitored in plants raise of several orders of magnitude, automated procedures are needed for an effective monitoring.
We have developed a novelty detection framework with the objective of monitoring each and every variable in the plant, detecting anomalies in real time and therefore allowing the operators to investigate more in depth on the possible causes before any damage is made.
In order to do so, we had to define the "normality" of a signal, which can heavily vary from one to the other. Therefore, we setup a learning procedure that integrates several steps.
First, we need to distinguish the normal periods from the anomalous ones. While there are failures that are known to have impacted at certain times certain sections of the plant, three will definitely be more anomalies that have remained hidden so far. We hence labelled each timestamp of the series using an isolation forest algorithm.
Using the obtained normal dataset, we then extracted for each sensor the features that we have identified to better characterize a time series in its normal operating conditions. First, we select the signals in the plant that are the most correlated with the one at hand and fit a Ridge Regression and estimate the residual distribution. Then, we extract statistics such as mean, standard deviation, mean length and frequency of frozen periods, outliers, NaNs, Fast Fourier Transform and Welch’s approach for spectral density estimation. Finally, we heuristically define a number of tests capable of distinguishing a normal from an anomalous time window.
With this procedure, we are able to detect in real time whenever a signal is behaving differently from the way it is expected to. Depending on the operator’s experience, it would then be possible to understand whether it is a sensor malfunction or whether it indicates that something is wrong with the physical phenomenon, determining different actions, such as maintenance rescheduling. We have therefore conceived a dashboard that allows each operator to input its feedback, producing a refined dataset ready for continuous retraining. Ultimately, this anomaly detection framework will be used also to filter out the inputs to many advanced analytics solutions, guaranteeing the quality of their results.