bluuebunny/crossref_metadata_2025 huggingface dataset:
Nanoemulsions: A Versatile Technology for Oil and Gas Applications
Authors: AlJabri Nouf , Shi Nan
Published: December 2021

Nanoemulsions (NEs) are kinetically stable emulsions with droplet size on the order of 100 nm. Many unique properties of NEs, such as stability and rheology, have attracted considerable attention in the oil industry. Here, we review applications and studies of NEs for major upstream operations, highlighting useful properties of NEs, synthesis to render these properties, and techniques to characterize them. We identify specific challenges associated with large-scale applications of NEs and directions for future studies. We first summarize useful and unique properties of NEs, mostly arising from the small droplet size. Then, we compare different methods to prepare NEs based on the magnitude of input energy, i.e., low-energy and high-energy methods. In addition, we review techniques to characterize properties of NEs, such as droplet size, volume fraction of the dispersed phase, and viscosity. Furthermore, we discuss specific applications of NEs in four areas of upstream operations, i.e., enhanced oil recovery, drilling/completion, flow assurance, and stimulation. Finally, we identify challenges to economically tailor NEs with desired properties for large-scale upstream applications and propose possible solutions to some of these challenges. NEs are kinetically stable due to their small droplet size (submicron to 100 nm). Within this size range, the rate of major destabilizing mechanisms, such as coalescence, flocculation, and Ostwald ripening, is considerably slowed down. In addition, small droplet size yields large surface-to-volume ratio, optical transparency, high diffusivity, and controllable rheology. Similar to applications in other fields (food industry, pharmaceuticals, cosmetics, etc.), the oil and gas industry can also benefit from these useful properties of NEs. Proposed functions of NEs include delivering chemicals, conditioning wellbore/reservoir conditions, and improve chemical compatibility. Therefore, we envision NEs as a versatile technology that can be applied in a variety of upstream operations. Upstream operations often target a wide range of physical and chemical conditions and are operated at different time scales. More importantly, these operations typically consume a large amount of materials. These facts not only suggest efforts to rationally engineer properties of NEs in upstream applications, but also manifest the importance to economically optimize such efforts for large-scale operations. We summarize studies and applications of NEs in upstream operations in the oil and gas industry. We review useful properties of NEs that benefit upstream applications as well as techniques to synthesize and characterize NEs. More importantly, we identify challenges and opportunities in engineering NEs for large-scale operations in different upstream applications. This work not only focuses on scientific aspects of synthesizing NEs with desired properties but also emphasizes engineering and economic consideration that is important in the oil industry.
Innovative Approach of Drilling Risk Identification and Mitigation Using Drilling Automation Services: Case Studies
Authors: Roy Chowdhury Ashabikash , Forshaw Matthew , Atwal Narender , Gatzen Matthias , Habib Salman , Afolabi Jonathan
Published: December 2021

In the increasingly complex and cost sensitive drilling environment of today, data gathered using downhole and surface real-time sensor systems must work in unison with physics-based models to facilitate early indication of drilling hazards, allowing timely action and mitigation. Identification of opportunities for reduction of invisible lost time (ILT) is similarly critical. Many similar systems gather and analyze either surface or downhole data on a standalone basis but lack the integrated approach towards using the data in a holistic decision-making manner. These systems can either paint an incomplete picture of prevailing drilling conditions or fail to ensure system messages result in parameter changes at rigsite. This often results in a hit or miss approach in identification and mitigation of drilling problems.

The automated software system architecture is described, detailing the physics-based models which are deployed in real-time consuming surface and downhole sensor data and outputting continuous, operationally relevant simulation results. Measured data from either surface, for torque & drag, or downhole for ECD & ESD is then automatically compared both for deviation of actual-to-plan, and for infringement of boundary conditions such as formation pressure regime. The system is also equipped to model off-bottom induced pressures; swab & surge, and dynamically advise on safe, but optimum tripping velocities for the operation at hand. This has dual benefits; both the avoidance of costly NPT associated with swab & surge, as well as being able to visually highlight running speed ILT. All processing applications are coupled with highly intuitive user interfaces.

Three successful deployments all onshore in the Middle East are detailed. First a horizontal section where real-time model vs. actual automatic comparison of torque & drag samples, validated with PWD data allowed early identification of poor hole cleaning. Secondly, a vertical section where again the model vs. actual algorithmic automatically identified inadequate hole cleaning in a case where conventional human monitoring did not. Finally, a case is exhibited where real-time modelling of swab and surge, as well as intuitive visualization of the trip speeds within those boundary conditions led to a significant increase in average tripping speeds when compared to offset wells, reducing AFE for the operator. Common for all three deployments was an integrated well services approach, with a single service company providing the majority of services for well construction, as well as an overarching remote operations team who were primary users of the software solutions deployed.
Hybrid Fluid Flow Simulation Combining Full Physics Simulation and Artificial Intelligence
Authors: Mezghani Mokhles , AlIbrahim Mustafa , Baddourah Majdi
Published: December 2021

Reservoir simulation is a key tool for predicting the dynamic behavior of the reservoir and optimizing its development. Fine scale CPU demanding simulation grids are necessary to improve the accuracy of the simulation results. We propose a hybrid modeling approach to minimize the weight of the full physics model by dynamically building and updating an artificial intelligence (AI) based model. The AI model can be used to quickly mimic the full physics (FP) model.

The methodology that we propose consists of starting with running the FP model, an associated AI model is systematically updated using the newly performed FP runs. Once the mismatch between the two models is below a predefined cutoff the FP model is switch off and only the AI model is used. The FP model is switched on at the end of the exercise either to confirm the AI model decision and stop the study or to reject this decision (high mismatch between FP and AI model) and upgrade the AI model.

The proposed workflow was applied to a synthetic reservoir model, where the objective is to match the average reservoir pressure. For this study, to better account for reservoir heterogeneity, fine scale simulation grid (approximately 50 million cells) is necessary to improve the accuracy of the reservoir simulation results. Reservoir simulation using FP model and 1024 CPUs requires approximately 14 hours. During this history matching exercise, six parameters have been selected to be part of the optimization loop. Therefore, a Latin Hypercube Sampling (LHS) using seven FP runs is used to initiate the hybrid approach and build the first AI model. During history matching, only the AI model is used. At the convergence of the optimization loop, a final FP model run is performed either to confirm the convergence for the FP model or to re iterate the same approach starting from the LHS around the converged solution. The following AI model will be updated using all the FP simulations done in the study. This approach allows the achievement of the history matching with very acceptable quality match, however with much less computational resources and CPU time.

CPU intensive, multimillion-cell simulation models are commonly utilized in reservoir development. Completing a reservoir study in acceptable timeframe is a real challenge for such a situation. The development of new concepts/techniques is a real need to successfully complete a reservoir study. The hybrid approach that we are proposing is showing very promising results to handle such a challenge.
Condensate Banking Removal Using Slow Release of In-Situ Energized Fluid
Authors: Al-Nakhli Ayman , Hassan Amjed , Mahmoud Mohamed , Al-Baiz Abdualilah , Buhaezah Wajdi
Published: December 2021

Condensate banking represent a persistent challenge during gas production from tight reservoir. The accumulation of condensate around the wellbore can rapidly diminish gas production. When reservoir pressure drop below dew point, condensate start to dropout from gas phase, filling pores and permeable fractures, and block gas production. There are several strategies to mitigate condensate banking, however, these strategies are either demonstrate limited results or are economically not viable.

In this study, a novel method to mitigate condensate was developed using thermochemical reactants. Slow-release of thermochemical reactants inside different core samples was studied. The effect of in-situ generation of gas on the petrophysical properties of the rock was reported. Thermochemical treatment was applied to recover condensate on sandstone and carbonate, where the reported recoveries were around 70%. However, when shale sample was used, the recovery was only 43%.

Advanced Equation-of-State (EoS) compositional and unconventional simulator (GEM) from CMG (Computer Modelling Group) software was used to simulate thermochemical treatment and gas injection. The simulation study showed that thermochemical stimulation had increased production period from 3.5 to 22.7 months, compared to gas injection.
CO2 Waterless Fracturing and Huff and Puff in Tight Oil Reservoir
Authors: Cui Weixiang , Chen Li , Wang Chunpeng , Zhang Xiwen , Wang Chao
Published: December 2021

CO2 fracturing technique is a kind of ideal waterless stimulation tech. It has the advantages of water free, low reservoir damage, and production increase by improving the reservoir pressure. At the same time, combined with reasonable shut-in control after fracturing, it can be realized integrated development technology of energy storage -fracturing and oil displacement with CO2 waterless stimulation. For low-grade and low-permeability tight reservoirs, through the integration technology of CO2 fracturing and CO2 flooding, fracture-type "artificial permeability" is formed in the formation, and micro-nano pore throat of underground matrix is formed as oil and gas production system, which realizes the development of artificial energy, reduces carbon emissions, effectively improves the productivity of low-permeability and tight reservoirs, thus further improves oil recovery. The technology mainly includes two aspects: vertical wells adopt CO2 fracturing + huff and puff displacement integration technology, horizontal wells adopt water-based fracturing + CO2 displacement technology, and utilize the high efficiency of CO2 penetration in reservoirs and crude oil viscosity reduction, which can greatly improve oil recovery, while achieving large-scale CO2 storage and reducing carbon emissions. It is both realistic and economic, and has great social benefits.

The integrated development technology of energy storage -fracturing and oil displacement with CO2 waterless stimulation has been applied for 10 wells in oilfield, which has achieved good results in increasing reservoir volume, increasing formation energy, reducing oil viscosity and enhancing post-pressure recovery. As a result, the production of them has increased by over 100%. With low viscosity and high diffusion coefficient, supercritical CO2 is good for improving fracturing volume. Effective CO2 fracturing technology can improve stimulated reservoir volume, downhole monitoring results show that the cracks formed by CO2 fracturing is 3 times the size of those formed by water-based fracturing.
Application of Time Lapse 3D/4D Seismic in the Monitoring of Steam Conformance and Cap Rock Integrity of Heavy Oil Thermal Production Project in North Kuwait
Authors: Ren Zu Biao , Al-Rabah Abdullah Akarim , Pico Antonio , Freeman Michael
Published: December 2021

The challenge of Heavy oil thermal production Kuwait includes how to monitor steam flood effectiveness and cap rock integrity. Due to shallow & heterogeneous reservoirs and thin cap rock, pressurized and heated steam could diffuse in all directions and breach the cap rock. KOC acquired a baseline & time-lapsed surface seismic and 3D VSP for purposes of monitoring CSS production. This paper presents a technical application of seismic inversion to steam chamber size & cap rock integrity interpretation.

The seismic image area includes 13 CSS wells, at varying CSS stages of steam injection, soaking and production. The data acquisition consisted of a base and a time-lapsed monitor seismic; each acquisition period lasting for around a week and separated by 40 day intervals. The simultaneous acquisition of surface seismic and the 3D VSP enabled complimentary data exchange and results validation. Well data of sonic and PHIT are used for building a low frequency inversion model. Rock physical modeling is also required to understand the effect of steam and production changes on acoustic and elastic properties. Various geophysical inversion methods are performed on AI inversion of post & pre stack seismic and Poisson's ratio inversion. To estimate reservoir temperature changes due to steam injection, the calibrated rock-physics model was utilized to relate the AI response to temperature change.

The steam injection is expected to decrease acoustic impedance. The AI difference exhibits much wider impedance anomalies revealing steam chamber size and the production zone around the wells at various stages of the CSS cycle. Average temperature maps in reservoirs derived from rock-physical modeling also show temperature change around the wells. Inverted seismic attributes of acoustic impedance and temperature were used for study of cap rock integrity.

Interpretation results of the steam size through AI and temperature analysis at reservoir and cap rock enable optimization of our CSS and SF completion strategies include steam pressure and volume, soaking period and thermal production control. The result of cap rock integrity monitoring also indicate no serious damage of cap rock under existing conditions of CSS operation (WHT: 420 °F & WHP: 320 PSI), which defines the limits of strategies to increase steam pressure and volume to increase EOR efficiency.
Stratigraphic Trap Potential in the Lower Cretaceous Ratawi Interval, Partitioned Zone PZ, Saudi Arabia and Kuwait
Authors: Hakam Ibrahim , Toomey Niall , Ghose Sujoy , Ponthier Joe , Zimmerman Jeremy
Published: December 2021

The Lower Cretaceous Ratawi Oolite Formation is among the most prolific reservoirs in the PZ, having produced a significant amount of oil since the 1950's. The Ratawi is interpreted as a low angle carbonate ramp, with high-energy grainstone facies developing on structural highs. Production is focused on these structural highs, with very few well penetrations off structure. Recent work has identified potential Ratawi stratigraphic traps in prograding clinoforms along the flanks of the North Fuwaris structural high.

Core data from Ratawi wells illustrate the interplay of depositional environment and diagenesis on reservoir quality. Gross depositional environment (GDE) maps created from the integration of seismic facies and core observations indicate the stratigraphic trap lies in the ramp slope. Reservoir quality variability of the ramp slope across the PZ is explained by the diagenetic history of the Ratawi. Early equant calcite cement develops from substantial meteoric runoff and lowers porosity, while later dissolution enhances reservoir quality. The area of interest is isolated from potential meteoric inputs; we do not expect equant calcite cement or the associated reduction in reservoir quality.

Seismic interpretation was performed on recently acquired PZ 3D data to map the Ratawi section. Clinoforms (inclined geometry) were mapped along the western flank of the North Fuwaris high. These facies appear to have developed as a result of progradation to the NW and are indicative of good reservoir development. Leads were generated using the depth structure and GDE maps, supported by amplitude extraction and seismic inversion volumes. Amplitudes extracted from the clinoform shows that the strongest anomaly is along the structurally highest part of the horizon and the anomaly weakens downdip. High amplitudes could be a proxy for reservoir (porosity), and sharp turn-off in amplitude might indicate that lateral and updip facies changes to non-reservoir which is needed for an effective seal. Recent seismic inversion performed on the Ratawi interval shows a good match between the Acoustic Impedance (AI) from logs and the computed AI from the seismic. The Ratawi Oolite appears as a low impedance interval between overlying Ratawi Limestone and underlying Makhul. Porosity estimated from AI volumes appear to support possible Ratawi reservoir development along the flanks of North Fuwaris and Wafra highs.
The Impact of Rock Microstructure and Petrophysical Properties on the Velocity-Pressure Relationship of Carbonates
Authors: El-Husseiny Ammar
Published: December 2021

This study investigates the impact of petrophysical rock properties on the velocity-pressure relationship in carbonates. It presents an approach to predict the changes in compressional velocity (Vp) as function of pressure in carbonates. The approach honors the complexity of carbonates by incorporating various petrophysical rock properties including bulk density, porosity, mineralogy and pore stiffness. The data used in this study consists of rock properties (density, porosity, mineralogy) and elastic velocity measured as function of confining pressure for 220 carbonate core plug samples from published literature. Pearson correlation coefficient was calculated to evaluate the significance of each property in predicting velocity-pressure relationship. A simple regression was formulated incorporating all significant input rock properties to predict Vp as function of pressure based on initial measured velocity at a given pressure. The predictions were compared with the measured Vp. The results show that the sensitivity of Vp to changes in pressure increases as the porosity and pore compressiblity increases. On the other hand, samples with higher bulk density and Vp / Vs ratio (at initial lowest pressure) show little Vp variations as function of increasing pressure. High Vp / Vs values are observed in samples that are well cemented and have less clay or silisiclastic fraction. Such characteristics reduce the compressibility of pores leading to non-variable velocity-pressure relationship. Incorporating the rock properties in regression analysis could successfully predict Vp as function of pressure with a correlation coefficient of 0.99 and average absolute error of less than 3%. Since all input parameters (rock properties) can be estimated from well logs, the presented approach can potentially be used to predict in-situ changes in Vp due to pressure changes. This can assist the interpretation of time lapse seismic, and in geomechanics-related applications.
An Eco-Friendly and Low Carbon Footprint Water Treatment Technology for Produced Water Recycling
Authors: Aljedaani Abdulrahman , AlOtaibi Mohammed , Ayirala Subhash , Al-Yousef Ali
Published: December 2021

Many challenges and limitations are experienced while treating the produced water in oil fields, due to large volumes of water produced together with oil. In this paper, we propose a new method to treat produced water, by integrating humidification and de-humidification desalination (HDH) unit with waste heat, extracted from abandoned oil and gas wells. This solution is based on circulating the produced water through abandoned wells (both vertical and horizontal wells) and heat them up to 60-80°C so that the heated water can be directly used as hot feed water into the HDH unit. This eliminates either electricity or power requirements from an external source thereby significantly lowering the energy requirements. The direct use of hot produced water at the desired temperature range allows for better performance of the HDH desalination unit, while reducing the operating cost, besides minimizing CO2 emissions to the environment. The use of heat extracted from abandoned oil and gas wells in the form of geothermal energy enables the utilization of waste heat associated with existing wells, which is already available in most of the oil fields. The proposed method therefore provides a sustainable renewable energy solution for produced water desalination using HDH processes.
Bringing New Levels of Automation and Flexibility to Well Testing Operations — Case Study
Authors: Temer Elias , Zerpa Mendez Nahomi , Kaipov Yermek
Published: December 2021

The oil industry has been perpetually examining well testing methods, with the goal of improving overall efficiency, ensuring data quality, and streamlining processes to achieve program objectives. Over the years, the aim of drillstem testing (DST) has remained mostly unchanged. However, operators want to meet the forecasted production investments of their fields, while improving operational efficiency and maintaining the highest level of operational standards, with safety and the environment being paramount. One of the solutions was developing a live, downhole, reservoir testing platform. The breakthrough consisted in introducing automation and real time monitoring to adjust the test program according to the actual reservoir response rather than blindly following a predefined test program, necessitating better operational flexibility. This platform is united by a wireless telemetry technology allowing an acoustic communication with downhole tools in real time. The automation of the data acquisition, downhole tools actuation and real time monitoring of the downhole operations, gives the operators the ability to perform well tests with reduced uncertainties, less human intervention and improved data quality. The early availability of reservoir knowledge enables operational efficiencies by meeting the test objectives earlier, thus reducing significantly the overall test period and the associated well testing costs.

This paper describes the common well test objectives and challenges, the overall design of the wireless telemetry system, and automation of the job preparation and execution of the downhole operations that led to the successful completion of the well test campaign in very hostile condition, remote areas and restricted period. The use of the telemetry system in several well testing campaigns in different regions of the world, allowed to control critical downhole equipment and to acquire reservoir data transmittable to the clients office in town in real time. Various operation examples will be discussed to demonstrate how the automated data acquisition and downhole operations control has been used to optimize operations.
Rigorous Performance Evaluation of Stochastic Optimization for Water Injection Strategies
Authors: BuKhamseen Nader , Saffar Ali , Maucec Marko
Published: December 2021

This paper presents an approach to optimize field water injection strategies using stochastic methods under uncertainty. For many fields, voidage replacement was the dictating factor of setting injection strategies. Determining the optimum injection-production ratio (IPR) requires extensive experience taking into consideration all the operational facility constraints. We present the outcome of a study, in which several optimization techniques were used to find the optimum field IPR values and then elaborate on the techniques? strengths and weaknesses. The synthetic reservoir simulation model, with millions of grid blocks and significant numbers of producers and injectors, was divided into seven IPR regions based on a streamline study. Each region was assigned an IPR value with an associated uncertainty interval. An ensemble of fifty probabilistic scenarios was generated by experimental design, using Latin Hypercube sampling of IPR values within tolerance limits. Scenarios were used as the main sampling domain to evaluate a family of optimization engines: population-based methods of artificial intelligence (AI), such as Genetic algorithms and Evolutionary strategies, Bayesian inference using sequential or Markov chain Monte Carlo, and proxy-based optimization.

The optimizers were evaluated based on the recommended IPR values that meet the objective of minimizing the water cut by maximizing oil production and minimizing water production. The speed of convergence of the optimization process was also a subject of evaluation. To ensure unbiased sampling of IPR values and to prevent oversampling of boundary extremes, a uniform triangular distribution was designed. The results of the study show a clear improvement of the objective function, compared to the initial sampled cases. As a direct search method, the Evolutionary strategies with covariance matrix adaptation (ES-CMA) yielded the optimum IPR value per region. While examining the effect of applying these IPR values in the reservoir simulation model, a significant reduction of water production from the initial cases without an impact on the oil production was observed. Compared to ESCMA, other optimization methods have dem
Housingless ESPs for Slim Completion Wells
Authors: Xiao Jinjiang , Ejim Chidirim
Published: December 2021

This paper describes a new electrical submersible pump (ESP) design concept to overcome the challenges of applications in slim well completions or thru-tubing deployment. The housing of the conventional pump is removed, allowing the pump impellers to have a larger diameter. The impact of this design change on pump hydraulic performance is assessed in this paper.

Downhole ESPs operate in environments where space is limited radially. This is especially the case for slim completions or for thru-tubing rigless deployment. To provide the required rate and total dynamic head, the current approach is to use permanent magnetic motors and operate the slim systems at rotational speed over the conventional speed of 3500-4000 RPM. High-speed operations require new pump stage designs to minimize erosion and vibration. This paper provides an alternative pump design, which removes the pump housing with the benefit of increasing the impeller tip diameter, and hence potentially reducing pump length and operational speed. To ensure the pump retains the well fluids, the diffusers are designed to be externally threaded with an O-ring feature. The centrifugal pump affinity laws are applied to evaluate the impact of removing the pump housing and increasing the impeller outside diameter.

A typical ESP housing wall thickness is about 0.18-0.25 inch. With the housing removed, the incremental space available for the impeller tip to occupy is increased by 0.36-0.5 inch. Analysis shows that, for the same pump speed as a conventional pump with a housing, a housingless pump will increase the head generated by 23-32%, and the rate capacity about 36-51%, depending on the pump series. In general, the smaller the pump outer diameter, the greater the flow and head capacity increase. This is because the available space due to removing the housing becomes a considerable size of the impeller tip diameter for the smaller series pumps.

The elimination of pump housing enables impellers with a larger diameter to be used to generate more head per stage. In comparison to a conventional pump of the same outside diameter, and providing the same amount of total dynamic head, the housingless pump can have fewer stages and a shorter length or operate at a reduced speed. The reduced length can help mitigating pump-bending stress for installation in deviated or horizontal wells. The reduction in required operating speeds will reduce pump wears, heat generation and vibration. The housingless ESPs have applications for slim well completions or thru-tubing deployments.
Smart SRUs Pre-Investment Utilizing Oxygen Enrichment Technology
Authors: Alhazmi Waleed , Alabdullatif Maher
Published: December 2021

This paper presents an unparalleled engineering assessment conducted to evaluate the feasibility of pre-investing in O2 enrichment technology, with the purpose of increasing the processing capacities of conventional air-based sulfur recovery units (SRUs). Ultimately, the goal is to minimize the overall number of required SRUs for a greenfield gas plant and, consequently, capture a significant cost-avoidance opportunity.

The technology review revealed that a high-level O2 enrichment can double the processing capacity of air-based SRU, depending on the H2S content in acid gas. As H2S mole fraction in feed increases, the debottlenecking capability increases. For the project under assessment, the processing capacity of air-based SRUs showed a maximum increase of 80%. On the contrary, operating with high O2 levels, will elevate SRU reaction furnace temperature, and mandates installing high-intensity burners, along with special control and ESD functions, to manage potential risk and ensure safe operation. Additionally, the liquid handling section of SRUs (condensers, collection vessels, degassing vessels, sulfur storage tanks) should be enlarged to accommodate more sulfur production. Typically, the enriched oxygen can be supplied from air separation units (ASUs), which entails significant capital cost.

Apart from these special design considerations, there are several advantages for adopting this technology. Oxygen enrichment removes significant nitrogen volumes, which reduces loads on Claus, tail gas treatment, and thermal oxidizer units. Hence, lower capital cost for new plants is acquired due to equipment size reduction. In addition, higher HP steam production and less fuel gas consumption are achieved. Conventionally, O2 enrichment technology is employed in the initial design stage or used to retrofit operating SRUs facilities. However, it is unique to consider O2 enrichment-design requirements as part of new air-based SRUs design for phased program development. The objective is to enable smooth transition to fully O2 enrichment operated SRUs at a later phase of the project without the need for any design modification. This exceptional pre-investment strategy has resulted into reducing the required number of SRUs at phase II from eight to five units; and accordingly, a significant cost avoidance was captured.
Internet of Things IoT Edge Computer Vision Systems on Drilling Rigs
Authors: Alsheikh Mohammed , Gooneratne Chinthaka , Magana-Mora Arturo , Ibrahim Mohamad , Affleck Mike , Contreras William , Zhan Guodong David , Jamea Musab Al , Umairin Isa Al , Zaghary Ahmed , Ayachi Mohammed-ilies , Abdel-Kader Ahmed Galal , Ahmed Shehab , Makowski Greg , Kapoor Hitesh
Published: December 2021

This study focuses on the design and infrastructure development of Internet-of-Things (IoT) edge platforms on drilling rigs and the testing of pilot IoT-Edge Computer Vision Systems (ECVS) for the optimization of drilling processes. The pilot technology presented in this study, Well Control Space Out System (WC-SOS), reduces the risks associated with hydrocarbon release during drilling by significantly increasing the success and time response for shut-in a well. Current shut-in methods that require manual steps are prone to errors and may take minutes to perform, which is enough time for an irreversible escalation in the well control incident. Consequently, the WC-SOS enables the drilling rig crew to shut-in a well in seconds. The IoT-ECVS deployed for the WC-SOS can be seamlessly expanded to analyze drillstring dynamics and drilling fluid cuttings/solids/flow analysis at the shale shakers in real-time. When IoT-ECVSs communicate with each other, their value is multiplied, which makes interoperability essential for maximizing benefits in drilling operations.
Integration of Neural Networks and Wellbore Stability, a Modern Approach to Recognize Drilling Problems Through Computer Vision
Authors: Rocha Vargas Luis Alejandro , Izurieta Carlos Andres
Published: December 2021

Cavings are a valuable source of information when drilling operations are being performed, and multiple parameters can contribute to producing cavings which indicate that failure has occurred or is about to occur downhole. This study will describe a project which is an integrated study of Machine Learning, Computer Vision, Geology, and Photography so that the recognition of cavings in the shaker is possible and how to link the cavings morphology with causal mechanisms related to wellbore instability problems. This study aims to develop a model which can extract caving features such as Shape, Edge Definition, Color, and Size.

One of the core aspects of this study was to develop a structured image database of cavings from the Norwegian Continental Shelf which contains important feature information and the application of different algorithms used for automation enabled several opportunities to analyze and identify causal mechanism related to wellbore instability problems in real-time. As a result of that, the drilling operations would experience an improvement in terms of a faster decision-making process to solve operative problems related to wellbore stability which will lead to optimization not only in time and resources but also in safer drilling operations.

Different algorithms and artificial intelligence tools were used to investigate the best approach to correctly detect and derive meaningful information about the shape, color size and edge from cavings like supervised learning, unsupervised learning, neural networks and computer vision. A key part of this study was image augmentation which plays a significant role for the detection of the cavings and their features. Multiple data sets can be created, and by using data augmentation, this will enable recognition of more complex patterns that will have on-rig applicability. Also, this new approach can deliver multiple outcomes besides failure mechanism identification such as volume of rocks being drilled, transport of cutting, type of formation being drilled.
Comprehensive Analysis of Production Loggings in Fuling Shale Gas Play in China
Authors: Liu Yaowen , Pang Wei , Shen Jincai , Mi Ying
Published: December 2021

Fuling shale gas field is one of the most successful shale gas play in China. Production logging is one of the vital technologies to evaluate the shale gas contribution in different stages and different clusters. Production logging has been conducted in over 40 wells and most of the operations are successful and good results have been observed. Some previous studies have unveiled one or several wells production logging results in Fuling shale gas play. But production logging results show huge difference between different wells. In order to get better understanding of the results, a comprehensive overview is carried out. The effect of lithology layers, TOC (total organic content), porosity, brittle mineral content, well trajectory is analyzed.

Results show that the production logging result is consistent with the geology understanding, and fractures in the favorable layers make more gas contribution. Rate contribution shows positive correlation with TOC, the higher the TOC, the greater the rate contribution per stage. For wells with higher TOC, the rate contribution difference per stage is relatively smaller, but for wells with lower TOC, it shows huge rate contribution variation, fracture stages with TOC lower than 2% contribute very little, and there exist one or several dominant fractures which contributes most gas rate. Porosity and brittle minerals also show positive effect on rate contribution. The gas rate contribution per fracture stage increases with the increase of porosity and brittle minerals. The gas contribution of the front half lateral and that of latter half lateral are relatively close for the "upward" or horizontal wells. However, for the "downward" wells, the latter half lateral contribute much more gas than the front half lateral. It is believed that the liquid loading in the toe parts reduced the gas contribution in the front half lateral.

The overview research is important to get a compressive understanding of production logging and different fractures’ contribution in shale gas production. It is also useful to guide the design of horizontal laterals and fractures scenarios design.
Study on the Oil Displacement Effect and Application of Soft Microgel Flooding Technology
Authors: Zhang Jian , Sun Zhe , Wang Xiujun , Kang Xiaodong
Published: December 2021

Due to the reservoir heterogeneity, there is still a lot of remaining oil that cannot be displaced by water flooding. Therefore, taking the whole injection-production flow field as the research object, the dominant channel is divided into macro and micro channel. Then the corresponding oil displacement system is adopted to realize the continuous flow diversion and effective expansion of swept volume. For micro channels, the soft microgel particle dispersion can be used. It is a novel flooding system developed in recent years. Due to its excellent performance and advanced mechanism, the oil recovery rate can be greatly improved.

Soft microgel particle dispersion consists of microgel particles and its carrier fluid. After coming into porous media, its unique phenomenon of particle phase separation appears, which leads to the properties of "plugging large pore and leave the small one open", and the deformation and migration characteristic in the poros media. Therefore, particle phase separation of soft microgel particle dispersion is studied by using the microfluidic technology and numerical simulation. On this basis, by adopting the NMR and 3D Printing technology, the research on its oil displacement mechanism is further carried out. Furthermore, the typical field application cases are analyzed.

Results show that, soft microgel particles have good performance and transport ability in porous media. According to the core displacement experiment, this paper presents the matching coefficient between microgels and pore throat under effective plugging modes. Also, the particle phase separation happens when injecting microgels into the core, which makes the particles enter the large pore in the high permeability layer and fluid enters into small pore. Therefore, working in cooperation, this causes no damage to the low permeability layer. On this basis, theoretically guided by biofluid mechanics, the mathematical model of soft microgel particle is established to simulate its concentration distribution, which obtained the quantitative research results. Furthermore, the micro displacement experiment shows that, microgels has unique deformation and migration characteristic in the poros media, which can greatly expand swept volume. The macro displacement experiment shows that, microgels have good oil displacement performance. Finally, the soft microgel particle dispersion flooding technology has been applied in different oilfields since 2007. Results show that these field trials all obtain great oil increasing effect, with the input-output ratio range of 2.33-14.37. And two field application examples are further introduced.

Through interdisciplinary innovative research methods, the oil displacement effect and field application of soft microgel particle dispersion is researched, which proves its progressiveness and superiority. The research results play an important role in promoting the application of this technology.
Near-Borehole Imaging Using Full-Waveform Sonic Data
Authors: Alqatari Hala , Tonellot Thierry-Laurent , Mubarak Mohammed
Published: December 2021

This work presents a full waveform sonic (FWS) dataset processing to generate high-resolution images of the near-borehole area. The dataset was acquired in a nearly horizontal well over a distance of 5400 feet. Multiple formation boundaries can be identified on the final image and tracked at up to 200 feet deep, along the wellbore's trajectory.

We first present a new preprocessing sequence to prepare the sonic data for imaging. This sequence leverages denoising algorithms used in conventional surface seismic data processing to remove unwanted components of the recorded data that could harm the imaging results. We then apply a reverse time migration algorithm to the data at different processing stages to assess the impact of the main processing steps on the final image.
Application of a Novel Ecofriendly Okra Powder as Fluid Loss Controller in Water Based Drilling Fluids
Authors: Murtaza Mobeen , Tariq Zeeshan , Zhou Xianmin , Al Sheri Dhafer , Mahmoud Muhammad , Kamal Shahzad
Published: December 2021

Saudi Arabian based companies are spending many millions of dollars a year on import of drilling mud additives to meet the drilling industry demand. To cut the imported materials, locally available materials are preferable. Out of many drilling fluid additives, a single locally available additive such as fluid loss can save millions of dollars a year. The cost and locally available raw material justify the development of drilling fluid additives in the Kingdom of Saudi Arabia. In other aspect, local development provides many benefits to the Kingdom including industrial growth, technology ownership and new job opportunities.

Okra (Hibiscus esculents) is widely used as a thickener and viscosifier in medical and food industries due to its low cost, availability, longer shelf life, and high thermal tolerance. In addition to that, it is environment friendly and available in abundance locally in Kingdom of Saudi Arabia. The composition of Okra powder was diagnosed by X-ray fluorescence (XRF) and Fourier-transform infrared spectroscopy (FTIR). The thermal stability of Okra was tested using thermal gravimetric analysis (TGA). The Okra powder was mixed in various concentrations such as (1, 2 and 3) grams in 350ml of water based drilling fluid (WBDF). The performance of Okra contained drilling fluids was compared with starch-based drilling fluid. The addition of Okra reduced fluid loss in different proportions at different concentrations. For instance, drilling fluid with 3g Okra concentration had 42% lower fluid loss as compared to the base fluid. The cake thickness was reduced upon the addition of Okra. The low fluid loss and thin filter cake make Okra a useful solution as a fluid loss controller in WBDFs. The addition of Okra powder also increased the viscosity and gel strength of the WBDFs. TGA analysis of Okra powder showed that it has strong thermal stability as compared to starch. Overall, the experimental results suggest that Okra mixed drilling fluids can be used as an alternate solution to starch mixed drilling fluids.
Numerical Investigation of the Influence of the Drill String Vibration Cyclic Loads on the Time Dependent Wellbore Stability Analysis
Authors: Kamgue Lenwoue Arnaud Regis , Deng Jingen , Feng Yongcun , Songwe Selabi Naomie Beolle
Published: December 2021

Wellbore instability is one of the most important causes of Non-Productive Time causing billions of dollars of losses every year in the petroleum industry. During the drilling operations, the drilling mud is generally utilized to maintain the wellbore stability. However, the drilling mud is subjected to fluctuations caused by several processes such as the drill string vibration cyclic loads which can result into wellbore instability.

In this paper, a nonlinear finite element software ABAQUS is utilized as the numerical simulator to evaluate the time dependent pore pressure and stress distribution around the wellbore after integration of drill string vibration cyclic loads. A MATLAB program is then developed to investigate the wellbore stability by computation of the time dependent wellbore collapse pressure and fracture pressure.

The numerical results showed that the safe mud window which was initially constant became narrower with the time after integration of vibration cyclic load. The collapse pressure without vibration cyclic load increased by 14.33 % at the final simulation time while the fracture pressure decreased by 13.80 %. Interestingly, the safe mud windows widened with the increase of the normalized wellbore radius as the wellbore fracture pressure increased and the collapse pressure decreased.

This study provides an insight into the coupling of the wellbore stability and the continuous cyclic loads generated by drill string vibrations which is an aspect that has been rarely discussed in the literature.
Successful Barrier Enhancement Application of Epoxy Based Resin for Multiple Casing to Casing Annuli Having Tight Injectivity - Case Study from Saudi Arabian Peninsula
Authors: Shamsan Abdulmalek , De la Cruz Alejandro , Jimenez Walmy
Published: December 2021

This study describes the approach used for enhancing the well integrity that was compromised with gas flow through a casing-casing annulus (CCA). Extremely tight injectivity at a CCA demands a solid free solution which not only can be injected but also resist high differential pressures to provide a long-term barrier in CCA. In this paper a successful leak remediation using an epoxy resin system helped the operator save a well and restart its production. Several pressure tests were conducted for identifying an extremely tight casing leak which was causing formation gas travelling to surface through the annulus. This issue required the customer to look for an efficient remedial solution to seal off the gas leakage and regain productivity. Due to the extremely low injectivity, a conventional cement squeeze or any solid laden particle-based squeeze approach was prone to fail. Alternatively, a tailored solid free epoxy resin system was placed in the annulus using an unconventional placement technique resulted in barrier enhancement and helped the operator place the well back into production. For a mature well flowing through 7 × 9 5/8‑in. and 9 5/8 × 13 3/8‑in., a tailored epoxy-based resin system formulation was placed in the well bore with modified surface operations procedures which helped in eliminating current annular pressure to regain well integrity and production. Remedial operations were performed from the surface by squeezing to seal off the gas coming from the annulus. A Tailored design derived from rigorous lab testing and perfect field execution resulted in CCA pressure remediation in a single attempt of the treatment injection, proving that the concept of using a solids-free resin to enhance existing deteriorated barriers is a reliable method. This epoxy resin system helped the operator to regain the well integrity and production in the shortest time without expensive well intervention operations. Epoxy resin based systems have been identified as a novel solution to remediate barrier integrity for well construction and workover operations, hence such case histories with enhanced operations procedures are helpful in increasing awareness of the benefits that can be attained in challenging high-pressure, low-injectivity environments, and can improve well economics.