Liu, Wenyuan (China University of Petroleum – Beijing) | Hu, Jinqiu (China University of Petroleum – Beijing) | Sun, Fengrui (China University of Petroleum – Beijing) | Sun, Zheng (China University of Petroleum – Beijing) | Chu, Hongyang (China University of Petroleum – Beijing) | Li, Xiangfang (China University of Petroleum – Beijing)
Hydrates generation-blockage in submarine natural gas pipelines has always been related to the safety of deepwater natural gas production and transportation. However, the current hydrate formation risk prediction in subsea pipelines is still immature. In this paper, a model for evaluating the risk of hydrate formation in submarine natural gas pipelines has been established. The model has been applied and the sensitivity analysis of typical factors has been carried out. The results show that: (a) owing to the low temperature of the seabed, hydrate formation region (HFR) often exists in submarine pipelines. Avoiding HFR by injecting inhibitors is the key to ensure the safe transmission.
The term "safety" has become widespread, but since it is a big idea, it may result hard to grasp. In managing safety, the focus is often on accidents and incidents, however, serious events are infrequent and with them the occasions to learn. Learning focuses on everyday events can take place continuously rather than being a reaction to a single serious event. The aim has been to raise awareness of all our people and to provide them with tangible measurements of safety in absence of incidents. In this work it has been detailed a method to quantify monetary returns associated to the continuous identification, analysis and evaluation of risk and relevant controls, based on the fact that management is traditionally focused on financial goals and therefore more inclined to understand such sort of a language. Thus, it has been considered what a return on investment looks like in safety for transport operations. Based on evidences collected from our Business Units, a business case was developed where a disruption occurred in the operating activities due to some issues (i.e.
Carbonate rocks are complex in their structures and pore geometries and often exhibit a challenge in their classification and behavior. Many rock properties remain unexplained and uncertain because of improper characterization and lack of data QC. The main objective of this paper is to study flow behavior of relative permeability with different rock types in complex carbonate reservoirs.
Representative core samples were selected from two major hydrocarbon reservoirs in Abu Dhabi. Rock types were identified based on textural facies, PoroPerm characteristics and capillary pressure. Porosity ranged from 15% to 25%, while permeability varied from 1 mD to 50 mD. Primary drainage and imbibition water-oil relative permeability (Kr) curves were measured by the steady-state technique using live fluids at full reservoir conditions with in-situ saturation monitoring. High-rate bump floods were designed at the end of the flooding cycles to counter capillary end effects. Aging period of 4 weeks was incorporated at the end of the drainage cycle. Robust data QC was performed on the samples, and final validation of the relative permeability was conducted by numerical simulation of the raw data and measured capillary pressure.
The followed QC procedure was crucial to eliminate artefact in the relative permeability curves for proper data evaluation. The different rock types showed consistent variations in the relative permeability hysteresis and end points. Imbibition relative permeability curves showed large variations within the different rock types, where Corey exponent to oil ‘no’ increased with permeability from 3 to 5, whereas the Corey exponent to water ‘nw’ decreased with permeability and ranged from 3 to 1.5. The variations in the relative permeability curves are argued to be the result of different rock structures and pore geometries. Variations were also seen in the end-point data and showed consistent behavior with the rock types.
The different carbonate rock types were identified based on geological and petrophysical properties. Higher permeability samples were grain-dominated and more heterogeneous in comparison to the lower permeability samples, which were mud-dominated rock types. Imbibition Kr curves showed larger variations than the primary drainage data, which cannot be interpreted based on wettability considerations only. The relative permeability curves have been thoroughly evaluated and QC'd based on raw data of pressure and saturation by use of numerical simulation. Such RRT-based Kr data are not abundant in the literature, and hence should serve as an important piece of information in mixed-wet carbonate reservoirs.
Ahmed, Syed (Saudi Arabian Oil Company, Saudi Aramco) | Al-Zubail, Ahmad (Saudi Arabian Oil Company, Saudi Aramco) | Al-Jeshi, Majed (Saudi Arabian Oil Company, Saudi Aramco) | Yousef, Khaled (Saudi Arabian Oil Company, Saudi Aramco) | Musabbeh, Alya (Saudi Arabian Oil Company, Saudi Aramco) | Mousa, Saad (Saudi Arabian Oil Company, Saudi Aramco) | Bukhari, Adeeb (Saudi Arabian Oil Company, Saudi Aramco) | Seraihi, Emad (Saudi Arabian Oil Company, Saudi Aramco) | Alamri, Sultan H. (Saudi Arabian Oil Company, Saudi Aramco)
This paper describes integrated solution that leverages Industrial Revolution 4.0 to sustain crude quality specifications for Saudi Aramco supply chain covering more than 50 GOSPs (Gas Oil Separation Plants), Pipelines, and Terminals. Sustaining crude quality specifications such water content (BS&W), salt content, etc. for the Arabian Crudes (Arab light, Arab Extra Light etc.) requires big data analysis across the supply chain. To address this challenge, Saudi Aramco developed a customized solution called Crude Quality Monitoring Solution (CQMS) which leverages 800 critical data streams every minute (PI values), classifies the data according to the risk level impacting crude quality specifications. Three developed risk levels are leading proactive, lagging proactive, and lagging reactive, each of which has a defined acceptable risk matrix. Each risk matrix initiates automated notifications for corrective actions proactively. Moreover, patterns and operational events can be easily recognized in the solution visually. The paper also describes several examples where the solution notifications have proactively remediated process disturbances by up to 20% at upstream and downstream facilities while ensuring asset integrity. The solution deployment has also substantially improved the operational efficiency across the network by benchmarking critical data streams. Saudi Aramco is continuing to enhance the solution capabilities to ensure maximization of the crude network.
Yuan, Chengdong (Southwest Petroleum University) | Pu, Wanfen (Kazan Federal University) | Varfolomeev, Mikhail A. (Southwest Petroleum University) | Wei, Junnan (Kazan Federal University) | Zhao, Shuai (Southwest Petroleum University) | Cao, Li-Na (Kazan Federal University)
Conformance control treatment in high-temperature and ultra-high-salinity reservoirs for easing water/gas channeling through high-permeability zones has been a great challenge. In this work, we propose a deformable micro-gel that can be used at more than 100 °C and ultra-high salinity (TDS > 200000 mg/L, Ca2+ + Mg2+ > 10000 mg/L), and present a method for choosing the suitable particle size of micro-gel to achieve an optimal match with the pore throat of core.
First, the particle size distribution of micro-gel was analyzed to decide d50, d10 and d90 (diameter when cumulative frequency is 50%, 10% and 90%, respectively). Core flooding experiments were conducted under different permeability conditions from 20 to 900 mD. The migration and plugging patterns of the micro-gel were studied by analyzing and fitting injection pressure curves together with the change in the morphology of produced micro-gel analyzed by microscope. Finally, a quantitative matching relation was established between the size of micro-gel particles and the pore-throat size of core, its effectiveness was verified by evaluating plugging ability in subsequent water injection process.
The migration and plugging patterns were divided into three patterns: complete plugging, plugging – passing through in a deformation or broken state – deep migration, and inefficient plugging – smoothly passing through – stable flow. The second pattern can be further divided into three sub-patterns as strong plugging, general plugging and weak plugging. Based on the five patterns, a quantitative matching relation between the size of micro-gel particles and the pore-throat size of cores was established by defining three matching coefficients α=d10/d, β=d50/d, γ=d90/d (d is the average pore throat diameter). The effectiveness of this quantitative matching relation was verified by evaluating the plugging ability (residual resistance coefficient) in sequent water flooding process after the injection of 1.5 pore volume of micro-gel. For a strong permeability heterogeneity, the strong plugging is believed to be the expected pattern. The particles size and the pore-throat size should meet the following relationship: 1 < α < 2, 2 < β < 4, 4 < γ <6. In this scenario, the deformable micro-gel particles could achieve both an effective plugging and a deep migration. The quantitative matching relation can provide an indication for the quick determination of the suitable size of deformable micro-gel for conformance control processes in field application, including profile control and water-shut off treatment.
To stimulate a reservoir efficiently, multistage plug-and-perf completion and fracturing technologies are widely utilized to create multiple hydraulic fractures along a horizontal wellbore. However, excessive field cases and lab tests evidenced that, the simultaneous initiation and propagation of multiple fractures within a stage could compete with each other, cause uneven fluid and proppant partition into each placed cluster. Resulting in low cluster efficiency and non-uniform fracture development. Solid particulate diverters can aid to influence the fluid distribution between open clusters to optimize stimulation efficiency. The objective of this study is to use numerical models to thoroughly investigate the functionality of particulate system in fracturing process and optimize the completion and stimulation strategy under specific downhole conditions.
In this study, both CFD-DEM model and a 3D fracture simulator are employed to model fluid diversion and fracturing process for wells completed with plug-and-perf technique. For a field case study, sensitive analyses were performed to quantify the impact of completion design and pumping strategy on the resulted stimulation efficiency. The overall conductive reservoir volume is predicted to compare the cluster efficiency between different design scenarios. Thereafter, the stimulation efficiency of placed perforation clusters is analyzed and optimized with engineered solid particulate diverters.
For the presented particulate diversion technique, both in-stage and inter-stage fluid diversion are operationally feasible. From our analysis, engineered solid particulate diverters can effectively plug the active perforation clusters and build-up enough pressure to divert fracturing fluid into non-active perforation clusters to create additional fractures. Proper number of diverter pills and adequate pumping schedule can boost the cluster efficiency and eventually increase the conductive reservoir volume.
Through a field case study, the presented geomechanical analyses showed that the diverter design and operational parameters can be customized to enhance cluster efficiency. By adjusting completion design, the usage of particulate diverters can be optimized accordingly to maximize the stimulation efficiency. With the proposed efficient design, all the planned perforation clusters can develop and propagate hydraulic fractures and contribute to the overall production.
The characterization of the clastic Zubair reservoir is challenging because of the high lamination and the oil properties change making the conventional saturation technique uncertain. A new workflow has been recently established in the newly appraised wells which has involved advanced petrophysical measurements along with the fluid sampling. The new technique has led to identify new HC layers that were overlooked by the previous techniques, thus adding more reserves to the KOC asset.
Because of the high lamination of clastic Zubair formation and the change of the oil properties, the dielectric dispersion measurement was integrated along with the diffusion-based NMR to identify new oil zones that has been initially masked by the resistivity-based approach. The new approach has also provided details on the oil movability and the characterization of its property. As the newly identified layers were identified for the 1st time across the field, the fluid sampling was conducted to confirm the new findings.
The advent of a new logging technology from a multi-frequency dielectric technique deployed over the formation has independently pinned down the HC pays over the Zubair interval, including a new zone below the water column. The zone was initially identified as heavy Tar zone. The advanced diffusion-based NMR was thus conducted and integrated with Dielectrics which has demonstrated the movability of HC using the diffusion-based NMR approach over the newly identified zone. A fluid sampling was later performed which has confirmed the new finding. The new identified zone was initially overlooked by the previous interpretation and extensive modeling over the entire field. The seal mechanism was also explained by taking advantage of the high-resolution dielectric dispersion measurement (mainly the low frequency), which has been also supported by the Images interpretation. This new approach has added an incremental oil storage over the field.
As the main gas producing blocks of South China Sea, Y field group has four gas fields on operation and two gas fields on going. In production process, there is water influx, sand, carbon dioxide rich, high pressure, high temperature, limitations of the decarbonization ability, and hydrocarbon components content requirement of downstream users. This paper focuses on establishing the integrated model of reservoir, well, gathering network and provides forecasting schemas for meeting contract requirements.
This paper addressed the Y-gas filed group challenges and methodology of flow behavior from reservoir to pipeline, using the Petroleum Experts' Integrated Production Model suite of software (IPM). The integrated model lays special stress on high temperature, multi-layer IPR, liquid loading, CO2 component change. Model calibrations include the characteristics of water vaporization condensation, getting multi-layer IPR though iterating MBAL model and multi-phase flow model, analyzing rules between cumulative gas production rate and component CO2, N2.
Based on the objective gas field group integrated model, the production forecasting and gas supply optimization are studied to solve the problem of multi-system and multi-constraints while conventional research are difficult to achieve the global objective optimization. According to forecasting results, the contract requirements of 4.251 billion cubic meters can be met by 2025. Due to production decline, the gas field group has been unable to meet the contract since 2026. The terminal decarbonization capacity can fully meet the needs. 13-2 gas field is a high proportion hydrocarbon gas reservoir, and hydrocarbon gas volume of the gas field group could meet the contract demand during the whole production forecast period. Some preliminary results from this optimization are also presented.
In the future, the integrated model of simulation and optimization can be carried out in combination with other possible conditions. The objectives and constraints can be adjusted according to the change of production conditions, that optimize the development plans and submit the optimization results.
ADNOC Onshore 24" Main Oil Spurline -1 transferring stabilized crude from Buhasa field (BUH) to MP (Mile Point)-21 hub had a defective 24" Gate Valve on the upstream side of Pig Receiver at MP-21. The Objective was to replace the defective valve with a refurbished 24" Gate Valve with minimum production impact and without the need for depressurizing /draining the entire 35km section of 24" pipeline from BUH to MP-21. A novel isolation technique using Tethered TECNOPLUG was identified and utilized for successful replacement of the defective upstream valve without causing any impact on the oil production.
The corrosion of carbon steel tubing, pipelines and process equipment during Oil and Gas production due to salt water saturated by corrosives gases, such as carbon dioxide and hydrogen sulphide, can lead to substantial environmental and economic consequences. A lot of different technics are used to reduce the corrosion in the pipelines: use of specific alloys, biocides or H2S scavenger. One of the proven and most widely used mitigation techniques is the addition of film-forming corrosion inhibitors into production streams. Those compounds have affinity with metals and will thus form a film at the surface of the metal, creating an electric resistance between the metal and the corrosive species. The products used offshore and released in the North Sea are currently controlled by OSPAR Convention requiring to meet environmental criteria on three different parameters: Biodegradability, Toxicity and Bioaccumulation. Passing 2 out of 3 criteria is enough to comply with the OSPAR Convention. This paper presents the performance results obtained with novel biodegradable compositions used as corrosion inhibitors for continuous injection with a thermal stability up to 135 C. A superior performance against sweet corrosion was obtained at 80 C in brines of different salinity, both in the presence and absence of a hydrocarbon phase. Additionally, new compositions exhibit low critical micelle concentrations and their structure can be further modified to adapt to various salinity conditions.