bluuebunny/crossref_metadata_2025 huggingface dataset:
Enhanced Gas Condensate Recovery by CO2 Injection in Low Carbon World
Authors: Nasralla Ramez , Wei Lingli , Al-Bulushi Nabil
Published: April 2024

CO2 injection in gas condensate reservoirs has the potential to enhance gas recovery while reducing CO2 emissions, aligning with Petroleum Development Oman’s (PDO) goal of decreasing greenhouse gas intensity and producing low-carbon oil. PDO has a rich portfolio of gas condensate reservoirs, which could be good candidates for the injection of captured CO2. However, finding the best candidate for CO2 injection may be a challenge given the diversity of the portfolio. The focus of this paper is to explore key mechanisms of CO2 injection in gas condensate reservoirs to enable the selection of the most economically attractive candidates and understand the key factors that can impact the economics of an enhanced gas condensate recovery (EGCR) project.

Conceptual and full-field simulation models were developed to estimate the potential incremental recovery and the amount of retained CO2 during the production phase of the project, allowing for the estimation of the net gas utilization factor. One-dimensional conceptual models were employed to reveal the predominant mechanisms and net gas utilization (NGU) for different scenarios, varying the depletion state of the reservoir, condensate-to-gas ratio (CGR), and injection rate. Additionally, two field examples are presented to demonstrate the expected NGU and suggest strategies for improving CO2 utilization.

The results of this study demonstrate the high potential of CO2 injection to maximize the recovery of gas condensate. In addition, this study demonstrates the importance of the miscible displacement of condensate by CO2 for depleted reservoirs over revaporization, which requires higher pressure than miscible displacement and hence higher amount of CO2. The results suggest that CO2 injection in less depleted gas condensate reservoirs at the start of CO2 injection can be more economically attractive than in depleted reservoirs due to the better net gas utilization (NGU) of CO2. For highly depleted reservoirs, higher injection rates are required to increase pressure, resulting in poor NGU compared to less depleted reservoirs. The study also highlights the importance of optimizing injection rates and/or injection durations to maximize oil production per ton of injected CO2.

In conclusion, while CO2 injection presents significant opportunities for enhancing gas condensate recovery and CO2 storage, the economics of such projects are contingent upon improving NGU and ensuring the cost-effectiveness of CO2 capture, transport, and injection compared to oil revenue.
Applications of Intelligent Formation Breakdown Automation Algorithms in Tight Formation for Creating Conductive Propped Fractures, Improving Pumping Efficiency and Maximizing Hydrocarbon Productivity
Authors: El-Sayed M. , Abdelhalim M. , Seada M. , Mahmoud B. , Farouk E. , Bapetco A. Maher
Published: April 2024

Hydraulic Fracturing is one of the most widely used reservoir stimulation techniques for enhancing production of hydrocarbons from various subsurface formations. Although the nature of hydrocarbon-bearing formations can vary being conventional and unconventional formations, high perm and tight formations, hydraulic fracturing will be the primary stimulation technique to be considered with all challenges that can be faced. One of these challenges arose in this method of stimulation is the formation breakdown and fracture initiation processes that can be accompanied with high pumping pressures in the beginning of the treatment. Uncontrolled formation breakdown can affect hydraulic fracturing treatment impeding creating a dominant fracture geometry due to initiation of multiple fractures increasing leakoff during pumping accordingly increasing treatment placement risk and dampening fracture efficiency in tight formations with near-wellbore complexity.

This paper discusses the applications of how smart algorithms can optimize pumping parameters using an intelligent automation to achieve maximum fracture conductivity and stimulated reservoir volume in tight formations. The proposed approach involves the use of automated engineered breakdown technique to reduce pumping pressures thus giving more room for increasing proppant concentration hence improving overall surface efficiency even in tight gas formations where formation breakdown and rate establishment become more formidable to achieve.

This paper will review some treatments where the intelligent engineered breakdown automation technique was applied in formations that are tight and have near-wellbore complexities in different fields of Egypt’s western desert. This study will include reservoir quality, well geographic data, OHL interpretation, diagnostic pumping analyses, formation responses and placement challenges and productivity results. In addition, will highlight and compare the results with some case histories of offset wells where the intelligent engineered breakdown automation technique was not used.

Combining digitalization, artificial intelligence and reservoir stimulation techniques will allow maximizing the value of assets and natural resources which is vital in the current marketing conditions.
A Unique Solution Designed to Deploy 15k Multi-Stage Fracturing Systems Successfully in Horizontal Wells With Complex Profiles, Resulting in 100% Success Rates with 6 Days of Savings Per Well
Authors: Agarwal Rohit , Bansal Sarvodaya , Levario Jesus , Corona Mauricio , Alismail Ahmed , Paz Daniel
Published: April 2024

Deployment of Open Hole Multistage Fracturing (OH MSF) completion system in long horizontal wells has always been a daunting task, and often presents high risk of getting stuck in open hole due to complex completion design with very stiff assemblies that include multiple large OD packers. This paper introduces a novel technology called Cemented MSF, which addresses the deployment risks associated with OH MSF. Notably, this technology eliminates the need for time-consuming coil tubing operations for plug-and-perf, thereby avoiding production delays.

The paper examines the major bottleneck in deployment of OH MSF, a very stiff completion string, which is particularly influenced by the number of stages, elevating the risk of equipment getting stuck in the open hole due to ledges and washout created while drilling the reservoir. Consequently, there is a constant trade-off between maximizing deployment chances and minimizing the risk of getting stuck by reducing the number of stages. However, this trade-off comes at the expense of production efficiency.

Cemented MSF is a hybrid integrated system that provides all the production benefits of OH MSF without the deployment risk. In this novel solution, OH packers are eliminated, and the completion is run like a cemented liner. The cemented MSF lower completions was successfully implemented in a long horizontal well with > 6,000 ft of reservoir contact. While drilling the lateral section, this system enables greater degree of directional flexibility and navigation control as compared to conventional OH MSFs, which have very strict limitations for dogleg and inclination citing risk of deployment complexities with the stiff completions string. Having no OH packers eliminates the need to record open hole logs for packers placement and further eliminates the need for a simulation run (Dummy Run) to simulate actual completion string stiffness, resulting in a direct savings of minimum six-days. Furthermore, to ensure that the frac ports are not activated prematurely, a fit for purpose cementing program was developed using precise volume and hydraulic displacement calculations and optimum shoe track length. Among the unique features of this system is its ability to run maximum possible stages, ensuring that productions will not be compromised. At the end of completion phase, the frac. Ports can be activated by dropping balls just like a conventional OH MSF system and prepare the well for production.

The paper outlines essential design considerations, checkpoints, an execution phase roadmap, and potential contingencies related to the deployment of the Cemented MSF technology.
Functional Neural Networks Model for Prediction of the Formation Tops in Real-Time While Drilling
Authors: Mahmoud Ahmed Abdulhamid , Elkatatny Salaheldin , Abdulraheem Abdulazeez , Gowida Ahmed
Published: April 2024

The determination of formation tops while drilling plays a pivotal role in the efficiency and cost-effectiveness of the drilling operations. Identifying lithology changes in real-time is crucial for adapting drilling programs, optimizing well designs, and ensuring the overall success of the drilling process. Real-time detection of lithology changes provides a valuable tool for mitigating uncertainties associated with geological data limitations, especially during the exploration phase. As formations vary in composition and characteristics, the ability to predict these changes enhances the overall management of drilling operations, minimizing risks and contributing to the economic viability of oil well projects. Current methods for detection of the formation tops rely on geological data, introducing uncertainties, especially in exploration due to data limitations. This study explores the real-time predictive capabilities of the functional neural networks (FNNs) for the prediction of the formation tops. Trained on 3162 datasets of six drilling parameters, the FNNs model aims to predict lithology changes and formation tops across the sandstone, anhydrite, carbonate with shale streaks, and carbonate formations. Testing on 1356 datasets from a different well validated the FNNs model. Results affirm the FNNs accurately predicted the carbonate/shale formation top in training data, while it struggled to accurately predict tops for all formations in testing data compared to the reported high accuracy for the artificial neural networks model.
Unlocking Reservoir Potential with Logging-While-Drilling Technologies in Mature Fields
Authors: Taher A. , Fouda M.
Published: April 2024

Wireline logging has been the preferred primary formation evaluation tool commonly used for decades for assessing reservoir quality. However, where the complexity of the well plan and uncertainty in formation pore pressure may necessitate decision making in real time, logging while drilling (LWD) has become more commonplace.

Assessing the reservoir properties of previously drilled laterals presents a challenge due to hole condition deterioration over time. Even if the borehole is stable and competent while drilling, it might be subject to time-dependent deterioration that could be due to reservoir pressure depletion. LWD tools can be used to re-evaluate previously drilled wells as well as log new wells while drilling. In some wells it is required to measure the formation pressure to be able to log, deepen, and consequently drill several laterals from existing wellbores. The uncertainty in formation pressure depletion can result in operational delays due to difficulties in optimizing the mud weight window based on available data. LWD tools, including formation testers, can be utilized in real time to acquire formation pressure and mobility information, which are key measurements for mud-weight optimization and confirming the feasibility of drilling deeper.

LWD tool strings, including formation testers, have been used to acquire real time formation evaluation and reservoir pressure measurements in formations which had previously limited success due to the relatively low mobility, decreasing the likelihood of obtaining a reliable measurement. Lessons learned have been developed to implement best operational practices in successfully testing in these low mobility environments.

Gamma Ray, Resistivity, density, neutron, and NMR LWD sensors were also used in the bottom hole assembly (BHA) to replace wireline logging due to the risks associated with wireline deployment under these unfavorable hole conditions. Measurement integrity and data quality provided by LWD sensors have been evaluated and used for the design of multilateral wells.

This paper presents the effective utilization of LWD technologies to address operational risks of logging highly deviated well while facilitating robust formation evaluation for this development re-entry drilling program.
Development of Fast Predictive Models for CO2 Enhanced Oil Recovery and Storage in Mature Oil Fields
Authors: Peralta Yessica , Ganesh Ajay , Zambrano Gonzalo , Chalaturnyk Rick , Shokri Alireza Rangriz
Published: April 2024

Reservoir modelling tools have played a significant role in designing the subsurface fluid injection, such as CO2 enhanced oil recovery (EOR). However, these models are computationally expensive; they require extensive geological and engineering data that often are not available in the early phase of carbon utilization and storage projects. This work presents the development of fast predictive models and optimization methodologies to quickly evaluate the CO2 EOR and storage operations in mature oil fields.

Considerable experience with CO2 EOR and storage has been gained by the petroleum industry. In particular, the Weyburn-Midale project (Canada) is a comprehensive case to show how an oil reservoir could securely store CO2. Employing the Weyburn-Midale project, we developed, trained and tested several types of proxy models in multiple scenarios to assess the performance of the miscible CO2 flood in recovering residual oil, increasing the ultimate oil recovery factor while maximizing the permanent CO2 storage.

The history matching of the Weyburn-Midale CO2 EOR model involved 216 well histories (producers and injectors) from 1964 to 2006 using a compositional reservoir simulator. The predominant exploitation scheme was based on an inverted nine-spot pattern waterflooding, water alternating CO2, and consequently CO2 injection. Two simulation data sets were employed at different periods of 1956 through 2006, and 2007 through 2025. Among several proxy models, an artificial neural network (ANN) model proved to accurately estimate features of interest, namely fluid production (oil, water, gas), fluid injection (water, CO2) and the amount of CO2 stored in the reservoir. Additionally, an autoregressive exogenous input (ARX) model was implemented to predict the future outputs in response to a future input. Inspection of the relative estimation error and the model fitness score showed that the proxy model was capable of rapidly reproducing the trend in the validation set satisfactorily. Lastly, we evaluated the transfer of learning from a proxy model, trained to the Weyburn-Midale field (Canada), to assess the performance of CO2 EOR in another mature oil reservoir in Europe (Romania).

The application of proxy models under geological and operation uncertainties offers huge reduction in computational time and engineering data requirements. The results from the Weyburn-Midale case study deliver critical insights into the analysis of many process factors and modeling techniques intended to assess the economic limits and long-term performance of CO2 EOR and storage in mature oil fields.
Mitigation of Vortex-Induced Vibration in Offshore Structures
Authors: Majumdar Ananya , Adhikary Biplab Ranjan
Published: April 2024

Vortex-induced vibration (VIV) study of any offshore structure is of paramount importance to check the structural stability. VIV poses a significant concern for these structures, as the excessive vibration can lead to fatigue damage and structural failure. Mooring lines, risers, pipelines, and other attachments can also get damaged in case of offshore structures. When the shedding frequency approaches the structure's shedding frequency, these vibrations can be major and perhaps dangerous. VIV can occur at low as well as high Reynold's number regime. Because of rising demand for crude oil, offshore gas, and oil, exploration has been shifted to deeper sea levels. Offshore floating wind turbines are used to conserve energy and generate electricity. It can further help to reduce visual pollution and achieve stronger and more constant winds. Floating offshore wind turbines are considered a viable solution in ocean depths more than 50 to 60 meters and with significant wind resources. As an emerging technology, it can utilize less foundation material, shorten the installation and decommissioning times, and create more wind energy. New dangers can be mitigated by employing commercially available bottom fixed turbines and well-known oil and gas technologies for floaters.

VIV can cause large-amplitude vibrations of tethered structures in the ocean. Thus, the effect of VIV on floating structures needs to be studied.

The flow-induced response of a floating structure is generally checked for crossflow. In this study a response reduction technique is proposed based on the in-house modelled two-way coupled interaction of fluid and structure due to vortex-induced motion.
Revolutionizing Offshore Installation and Terminal Manager Emergency Response Training and Assessment: An Innovative, Cost-Effective, and Global Solution for Competency Sustainment
Authors: Wijaya Hendrik A. , Yusof Yushafidi Bin , Bawan Mohd Zainuri Bin , Idrus Hana Maslinda Binti Md
Published: April 2024

In response to the challenges posed by the COVID-19 pandemic, this paper unveils a pioneering emergency response training and assessment framework tailored for Offshore Installation Managers (OIMs) and Terminal Managers (TMs). Focused on the development and deployment of an innovative remote simulation system, the objectives of this program extend beyond the initial constraints of the pandemic, evolving into a best practice model. The paper expounds on the cost-saving benefits of the system, its successful extension to facilities in Malaysia, Iraq, and Turkmenistan, and the establishment of a centralized training hub in Malaysia.

The methodology involves a systematic approach that includes the design, development, and deployment of a cutting-edge online simulation system. This system replicates diverse emergency scenarios, including helicopter crashes, work boat collisions, tank fires, bomb threats, and other incidents outlined in emergency response plans. Centralizing training in Malaysia while engaging participants globally, the program ensures command and control training, fostering competency in managing major emergencies.

The results showcase the effectiveness of the program, with substantial cost savings and sustained high-quality training for OIMs and TMs. Implementation across diverse regions, with assessors and directors operating remotely from Malaysia, underscores the scalability and efficiency of the approach. Real-life situations attest to the preparedness and effectiveness of offshore and terminal leaders in command and control.

In its contribution to the petroleum industry, this paper introduces a cost-efficient and sustainable emergency response training and assessment program. The unique online simulation system, coupled with a centralized training hub, not only reduces costs but also minimizes the carbon footprint, ensuring consistent quality across geographically dispersed facilities. By detailing the successful implementation of this program, the paper enriches the existing literature, providing a blueprint for organizations aiming to enhance the readiness of their leadership in responding to emergencies.
Improving Drilling Performance Through Intelligent and Automated Operating Parameter Planning
Authors: Chen Wei , Hiep Nguyen Tien , Zhang Zhengxin , Shen Yuelin , Scarioni Franklin Linares , Vasquez Daniel Cardozo , Gonzalez Luis Felipe , Skoff Greg , Arevalo Yezid , Converset Julien
Published: April 2024

Drilling operations are subject to drilling dynamics dysfunctions like bottom hole assembly (BHA) shocks and vibration (S&V) that can lead to premature downhole tool failures, poor hole quality and reduced rate of penetration (ROP). This is addressed by domain experts by selecting optimum drilling parameters based on their knowledge and offset performance. A hybrid approach was developed that blended machine-learning algorithms and domain knowledge to automate and improve the design of an optimum operating window for the best drilling parameters (weight-on-bit (WOB), top drive rotary speed (RPM) and flow rate) using historical offset data. The philosophy for optimum operating parameter intelligent planning is based on evolution and continuous learning from historical data. The workflow for the hybrid approach begins with the automated selection of offset well data, then an algorithm is used to align data by formation tops and automatically detected drilling zones which enables parameter statistics evaluation along the depth of the subject well. Based on offset well S&V data and computed mechanical specific energy (MSE), a machine-learning algorithm is applied to divide the intervals into drilling zones, such as benign drilling zone, hard stringer zone, interbedded zone, and severe S&V zone. When the optimum operating window is generated, more aggressive parameters are explored for benign drilling zones to maximize ROP, whereas for the other zone types, the best parameters are automatically identified through the usage of sweet spots in self-generated S&V heatmaps in offset wells. If no stable operating window is found in the heatmaps, domain mitigation logics are used based on the observed S&V modes (axial, lateral, or torsional) in offset data. The parameters’ roadmap is then executed and monitored in real-time, and the post-run data are collected to feed into another evolution cycle for continuous learning and improvement. We implemented this intelligent parameter planning workflow into a mature drilling data analytics platform for deployment to domain users. It was used by drilling engineers in four different drilling environments for field testing to replace the legacy manual drilling roadmap preparation process. Considerable time savings have been reported for offset well data collection and analysis for parameter roadmap generation. More importantly, jobs executed with the new roadmaps have demonstrated reduction in both drilling time and downhole dysfunctions. In this work, we leveraged data analytics, domain knowledge, and physics and machine-learning models to generate a depth-based optimum operating parameter roadmap automatically. This workflow enables ROP improvement and the reduction of drilling risks, becoming a key element for the evolution of autonomous drilling operations and well cost reduction.
Decarbonization Through Reducing Energy Losses in Water Injection Systems: Mechanical Degradation of Drag Reducers in Friction Loops Testing
Authors: Al Moajil A. M. , White R. , AlRustum A.
Published: April 2024

Drag reducing agents (DRAs) are used to reduce friction created by turbulence flow in water transport and injection systems. The objective of this paper to assess mechanical degradation of rigid and flexible polymers used drag reduction applications.

Commercial synthetic polyacrylamide-based DRA and CMHPG polymers were obtained. Synthetic brine was prepared to simulate typical water in surface pipelines. Friction loop test was used to assess friction reduction at various conditions, testing modes, and DRA polymer concentrations.

Mechanical degradation of flexible and rigid polymers for drag reduction application was assessed. TGA analysis indicated the activity of the polyacrylamide polymer was 29 wt%. Viscosity measurements indicated ammonium persulfate reduced the viscosity of 1000 ppm polyacralamide-based DRA by 41 and 36% at 25 and 40°C, respectively. Flow loop testing showed that the flexible polymer was mechanically degraded (i.e. DR’ < 0.1) within 15, 47, and >200 min at 12 gal/min, NRe 70,022, 75°F, at reservoir tank bypass flow mode using 150, 300, and 1000 ppm of the PAM-based DRA, respectively. Rigid polysaccharides-based drag reducing agents showed significant resistance to mechanical degradation compared to polyacralamide-based DRA. Mechanical degradation of the polymer (via chain scission) was mainly caused by shearing/turbulence flow, circulation pump, number of flow cycles, and time. The degradation rate depended on DRA concentration, flow rate, polymer type, and circulation flow mode. DRA injection is a viable alternative to increase production capacity and/or improve energy efficiency.
A Pioneer Step in Restoring Well Integrity of Extreme Sour Well Through End to End Workover Optimization Utilizing Lean Methodologies
Authors: Al Omairi S. M.
Published: April 2024

Yibal Khuff (YK) is a highly sour oil field located in the North of Sultanate of Oman. During Production phase, pressure builds up the annulus behind production tubing resulted in integrity failures, where wells workover required. This paper demonstrates how the operator successfully reduced the planned intervention time by 60 % and restore wells back to healthy production. The paper will also explain how engineering enhancements and innovative Lean methodologies were used for efficiency optimization.

Lean Project (LP), an innovative continuous improvement-based approach; was re-structured to address end to end (E2E) workover challenges. The Project stakeholders management consisted of utilizing Suppliers, Inputs Process, Outputs and Customers (SIPOC) which included identification of main stakeholders, assessment of impact and Voice of Customers (VOC). Value Stream Mapping (VSM) exercise was done for the workover and resulted in list of waste and opportunities to optimize the process. VSM allowed for visualizing the end-to-end process and optimize Process Cycle Efficiency (PCE). Root Cause Analysis (RCA) was conducted using the "5 Whys" method. Moreover, countermeasures were assessed and designed to be deployed.

After piloting the suggested solutions with required controls in place, and because of LP countermeasures, a 60% reduction in planned operation time and 54% cost saving have been observed. This was achieved by eliminating the un-planned change in well sequence which eliminated 62.4 hours of operational downtime through developing fit per purpose sequence procedure. Combining Casing scraper and polish mill in one run saved 98.64 hours compared to planned phase duration. Optimization of operational steps reduced the Gap to Potential (GtP) time by 60% and eliminated Invisible Lost Time (ILT). In addition, the process was reflected in a Standard Operating Procedure (SOP) to be used and replicated across YK field. Finally, the SOPs that were developed on this project supported the local cluster in minimizing oil deferment by reducing the duration of hoist workovers and by raising the cluster's integrity compliance to a near-perfect record.

This paper will give a brief about the application of Lean thinking methodology in a large Omani operator and how the LP tool can help identify and solve day to day problems within well interventions. The LP technique was used for the first time to optimize high sour high risk workover processes. Tools including, stakeholder engagements, root cause analysis and value stream mapping will be explained in this paper in more detail.
Lessons from a Year-Long Operation of an Atmospheric Pressure Flare Gas Recovery System
Authors: Al Kalbani H
Published: April 2024

As the world approaches the 2030 deadline set by the World Bank to eliminate routine flaring, substantial investments are directed towards establishing flare gas recovery, treatment and export infrastructure. This paper delves into the critical components of this imperative task: isolating the flare system and implementing a gas recovery system. The objective is to distill valuable insights and lessons learned from our year-long experience operating such a system, providing a valuable resource for future projects. The lessons learned encompass concept development, design considerations, commissioning procedures, and essential operational aspects. These lessons cover a broad spectrum of critical considerations, including compressor selection, process design fundamentals, control, startup & shutdown sequences, commissioning procedures and underscore the paramount importance of comprehensive training protocols.

The flare gas recovery project aimed to capture gas from atmospheric pressure (AP) sources within the plant. The AP flare gas network intricately collects atmospheric gas from diverse sources, including free water knockout tanks, skim tanks, buffer tanks, drain vessels, skimming vessels, purge gas, and more. The project installed an efficient isolation system which directs this gas to the newly installed gas recovery compressor, where the gas is compressed before being sent for further treatment.

Compressor selection was a crucial decision, and the project ultimately chose the rotary vane compressor due to its exceptional robustness in handling wet gas. Determining the compressor's flowrate entailed a meticulous process, factoring in operational dynamics, site-specific conditions, and gas flashing considerations.

Implementing the control schematic was equally careful, given the challenge of low suction pressure. Careful placement of pressure transducers ensured adequate volume at compressor suction to prevent pressure spikes triggering frequent shutdowns. The isolation system incorporated both an emergency shutdown valve and a pressure control valve, designed to re-route gas back to the flare when necessary

The start-up sequence was thoughtfully designed to meet the dual requirements of isolating the flare while preventing back pressure in the connected tank until the compressor was in operation. Similarly, the shutdown sequence was carefully engineered to prevent the compressor from running while the flare emergency shutdown valve was open. Rigorous commissioning involved using fuel gas to validate the control scheme's functionality, ensuring it operated as intended.

Training considerations were integral from the project's inception, incorporated into design reviews and Hazard and Operability Studies (HAZOPs) and upheld during commissioning. In summary, our experience underscores the indispensable role of meticulous planning, technology selection, and comprehensive training in realizing efficient and environmentally responsible gas recovery project.
Using Casein Peptone as a Sustainable and Natural Solution for Mitigating Gas Hydrate-Induced Flow Assurance Challenges in Natural Gas Pipelines
Authors: Singh A. , Suri A.
Published: April 2024

Casein peptone efficacy as a hydrate inhibitor is investigated, as is its potential for synergy with two eminent kinetic hydration inhibitors (KHIs), polyvinylcaprolactam (PVCap) and polyvinylpyrrolidone (PVP), to improve hydrate inhibition performance. The induction time (IT) / hydrate formation delay time and the average hydrate growth rate (AHGR) post-hydrate formation at concentrations of 0.25 wt%, 0.5 wt%, and 1 wt% of casein peptone were evaluated for methane gas at 7.6 MPa, with a hydrate equilibrium temperature of 10.45°C. 1°C/h constant cooling rate is used in the hydrate formation tests.

The individual effectiveness of casein peptone, PVP, and PVCap is evaluated. The synergy between common KHIs (PVP and PVCap) and casein peptone is assessed by creating 1:1 blends of casein peptone with PVP and PVCap, with the individual performance of PVP and PVCap at an equivalent total inhibitor concentration (KHI + synergist and KHI) for a fair comparison.

Casein peptone is found to have a promising hydrate inhibiting performance in the study. At similar concentrations, it outperformed the conventional KHI PVP40K, demonstrated similar efficacy to the conventional KHI PVP10K, and exhibited only slightly lower performance than the conventional high performing KHI PVCap 40K. This finding highlights the potential of casein peptone as a viable alternative to traditional KHIs, particularly for offshore locations where environmental concerns are a priority. The ability of casein peptone to inhibit hydrate formation at levels comparable to existing conventional inhibitors, coupled with its natural origin and biodegradable properties, make it an attractive candidate for future research in the field of deep-sea hydrate risk management.
AI-Assisted Automation of Well Type Selection and Pad Optimization During Well Placement in Yan'an Tight Gas Reservoir
Authors: Wang Xiangzeng , Zhang Longjun , Song Jiaxuan , Zhang Ping , Lin Jin , Liu Yunlong , Zhang Jianfeng , Zhang Lei , Qiao Xiangyang , Liu Peng , Wang Kai , Xie Xiaofei , Zhang Le , Ye Dongqing
Published: April 2024

The Yan'an tight gas field, situated in the Ordos basin in central China, is emblematic of a typical tight gas reservoir. The field's development planning has been confronted with numerous challenges arising from conditions characterized by high geological heterogeneity, low porosity, multiple production formations, low lateral sand continuity, and a complex topography. Among the pivotal tasks in field development that necessitate addressing these challenges are the screening of well types and the optimization of pad locations. The judicious selection of well types, including horizontal, deviated, or vertical wells, in conjunction with the optimization of pad locations, not only facilitates the control of reserves on a larger scale but also significantly diminishes well construction costs. Conventionally, the manual determination of well types and the optimization of well pad locations rely on the analysis of 2D maps depicting sand distribution and other geological properties. This conventional approach heavily depends on individual experience and meticulousness, requiring weeks or even months to reach a final decision, with results that may lack consistency.

To address the aforementioned challenges, two algorithms have been developed, harnessing both domain expertise and a state-of-the-art machine learning (ML) algorithm. The first algorithm concentrates on well type selection based on considerations such as well targets, geological conditions, and drilling constraints. A heuristic algorithm, in conjunction with the nearest neighbors method, has been devised to identify optimal combinations of various well types with the least number of wells. The second algorithm focuses on optimizing well pad locations, taking into account surface, drilling, and cost constraints, using a modified K-means clustering method tailored to address real problems under diverse conditions. Through the implementation of these developed algorithms, the planning of hundreds of infill wells in the Yan'an tight gas field has been achieved with minimal human involvement in as little as half a day, in contrast to the traditional timeline of months. The developed algorithms serve to significantly enhance well placement efficiency, reduce operational expenditures, and consistently yield reliable results.
Tubing Conveyed Perforation in a Highly Sour High Pressure Horizontal Well in Sultanate of Oman
Authors: Al Balushi S. , Charushin A. , Maskari S. , Guzman R. Castiblanco , Al Busaidi Q. , Al-Lawati H. , Al-Sukaiti A. , Al-Breiki I. , Al-Taiwani M. , Al-Nadhairi N.
Published: April 2024

The Yibal Khuff field is located in the North of Sultanate of Oman and is renowned to be part of the second largest and most technically complex project in Petroleum Development Oman's history. The target oil and gas wells are Highly Sour with High Pressures and Temperatures. This paper describes successful Tubing-Conveyed Perforation (TCP) in horizontal wells using Coiled Tubing, where over 100 m of additional reservoir was perforated boosting the production of wells existing perforations.

The coiled tubing attended the horizontal live well at highly sour and HPHT downhole conditions with a suspended height above 25 m. The approach was to manage the downhole environment prior to proceeding with the Tubing-Conveyed Perforation by controlling the bottomhole pressure. Once the downhole environment was addressed and controlled, the depth correlation took place using Memory CCL-GR to locate the required target zones. The main operation consisted of 10 repeated perforation runs at a gun length of 12m per run to accumulate a total of120m of perforation interval.

The well provided a combined challenge of highly sour environment, existing open perforations, high surface and high bottomhole pressures. Following a thorough analysis and selection criteria where multiple conveyance methods were considered and evaluated such as Eline Tractors, Tubing Conveyance with Rig/Hoist, E-Coil and Conventional Coil Tubing via Sand Jetting and deployment means, the selected method of intervention was Tubing Conveyed Perforation via Coiled Tubing. A combined approach of utilizing controlled intervention techniques enabled the increased production access to the hydrocarbon reserves. In addition to the inherent safety precautions, the project maintained quality assurance as another main driver resulting in flawless delivery of the project.

This solution provides an effective method of tackling perforating challenges in highly sour environments, where coiled tubing conveyed perforation was executed for the first time at a suspended height in a live horizontal well with open perforations. The bottomhole pressure was 4,600 psi and H2S above 3%. TCP via Coiled Tubing has proved to be a high production gain concept, where replication will be beneficial not only to Petroleum Development Oman but to the industry as a whole.
Advanced Robotics for Oil and Gas Applications
Authors: Al Ghafri H. , Saidi M. , Al Sulaimani M. , Al Habsi Z. S. , Al Abri H.
Published: April 2024

Robotics are revolutionizing the transformation of many industries across the globe; one is oil and gas industry. The industry has lately been under a huge pressure to stay efficient, safe, cost competitive and reliable. Therefore, new technologies and solutions have been a focus of companies in the industry to optimize and move on from their conventional practices to more efficient and reliable methods. Autonomous robotic vehicles equipped with advanced sensors, camaras & tools can perform complex and sophisticated maintenance and inspection tasks such as robotic tank cleaning & inspection, robotic UT inspection for elevated assets & robotic coating removal vehicle. These robots have gained the company benefits in both directly & indirectly reducing the cost and time and more efficient and comprehensive outcome. Finally, safety & environmental impact has been an optimum benefit out of using these robots which can easily be navigated into a hazardous confided spaces and high elevated assets.
Automated Engine Management and Monitoring with AI
Authors: Koritala C. , Avilala S. A. R. , Al Amin S. T. , Lakkaraju R.
Published: April 2024

Efficient power management in diesel-powered drilling rigs stands as a pivotal factor in operational efficacy, fuel cost, and emissions reductions. In this study, we concentrate on the criticality of maintaining diesel engines at higher loads to attain optimal performance. To realize the objective of sustaining diesel engines at higher load, in this paper, we present a comprehensive end-to- end solution. This solution encompasses multifaceted elements, a predictive framework for anticipating power demands, an evaluation of engine efficiency prediction, optimized fuel consumption and emissions, condition-based engine maintenance and the implementation of efficient engine start-stop methodologies.

We introduce a methodology to predict expected power demand, furnishing a proactive mechanism to manage fluctuating power requirements during drilling operations. The study also delves into predicting engine conditions, furnishing insights into maintenance scheduling and proactive measures to prevent potential issues. Effective engine start-stop techniques are elucidated as part of the overarching strategy to sustain engines at optimal load parameters.

The garnered insights underscore the successful adoption of Al-based automation across multiple rigs, yielding tangible benefits including automation, operator support, fuel economy, emissions reduction, and deployment across 68 rigs. Operating engines at higher, more fuel-efficient loads not only curtails generator runtime but also prolongs engine lifespan and reduces maintenance intervals. Moreover, in this paper, we emphasize the paramount significance of this approach of mitigating downtime linked to generator complications, providing a holistic view of the advantages and successful outcomes of the proposed comprehensive solution.

In conclusion, we furnish invaluable insights into engine management optimization in diesel-powered drilling rigs, conducting an intricate exploration of pivotal factors, methodologies, and lessons learned with a focal point on achieving efficiency, fuel savings, and emissions reduction.
A Proactive Geosteering Approach Integrating Advanced LWD Nuclear Magnetic Resonance and Deep Azimuthal Resistivity Tools for Landing a Deep Jurassic Horizontal Well in the Best Carbonate Reservoir Facies
Authors: Mohamed Said Beshry , Fahmy Mahmoud Fawzy , Nguyen Kim Long , Al-Mutairi Nami , El Masry Hisham , Sitinjak Eri , Shinde Neha
Published: April 2024

The Jurassic Marrat formation in West Kuwait is a tight and heterogeneous carbonate reservoir in which petrophysical characteristics lead to a limitation in the predictability of reservoir properties. Landing a later well exposes operational risks, therefore LWD triple combo is excluded to avoid environmental issues and cost effects. Instead, LWD-NMR combined with Deep Azimuthal Resistivity tools emerges as the optimum solution to evaluate the formation and optimize well placement in the best reservoir quality.

NMR is utilized for accurate porosity because it is independent of lithology. The T2 distribution is a direct indicator of porosity and permeability. DAR is an azimuthal propagation resistivity tool that can greatly reduce the risk of misplacing the wellbore while drillingextended reach and complex 3D horizontal wells. Marrat reservoir tends to have high resistivity, but theporosity isn't always ideal. It makes geosteering operation more challenging if only gamma & resistivity logs are used to overcome this challenge, LWD-NMR in combination with DAR maximizes the reservoircontact and produces from the best reservoir quality.

Deep Azimuthal Resistivity shows the F-11 surface was found 25 ft. shallower than the A-1 plan. The plan was modified in real-time to ensure a successful landing within the target zone, the starting plan of 3.8 DLS was modified and increased to 4.65 DLS to account for the shallower F-11 with the aim of achieving a TVD depth of 20 ft. inside the reservoir zone. After landing the well at 90 deg inclination following the NMR & DAR signatures, we continue building the inclination angle to 90.5 deg to gently upwards cut stratigraphically across the section and to penetrate the optimum reservoir zone before leveling off gradually to 89.3 deg following NMR & DAR signature to maintain the well in the best reservoir facies. During the geosteering operation in the F-11 zone, a decrease in porosity from 16 pu to 2 pu was detected by the NMR. Consequently, a real-time adjustment was made to avoid the tight area and guide the well toward the sweet spot in the F-11 zone. The combination of NMR and DAR tools successfully landing of the well in the F-11 zone with high-confident hydrocarbon potential.
Assessment of Reservoir-Souring Potential of a Sour Middle Eastern Field Using a Quantitative and Predictive Approach
Authors: Salimi H. , Hadhrami M.
Published: April 2024

Souring potential of fields during depletion and waterflood developments needs to be investigated ahead to enable making sensible decisions on injection-water source, well material selection, and facility design. This paper presents the application of a novel reservoir-souring approach to assess the souring potential of a Middle Eastern field (B) that comprises two reservoirs (the "U" reservoir with a strong aquifer pressure support, and the "M" reservoir with negligible aquifer pressure support.

Both reservoirs produced sour fluids before the start of water injection, although the H2S levels in the U reservoir are much higher than those in the M reservoir. Because there is no sulfur-isotope data to determine the origin of the produced H2S, four possible hypotheses were proposed: (I) the reservoirs were initially sweet and bacterial-sulfate reduction (BSR) was triggered with drilling fluids; (II) the reservoirs were initially sour because of non-microbial geological sources and BSR has occurred since the start of waterflooding; (III) the same as hypothesis II but BSR has happened since drilling, and (V) the reservoirs were originally sour because of bacterially mediated sulfate reduction during early diagenesis. Each of these plausible hypotheses were modeled to history match the historical H2S and to predict future souring levels.

A comparison between the simulated and historical H2S concentrations indicates that these two out of the four proposed hypotheses are more likely to explain the origin of the produced H2S, viz., (I) the reservoirs were initially sweet, but BSR was triggered with drilling and continued with production given that all the reservoir and environmental parameters were in favor of microbial activities, or else (II) the reservoirs were originally sour because of a non-microbial source, and then BSR has been occurring with water injection. However, because the H2S-abstraction capacity only plays a role in hypothesis (I), sensitivity analysis was performed on this hypothesis.

The different H2S levels in the U and M reservoirs as well as in different wells can be attributed to different H2S abstraction capacities of the reservoir rock.

Sensitivity runs reveal that for the U reservoir that waterflooding is not effective, the nutrients content of the formation water and the H2S-abstraction capacity have significant impacts on the max H2S concentration. However, for the M reservoir with waterflooding, the sulfate content of the injection water and the injection rate in addition to the aforementioned parameters have significant effects on the max H2S concentration.