bluuebunny/crossref_metadata_2025_split huggingface dataset:
Multicomponent Gas Transport Modeling in Nanopo Rous Media with Adsorption
Authors: Babatunde Kawthar , Emami-Meybodi Hamid 
Published: April 2024

Abstract
Multicomponent gas transport in nanoporous adsorption media, such as organic-rich shales, is influenced by various mechanisms of mass transport and storage, posing challenges to understanding fluid transport in these porous media. We present a predictive diffusion-based model for the transport of multicomponent gas through nanoporous media using modified Maxwell-Stefan formulations for the free and sorbed phases. The developed model considers the transport of free and sorbed phases through nanopores and incorporates the extended Langmuir isotherm for multicomponent adsorption. The diffusive mass fluxes for both phases are coupled to obtain the governing equations with multicomponent effective diffusion coefficients and capacity factors that account for adsorption. The governing equations are functions of the free-phase composition and pressure and are solved numerically. The model is utilized to conduct a sensitivity analysis of the effective diffusion coefficients, capacity factors, and sorbed-phase porosity with respect to the pressure and fluid composition. Furthermore, co- and counter-diffusion processes are simulated to investigate CO2/CH4 flux from and CO2 injection into organic-rich shale and coal samples, representing moderate and high adsorption capacity systems. The pore-volume fraction of each phase is calculated to determine the overall contribution of the phases to total gas transport. The results show that the sorbed phase occupies nearly half of the pore volume in the chosen coal sample. The results also show that the diffusion coefficients for CH4 and CO2 in shale and coal are inversely proportional to the adsorption capacity. Thus, low or moderate adsorption systems have higher effective and apparent diffusion coefficients. During the co-diffusion process on the shale sample, the sorbed phase stops contributing to production after 12 months but continues to produce in the coal sample even after 12 years of production. For the counter-diffusion process in coal and shale samples, CO2 takes up the sorbed phase faster than it does the free phase, leading to a faster decrease in the sorbed phase concentration of CH4. For both co- and counter-diffusion processes, the sorbed phase concentrations are higher in the coal sample than in shale, while the free phase concentrations are higher in shale samples than in coal. The contribution of the sorbed phase to the total mass is dependent on both pore size and adsorption affinity for low-pressure systems while it depends only on adsorption affinity for high-pressure systems.
Optimizing Enhanced Oil Recovery: The Benefits of Preceding ASP and SP Floods with Polymer Flooding
Authors: Southwick J. G. , Driver J. W. , Dean R. M. , Aitkulov A. , Ravikiran R. , Nieuwerf J. , Rivas C. , Dupuis G. , Thomas A. 
Published: April 2024

Abstract
This study aims to illustrate the benefits of polymer injection before other chemical processes, e.g., ASP, SP, ACP, etc. Data in the literature showcases the benefits of polymer pre-injection, but the information is not organized into a coherent, unambiguous study to enable operators to confidently move forward with polymer projects where other chemical processes will be implemented in the future. Furthermore, a train of thought states it is deleterious to inject polymer in advance of a surfactant-based flood because viscous fluid ahead of surfactant could slow down chemical front propagation, and oil recovery.
The benefits of reduced surfactant mass with alkali and polymer pre-flooding have been shown in optimization work (Dean, et al., 2014). The highly successful Mangala ASP project (Pandey, et al., 2016) followed a well-established polymer flood. The Sabriyah Mauddud ASP pilot also used a polymer pre-flood to increase injectivity into low permeability zones. Laboratory studies (Dean, et al., 2014) show polymer pre-injection for the successful ASP pilot in Minas (Masduki, et al., 2020).
Aitkulov (2017) showed improved recovery, reduced surfactant retention, and better conformance when a heterogenous 2-D reservoir model in the laboratory was polymer flooded before ASP flooding rather than waterflooding.
Commercial simulators do not properly model surfactant phase behavior. Polymer is better modeled with the Jouenne model (Jouenne & Levache, 2020) in UTCHEM with salinity changes such as those seen in chemical floods. This study uses the mechanistic simulator UTCHEM to history match both of the heterogenous 2-D experiments in Aitkulov (2017). The first case shows water injection before ASP, whereas the second case shows polymer injection before ASP.
The history-matched parameters were then upscaled to a reservoir model. Due to existing ASP studies in Milne Point, it is also suggested to history match the most favorable ASP coreflood to obtain the proper inputs for the field scale model. The conformance learnings of Milne Point, e.g., the drop in water-cut shortly after polymer injection, indicate that the polymer injection is improving conformance and not allowing water to flow through pre-existing fingers, thus making the field a good example to simulate.
Development and Evaluation of Novel Emulsion and Foam Breakers for Chemical EOR Applications
Authors: Palayangoda Sujeewa S. , Pinnawala Gayani W. , Salman Mohamad , Griffith Christopher , Dwarakanath Varadarajan 
Published: April 2024

Abstract
Emulsion and foam are sometimes quite persistent in the oil field and can create numerous operational challenges in production facilities. Demulsifier and defoamers can play a role in demulsification and defoaming during field chemical treatments. There is demand for efficient and easily available emulsion and foam breakers for emulsion and foam issues especially during chemical stimulation/EOR flowback. The current inventory of commercially available oil field emulsion and foam breakers are typically not tailored to manage the complex chemistry of enhanced oil recovery. Identification of breakers tailored for chemical stimulation/EOR efforts is therefore essential for successful improved oil recovery. In this study, liquid and easily available partitioning agents were tested as emulsion and foam breakers with selective surfactants mixtures. Water soluble partitioning agents with relatively high partition coefficients were shown to be better foam and emulsion breakers compared to agents with low partition coefficients. The effectiveness of a partitioning agent in breaking foam and emulsions can vary depending on both temperature and salinity. Partitioning agents such as aryl-based chemicals tend to produce additional layer heavier than water during the emulsion breaking process due to oil interactions and should be avoided until further research is completed.
Advancement in Subsea Flexible Riser Installation Methodology
Authors: Ramesh S 
Published: April 2024

Abstract
The flexible pipe riser systems are used in various water depths and the advantages are well recognized in the oil and gas industry. The flexible riser systems are markedly advantageous with a floating platform such as FPSO, FPU, etc. The design of the Flexible product and the ancillaries can be custom made and hence, the flexible riser systems result in reduced hang-off load on the floating platform, have better fatigue outcome at the hang-off location and TDP. In general, flexible riser systems when used in suitable water depths will result in better performance over the lifetime, which has an outcome of cost optimization as far as the in-place performance is considered.
The broad optimization of the riser systems and in-place configuration many times leads to a set of challenges during the installation stage. Although the weather limitations during the installation process are relatively lower as compared to in-place configuration, some of the intermittent configurations formed during the installation process lead to the equipment subjected to much higher loads than the in-place configuration.
The installation loads on the product needs to be identified early in the design stage of the equipment. The early engagement and extensive engineering is performed in order to identify critical stages, provide optimizations, as well as mitigate any risks during the installation process.
This paper provides an insight into the engineering and development of practical installation methodology of complex Flexible risers system. The early development of the installation process and the identification of critical steps in order to mitigate the challenges involved which resulted in an optimized design of the equipment as well as avoiding any unexpected behaviors during the installation process. The findings from a recently installed riser system in the East coast of India is used as an example.
Novel Non-Damaging Fluid System Cured Losses in Large Fracture Networks and Established Well Integrity
Authors: El Zanaty O. , Kropochev Y. , Popov A. , Mukhamatyarov S. , Shahzad K. , Sarbast M. 
Published: April 2024

Abstract
The paper describes the use of ECD shielding novel fluid technology system along with engineering design method to effectively cement production strings under losses conditions. The studied wells were drilled in Kurdistan in the northern region of Iraq, an area where losses are a common drilling challenge due to naturally occurring fractures and high permeability in carbonate reservoirs.
The design allowed the operator to establish well integrity and achieve zonal isolation across production zones and minimize formation damage. The close collaboration between the operator and service company helped develop a fluid design and placement strategy that eliminated the need for remedial cementing jobs, thus providing a cost reduction and a reduced carbon footprint and helped obtaining reliable well testing information.
Enhancement of Process Efficiency by Implementation of an Improved Back-Allocation Logic for Gas Volume Computation: A Case Study
Authors: Sanyal S. , Soltybayev Y. , Al-Mutairi F. , Al-Qallaf A. , Al-Ajmi F. , Al-Ajmi A. , Barjas M. , Al Mutairi F. 
Published: April 2024

Abstract
Gas back-allocation evaluates process-efficiency in production domain by computing the contribution of individual wells to total production measured at surface facilities. In the case study, the previously deployed gas back-allocation method resulted in a substantial difference between measured and allocated gas volumes. To improve forecasting reliability, essential for all future expansion projects, the legacy approach needed to be revised and replaced by a more precise and robust methodology.
The legacy method of gas back-allocation relied on well-test gas measurements and oil back-allocation factor. With inherent inaccuracies in well-test gas measurement, and the separate surface-nodes utilized to measure oil and gas, the resulting back-allocated gas volumes were substantially lower than actual. An innovative approach was proposed to reconcile gas production at individual wells using daily estimated oil production, and a combination of GOR from PVT and well-test measurements, to compute the total summation of produced gas and compare that with gas measured at each sub-center. This would imply relocating the gas back-allocation node from Asset level to sub-center level.
The primary objective for method revision was to reduce inaccuracies introduced during gas-rate measurements at well-test level and further compounded by human error during validation of the test results. The revised logic introduced the concept of using guiderails of reservoir-specific GOR values, as obtained from PVT analyses and deploy an automated test validation process to filter-out all incorrect GOR values at the well-test level, which can be considered as the Input end for back allocation. Since gas volume computation at individual wells require both GOR and oil rates, accuracy was further enhanced by utilizing daily estimates of oil production per well, computed with the combination of latest well-test data, historical decline rates and well uptimes. At the output end, it was proposed to assign sub-centers, which are essentially the metering points for surface gas, as nodes for top level of the network to calculate gas back-allocation. With this method, each sub-center, attached to a specific field and reservoirs, would have its own gas back-allocation factor. This would also be a distinct departure from the previous method that assigned a single allocation factor for the entire asset.
The case study suggests a novel approach of increasing computation accuracy for cases with restricted data availability or questionable accuracy of raw data. Implementation of the new logic revised the allocated gas to within 10% of the total measured gas volumes at the Asset level. It has further provided the opportunity to re-visit the gas metering accuracy and meter re-calibration requirements for each sub-center and evaluate gaps in historical PVT data for individual fields and reservoirs.
Through Barrier Flow and Integrity Diagnosis of Complex Completion Enables Targeted Remediation to Reduce Water Cut and Restore Productivity
Authors: Al-Quoud K. , Elias M. , Al-Zoabi A. , Raffi M. , Sergeev E. , Petrova I. , El Dine S. , Vishnu R. 
Published: April 2024

Abstract
Well completions featuring an ICD, swell packers and sliding sleeve doors (SSD) are a popular option in highly heterogeneous reservoirs and homogeneous with barriers. However, this arrangement presents challenges for evaluating the integrity isolation in terms of the swell packer's isolation of layers. The subject well, an oil producer in Raudhatain field, Kuwait, was completed with an ICD with seven packers and five SSDs. The well showed a 100% water cut from the start of production. This paper describes a technique that combines high-precision temperature surveys and a spectral acoustic method to enable accurate flow profiling and integrity evaluation in such wells.
A diagnostic survey was planned for the subject well. This was designed to determine if there was flow from below the survey interval, establish whether the SSDs were active and check the integrity of the swell packers. This comprehensive study combined results from high-precision temperature surveys and spectral acoustic surveys. The analysis identified the contributing intervals of the formation behind the ICD blank zone. Each of the swell packers was assessed for possible leaks and the performance of each SSD was evaluated. The survey indicated that two of the SSDs were not contributing to production and that one of the swell packers was being bypassed. The temperature divergence between shut-in and flowing and temperature gradients suggested a significant inflow of fluid from a source, below the survey interval.
The survey provided an accurate evaluation of swell packer and SSD performance and enabled the operator to formulate an effective and efficient remediation strategy. This operator performed a straightforward workover program that involved setting a coilflate (plug) in the ICD shoe where damage was found. Confirmation from the diagnostic survey that the swell packers were holding above the planned depth for the plug suggested that this kind of workover would be effective. After confirming that the plug was holding (by pressure test), a surface-produced gas oil ratio (PGOR) test showed that the water cut in the well had been reduced to 74% and there was now a significant inflow of oil. The result of the diagnostic survey and subsequent workover operation enabled the operator to kick-start production from what had been a nonproductive well.
The combination of a high-precision temperature survey and a spectral acoustic method enabled accurate flow profiling and integrity evaluation in a well with ICD, swell packers and SSDs. These accurate assessments of reservoir flow and well condition would not have been possible with conventional production logging [PLT] techniques.
Derisking Low-Tension-Gas Flooding in a Carbonate Field in North Oman: Results and Insights from a Successful Foam-Assisted WAG Injection Pilot
Authors: Al-Abri Mohammed , Al Mahruqi Dawood , Al-Aamri Nawal , Das Anindya , Kahrobaei Siavash , van Batenburg Diederik , Jeroen Groenenboom , Abram Peter , Ramez Nasralla , Abuawad Ahmed , Farsi Samya , Jamaei Hana , Al Shabibi Hatem , Al Bulushi Abdullah 
Published: April 2024

Abstract
Lekhwair is a medium-large low-permeability carbonate reservoir in Northern Oman in a mature waterflood stage. To address the challenges of EOR in this reservoir, Low-Tension-Gas (LTG) flooding has been identified as a promising technology. The LTG concept is to use surfactants to reduce the interfacial tension between water and oil to mobilize residual oil in combination with foam for conformance control. In practice, for each goal different surfactant types are required. The objectives of this paper are to present the results and insights gained from the first successful foam pilot of LTG flooding in Oman. This pilot focused on the first objective of improving gas conformance by demonstrating the in-situ foam generation through Surfactant Alternating Gas (SAG) injection.
The injection plan consisted of 5 cycles of immiscible Water-Alternating-Gas (WAG) injection using N2 to establish a baseline, followed by 11 cycles of Surfactant Alternating Gas (SAG) injection for foam generation. A robust surveillance program was implemented for real-time monitoring of pressure responses, saturation profiles, and reservoir fluids dynamics, ensuring a detailed evaluation of the SAG flooding process.
The pilot successfully achieved its objectives. Foam generation through SAG injection was confirmed. Bottom hole pressure data demonstrated increasing trends during SAG stages, providing evidence of foam generation within the reservoir. Logging data validated flow diversion from high-permeability to low-permeability zones. The integration of field data for history matching the reservoir dynamic model allowed for better understanding of the SAG process and to evaluate the feasibility of several development concepts.
The single-well pilot demonstrated the successful generation of in-situ foam through SAG injection. This achievement has profound implications for maturing LTG technology in low-permeability carbonate reservoirs in Oman. The success of this pilot contributes novel insights into the application of Low-Tension-Gas (LTG) flooding in low-permeability carbonate reservoirs and opens exciting opportunities of chemical EOR in Northern Oman.
Novel Workflow to Properly Assess the Potential of a Naturally Fractured Gas Reservoir in a Tight Matrix Sandstone
Authors: Ruffino R. , Avanzini A. , Bianco A. , Marino R. , Bigoni F. , Albertini C. , Tarantini V. 
Published: April 2024

Abstract
The North-African asset under evaluation is characterized by a tight matrix sandstone with poor petrophysical properties, although with natural fractures that sometimes improve the well performance. In this context, the simple description of the matrix system can result inadequate, therefore a dual media modelling (matrix & fractures) was performed, capable of capturing petrophysical heterogeneity and reproducing observed well deliverability.
Given the uncertainties related to fractured systems, a Petrel RE uncertainty workflow was properly designed to evaluate the impact of different parameters on DST matching, future production profiles and well behavior through a Monte Carlo risk analysis. The workflow incorporates different combination of natural fracture scenarios (extracted from seismic curvature), matrix block size and microfractures diffusion (observed at core/well scale) in the matrix system, together with petrophysical parameters. Since some historical well performance was improved by hydraulic fracturing, this action was also considered in the uncertainty workflow.
The outcomes show, on one hand, that the well start-up rates are dependent on the hydraulic fracture interaction with the natural fractures system in the near wellbore area, on the other hand the well performances (gas cumulative and plateau length) are influenced by the connectivity of the DFN and the diffusion of micro fractures in the matrix system. Among all the investigated parameters, the most impacting on well deliverability are: different seismic DFN scenarios, fracture permeability, matrix-fracture interaction and the microfractures diffusion. The automated parametrization of these variables allowed to generate multiple scenarios for infill wells placement and recovery maximization. This workflow works as an effective and powerful tool to properly evaluate the asset.
This novel approach has been successfully tested in a naturally fractured gas reservoir characterized by a generally tight matrix sandstone. All the recognized uncertainties were combined in a sophisticated, yet user-friendly workflow allowing a robust asset evaluation.
Methodology to Estimate the Optimum Reservoir Operating Pressure and Envelope
Authors: Al Balushi F. I. , Al Amri S. S. 
Published: April 2024

Abstract
Petroleum Development Oman (PDO) has recently embarked on a journey towards maximizing reservoir throughput and improving waterflood efficiency across its large portfolio of fields undergoing secondary recovery via waterflooding. It was observed that, in most of the waterflood developments reviewed, there was a lack of understanding of the reservoir operating limits, and the concept of an optimum operating target by subsurface engineers. A methodology is developed to estimate the optimum reservoir operating pressure target to maximize throughput and visualize the reservoir operating envelope of waterflooded reservoirs by identifying the reservoir offtake and intake limits which are calibrated with actual field data. The approach is based on identifying the reservoir Intake and Offtake limits and plotting the Inflow & Outflow Performance Relationships derived from average well performance data within a pattern to visualize the reservoir operating envelope. It utilizes the well productivity index equation to build the relationship between the reservoir limits to derive the Optimum Reservoir Pressure target at which maximum offtake and intake at an instantaneous voidage replacement ratio (iVRR) of ∼1 can be achieved within the defined limits (i.e., Maximum Throughput). The workflow and method are described in detail to allow the readers to replicate approach.
The methodology has been assessed on several waterflood development projects across PDO covering clastic and carbonate reservoirs with varying properties, well types (vertical and horizontal) and pattern types. The workflow was found to provide engineers with a deeper understanding of the reservoir operating limits for a given pattern that allows them to quickly assess pattern performance against benchmarks and make well informed decisions. It allows for setting a target reservoir pressure with a technical basis that is calibrated with actual field performance and can be continuously reviewed as fields mature. It was also observed that the method provides for an assessment of the efficiency of pattern configurations where producer to injector ratio is greater than 1, and a parameter sensitivity analysis to support in well optimization decisions. Understanding the reservoir operating envelope is critical in waterflood developments to optimize a pattern's well offtake and intake, maximize reservoir throughput, and optimize pattern configuration.
The novelty of this method is to standardize an approach across the company to identify the Reservoir operating limits by outlining the workflow to define and visualize the operating envelope for a given pattern that is calibrated with actual field data and derive the optimum reservoir operating conditions (rates and pressures).