Data Analytics into Hydraulic Modelling for Better Understanding of Well/Surface Network Limits, Proactively Identify Challenges and, Provide Solutions for Improved System Performance in the Greater Burgan Field

A network modeling campaign for 15 surface gathering centers involving more than 1800 completion strings has helped to lay out different risks on the existing surface pipeline network facility and improved the screening of different business and action plans for the South East Kuwait (SEK) asset of Kuwait Oil Company. Well and network hydraulic models were created and calibrated to support engineers from field development, planning, and operations teams in evaluating the hydraulics of the production system for the identification of flow assurance problems and system optimization opportunities. Steady-state hydraulic models allowed the analysis of the integrated wells and surface network under multiple operational scenarios, providing an important input to improve the planning and decision-making process. The focus of this study was not only in obtaining an accurate representation of the physical dimension of well and surface network elements, but also in creating a tool that includes standard analytical workflows able to evaluate wells and surface network behavior, thus useful to provide insightful predictive capability and answering the business needs on maintaining oil production and controlling unwanted fluids such as water and gas. For this reason, the model needs to be flexible enough in covering different network operating conditions. With the hydraulic models, the evaluation and diagnosis of the asset for operational problems at well and network level will be faster and more effective, providing reliable solutions in the short- and long-terms. The hydraulic models enable engineers to investigate multiple scenarios to identify constraints and improve the operations performance and the planning process in SEK, with a focus on optimal operational parameters to establish effective wells drawdown, evaluation of artificial lifting requirements, optimal well segregation on gathering centers headers, identification of flow assurance problems and supporting production forecasts to ensure effective production management.

Interpretation Challenges and Solutions for Real-Time Asphaltene Paramagnetic Sensing at the Wellhead

Asphaltene deposition presents a significant flow assurance to oil production in many parts of the Middle East and beyond. Until recently, there had been no intervention-free approach to monitor deposition in the asphaltene affected wells. This prompted ADNOC to sponsor MicroSilicon to develop of an intervention less real-time sensor device to monitor asphaltene deposition. This new state-of-the-art device is currently installed and automatically collecting data at the wellhead and nearby facilities of an ADNOC operated field. Historic ways of measuring asphaltene in oil relied upon laboratory processes that extracted the asphaltene using a combination of solvents and gravimetric techniques. Paramagnetic techniques offer a potentially simpler alternative because it is known that the spins per gram of an oil is a constant property of that oil, at least when the oil is at constant temperature and pressure. Taking the device to the field means that any interpretation needs to be made independent of these properties. Additionally, the fluid entering the sensor is multiphase and subject to varying temperature and pressure which raises challenges for the conversion of raw spectroscopic data into asphaltene quantity and particle size. These challenges were addressed with a combination of hardware, software and cloud-based machine learning technologies. Oil from over two dozen wells has been sampled in real-time and confirmed that the asphaltene percentage does not just vary from well to well but is also a dynamic aspect of production, with some wells having relatively constant levels and others showing consistent variation. One other well was placed on continuous observation and showed a decrease in asphaltene level following a choke change at the surface. Diagnostic data enhanced by machine learning complements the asphaltene measurement and provides a much more complete picture of the flow assurance challenge than had been previously been available.

Impact of CCUS Impurities on Dense Phase CO2 Pipeline Surface Engineering Design

Numerous CO2 injection pipeline applications have been developed and implemented in the past decades in the UAE and all around the globe. Transporting the CO2 in dense phase, rather than in gas or liquid phases, is well recognized of being techno-economically attractive with respect to its major CAPEX benefits of optimized pipeline material of construction; which is driven by the high water solubility in dense phase CO2 as well as the optimized pipeline size which is greatly influenced by the density and viscosity characteristics of supercritical/dense phase CO2. In light of the active deployment of dense phase CO2 injection EOR pipeline transportation across the various existing and future CO2 capture facilities across the UAE, ADNOC onshore technical expertise team has been conducting intensive research analysis on the unique thermodynamic aspects of dense phase CO2 pipeline systems. The focus was directed towards understanding the transient characteristics, which directly influence crucial design strategies including and not limited to CO2 purity specifications, CO2 pipeline pressure and temperature operating envelopes as well as the developed operating philosophy which involves start-up, shutdown and depressurization. While optimizing the economics of the carbon capture units (CCUS) is a pivotal strategy mandating rationalizing the dictated purity level of the captured CO2 and valorizing the projects. However, such thrifty initiatives to moderate the costs of the selected CO2 removal technologies can lead to underlying cascading effects of the lower purity recovered CO2 on systems design and its operation. As part of the nation's strategic objective to reduce carbon footprint, CO2 has been recovered for EOR re-injection applications. Relaxing the purity specification met by the CO2 capture units can positively improve the cost of the recovery plant while may potentially have adverse impacts on CO2 pipeline integrity. This paper provides a comprehensive analysis of the impact of the CO2 purity specification on the flow assurance safety performance of dense phase CO2 pipeline. It is worth highlighting that the design of CO2 systems is challenged by the paucity of the available reference design guidelines since domain of CO2 itself is still evolving under an active area of research. Although some previous publications have demonstrated the latent underlying effects of imputiries such as (N2, H2, SO2, NO2, CH4, C2H6, and Argon) on the physical and thermodynamic behavior of CO2 systems, however, this was supported by literature experimental modelling without transient analysis. In this paper, the behavior of varying CO2 purity levels on the design and operational aspects of CO2 pipeline is substantiated and both steady state and transient flow assurance modelling are presented. Gauging the system's design integrity cannot be solely assured from the perspective of steady state behavior and hence this paper's findings provide additional information to that previously published with the detailed modelling applied for varying purity scenarios of captured CO2 streams employed in EOR applications across the UAE. The findings of the analysis are benchmarked against plausible worldwide CO2 compositions with a wide range of impurity levels with further in depth demonstration of the transient effects which are usually absent in the available literature.

Subsea Gas Well Late Life Restart Lesson Learned: Failure Analysis and Operating Strategy

This paper elucidates the importance of flow assurance transient multiphase modelling to ensure uninterrupted late life productions. This is discussed in details through the case study of shut-in and restart scenarios of a subsea gas well (namely Well A) located in South China Sea region. There were two wells (Well A and Well B) producing steadily prior to asset shut-in, as a requirement for subsea pipeline maintenance works. However, it was found that Well A failed to restart while Well B successfully resumed production after the pipeline maintenance works. Flow assurance team is called in order to understand the root cause of the failed re-start of Well A to avoid similar failure for Well B and other wells in this region. Through failure analysis of Well A, key root cause is identified and associated operating strategy is proposed for use for Well B, which is producing through the same subsea infrastructure. Transient multiphase flow assurance model including subsea Well A, subsea Well B, associated spools, subsea pipeline and subsea riser is developed and fully benchmarked against field data to ensure realistic thermohydraulics representations of the actual asset. Simulation result shows failed restart of Well A and successful restart of Well B, which fully matched with field observations. Further analysis reveals that liquid column accumulated within the wellbore of Well A associates with extra hydrostatic head which caused failed well restart. Through a series of sensitivity analysis, the possibility of successful Well A restart is investigated by manipulating topsides back pressure settings and production flowrates prior to shut-in. These serve as a methodology to systematically analyze such transient scenario and to provide basis for field operating strategy. The analysis and strategy proposed through detailed modelling and simulation serves as valuable guidance for Well B, should shut-in and restart operation is required. This study shows the importance of modelling prior to late life field operations, in order to avoid similar failed well restart, which causes significant production and financial impacts.

Application of Synthesized Novel Biodegradable Pour-Point Depressant from Natural Source on Flow Assurance of Indian Waxy Crude Oil and Comparative Studies with Commercial Pour-Point Depressant

Summary Pour-point depressants (PPDs) were synthesized from natural sources and used in waxy crude oil transportation to reduce the pour point and improve flow. A biodegradable PPD (BPPD) was synthesized and tested to mitigate crude oil flow assurance problems in the present work. The transesterification process was used to synthesize coconut oil ethyl ester (COEE, termed as BPPD). Fourier transform electron spectroscopy (FTIR), proton nuclear magnetic resonance (H-NMR), and microscopic analysis were performed for better understanding of mechanisms for both BPPD and a commercially available PPD named PPD-A. The pour point of crude oil was reduced by 12 and 9°C after the addition of 800 ppm BPPD and PPD-A, respectively. The microscopic analysis confirms that the crystals of wax converted to very fine and dispersed particles during mixing of additives, which in turn increase flowability. BPPD performs better to reduce interfacial tension than PPD-A. The maximum reduction of 19% in interfacial tension was observed after the addition of 800 ppm BPPD. BPPD alters the wettability of the pipeline surface from intermediate wet to water-wet within 60 seconds, which results in reduced slip velocity and consequently lessens the deposition of wax. As a result, crude oils will not stick to the wall of the pipe surface and will experience less resistance to flow through pipelines. FTIR analysis indicated that long-chain alkane and aromatic groups are responsible for a higher pour point, and their concentration level was reduced after the addition of BPPD. The viscosity of crude oil was reduced by almost 94% after the addition of 800 ppm BPPD with crude oil, which in turn minimizes pumping costs for crude oil. As a result, the total project cost was reduced substantially. Biodegradability tests confirm that the BPPD is biodegradable and nontoxic. Due to its biodegradability and nontoxic nature, BPPD has a promising capacity to be used in the petroleum industry for easier pipeline transportation of waxy crude.

Technology Focus: Flow Assurance (November 2021)

I sincerely hope that all JPT readers and your families, peers, and employers remain safe and healthy and have work as they read this year’s Flow Assurance feature. Flow-assurance effects from slug-flow engineering, design, maintenance, and operations technical concerns still create and sustain challenging technical issues requiring safe, economical solutions for both onshore unconventional and offshore conventional production facilities. The recurring long-term mitigation of slugging and various flow-assurance phenomena—along with the prevention of wax, erosion, asphaltenes, corrosion, and salt deposition—and gas hydrate prediction and handling still demand attention and considerable project technical effort. Slug-flow assessments present opportunities for significant optimization in work flows to target governing operating scenarios. Paper OTC 30172 describes an integrated iterative approach between the flow-assurance and pipeline-engineering disciplines to streamline the work flow based on the value or cost associated with changes in input parameters that affect pipeline fatigue-assessment outcomes. Case studies on two multiphase pipelines are presented to illustrate this design approach. The results show that early identification of the key pipeline profile features and dominating spans for pipeline slugging fatigue assessments facilitated the optimization of slug-flow modeling and reduced computational time. The second paper, SPE 203448, presents decision trees that are considered as nonparametric machine-learning models. The data sets used in training and testing the predictive model are experimental and were collected from literature. Air/kerosene and air/water mixtures were used in obtaining the experimental data points. Results show that the proposed boosted decision tree regression (BDTR) model outperforms the best empirical correlations and the fuzzy-logic model used in estimating liquid holdup in gas/liquid multiphase flows. For the built model, the most important input feature in estimating liquid holdup is the superficial gas velocity. The empirical correlations developed in the past for identifying liquid holdup in multiphase flow can be applied only under the flow conditions by which they were originally developed. However, this machine-learning model does not suffer from this limitation. The third paper, OTC 31298, describes a slugging-control solution that was rejected because of the use of a pseudovariable as the principal control point. A novel control scheme, therefore, was developed and tested on simulations for both hydrodynamic slugging and severe riser-induced slugging in an Angolan field. The project implemented the novel active slugging control using a topsides control valve and topsides instrumentation. While a pseudovariable, a pseudoflow controller, was used, it was part of a cascade scheme such that the principal control variable was a real top-side pressure measurement. Upon com-missioning, slugging at the facility was found to be more severe than anticipated during design, but the novel active slug-control scheme was effective in controlling incoming slugs. The desire to understand better how to describe and improve flow assurance and multiphase flow for both offshore and onshore facilities drives new production technology research, applications, and approaches. The three papers listed for additional reading focus on developing further new analytical tools while providing safe, cost-effective, and reliable operations for flow assurance. I hope you find them as interesting as I did. In addition, I invite you to join the Flow Assurance Technical Section to augment your learning. Recommended additional reading at OnePetro: www.onepetro.org. OTC 30177 - Real-Time Online Hydrate Monitoring and Prevention in Offshore Fields by Syahida Husna Azman, Petronas, et al. SPE 201316 - Modeling Dynamic Loads Induced by Slug Flows Considering Gas Expansion Caused by the Pressure Gradient in a Free Span Horizontal Hanging Pipeline by Gabriel Meneses Santos, Universidade Estadual de Campinas, et al. OTC 31238 - Taylor Bubbles of Viscous Slug Flow in Inclined Pipes by Longtong Abednego Dafyak, University of Nottingham, et al.