bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improving the Predictive Power of Equation of State Models for Fluid Systems Undergoing CO2 Injection
Authors: Mogensen K. 
Published: October 2023

Abstract
Phase equilibrium calculations require experimental lab data to constrain component properties in an equation of state (EOS) model. These thermodynamics-based models generally perform well when it comes to predicting conventional PVT experiments but often fall short when it comes to predicting gas injection experiments, particularly for CO2 injection. We therefore seek to develop methods that can help provide a good initial estimate of the swelling curve, in cases where laboratory data are not available.
Our company PVT database compromises more than 2,200 PVT studies, which enables us to pursue three different avenues for predicting the CO2 swelling curve. The first method relies on a machine-learning algorithm, which takes fluid composition and temperature as input. In general, we find that this solution does not preserve monotonicity of the pressure-dependent properties and it extrapolates poorly outside the parameter space used for training. As an example, it fails to predict the first-contact miscible pressure defined as the maximum pressure on the swelling curve.
The second option involved correlating swelling pressure, swelling factor and swelling density as a function of the amount of injected gas. We find that all three curves are well-represented by a parabolic expression and we were able to correlate the coefficients as a function methane content in the reservoir fluid only. The resulting model predicts saturation pressure, swelling factor, and density of the swollen mixtures with an absolute average deviation of 4.8%, 2.3% and 1.7%, respectively, which is an excellent starting point for tuning an EOS model for EOR screening studies until experimental data becomes available.
The third strategy involved tuning a separate EOS model to each of the 34 CO2 swelling studies and then attempt to correlate the EOS component properties. We compare the values of the tuned pseudo-component properties against some standard correlations such as Pedersen, Kesler-Lee, Riazi-Daubert and others. We find that the Pedersen correlations for critical pressure, critical temperature and acentric factor provide a more accurate initial guess than the other correlations tested. However, we observed that the tuned solution depended to some extent on the initial guess. We find that for our fluid systems, the default values for the critical volume of the pseudo-components need to be reduced by 15% to better predict the viscosity using the LBC model. Despite the slightly improved property estimation, we did not manage to find a clear trend for the binary interaction coefficient between CO2 and the plus fraction. Therefore, we would recommend predicting the CO2 swelling curve with the set of parabolic correlations.
Khebra Program
Authors: Al Hosani Mariam Abdul Aziz 
Published: October 2023

The Khebra Program is a well-structured initiative aimed at utilizing the expertise of subject matter experts (Alumni - former Employees who meet the minimum years of continuous service at the organization) to transfer their knowledge from diverse disciplines across the organization. Through this Program, the company gains access to a vast pool of SMEs from the Headquarter of the organization and it Group Companies, enabling the utilization of their knowledge through short-term consultancy contracts with a minimum period of two weeks to 6 months (extendable as per the business requirement and KHEBRA Committee approval).
The program allows utilizing the experience on a consultancy basis for various matters on full time work basis daily or selected days as per the signed contract and the project scope, including but not limited to delivering know-how for mega projects and future business development as well as sharing their knowledge and training the next generation and maintain a sustainable connection with the organization.
To ensure the effective implementation of the Khebra Program, an advisory committee has been established. This committee holds the responsibility of selecting the most suitable SMEs to participate in the Program, providing them with professional guidance, training, and coaching. The selection process follows specific criteria outlined in the Khebra Procedure, ensuring that only qualified SMEs are enrolled in the Program.
CO2 Storage in a Giant Depleted Carbonate Gas Reservoir -Addressing Feasibility and Design Challenges with Field Data
Authors: Xu Siqing , Al Keebali A. , Baslaib M. , BinAmro A. A. , Ali I. , Vantala A. , El Yosef B. , Abdelazim M. Farouk , Perumalla S. , Mascagnini C. , Benaichaoui F. , Harper C. , Singh H. , Pandya S. , Kasekar H. 
Published: October 2023

Abstract
An integrated study on CO2 storage in a giant depleted gas reservoir was completed. The objectives were to assess feasibility, potential capacity and timing for CO2 storage. Significant design challenges were addressed, including thermal-geo-mechanical impact on cap-rock integrity due to injection CO2 cooling, hydrate, injection well life cycle design and clusters location and surface facilities options. Further de-risking is recommended and ongoing.
An integrated approach was adopted combining/optimizing requirements from reservoir, injection wells, cap rock integrity, surface clustering, CO2 transportation and compression/pumping. Key impacts were accounted for: injection J-T effect, hydrate, stress changes, cap rock integrity, well life cycle design, existing well integrity, costs, and surface facilities. Single well models were developed for injection cooling simulation and well design options. 3D reservoir simulations were performed for reservoir pressure changes, storage options, thermal and geo-mechanics for cap rock integrity. Surface facilities options were evaluated, arrival pressure and temperature impact. Several iterations were carried out aiming at optimizing project economics with uncertainty analysis. Results from a CO2 field injection test are presented, part of key design input.
Detailed 3D reservoir simulations show that CO2 injection start-up timing and ramping up strategy are important: starting early helps additional gas recovery, late would exacerbate injection CO2 J-T cooling. Placing CO2injectors further away from producers helps enhanced gas recovery. The results of an extended actual field CO2 injection tests are presented, showing downhole temperature changes with injection rate and transient stabilization. Existing well logs and stress profile measurements were combined. Single well models were developed to simulated cooling around well-bore. Velocity strings, small tubing sizes, are potential injector design options. Hydrates formation was found in certain scenarios. Thermal-Geo-mechanics analysis show appreciable stress changes possibly propagating &gt; 150m into cap-rock. Although CO2 surface arrival temperature can be boosted by installing heaters, but would incur higher costs and additional requirements on wellhead design. It became apparent that individual subject requirements would affect the overall design. An iterative-looping integrated approach was adopted with CO2containment and maximizing project economics as over-riding objectives. Overall CO2 storage capacity was maximized. Adequate field data/measurements are essential and critical modelling input. Further de-risking recommendations include core laboratory geo-mechanical testing, further CO2 field higher rate testing, and comprehensive existing well integrity assessment.
Testing Of Production Profile Monitoring in Multi-Stage Fractured Horizontal Wells of Changqing Oilfield, China: Based On the CT-Conveyed ESP
Authors: Lu Hongjun , Liu Guangsheng , Li Dajian , Yang Haitao , Gan Qingming , Zhu Hongzheng , Cui Wenhao , Su Zubo 
Published: October 2023

Abstract
For horizontal wells of the Changqing ultra-low-permeability oil reservoir stimulated via the multi-stage multi-cluster fracturing, an innovative production profile monitoring technology, adapted to the long horizontal wellbore and low liquid production, was developed to provide references for adjustment and treatment of production performance of wells.
The presented production profile test method at the stage/cluster scale for horizontal wells uses the coiled-tubing, internally penetrated by a load-bearable multi-core composite cable to connect the small-diameter electric submersible pump (ESP) and FSI production logging tool. The ESP and FSI logger are conveyed to the horizontal wellbore by the cable-through coiled- tubing. The cable-powered ESP drains the wellbore, and simultaneously, the coiled tubing drags the ESP and FSI logger along the wellbore to perform production profiling of frac stages/perforation clusters. The monitoring signals are transmitted via the composite cable to the surface, where the production monitoring, interpretation and analysis are completed.
Increasing the well production rate with an ESP and dragging the tool string for continuous measurement effectively solve the technical challenges of the low success rate and inferior operation efficiency of production profiling in oil wells with low liquid production and extended horizontal wellbores. The test results, combined with near-wellbore and far-field acoustic fracturing propagation monitoring, enable quantified characterization of the production contribution pattern of stages/clusters and also the mechanisms and regularity of water breakthrough of horizontal wells in the case of water flooding. Testing in two wells demonstrates that the presented technology is technically competent for production logging in a horizontal wellbore no longer than 1500 m with various production rates. It provides a new methodology and technical approach for horizontal well production monitoring and interpretation in low-permeability oil reservoirs.
This CT-conveyed ESP-assisted production profile testing technology for horizontal wells represents the first of its kind in the world, in terms of the integration of the cable-through CT operation, ESP artificial lifting and FSI production logging. Multiple challenges were overcome for technical crossover and integration, and the operation code was developed, which are practically valuable for the progress of the testing technology of oil and gas wells.
Comparison of Drilling Rate Penetration Prediction Based on Deep Learning Approaches, A Volve Dataset Use Case
Authors: Djamaluddin B. R. , Mohammed S. A. 
Published: October 2023

Abstract
Efficient drilling operations in the oil and gas field is an important area that can lead to major cost and hazard reduction. One of the key parameters for drilling optimization is predicting the rate of penetration. The penetration rate depends on the physical process which contains variables or features that will affect the values. Using these features, it is possible to predict the penetration rate more accurately during the drilling operation. In this study, we propose comparison of deep learning models between models based on deep recurrent neural network and transformer to predict penetration rate. The result shows that the transformer model outperforms the other models.
Innovative In-Situ Foam Generation and Injection Strategy Using Greenhouse Gases for Conformance Control
Authors: Hanamertani Alvinda Sri , Elkhatib Omar , Yu Ying , Ahmed Shehzad 
Published: October 2023

Abstract
Mobility control is one of the most pressing challenges facing greenhouse gas injection for enhancing oil recovery (EOR). A promising solution for this issue was portrayed in employing foam technology due to its favorable mobility ratio and ability to delay the breakthrough of the injected gases. However, the costs pertaining to the utilization of expensive foaming chemicals have prompted economical complications for the wide scale application of the foam EOR techniques. In this study, we compared different foam injection strategies with the economical aspect in mind and introduced a novel injection approach with superior techno-economic performance in generating CO2 and CH4 foam in-situ at harsh pressure and temperature conditions.
Four foam injection strategies were evaluated in terms of their impact on the mobility reduction of the in-situ generated CO2 and CH4 foams. In the methane foam case, the co-injection mode produced high mobility reduction factor (MRF) compared to the single cycle surfactant alternating gas mode (1-SAG). However, the multicycle strategies including the SAG and the proposed gas alternating foam (GAF) outperformed the co-injection mode yielding MRFs of 289 and 336, respectively. The steady state co-injection of CO2 and surfactant solution, however, produced less mobility control compared to the 1-SAG mode. The multicycle SAG and GAF strategies provided more favorable mobility ratio, with MRFs of 99 and 120 respectively, when compared with the other injection strategies of CO2-foam. Consequently, the novel GAF injection and in-situ foam generation strategy displayed the most prominent mobility control potential for both gases. Besides, this injection strategy decreased surfactant consumption by more than 70% compared to the other injection strategies shedding light on its worth as the most promising economical foam generation strategy in EOR field applications.
Unconventional Cementing Technique to Achieve Good Zonal Isolation in Primary Casing Cementation Jobs for Weaker Formations or Loss Zones
Authors: Khaldy A. , Hassan J. , Gupta S. K. , Baloushi Z. A. , Alqattan F. A. , Datta Abhijit , Monterio Ken , Kunchur B. , Hussain M. Khadar , Ellis Chelsea , Singh R. , Kalgutkar N. 
Published: October 2023

Abstract
This article discusses the big volume top job of oil and gas wells, specifically wells A and B which were drilled in Kuwait. The process involves pumping a larger volume of mixture of cement, water, and other additives into the annulus to seal the wellbore, prevent fluid migration and provide structural support.
The article highlights the need for precision and control to ensure proper placement. The conventional methods like two stage method and lightweight systems used for the wells A and B were not sufficient to get the good zonal isolation throughout the well bore due to the lower fracture gradient observed in this well. The successful zonal isolation was achieved due to pumping large volumes from the annulus.
The wells were under losses before and during the primary cementing process, which was difficult to achieve the desired top of cement (up to surface). To overcome these challenges, the well was cemented in unique unconventional method which is pumping the bigger volumes from the annulus to cover up to loss zone and eliminate any other fluid column in between. Cement Bond Log (CBL) and Variable Density Log (VDL) were taken after a 24 Hrs wait on cement and the results were good, indicating that the wellbore is properly sealed, and the well is structurally stable.
Pumping large volumes of cement through the annulus can be challenging, as it requires a high level of precision and control to ensure that the cement is properly placed. This process is different to that of conventional top jobs carried out by installing cement baskets. The intention of conventional top job methods is to just seal the annulus at surface without paying any attention to mud caps left in the open hole. This has resulted in remedial jobs which has increased the cost or reduced the life span of wells.
One of the key considerations when pumping cement through the annulus is the volumes considered and thickening time. The rate of flow must be carefully controlled to ensure that the cement is properly mixed along with the additives and that it does not become too thick or too thin. In addition, the rate of flow must be adjusted to account for the variations in pressure and temperature that occur as the cement moves through the well.
Cementing also plays an important role in preventing fluid migration. If the well is not properly sealed, there might be inter communication of the fluids which affects the life of the well. The extremely lower frac gradient wells undergo losses Inspite of using the conventional methods (light weight systems and two stage method) and is the reason to follow the unconventional method of cementing from the annulus so that entire well bore from shoe to the surface is properly sealed with cement. This will result in reducing the unnecessary remedial jobs during the life of the well.
A Robust Method for Data-Driven Gas-Lift Optimization
Authors: Gambaretto A. , Rashid K. 
Published: October 2023

Abstract
Traditional simulation-based approach for Gas-Lift Optimization depends heavily on the quality of reservoir and fluid data. Excessive OPEX and man-hours are needed to maintain data integrity and to ensure the models are suitably calibrated. Even then, pseudo-steady-state models do not consider losses due to multi-pointing condition and slugging behavior; and for dynamic multiphase flow simulation, the added complexity and man-hours required to assert accurate results cannot be sustained on a full field scale deployment.
Gas-Lift Optimization essentially relies on the relationship between the Well Production Rate with the Gas-Lift Injection Rate. The objective of the proposed solution is to remove the need for well models, correlations and personnel from the optimization process and to implement a data-driven (model-free) approach that, by focusing just on the relationship of these variables over time is able to find the next best optimized Gas-Lift Injection Rate setpoint and to implement it directly at the wells via an automated local control loop.
This data-driven approach has been compartmentalized and developed as an Edge Application, ran directly on site in an IIOT gateway device. This method has the advantage of providing a predictive response that can be used directly in conjunction with a solver for single-well and multi-well optimization (handling well level and group level constraints by need). The application operates under iterative optimization cycles that progress towards system optimality. Even though well conditions are constantly changing over time, and consequently system optimality, these changes are reflected in the high-frequency data gathered by the application running on the gateway on site. Due to the iterative nature of the process, the solver can recognize these changes and react accordingly, adjusting based on the new system conditions in a closed-loop manner.
This paper presents the methodology and the results of a case study of eight wells, including both, single and multi-well optimization. All these wells are unconventional horizontal wells from the Permian basin in Texas, US. Regardless of the complexities associated with unconventional wells, noted by severe slugging and fast changing well conditions, in all the cases the results were outstanding. For the single well optimization, the candidate well was able to outperform the remaining wells in the pad by 5% in production improvement. For the multi-well optimization results vary from 5% to 25% production improvements. The full execution and optimization process was done in a fully autonomous manner, removing completely office and field personnel, as well as the need for well modeling from the optimization process.
This solution demonstrates a fully autonomous and Data-Driven Gas-Lift Optimization workflow, from data gathering and processing, edge computation, multi-well optimization based on field constraints, to the direct well implementation via closed-loop control.
Novel Combination Iron Sulfide-Corrosion Inhibitor Development, Testing and Field Assessment for an Integrated Scale Management System
Authors: Okocha Cyril , Obeyesekere Nihal 
Published: October 2023

Abstract
This paper concerns wet gas production in East Texas area highlighting the use of an innovative approach to solve a unique severe scaling challenge with a cooperative operator. The scope of application spans some 1,200 wells in the Central and East Texas area where the challenge was gas production with associated corrosive fluids in low pressure condition, leading to significant deposition of carbonate and iron sulfide scale within the production tubing. This paper details unique challenges and solutions in developing a single lift chemistry that prevents inorganic scales, particularly iron sulfide scale in the production tubing whilst providing adequate lift to the well. Development work presented includes laboratory and field foamer testing, anoxic iron sulfide scale testing, and autoclave corrosion testing. This was made more challenging due to the high downhole temperatures of 300°F with a pressure of 1,000 psi and a mixed sweet / sour gas with a composition of 2.2mol% CO2 and 0.75mol% H2S. Testing showed that application of these products at 2,000 to 4,000 ppm were able to stabilize gas production, reduce the corrosion to acceptable corrosion rates and prevent the deposition of iron sulfide scale in static and dynamic tests. Extensive detail is provided during the field trials and the monitoring regimen that was put in place to monitor all functionalities provided by this chemistry. As this was across a whole host of different well types significant data was generated and a wealth of information and lessons learned for the industry can be extracted from it. The paper concludes with the overall lessons learned and summary of the validity of this technology and how it could potentially be a game changer for the industry at large in East Texas where gas well deliquification combined with corrosion and scale formation is a shared challenge.
Adopting Cost Effective Cutting-Edge Technology to Mitigate Cemented Annulus Pressure and Reduce Carbon Footprint
Authors: Abdi R. M. , Alhosani A. H. , Sumaida Ali. S. Bin , Ahmad M. H. , Alshehhi H. , Altamimi A. , Issa F. H. , Elrefai F. M. A. , Barker D. , Murty M. J. 
Published: October 2023

Abstract
Sustained casing pressure (SCP) is one of the major well integrity challenges. A variety of annular pressures exist in the wells. Well integrity teams strive to ensure that once the well is flowing at steady state conditions, the pressure from all casing strings should be manageable as low as possible below the Maximum Allowable Annulus Surface Pressure (MAASP). If the annular pressure builds above this level, then the casing exhibits unacceptable SCP. The impact of SCP can develop to critical consequences if not timely managed and brought to an acceptable level.
This paper describes a new approach in controlling SCP using a technique with a high-density, solids-free, non-corrosive, environmentally approved, low-viscosity fluid to control and substantially reduce SCP to acceptable operating levels. The focus of this paper is to demonstrate how to mitigate SCP in the cemented annuli. Production (tubing and packer) and un-cemented annuli are not covered.