bluuebunny/crossref_metadata_2025 huggingface dataset:
Engineered Solution Helps Tackle Tricky Shale Gas Cementing Challenge in HP/HT to Deliver Good Cement Bond Across Shale Section Located in Western India
Authors: Chandrashekar DV , Dange Mikhil , Kumar Animesh , Bhaisora Devesh
Published: December 2021

In a world where energy is a major concern, the revolution of shale gas globally has triggered a potential shift in thinking about production and consumption that no one would have expected. The enormous shale gas resources identified today are becoming game changers in many developing countries. The booming economy of India is seeing a significant increase in its energy demand, with industries establishing new footprints in the western region of the country. Operators are venturing into deeper and harsher conditions (HP/HT environments) to tap those resources.

Even though shale gas is now found globally, it is still described as an unconventional source of hydrocarbons. This is because the extraction of shale gas is tricky and challenging. To unlock the unconventional gas reservoir most of the wells are horizontally drilled and hydraulically fractured. This process has a strong impact on cement bonding across the section. Firstly, the cement needs to provide an effective barrier in the annulus around the casing, which has been horizontally placed. Secondly, cement has to withstand various mechanical loads during hydraulic fracturing and ultimately over the life of the well.

The present study covers the Navagam field located in the Ahmedabad block of North Cambay Basin. Cambay Basin is bounded on its eastern and western sides by basin-margin faults and extends south into the offshore Gulf of Cambay, limiting its onshore area to 7,900 mi2. The operator's western asset had already deployed its resources on evaluating the data to assess the potential shale gas in the Navagam block in the Cambay Basin.

This paper highlights successful cement placement in an unconventional shale gas reservoir in onshore western India. It was crucial to understand why early exploration wells in the area resulted in poor initial zonal isolation in order to refine the asset development model for future wells. Based on these models, a mechanically modified resilient cement system was engineered. Subsequent exploration wells were then cemented with the resilient cement system to allow for dependable zonal isolation of reservoir bands permitting the accurate determination of discrete reservoir geomechanical properties within the overall reservoir target.
Enhancing Production Through Well Interventions Using End-to-End Evaluation Methodology
Authors: Oatey Mark , Duff Fay , Emslie Neil , Christie Steven , Rikabi Rida , Henderson Peter , Singh Kamaljeet , Kumar Apoorva , Agrawal Gaurav , Dutta Shaktim , Bajwa Haroon
Published: December 2021

In this paper, an end-to-end evaluation service using well historical production, petrophysics and reservoir data combined with new logs to perform well intervention solution methodology is followed. Across four wells, production logging data is acquired and analysed to understand the current performance of different heterogeneous layers. Combining this with openhole data, additional perforations and reperforations are planned. Perforations are carried out using deep-penetration charges to create a larger and deeper flow path between the reservoir and the wellbore. Post-perforation production logs are carried out, and the data is analysed to understand the effectiveness of newly perforated layers.

Detailed production enhancement of all four wells is discussed in the paper. The majority of the wells displayed a significant increase in production when compared with pre-intervention flow rates. Minor scale buildup in the production liner was observed during pre-perforation production log data which was observed to be cleared during post-perforation production log data. The deliverability of the wells had also gone up, with similar production rates at much higher bottomhole pressure compared with pressures before intervention. This also confirmed the effectiveness of deep-penetration charges during perforation in providing better conduit from reservoir to wellbore. Additional perforations carried out, based on the heterogeneity of the reservoir and combining the openhole data, proved to be highly effective, with high deliverability observed from these new layers. In conclusion, a successful production enhancement of these low-flow-rate gas condensate wells was achieved with an end-to-end solution.

A highly heterogeneous reservoir with multiple thinly bedded layers presented challenges in understanding their productivity. The combination of pre-perforation production log and post-perforation production log enabled evaluation of the deliverability of the complex heterogeneous reservoir. Further, production enhancement from each reperforated interval was confirmed using a direct measurement, i.e., production log data instead of relying on surface flow rates to better understand the downhole dynamics.
Processing of Seismic-While-Drilling Data from the DrillCAM System Acquired with Wireless Geophones, Top-Drive, and Downhole Vibrations Sensors
Authors: Silvestrov Ilya , Hemyari Emad , Bakulin Andrey , Luo Yi , Aldawood Ali , Poletto Flavio , Liu Yujin , Du Yue , Egorov Anton , Golikov Pavel
Published: December 2021

We present processing details of seismic-while-drilling data recently acquired on one of the onshore wells by a prototype DrillCAM system with wireless geophones, top-drive, and downhole vibration sensors. The general flow follows an established practice and consists of correlation with a drillbit pilot signal, vertical stacking, and pilot deconvolution. This work's novelty is the usage of the memory-based near-bit sensor with a significant time drift reaching 30-40 minutes at the end of each drilling run. A data-driven automatic time alignment procedure is developed to accurately eliminate time drift error by utilizing the top-drive acceleration sensor as a reference. After the alignment, the processing flow can utilize the top-drive or the near-bit pilots similarly. We show each processing step's effect on the final data quality and discuss some implementation details.
A Novel Workflow for Geosteering a Horizontal Well in a Low Resistivity Contrast Anisotropic Environment: A Case Study in Semoga Field, Indonesia
Authors: Fransisca Yessica , Adiandra Karinka , Manurung Vinda , Warkhaida Laila , Arham M. Aidil , Yanto Yudi , Febrianto Dwi Hudya , Yaser Achmad
Published: December 2021

This paper describes the combination of strategies deployed to optimize horizontal well placement in a 40 ft thick isotropic sand with very low resistivity contrast compared to an underlying anisotropic shale in Semoga field. These strategies were developed due to previously unsuccessful attempts to drill a horizontal well with multiple side-tracks that was finally drilled and completed as a high-inclined well.

To maximize reservoir contact of the subject horizontal well, a new methodology on well placement was developed by applying lessons learned, taking into account the additional challenges within this well. The first approach was to conduct a thorough analysis on the previous inclined well to evaluate each formation layer’s anisotropy ratio to be used in an effective geosteering model that could better simulate the real time environment. Correct selections of geosteering tools based on comprehensive pre-well modelling was considered to ensure on-target landing section to facilitate an effective lateral section.

A comprehensive geosteering pre-well model was constructed to guide real-time operations. In the subject horizontal well, landing strategy was analysed in four stages of anisotropy ratio. The lateral section strategy focused on how to cater for the expected fault and maintain the trajectory to maximize reservoir exposure. Execution of the geosteering operations resulted in 100% reservoir contact. By monitoring the behaviour of shale anisotropy ratio from resistivity measurements and gamma ray at-bit data while drilling, the subject well was precisely landed at 11.5 ft TVD below the top of target sand. In the lateral section, wellbore trajectory intersected two faults exhibiting greater associated throw compared to the seismic estimate. Resistivity geo-signal and azimuthal resistivity responses were used to maintain the wellbore attitude inside the target reservoir.

In this case history well with a low resistivity contrast environment, this methodology successfully enabled efficient operations to land the well precisely at the target with minimum borehole tortuosity. This was achieved by reducing geological uncertainty due to anomalous resistivity data responding to shale electrical anisotropy. Recognition of these electromagnetic resistivity values also played an important role in identifying the overlain anisotropic shale layer, hence avoiding reservoir exit. This workflow also helped in benchmarking future horizontal well placement operations in Semoga Field.

Technical Categories: Geosteering and Well Placement, Reservoir Engineering, Low resistivity Low Contrast Reservoir Evaluation, Real-Time Operations, Case Studies
Challenges and Opportunities for Green Hydrogen Power Supply in Oil and Gas Remote Facilities
Authors: Ruvalcaba Velarde Salvador Alejandro
Published: December 2021

The energy transition to renewable energy and hydrogen as an energy carrier, along with low-carbon footprint production targets in the oil and gas industry act as a catalytic for exploring the role of hydrogen in oil and gas production. For upstream and midstream operations, potential opportunities for using hydrogen as an energy carrier are being developed both in hydrogen generation (X-to-hydrogen) as well as in hydrogen consumption (hydrogen-to-X), but not without series of technical and economical challenges.

This paper presents potential use cases in upstream and midstream facilities for hydrogen generation and consumption, be it both from hydrocarbon processing resultant in what is called "blue hydrogen" or from integration with renewable energy to form what is called "green hydrogen". It also explains process integration requirements with diagrams for full-cycle green hydrogen use from generation to consumption and its interaction with renewable energy technologies to achieve low to zero-carbon emission power supply systems. Different hydrogen generation and conversion technologies are reviewed as part of the modeling process.

Green hydrogen feasibility is assessed in terms of operational efficiency and cost constraints. Hybrid hydrogen and renewable energy power supply systems are simulated and presented according to the intended applications of use in oil and gas facilities.

This paper provides a feasibility analysis and hydrogen technology integration potential with renewable energy for applications in oil and gas remote facilities power supply. It also shows emerging hydrogen technologies potential for use in upstream and midstream applications.
Artificial Intelligence-based Predictive Technique to Estimate Oil Formation Volume Factor
Authors: Kalam Shams , Khan Mohammad Rasheed , Khan Rizwan Ahmed
Published: December 2021

This investigation presents a powerful predictive model to determine crude oil formation volume factor (FVF) using state-of-the-art artificial intelligence (AI) techniques. FVF is a vital pressure-volume-temperature (PVT) parameter used to characterize hydrocarbon systems and is pivotal to reserves calculation and reservoir engineering studies. Ideally, FVF is measured at the laboratory scale; however, prognostic tools to evaluate this parameter can optimize time and cost estimates. The database utilized in this study is obtained from open literature and covers statistics of crude oils of the Middle East region.

Multiple AI algorithms are considered, including Artificial Neural Networks (ANN) and Artificial Neural Fuzzy Inference Systems (ANFIS). Models are developed utilizing an optimization strategy for various parameters/hyper-parameters of the respective algorithms. Unique permutations and combinations for the number of perceptron and their resident layers is investigated to reach a solution that provides the most optimum output. These intelligent models are produced as a function of the parameters intrinsically affecting FVF; reservoir temperature, solution GOR, gas specific gravity, bubble point pressure, and crude oil API gravity. Comparative analysis of developed AI models is performed using visualization/statistical analysis, and the best model is pointed out. Finally, the mathematical equation extraction to determine FVF is accomplished with the respective weights and bias for the model presented.

Graphical analysis is used to evaluate the performance of developed AI models. The results of scatter plots showed most of the points are lying on the 45 degree line. Moreover, during this study, an error metric is developed comprising of multiple analysis parameters; Average absolute percentage error (AAPE), Root Mean Squared Error (RMSE), coefficient of determination (R2). All models investigated are tested on an unseen dataset to prevent a biased model's development. Performance of the established AI models is gauged based on this error metric, demonstrating that ANN outperforms ANFIS with error within 1% of the measured PVT values. A computationally derived intelligent model provides the strongest predictive capabilities as it maps complex non-linear interactions between various input parameters leading to FVF.
Complex Stimulation Approach to Low-Temperature Carbonate Formation Revitalizes Bahrain Brownfield
Authors: AlJanahi Ahmed , Abdelrady Sayed , AlMannai Hassan , AlTawash Feras , Ali Eyad , Yudin Alexey , Al-Jalal Ziad , Guleryuzlu Metin
Published: December 2021

Carbonate formations often require stimulation treatments to be developed economically. Sometimes, proppant fracturing yields better results than acid stimulation. Carbonates are seldom stimulated with large-mesh-size proppants due to admittance issues caused by fissures and high Young’s modulus and narrow fracture width. The Magwa formation of Bahrain’s Awali brownfield is a rare case in which large treatments using 12/20-mesh proppant were successful after the more than 50 years of field development.

To achieve success, a complex approach was required during preparation and execution of the hydraulic fracturing campaign. During the first phase, the main challenges that restricted achieving full production potential in previous stimulation attempts (both acid and proppant fracturing) were identified. Fines migration and shale instability were addressed during advanced core testing. Tests for embedment were conducted, and a full suite of logs was obtained to improve geomechanical modeling. In addition, a target was set to maximize fracture propped length to address the need for maximum reservoir contact in the tight Magwa reservoir and to maximize fracture width and conductivity.

Sufficient fracture width in the shallow oil formation was required to withstand embedment. Sufficient conductivity was required to clean out the fracture under low-temperature conditions (124°F) and to minimize drawdown along the fracture considering the relatively low energy of the formation (pore pressure less than 1,000 psi). Understanding the fracture dimensions was critical to optimize the design. Independent measurement using high-resolution temperature logging and advanced sonic anisotropy measurements after fracturing helped to quantify fracture height. As a result of the applied comprehensive workflow, 18 wells were successfully stimulated, including three horizontal wellbores with multistage fracturing - achieving effective fracture half-lengths of 450-to 500-ft. Oil production from the wells exceeded expectations and more than doubled the results of all the previous attempts. Production decline rates were also less pronounced due to achieved fracture length and the ability to produce more reservoir compartments. The increase in oil recovery is due to the more uniform drainage systems enabled by the conductive fractures.

The application of new and advanced techniques taken from several disciplines enabled successful propped fracture stimulation of a fractured carbonate formation. Extensive laboratory research and independent geometry measurements yielded significant fracture optimization and resulted in a step-change in well productivity. The techniques and lessons learned will be of benefit to engineers dealing with shallow carbonate reservoirs around the world.
Gravity Survey of King Fahd University of Petroleum and Minerals Dammam Dome, Saudi Arabia
Authors: Soupios Pantelis , Stampolidis Alexandros , Fedi Maurizio , Kaka SanLinn , Al-Ramadan Khalid , Tsokas Gregory , Pasteka Roman
Published: December 2021

The study area is a part of Dammam Dome that is situated at King Fahd University of Petroleum & Minerals (KFUPM) campus, Dhahran, Kingdom of Saudi Arabia. The gravity survey was conducted as a pilot case study to explore part of Dammam Dome in greater detail.

Gravity data were collected solely during night hours due to low noise levels. A significant part of the survey was conducted during the summer holiday period, , when there was no student are on campus. A total of 235 gravity measurements were made using a Scintrex CG5 gravitometer, while a Trimble R10+ differential GPS (DGPS) was used to measure the stations’ location and elevation with the highest accuracy.

All gravity data were reduced using several algorithms, and their outcomes were cross-compared. The Complete Bouguer anomaly map for the campus was then generated. Several enhancement filters including edged detection and shallow to deeper source separation were applied. Data were inverted, and 2.5D and 3D models were created to image the subsurface conditions.

The main purpose of this study is to better understand the subsurface geology, tectonic settings of the Dammam Dome by applying the high-resolution gravity method before carrying out any comprehensive geophysical (seismic) 3D survey.
Advancement in Data Engineering and Feature Processing Workflow by Using Deep Learning Techniques for the Automation of ESP Failure Root Cause Analyses
Authors: Karnik Saniya , Yenuganti Navya , Jusri Bonang Firmansyah , Gupta Supriya , Nirgudkar Prasanna , Mohajer Mahyar , Malik Asim
Published: December 2021

Today, Electrical Submersible Pump (ESP) failure analysis is a tedious, human-intensive, and time-consuming activity involving dismantle, inspection, and failure analysis (DIFA) for each failure. This paper presents a novel artificial intelligence workflow using an ensemble of machine learning (ML) algorithms coupled with natural language processing (NLP) and deep learning (DL). The algorithms outlined in this paper bring together structured and unstructured data across equipment, production, operations, and failure reports to automate root cause identification and analysis post breakdown. This process will result in reduced turnaround time (TAT) and human effort thus drastically improving process efficiency.
Thermochemical-Pulse Fracturing of Tight Gas: Investigation of Pulse Loading on Fracturing Behavior
Authors: Al-Nakhli Ayman , Tariq Zeeshan , Mahmoud Mohamed
Published: December 2021

Unconventional and tight gas reservoirs are located in deep and competent formations, which requires massive fracturing activities to extract hydrocarbons. Some of the persisting challenges faced by operators are either canceled or non-productive fractures. Both challenges force oil companies to drill new substitutional wells, which will increase the development cost of such reservoirs.

A novel fracturing method was developed based on thermochemical pressure pulse. Reactive material of exothermic components are used to generate in-situ pressure pulse, which is sufficient to create fractures. The reaction can vary from low pressure pulse, to a very high loading up to 20,000 psi, with short pressurization time.

In this study, Finite Element Modeling (FEM) was used to investigate the impact of the generated pressure-pulse load, by chemical reaction, on the number of induced fractures and fracture length. Actual tests of pulsed fracturing conducted in lab scale using several block samples compared with modeling work. There was a great relationship between the pressure load and fracturing behavior. The greater the pulse load and pressurization rate, the greater the number of created fractures, and the longer the induced fractures.

The developed novel fracturing method will increase stimulated reservoir volume of unconventional gas without introducing a lot of water to formation. Moreover, the new method can reduce formation breakdown pressure by around 70%, which will minimize number of canceled fracturing.
Significance of Smart and Integration System Solutions in Maintaining Well Integrity
Authors: Mugharbil Mohammed , Al Khunaizi Mohammed
Published: December 2021

Well integrity is one of the most critical elements for extending the producible life of a well. A healthy well enables optimization of productivity, enhanced oil recovery, trial tests of new technologies, and much more. Factors such as external corrosive aquifers, internal corrosion, corrosive hydrocarbons, cement bond damage, solids and sand production, and others are considered the main integrity dangers worldwide. When well integrity is affected, not only economic risks but also risks to health, environment and safety are probable. Well integrity is an objective achieved by optimum design and construction of the well after studying and assessing all possible hazards; effective monitoring of the well behavior while it's under production; and timely intervention when an integrity problem is detected.

Evaluating all the aspects of well integrity during well operation is crucial. Cyclic surveillance is important to be followed, including wellhead pressures/annuli surveys, temperature surveys, corrosion logs, wellbore clearance, and well fluid samples, among other activities. With the help of smart and integrated systems, production engineers can have much better control over well integrity and be proactive in making timely decisions prior to any unforeseen events. The smart system keeps the well surveillance records, risk-rank the wells, and sets KPIs to tackle necessary actions wherever applicable. The developed system immediately triggers any threat on well integrity when it occurs.
A Diverse Set of Validation Experiments for Hydraulic Fracturing Simulators
Authors: AlTammar Murtadha J. , Sharma Mukul M.
Published: December 2021

In recent years, numerical fracturing simulation has seen an unprecedented emphasis on capturing the complexities that arise in hydraulic fracturing to better design and execute hydraulic fracturing jobs. As the need for more sophisticated simulators grows, so does the need for more sophisticated physical models that can be used to study the mechanics of the fracturing process under a controlled environment, and to validate the numerical predictions of advanced hydraulic fracturing simulators. We developed and utilized novel laboratory capabilities to perform an extensive set of fracturing experiments across various aspects of hydraulic fracture propagation including the effect of far-field stress contrast, rock mechanical heterogeneity, multi-well injection, borehole notching, fluid injection method, type of injection fluid, and interaction with natural fractures. Numerous direct observations and digital image analyses are documented to provide fundamental insights in hydraulic fracturing. As demonstrated through a few case studies from the literature, our laboratory experiments are very useful for validating hydraulic fracturing simulators due to the small-scale, two-dimensional (2-D) nature, controlled environment, and well-characterized properties of the test specimens used in the experiments.
New Workflow of Sediment Mass Balancing, from Local Datasets, for Predicting Basin Scale Trends
Authors: Michael Nikolaos A. , Zuhlke Rainer
Published: December 2021

Objectives/Scope

Sediment volumetric budget estimates are very important input parameters for process-based depositional modelling (forward stratigraphic modelling). This paper presents a new integrated approach for analyze sediment volumetric budgets in sedimentary basins that is based on the reconstruction of regional grain size trends. In subsurface studies of sediment routing systems, noticeable uncertainties in estimated total sediment volumes occur when available datasets are limited to local areas that do not cover the entire sediment routing system. These uncertainties also affect models of catchment areas, structural uplift, and denudation rates as well as net:gross predictions.

Methods, Procedures, Process

The new integrated approach focuses on reconstructing sediment budgets for entire sediment fairways from limited local datasets. It uses a combination of sediment mass balancing and local grain size distributions to predict basin-wide grain size distributions. The comparison of local grain size to fairway-scale grain size trends is key in correcting sediment volumetrics for significantly reduced uncertainties in catchment reconstruction and net:gross ratios predictions at the scale of sediment fairways, sub-basins, prospects and exploration/production fields.

Results, Observations, Conclusions

The new approach has been applied successfully to two subsurface continental to marine delta systems. They cover periods of approximately 7 My in total and include four limited local areas of interest (AOI). These local AOIs measure 200×200 km, while the entire sub-basin measures 500×800 km. The new approach indicates that only up to 40% of the total sediment volume of each fairway could be captured by previous methodologies with limited local areas of interest. A maximum of 70% of the entire sink sediment volume could be incorporated in local areas of interest. The new approach presented in this paper significantly lowers the uncertainties in sediment volume estimates, depositional rates and lithology distribution input parameters in forward stratigraphic modelling. For the two case studies, previous sediment flux models indicated rates of 10,000 km/Myr. The new integrated approach indicates that sediment flux actually reached 30,000 km/Myr with major implications for sediment distribution, net:gross prediction and catchment size and denudation rates estimates.

Novel/Additive Information

The new integrated approach reduces uncertainties in catchment size and tectonic exhumation rate estimates for clastic depositional systems. It provides lower uncertainty parameters (sediment volume, source locations, sediment fractions, diffusion coefficients) for forward stratigraphic modelling, e.g., for reservoir quality prediction in hydrocarbon exploration. In fundamental research, provenance analyses can be better constrained by improved catchment size prediction and sediment grain size distribution models for sink areas
Design of a Dislocation Well Pattern and Drilling of Shallow 3D Cluster Horizontal Wells for Development of Ultra Heavy Oil
Authors: Chen Peng , Yang Guobin , Chen Lei , Zhang Guobin , Han Haochen , Chen Chen
Published: December 2021

The Junin block in Venezuela was known as an ultra heavy oil belt reserved in extra shallow layers (950ft-1,380ft) with unconsolidated formations. A cluster wells platform drilling was required for the Field Development Program (FDP). Optimisation of the well pattern and drilling of shallow 3D cluster horizontal wells for development of ultra heavy oil are presented in this paper.

A well pattern of hand-shape dislocation was forwarded to enhance effective recovery of heavy oil in diamond blind area. Optimisation of the casing programs and control of the well trajectories as well as other key performance drilling were designed. A strict anti-collision barrier design and operation steps were worked out to assure the drilling safety. The loss-resistance, anti-collapse, stick-stuck proof, lubrication and reservoir protection were put into considerations for the drilling fluid design. Recovery of heavy oil was enhanced by means of electrical heating system.

Drilling challenges such as shallow target zones, big build-up rate, long horizontal sections, great friction drag and torques, and well trajectories control were experienced and settled. Especially the puzzles of well trajectories control in unconsolidated formations, great friction drag and torques of strings in large displacement long horizontal sections for subsequent operations, and the unstable wellbore were tackled. A typical well data revealed that the horizontal displacement vs. TVD ratio was as high as up to 4.5. The setting depth of surface casing and the determination of KOP were critical to the horizontal wells with large displacement in shallow layers. Pressurized combined drilling and casing-running by means of top drive overcame the drag and torque and achieved planned TD and casing setting depth. The use of electrical wireline heating rod increased the temperatures in and close to the wellbore, and compensated the radius heat loss and avoided viscosity increase of heavy oil so that the output was maintained and improved.

It was the first time for successful drilling of shallow 3D cluster horizontal wells with ratio of horizontal displacement vs. TVD over 3.5 in heavy oil belt of Venezuela. The innovative palm-shape dislocation of the well pattern design satisfied the demand of reservoir development and contributed to good production gain of heavy oil.
Artificial Intelligence Aided Proxy Model for Water Front Tracking in Fractured Carbonate Reservoirs
Authors: Zhang Yanhui , Hoteit Ibrahim , Katterbauer Klemens , Marsala Alberto
Published: December 2021

Saturation mapping in fractured carbonate reservoirs is a major challenge for oil and gas companies. The fracture channels within the reservoir are the primary water conductors that shape water front patterns and cause uneven sweep efficiency. Flow simulation for fractured reservoirs is typically time-consuming due to the inherent high nonlinearity. A data-driven approach to capture the main flow patterns is quintessential for efficient optimization of reservoir performance and uncertainty quantification.

We employ an artificial intelligence (AI) aided proxy modeling framework for waterfront tracking in complex fractured carbonate reservoirs. The framework utilizes deep neural networks and reduced-order modeling to achieve an efficient representation of the reservoir dynamics to track and determine the fluid flow patterns within the fracture network. The AI-proxy model is examined on a synthetic two-dimensional (2D) fractured carbonate reservoir model. Training dataset including saturation and pressure maps at a series of time steps is generated using a dual-porosity dual-permeability (DPDP) model. Experimental results indicate a robust performance of the AI-aided proxy model, which successfully reproduce the key flow patterns within the reservoir and achieve orders of shorter running time than the full-order reservoir simulation. This suggests the great potential of utilizing the AI-aided proxy model for heavy-simulation-based reservoir applications such as history matching, production optimization, and uncertainty assessment.
A Practical Model for Water Injection Evaluation and Optimization in Typical Offshore Reservoirs Considering Formation Heterogeneity Based on Experimental Study
Authors: Huang Shijun , Zhu Yuanrui , Chai Shichao , Ding Guanyang , Xin Yicheng , Li Peiyu
Published: December 2021

A major concern with water injection in offshore oil reservoir is the water breakthrough. The formation heterogeneity is the main reason for it. In order to evaluate the water injection efficiency, a visualized 2-D experiment was carried out to obtain the distribution law of injected water and the variation of injection parameters in homogeneous and heterogeneous formation. In addition, a coupled wellbore/reservoir model was established by applying microelement method, superposition principle and imaging. This model considers the formation heterogeneity and pressure drop caused by wellbore friction. The visualized 2-D sand filling displacement experiment indicates that the injection rate at the horizontal well heel is greater than that at the toe and the injection front is more irregular in heterogeneous formation. The injection rate and injection pressure distribution along the horizontal well are obtained analytically based on the proposed model, the results show that the injection rate at the two sides of the wellbore is much higher than that in the middle when the formation is homogeneous and the wellbore is infinite-conductive. In this case, the injection rate curve along horizontal well shows a "U" shaped distribution. When a finite-conductive horizontal wellbore is considered, the injection rate at the heel of the wellbore is higher than that of the toe, although the injection rate curve along horizontal well also exhibits a deformed "U" shape distribution. For the formation heterogeneities along the horizontal wellbore, the injection rate distribution curve is not continuous anymore, but a deformed "U" shape is also observed for each wellbore segment. At last, the established model was applied to an ultra-heterogeneous offshore reservoir. It is concluded that the profile control effect of typical well is obvious. The results of this study are of great significance for the calculation of the injection rate profile and improving the water injection efficiency.
Autonomous Directional Drilling Planning and Execution Using an Industry 4.0 Platform
Authors: BA Samba , Ignova Maja , Mantle Kate , Chassard Adrien , Yu Tao , Chambon Sylvain , Akkaoui Ziad , Jiang Lu , Harmer Richard , Barcelata Olivia , Kim Jinsoo , Rhazaf Mustapha
Published: December 2021

Today, directional drilling is considered a mix between art and science only performed by experts in the field. In this paper, we present an autonomous directional drilling framework using an industry 4.0 platform that is built on intelligent planning and execution capabilities and is supported by surface and downhole automation technologies to achieve consistently performing directional drilling operations accessible for easy remote operations.

Intelligent planning builds on standard planning activities that are needed for directional drilling applications and advances them with rich data pipelines that feed predictive and prescriptive machine-learning (ML) models; this enables more accurate BHA tendencies, operating parameters, and trajectory plans that ultimately reduce executional risk and uncertainty.

Intelligent execution provides technologies that facilitate decision-making activities, whether they be from the wellsite or town, by leveraging the digital-drilling program that is generated from the intelligent planning activities. The program connects planning expectations, real-time execution data from the surface and downhole equipment, and generates insights from data analytics, physics-based simulations, and offset analysis to achieve consistent directional drilling performance that is transparent to all stakeholders.

This new framework enables a self-steering BHA for directional drilling operations. The workflow involves an automated evaluation of the current bit position with respect to the initial plan, automated evaluation of the maximum dogleg capability of the BHA, and the capability to examine the health of the BHA tools and, if needed, an automated re-planning of an optimized working plan. This is accomplished on a system level with interdependencies on the different elements that make up the complete workflow.

This new autonomous directional drilling framework will minimize operational risk and cost-per-foot drilled; maximize performance, procedural adherence, and establish consistent results across fields, rigs, and trajectories while enabling modern remote operations.
Methodology of Effective Lateral Placement for Underbalanced Coiled Tubing Drilling Wells
Authors: Abdul Aziz Azly , Moreno Sierra Ferney , Aldossary Nawaf
Published: December 2021

This paper describes a methodology that has been developed to maximize lateral placement in productive reservoir intervals during underbalanced coiled tubing drilling (UBCTD) operations. UBCTD has emerged as an effective and economically viable development solution for exploiting reserves in mature gas reservoirs. In some cases, it can be a suitable solution to develop reserves in more geologically complex and heterogonous reservoirs over the conventional drilling and stimulation techniques.

The methodology integrates big surface and subsurface data from multiple sources in multiple formats in real to near real-time that are normally acquired during UBCTD drilling operations. The multiple sources of data include subsurface geology, wellsite biosteering, reservoir influx, well testing and drilling, and can provide important information about the reservoirs encountered. With the aid of data analytics and an advanced visualization tool, the data is translated into in series of engineering plots that enable easier identification of productive intervals and more informed as well as efficient lateral placement decisions. This methodology has proven superior to the conventional instantaneous Productivity Index (PI) approach that is commonly used for UBCTD lateral placement.

The methodology has been tested with good success in a number of recently drilled UBCTD wells in geologically complex depositional environments across carbonates and clastic reservoirs. Post flowback and pressure transient test analyses have shown significant improvement in the well deliver abilities and effective lateral lengths. Past performance from wells drilled using the PI method will be compared with wells drilled with this method.
Surfactant Polymer SP vs. Alkali-Surfactant Polymer ASP: Do We Need the a in ASP?
Authors: Delamaide Eric , Rousseau David , Wartenberg Nicolas , Salaun Mathieu
Published: December 2021

The first surfactant-based pilots can be traced back to the 1960s and since then almost a hundred field tests have taken place. Interestingly, almost half of these pilots have used an alkali (ASP) and the other half has not (SP). This reflects the current status of the industry which is divided along the same lines and over the same question: do surfactant-based processes require alkali or not? This paper proposes to address this question by providing explanations and discussing case studies.

The paper will start by reminding the reader of the role of both surfactant and alkali and will review the pros and cons of alkali in terms of formulation performances, adsorption but also surface facilities and logistics. Several cases studies (lab and field) will be discussed to show when alkali can and cannot be used, and what solutions are available as alternatives to the use of alkali.

Although alkali allows reducing both surfactant concentration and adsorption, it can also cause severe scaling and requires additional facilities including water softening; in addition, the large volumes of alkali required can cause logistical challenges. On the other hand, the main challenges of formulations without alkali is finding surfactants that can develop a low enough Interfacial Tension and low adsorption, or to find an acceptable adsorption mitigation strategy such as salinity gradient or adsorption inhibitors. In the early years of SP projects, very high surfactant concentrations were used (micellar process) and the process was not economic; as a result, alkali was seen as the only realistic solution. This appears to no longer be the case due to the developments of new surfactants. Although most projects in recent years have favoured the use of alkali, it seems that a trend towards SP is growing, with recent field projects in Kuwait, Oman, China and Russia favouring the SP solution.

This paper will provide a discussion on the pros and cons of the use of alkali in surfactant-based processes. It will show that although using alkali has been a standard for many years it also entails severe surface issues such as scaling and requires additional capital for water softening and logistics. More importantly, recent developments in surfactants now seem to provide alkali-free solutions that can compete in terms of formulation performances. This now needs to be confirmed in the field.
Accurate Live Interfacial Tension for Improved Reservoir Engineering Practices
Authors: Okasha Taha , Al Hamad Mohammed , Sauerer Bastian , Abdallah Wael
Published: December 2021

Current reservoir simulators use interfacial tension (IFT) values derived from dead oil measurements at ambient conditions or predicted from literature correlations. IFT is highly dependent on temperature, pressure and fluid composition. Therefore, knowledge of the IFT value at reservoir conditions is essential for accurate reservoir fluid characterization. This study compares IFT values from dead and live oil measurements and the results of literature predicted values, thereby clearly showing the weakness of existing correlations when trying to predict crude oil IFT. A total of ten live oils was sampled for this study. Using the pendent drop technique, IFT was measured for each oil at different conditions: in the under-saturated region at reservoir pressure and temperature, in the saturated region at reservoir temperature, and for dead oil at ambient conditions. Basic PVT properties such as gas to oil ratio (GOR), gas and liquid composition, density, viscosity and molecular weight were also measured. The bubble point for each oil was identified to define the pressure step in the saturated region for extra IFT measurement. The equilibrium IFT values for the live oils were generally higher than for the corresponding dead oils. For oils where this general trend was not observed, contaminations were found in the crude samples. The use of current literature correlations does not allow to predict correct reservoir IFT. Therefore, this study provides accurate live IFT values for a variety of reservoir fluids and conditions in combination with live oil properties, highly beneficial to reservoir engineers, allowing better oil production planning.
NanoGram Detection of Drilling Fluids Additives for Uncertainty Reduction in Surface Logging
Authors: Zhu S. Sherry , Antoniv Marta , Poitzsch Martin , Aljabri Nouf , Marsala Alberto
Published: December 2021

Manual sampling rock cuttings off the shale shaker for lithology and petrophysical characterization is frequently performed during mud logging. Knowing the depth origin where the cuttings were generated is very important for correlating the cuttings to the petrophysical characterization of the formation. It is a challenge to accurately determine the depth origin of the cuttings, especially in horizontal sections and in coiled tubing drilling, where conventional logging while drilling is not accessible. Additionally, even in less challenging drilling conditions, many factors can contribute to an inaccurate assessment of the depth origin of the cuttings. Inaccuracies can be caused by variation of the annulus dimension used to determine the lag time (and thus the depth of the cuttings), by the shifting or scrambling of cuttings during their return trip back to the surface, and by the mislabelling of the cuttings during sampling. In this work, we report the synthesis and application of polystyrenic nanoparticles (NanoTags) in labeling cuttings for depth origin assessment. We have successfully tagged cuttings using two NanoTags during a drilling field test in a carbonate gas well and demonstrated nanogram detection capability of the tags via pyrolysis-GCMS using an internally developed workflow. The cuttings depth determined using our tags correlates well with the depth calculated by conventional mud logging techniques.
Field Assessment of Camera Based Drilling Dynamics
Authors: Koulidis Alexis , Abdullatif Mohamed , Abdel-Kader Ahmed Galal , Ayachi Mohammed-ilies , Ahmed Shehab , Gooneratne Chinthaka , Magana-Mora Arturo , Affleck Mike , Alsheikh Mohammed
Published: December 2021

Surface data measurement and analysis are an established mean of detecting drillstring low-frequency torsional vibration or stick-slip. The industry has also developed models that link surface torque and downhole drill bit rotational speed. Cameras provide an alternative noninvasive approach to existing wired/wireless sensors used to gather such surface data. The results of a preliminary field assessment of drilling dynamics utilizing camera-based drillstring monitoring are presented in this work.

Detection and timing of events from the video are performed using computer vision techniques and object detection algorithms. A real-time interest point tracker utilizing homography estimation and sparse optical flow point tracking is deployed. We use a fully convolutional deep neural network trained to detect interest points and compute their accompanying descriptors. The detected points and descriptors are matched across video sequences and used for drillstring rotation detection and speed estimation. When the drillstring's vibration is invisible to the naked eye, the point tracking algorithm is preceded with a motion amplification function based on another deep convolutional neural network.

We have clearly demonstrated the potential of camera-based noninvasive approaches to surface drillstring dynamics data acquisition and analysis. Through the application of real-time object detection algorithms on rig video feed, surface events were detected and timed. We were also able to estimate drillstring rotary speed and motion profile. Torsional drillstring modes can be identified and correlated with drilling parameters and bottomhole assembly design. A novel vibration array sensing approach based on a multi-point tracking algorithm is also proposed. A vibration threshold setting was utilized to enable an additional motion amplification function providing seamless assessment for multi-scale vibration measurement.

Cameras were typically devices to acquire images/videos for offline automated assessment (recently) or online manual monitoring (mainly), this work has shown how fog/edge computing makes it possible for these cameras to be "conscious" and "intelligent," hence play a critical role in automation/digitalization of drilling rigs. We showcase their preliminary application as drilling dynamics and rig operations sensors in this work. Cameras are an ideal sensor for a drilling environment since they can be installed anywhere on a rig to perform large-scale live video analytics on drilling processes.