bluuebunny/crossref_metadata_2025 huggingface dataset:
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.
Revisiting Subsalt Exploration Drilling Challenges
Authors: Alfayyadh Jaber , Al Moqbil Amal , Taher Ahmed
Published: January 2020

The quest for hydrocarbons continues to increase and is becoming more challenging as the search pushes operators further into unexplored basins and frontiers globally. In the last 20 years, subsalt drilling has provided some new and promising prospect landscapes and fairways; however, major challenges are inherent with drilling subsalt exploration wells. One of the most problematic properties of salt is deformation or mobile behavior; in other words, salt has almost no permeability and porosity, and it creeps under differential stresses, causing hole stability issues.

Historically, where global offshore and onshore exploration frontiers encountered, salt drilling posed significant challenges to drilling. Because salt behavior is also attributable to salt type and the stress state of the confining geological environment, lateral forces from the rift ridge system and evaporite seal produce high mobility in the halite subsalt accumulations. Major challenges faced while drilling this salt were stuck pipe, tripping in and out issues, wellbore enlargement, and severe bottomhole assembly (BHA) whirl leading to catastrophic lost-in-hole incidents and nonproductive time.

In-depth analysis of the formation’s geomechanical attributes, mud properties, drilling practices, and casing design was fundamental to developing better defined and customized drilling solution strategies to address the unique subsalt drilling challenge. Drilling fluid selection, chemistry, and application engineering also played a fundamental role in preventing washed-out holes.

Additionally, the salt creeping rate is generally a function of in-situ stress, exposure time, and temperature. Proper mud design and drilling practice help minimize potential risks of hole instability in addition to modifying the casing design to isolate the salt, which requires a different mud weight than the overlying and underlying formations.

Most early exploration wells through salt were drilled as vertical wells; however, achieving the necessary directional trajectory control through a mobile salt caused concern. Therefore, potential geomechanical risks, drilling mechanic analysis, such as torque and drag, and potential vibration issues are considered while designing the directional path through a subsalt formation.

This paper discusses a comprehensive geomechanical overview, recent successful experiences of drilling salt with the application of drilling fluid, drilling practices, casing design, and trajectory design perspectives in addition to a comprehensive report of lessons learned.
Production Gains and Extended Electrical Submersible Pump Run Lives in Harsh Well Conditions
Authors: Camilleri Lawrence , El Gindy Mohammed , Kaci Yacine , Othmanine Mohamed
Published: January 2020

Installing ESPs in a reservoir for the first time is always fraught with the uncertainty of achieving economic run lives and this is further amplified in harsh conditions. To mitigate the financial and production risks, sufficient production gains are required to overcome potential short ESP run lives. This paper discusses the results of four pilot ESP wells in Algeria and how infant mortality was eliminated in addition to achieving early production gains.

Key to achieving the production gains was candidate selection and well testing to confirm the well productivity and aquifer pressure support. This process also mitigated risk by selecting wells from a reservoir sector with a historical low incidence of asphaltenes and GORs, which have not spiked substantially above solution GOR. Once the ESPs were installed, the production gains were achieved by correctly managing drawdown through real time surveillance, which was also used to manage the stress on the ESP and avoid infant mortality. Longer term run lives was achieved by selecting the correct ESP materials and completion architecture for the well conditions.

At the time of writing this paper, none of the four ESPs had failed. The most recent installation had been running for 400 days and the oldest for over 1,300days, which is no small feat when one considers the harsh conditions; a reservoir depth of 10,500 ft TVD with a bottom hole temperature of 245 deg F and a volatile hydrocarbon (41 deg API) with a high GOR. This is compounded by an aquifer with water densities as high as 1.25 due to high salt content, which causes both corrosion and halite scale to form on a regular basis, which was treated with fresh water injection. In two of these wells, net oil production was doubled, but more importantly the recovery factor was substantially increased as the higher ESP drawdown mobilised reserves which would not have been produced with gas lift. Finally, the injection gas saved from converting two wells to ESP was sufficient to complete 4 to 5 new wells with gas lift completions.

In terms of technology, the main innovation was the use of an ESP digital twin to monitor ESP health in real time, which was particularly useful in managing the transients associated with slugging. An equally noteworthy take-away was how a holistic approach, which integrated reservoir, completions and production engineering provided seamless management from project definition all the way through to execution.
Liquid Film Mode for Prediction and Identification of Liquid Loading in Vertical Gas Wells
Authors: Landjobo Pagou Arnold , Wu Xiaodong
Published: January 2020

Characterized as the reversal flow of liquid film into the wellbore, liquid loading is a genuine issue for gas wells as it diminishes the gas production rate. In the event that fluid rate accumulating in the wellbore is excessively high, the gas production rate will decrease fundamentally and for severe instances of accumulation, the operating organization will relinquish the well which will cause immense budgetary misfortunes. Subsequently, so as to maintain a strategic distance from the latter occurring, it is proper for the working organization to anticipate and recognize the liquid loading status of the gas wells in order to utilize viable apparatuses and pathways to avert it. Therefore, to counteract those misfortunes, the forecast of the liquid reversal point is obligatory.

Several researchers studied and established models to predict the loading phenomenon. After thoroughly review those studies, conclusions made on the different models are controversy and their results are conservatives. This paper presents a model where the hypothesis relies on fluid film reversal. The model considers the change from annular flow (fluid film encompassing the gas core) to slug or churn flow to be the grounds of liquid film backflow. Subsequently, from the review of previous literature on vertical wells, it is obvious that the film thickness is more sensitive to the tubing inner diameter, the tubing pressure gradient, the changes of fluid properties, the film and gas gravitational forces. Therefore, it is more rational for the critical gas flow rate to be dependent on those parameters. Subsequently, the momentum balances of both the liquid and gas phase were developed, and a derivation of an expression of the gas void fraction leading to the derivation of the dimensionless liquid film thickness and thus the critical film thickness were obtained. As a result of this modeling, a simplistic practical critical gas velocity and critical gas flow rate correlation which at the same time combines and incorporates the parameters influencing the loading phenomenon are viable for any profundity of the well.

So as to assess the adequacy of this model, evaluation has been performed between the model and some well-known model such as Turner et al. (1969) model, Li et al. (2001) model, Belfroid et al. (2008) model and Liu et al. (2018) model on some of the vertical gas wells of the North-West Xinjiang gas field. The outcome of this evaluation provides an overall 95% prediction and identification precision, outclassing the models quoted above. Thus, the model is the most appropriate to classify and foresee liquid backflow and accumulation in gas wells.
Efficient Joint 4D Seismic and Electromagnetic History Matching Using an Ensemble-Based Approach
Authors: Zhang Yanhui , Hoteit Ibrahim
Published: January 2020

This study aims at enhancing reservoir characterization through simultaneous history matching of time-lapse seismic and electromagnetic (EM) data. We propose an efficient ensemble-based history-matching approach by exploiting the complementary nature of these data types.

The developed workflow consists of two main steps. Firstly, water saturation and porosity as the rock cross-properties relating to both seismic velocities and formation conductivity are estimated by joint inversion of seismic and EM data using an iterative ensemble smoother with an adaptive non-distance- based Kalman gain localization. Prescribed rock-physics models are used to quantify the corresponding relationship of rock properties to seismic velocities and formation conductivity, based on which synthetic EM and full-waveform seismic data are simulated. Secondly, instead of integrating the inverted saturation field directly, front positions are identified from the inverted saturation field and used as the observed data for history matching. Model parameters are conditioned to the observed fronts using the iterative ensemble smoother with a feature-oriented distance parameterization.

The approach is verified with synthetic data sets. Results show that joint inversion of seismic and EM data leads to better estimates of rock properties when compared with those from the separate inversion. Moreover, by integrating the extracted fronts from the improved estimation of the saturation field, which synthesizes the information from both types of data, the proposed approach significantly reduces the redundancy and number of data while still capturing the essential information. The novelty of the proposed approach consists in combining the feature-based history matching with ensemble-based geophysical inversion to achieve an efficient joint integration of time-lapse seismic and EM data.
A Machine Learning-Based System for Self-Diagnosis Multiphase Flow Meters
Authors: Barbariol Tommaso , Feltresi Enrico , Susto Gian Antonio
Published: January 2020

In the oil and gas industry, the need of Multiphase Flow Meters (MPFM) continues slowly to grow. The individual oil, gas and water flows rates measurements are important to monitor the reservoir, to improve the well performances and to optimize the well production. Traditionally the composition of the flow has been performed separating physically the phases with large, cumbersome, time consuming and expensive test separator vessels. A MPFM is, on the other hand, a compact multi-sensors system that provides real-time and continuous measurements of the individual oil, gas and water flows rates of a well without the need to separate the phases. Therefore, procedures for measure quality assessment are of crucial importance. In this work it is proposed an Anomaly Detection approach for MPFM based on unsupervised Machine Learning algorithms. It is effectively able to handle the complexity and variability associated with MPFM data and it has the capability both to detect outliers and to pinpoint the faulty sensor. The proposed approach is designed for embedded implementation.
Robust Chemical Dissolver for Reservoir Stimulation and Formation Damage Remediation
Authors: Panuganti Sai Ravindra , Misra Sanjay , Salleh Intan Khalida , M. Ibrahim Jamal Mohamad , Rodzali Mohamad Azmeer
Published: January 2020

The process of matrix acidizing, despite being one of the oldest operations in the petroleum industry, is still a challenge for tight carbonate reservoirs. This project considers the development of a multi-functional environment friendly chemical, for reservoir stimulation and formation damage remediation.

A microemulsion solution of biodegradable chelating agent is formulated, which is effective for tight carbonate reservoir stimulation even at high temperature. Together with the chelate based inorganic dissolver, aromatic naphtha as an organic dissolver is the other main active ingredient in the proposed microemulsion formulation. For this reason, the microemulsion solution can also be used to treat inorganic and organic mixed deposits which can involve in formation damage. The developed multi-application chemical is later tested for compatibility with reservoir fluids and production chemicals encountered during well flow back.

Formulations with low reactivity are required when the injection of stimulant is not possible at high rate. By making microemulsion with chelate, the reactivity and diffusivity of the chelating agent can be controlled further. Core flooding experiments on core samples from high pressure, high temperature and tight carbonate formation, are conducted to demonstrate wormhole formation during the matrix acidizing treatment with the formulated microemulsion. The synthesized stable microemulsion chemical is also subjected for detailed dissolution study on deep wellbore deposits of different composition from different fields. These inorganic and organic mixed deposits are otherwise hard to be remediated by aqueous or organic solvent alone.

The novelty of this article is in developing a chelate based microemulsion as the main stimulation fluid. Another uniqueness of the microemulsion solution is in the treatment of formation damage causing deposit species which are mixed in nature, without the need of any additives.
Research and Development of High-Efficient Nano Solid Defoamer and its Application
Authors: Cao Guangqiang , Li Nan , Shi Junfeng , Wang Haoyu , Jia Min , Wang Yun , Li Jun
Published: January 2020

Foam assisted lift is a vital significant technology for gas well deliquification. The foamer is injected into the wellbore, then the liquid in the hole is changed into foam by gas agitation, which can be carried to the surface by gas flow easily. The returned fluid should be defoamed before separator. Solid defoamers are often used to eliminate these foam. But there are many problems of solid defoamers, such as poor performance, short shelf lift and high cost, which affected its effectiveness seriously. To solve these issues, A new nano solid defoaming agent is presented in this paper. It consists of simethicone, hydrophobic nanoparticles, emulsifier and solidifying agent. The hydrophobic nanoparticles have improved the performance of new solid defoamer greatly. The characteristics of the new defoamer, including solubility, defoaming performance and anti-foaming performance are analyzed. Furthermore, the new defoamer was applied in a large amount of gas wells to validate its effectiveness and economy. And the field application results proved that the new solid defoamer is superior to the conventional solid defoamers in performance and economy.
Targeted-Acidizing Tech Meets Various Goals in Long Horizontal Wells: Enhance Productivity or Equilibrate Flow Profile
Authors: Xue Heng , He Enjie , He Bing , Kang Bo , Ye Jiexiao , Liu Fei , Mi Qiangbo , Cao Xianping , Liu Xue
Published: January 2020

CT (coiled tubing) acidizing is the main work before horizontal wells put into production in the Middle East. The targeted stimulation interventions directly affect the afterwards performance of production and injection wells. This work not only highlights the importance of removing damage to enhance productivity of producer in the initial production stage, but also put forwards the effective measures of equilibrating flow profiles of injector and producer in the stable production stage.

The real-time acidizing techniques combined with distributed temperature sensing (DTS) is used to equilibrate inflow profile in injectors successfully. However, it is lack of effective measures or BHA to guide removing the un-uniform damage and improving acid absorbing in poor interval of horizontal producers. Combined with logging interpretation data and drilling parameters, a velocity-based un-uniform damage model is developed to understand the drilling fluid displacement, mixture and diffusion process in the reservoir-scale. To help ensure accurate acid placement in producer at different production stages, a targeted-acidizing idea is proposed based on the quantitative prediction of inflow and skin factor profiles. To compare the acidizing efficiency between various proposals and illustrate the effectiveness of targeted-acidizing design, A three-dimensional diverted-acidizing simulator is developed for carbonate reservoir, and applied in AHDEB Oilfield, Iraq.

According to the simulation of various acidizing designs in new producer, the acid placement based on skin factors can receive the highest productivity compared with traditional uniform, cone-shaped or permeability-based acidizing measures. In the case study, 3 typical acidizing targets cooperated with re-open work of producer have been proposed. The injection rate and acid volume have been optimized through simulation. In order to make under-stimulated intervals absorbing more acid and avoid connecting thief layers, the CT selective acid jetting plus drag back tech is introduced. The production performance after acidizing shows that the stimulation ratio reaches to 7 times. The water cut is also controlled very well.

It is difficult to enhance productivity and equilibrate flow profile at the same time under the limited acidizing scale, especially in the long horizontal wells (over 1000m). this paper highlights which goals we should consider firstly at different production stages, and give out the effective measures of evaluation and execution in the matrix acidizing procedure of horizontal wells.
A New Method for Wet Gas Flow Measurement with Horizontal Venturi Meter Based on Numerical Simulation
Authors: Pan Yanzhi , Liu Haujian , Zheng Ziqiong , Wen Pengrong , Zhao Yueqian
Published: January 2020

Effectively measure wet gas phase fractions and flow rate has always been a challenge to the multiphase flow measurement community. While measurements using gamma ray approach has so far proven to be the most accurate, it also requires good "line of sight" phase fraction representation in the flow line. Such requirement often leads to increased complexity and cost in equipment configuration (i.e. vertical Venturi, or additional gamma ray detectors). Venturi placed horizontally reduces configuration complexity however the "line of sight" phase fraction would not be representative if a single gamma source/detector is used, due to gravitational separation of phases in horizontal flow. A model of two eccentric circles of the same diameter was developed to use the horizontal configuration, yet not sacrifice accuracy of phase fraction measurement. The model has been validated with previous experiment data and the results were well matched. Additional verification at a third party facility (National Engineering Laboratory of UK) was also conducted and RMS error in flow rate of each phase were well below 6%. The model and associated equipment configuration form a simple and effective system for wet gas flow measurements, reduce system cost, complexity in installation and associated safety risk, and have a great value for marginal oil and gas fields as well as production optimization management.
Application of Artificial Intelligence to Predict Time-Dependent Safe Mud Weight Windows for Inclined Wellbores
Authors: Phan Dung T. , Liu Chao , AlTammar Murtadha J. , Han Yanhui , Abousleiman Younane N.
Published: January 2020

This paper presents an artificial intelligence (AI) solution for predicting time-dependent safe mud weight windows and polar charts for inclined wellbores. The AI agents, in the form of neural networks, are trained and tested on data generated from a poroelastic analytical solution. The results show that the trained neural networks are capable of predicting time-dependent mud weight windows and polar charts as accurately as the analytical solution. The AI solution achieves a mean squared error (MSE) of 0.107 and a coefficient of determination (R2) of 0.995 for collapse mud weights, and an MSE of 0.043 and an R2 of 0.998 for fracturing mud weights on test datasets. They are also significantly faster and less demanding in computing capacity than the analytical solution, consistently showing three-orders-of-magnitude speed-ups in computational speed tests. Evaluations on two case studies similarly demonstrate the AI solution's capabilities and benefits.
A Holistic Approach to Achieve a Successful Liner Cement in Gas Bearing Early Cretaceous Formations in South Iraq
Authors: Cardenas Miguel Angel , Galaby Amir , Cengiz Ozgur , Al-Rubaye Mustafa , John Melvin , Ponomareva Daria , Antonov Maksim
Published: January 2020

Obtaining a good cement bond is a continuous challenge, especially if the well being cemented is a high-pressure exploration gas well, and it is one of the very few gas wells drilled in the country. Poor adherence to the casing and the formation, channeling due to gas migration and microannulus are some of the main risks that could result in a poor cement job. Achieving zonal isolation and a good cement sheath protecting the 7-inch liner turned out to be an objective missed for the first two wells of the campaign, compromising the long-term supply of gas to the South region of Iraq. To solve the situation, it was necessary to implement something more than a mere cementing additive; it required a multifactor analysis with an experienced multidisciplinary team. A set of good drilling practices, proper drilling fluids, proven cementing techniques and new technology slurries were combined to improve the precious results.

To obtain a sound cement quality log, the well engineering department teamed up with cementing experts, drilling fluids specialists, liner hanger company representatives and operations personnel. With effective meetings, proper risk assessment and visible leadership, the team generated a series of initiatives that included: drilling hydraulics optimization, mud weight selection, drilling practices re-definition, liner hanger procedure adjustments and cementing slurry design.

As a result, the borehole caliper was significantly improved, the liner hanger allowed full rotation while cementing, cement returns were observed above the liner top after the job, no evidence of gas migration was observed and the CBL-VDL-USIT log showed a remarkable improvement in the two jobs where the engineering initiatives were applied.

Being able to achieve a positive proof on cementing integrity, one of the most important acceptance criteria for the National Oil Company (NOC) regulation entity, enhanced the trust on the technical experts of the engineering team to deliver solutions of complex problems.
Integrated Reservoir/Wellbore Production Model for Oil Field Asphaltene Deposition Management
Authors: Ghasemi Mohammad , Al-Safran Eissa
Published: January 2020

Asphaltene deposition prevention, mitigation, and management remains a major challenge to the oil industry due to its complexity and current poor understanding and inadequate predictive tools. A literature review study on the asphaltene deposition revealed a lack of integrative models that link reservoir, wellbore, and surface facility to predict asphaltene deposition and take into account their effect on each other. In addition, most of the existing studies are focused on the thermodynamics aspects of asphaltene precipitation, or single-phase asphaltene deposition modeling. Therefore, it is critical to model asphaltene deposition under multiphase flow conditions to, accurately, develop prevention, mitigation, and management strategies, which depends on not only asphaltene thermodynamics, but also multiphase flow hydrodynamics and behavior. The objective of this study is to develop a robust systematic approach for predicting asphaltene deposition in production system through coupled reservoir and wellbore production model, which provides a cost-effective optimal mitigation and management strategies. The proposed work in this study integrates five models, namely reservoir asphaltene deposition model, equation-of-state (EOS) model, asphaltene thermodynamics precipitation model, mechanistic multiphase flow model, and asphaltene deposition transport model. The above-mentioned models are integrated using developed workflow platform, which enables compositional tracking throughout the entire production system. Furthermore, experimental fluid characterization data was used to tune the EOS model and the thermodynamic asphaltene precipitation models to ensure accurate phase behavior and the volumetric calculations, as well as of asphaltene and resin precipitations at any operating conditions. A field case study is used to evaluate the proposed integrated model, which indicates severe asphaltene depositions in production tubing and flowline. The proposed model predicted the thickness growth with time of asphaltene deposits on the inner tubing wall. The model results also show that local asphaltene deposition reduced tubing cross-sectional area, increasing in-situ superficial oil and gas velocities, thus increasing pressure drop. These results are critical in selecting, optimizing, and implementing asphaltene deposition mitigation and management strategies, which impacts project economics.
Utilization of Pump and Pull Cementing Technique in Highly Deviated and Horizontal Wells
Authors: Alghamdi Muataz , Alwarthan Abdulsalam , Bouaraki Mouloud , Abbas Athman
Published: January 2020

Pump and pull cementing method is introduced to overcome soft cement plugs due to the swabbing effect and contamination in an oil-based mud environment. The method aims to address quality concerns in challenging well profiles where conventional cementing techniques are deemed to fail, which potentially lead to additional cost for remedial cementing work and non-productive rig time.

The method is utilized to tackle a re-occurring issue of tagging soft cement plugs that are used for several applications, including plugging and abandonment and sidetracking operations, in deep highly deviated or horizontal wells. In such profiles, fluids and cement don't balance themselves as gravity is not the predominant factor. Subsequently, the cement plug cannot be balanced, and contamination takes place resulting in its failure. The method targets minimizing this by reducing the effect of pulling out of the plug by keeping the drill pipe stinger inside the cement slurry and replacing the volume created while pulling out of the hole by pumping cement until completing the placement of the plug.

The technique is time sensitive since most of the cement slurry remains in drillpipe while preforming the job. For that reason, intensive planning is required to ensure successful implementation. One factor that impact the quality of the job is the abundance of actual downhole data, including caliper and temperature logs. Based on that, cement slurry design can be adjusted to account for temperature effect as well as adjusting volume calculations. Also, lab and computer simulations play a significant role in determining several parameters such as spacer formulation, mud removal efficiency, ultimate compressive strength chart, and additives concentrations, especially retarders. In terms of field preparedness, specific equipment and competencies are required for such critical jobs. The method was deployed successfully in several jobs, resulting in excellent cement quality. At the top of that, the method was used to optimize operations by pumping a single long cement plug instead of several balanced cement plugs. This has directly resulted in saving several rig days while delivering satisfactory cement hardness. A couple of case studies are introduced to showcase the effectiveness of the method in challenging applications.

Pump and pull technique proved that it resolves the challenge of placing cement plugs in highly deviated and horizontal wells. It earns more importance as wells are growing in complexity. Recently, the technique was used to successfully place significantly longer cement plugs, achieving an outstanding level of operational efficiency by saving rig days and resulting in cost optimization of cementing operations by reducing the number of required plugs to be pumped.
Analysis of Interval Pressure Transient Test IPTT Performed in Oil Reservoir with Connected Transition Zone and Water Aquifer
Authors: Atadeger Aykut , Gok Ihsan Murat
Published: January 2020

Interval pressure transient tests (IPTT) are commonly used in the industry to obtain permeability distribution along the wellbore. Despite the remarkable progress achieved in IPTT analysis in last two decades, interpretation of IPTT is still unclear if test interval consists of oil zone with vertically connected transition zone and water aquifer. One easy and common approach for interpreting such data is to assume that oil zone, transition zone, and water aquifer as a distinct zone and then perform non-linear regression to measured IPTT pressure data set using single phase layer cake model. In this approach, due to the single-phase nature of the model, capillary pressure and relative permeability effects are totally ignored, however, it is assumed that water saturation data is available from log analysis and saturation weighted viscosity value represents the transition zone. As expected, it is determined only effective horizontal and vertical permeability values from this analysis rather than absolute permeability. It is also important to highlight that reliable effective permeability data is estimated solely in the zone where a test is performed. In fact, accurate prediction well and reservoir performance require values of absolute permeability information. As a second approach to analyze IPTT data, it is assumed that water saturation, relative permeability, and capillary pressure data are known parameters and optimization technique is used based on numerical reservoir simulation to estimate absolute permeability values. Like the previous case, horizontal and vertical permeability values are reliably obtained only in the zone where a test is performed. The only difference with the previous approach is that estimated permeability values are absolute permeability values rather than effective permeability. In practice in IPTT jobs, water cut is generally measured with pressure data in various depths in the transition zone to fine tune free water level. It is also important to note that relative permeability and capillary pressure data are not always available before IPTT interpretation. As a last approach in this study, both pressure and water cut data are simultaneously used in the optimization to find each zone’s horizontal and vertical permeability values, relative permeability and capillary pressure curves. Fairly satisfactory estimations are obtained from simultaneous regression of water cut and pressure data obtained from IPTT.
Lessons Learned from Established Unconventional Resource Plays: Application to Emerging Plays in the Middle East
Authors: Bromhead Alex , Sutcliffe Owen , Cousins Thomas , Weeks David , Davies Roger
Published: January 2020

The unconventional revolution in North America has firmly established unconventional resource plays as an integral component of global hydrocarbon production. The established North American resource plays are heterogeneous and vary considerably in terms of play type, stratigraphic organization, and the lithology of the target unit. The Middle East has several world-class source rocks that have charged giant and supergiant conventional fields, which implies many opportunities to develop unconventional resource plays. Within this study, the stratigraphic organization of two prolific source rock intervals within the Early Silurian (Qusaiba Member) and Middle-Late Jurassic (Tuwaiq Mountain Formation and equivalents) is characterized from public-domain data sets. From this, a variety of unconventional plays are conceptualized within these resource intervals.

The systematic classification of established resource plays in North America facilitates analogue identification for these emerging resource intervals across the Middle East. The Montney play is identified as an analogue for the Silurian resource interval and can be used to help validate unproven unconventional play concepts. Within the Jurassic resource interval, multiple analogues are identified that characterize different aspects of the emerging unconventional play types. For instance, stratigraphic architecture within the emerging Tuwaiq Mountain shale play is comparable to the Vaca Muerta play of the Neuquén Basin in South America, while mineralogy is similar to that within the Eagle Ford play and porosity development is akin to the Marcellus play. Applying understanding from these analogues can enable more informed and efficient exploration, appraisal, and development decisions within these frontier and emerging Middle East resource plays.
Cavings Morphology Analysis: A Critical Geomechanical Tool in Optimizing Drillability
Authors: Das Purkayastha Anjanava , Rana Rohit , Ranjan Kumar Rajeev , Basu Jayanta , Talreja Rahul , Singh Amit
Published: January 2020

Drill cuttings are a valuable source of information about lithology and wellbore condition. Although an abnormally high number of cuttings would indicate some sort of failure at the wellbore wall, a detailed analysis of cuttings can help to identify the type of rock failure. Cavings, fragments that are relatively larger and of different shape compared to normal cuttings, can be used to decode critical information about the wellbore geometry and formation pressure.

Cuttings analysis is most useful in absence of direct indicators of wellbore condition such as caliper, image logs, or logging-while-drilling (LWD) data, but even in presence of such data, cuttings analysis can be used to corroborate the interpretations with direct measurements. Several mechanisms, such as underbalanced drilling, pre-existing weak planes, stress relief, or even the drilling process itself, can lead to production of cavings. Examining the cavings to interpret wellbore instability and mechanisms responsible for it is an expert's job and requires a good overall understanding of the prevailing geology, geomechanical principles, drilling procedure, and drilling tools.

Identification of wellbore failure during drilling provides a better chance of immediate remedial action, even before a wireline logging program is executed. Differentiating cuttings generated by the drill bit from cavings created by the wellbore failure is not an easy and straightforward task due to a variety of bits and phenomena involved in the generation of cuttings. The first step in this analysis is to broadly define the different types of cavings based on their shape and size. Then, we move to the basic key features of these cuttings, and, finally, provide the remedial action plan for each type.

Drill cuttings analysis was successfully applied to improve hole condition in real time for two wells drilled in the Western Offshore basin, India. One case study illustrates the importance of mud chemistry over the mud weight being used to drill. The second case study underscores the interpretation of shear failure as the reason for cavings from cuttings morphology analysis. In both the cases, timely intervention integrated with the identification of prevailing drilling issues in real time helped in understanding the mud system and its effects on the wellbore.

The novelty of this approach lies in the deep understanding and geomechanical application of cavings in providing timely and cost-effective recommendations to optimize drillability in both the presence and the absence of LWD data. The results can be used during the well-planning stage of future wells and during drilling to improvise mud chemistry or to identify required increase in mud weight to avoid breakouts related to chemical instability or shear failure even though the pore pressure profile may not necessarily require any further increase in the mud weight.