Study on the Optimization of Hydrate Management Strategies in Deepwater Gas Well Testing Operations

2019 ◽  
Vol 142 (3) ◽  
Author(s):  
Shangfei Song ◽  
Bohui Shi ◽  
Weichao Yu ◽  
Lin Ding ◽  
Yang Liu ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Management Strategies ◽  
Hydrate Formation ◽  
Oil And Gas Industry ◽  
Gas Production ◽  
Optimal Dosage ◽  
Well Testing ◽  
Delayed Effect ◽  
Gas Well ◽  
Risk Margin

Abstract Low temperature and high pressure conditions favor the formation of gas clathrate hydrates which is undesirable during oil and gas industries operation. The management of hydrate formation and plugging risk is essential for the flow assurance in the oil and gas production. This study aims to show how hydrate management in the deepwater gas well testing operations in the South China Sea can be optimized. To prevent the plugging of hydrate, three hydrate management strategies are investigated. The first method, injecting thermodynamic hydrate inhibitor (THI) is the most commonly used method to prevent hydrate formation. THI tracking is utilized to obtain the distribution of mono ethylene glycol (MEG) along the pipeline. The optimal dosage of MEG is calculated through further analysis. The second method, hydrate slurry flow technology is applied to the gas well. Pressure drop ratio (PDR) is defined to denote the hydrate blockage risk margin. The third method is the kinetic hydrate inhibitor (KHI) injection. The delayed effect of KHI on the hydrate formation induction time ensures that hydrates do not form in the pipe. This method is effective in reducing the injection amount of inhibitor. The problems of the three hydrate management strategies which should be paid attention to in industrial application are analyzed. This work promotes the understanding of hydrate management strategies and provides guidance for hydrate management optimization in oil and gas industry.

Quantitatively Assessing Hydrate-Blockage Development During Deepwater-Gas-Well Testing

SPE Journal ◽  
2018 ◽  
Vol 23 (04) ◽  
pp. 1166-1183 ◽  
Author(s):  
Zhiyuan Wang ◽  
Yang Zhao ◽  
Jianbo Zhang ◽  
Xuerui Wang ◽  
Jing Yu ◽  
...  
Keyword(s):  
Water Depth ◽  
Gas Flow ◽  
Oil And Gas ◽  
Management Strategies ◽  
Oil And Gas Industry ◽  
Gas Production ◽  
Flow Assurance ◽  
Well Testing ◽  
Gas Well ◽  
Hydrate Layer

Summary Hydrate-associated problems pose a key concern to the oil and gas industry when moving toward deeper-offshore reservoir development. A better understanding of hydrate-blockage-development behavior can help flow-assurance engineers develop more-economical and environmentally friendly hydrate-management strategies for deepwater operations. In this work, a model is proposed to describe the hydrate-blockage-formation behavior in testing tubing during deepwater-gas-well testing. The reliability of the model is verified with drillstem-testing (DST) data. Case studies are performed with the proposed model. They indicate that hydrates form and deposit on the tubing walls, creating a continuously growing hydrate layer, which narrows the tubing, increases the pressure drop, and finally results in conduit blockage. The hydrate-layer thickness is nonuniform. At some places, the hydrate layer grows more quickly, and this is the high-blockage-risk region (HBRR). The HBRR is not located where the lowest ambient temperature is encountered, but rather at the position where maximum subcooling of the produced gas is presented. As an example case—a deepwater gas well with a water depth of 1565 m and a gas-production rate of 45 × 104 m3/d—the hydrate blockage first forms at the depth of 150 m. In the section with a depth from 50 to 350 m, hydrates deposit more rapidly and this is the HBRR. As the water depth increases and/or the gas-flow rate decreases, the HBRR becomes deeper. Inhibitors can delay the occurrence of hydrate blockage. The hydrate problems can be handled with a smaller amount of inhibitors during deepwater well-testing operations. This work provides new insights for engineers to develop a new-generation flow-assurance technique to handle hydrate-associated problems during deepwater operations.

Optimization of Hydrate Management in Deepwater Gas Well Testing Operations

2018 ◽  
Author(s):  
Shangfei Song ◽  
Bohui Shi ◽  
Weichao Yu ◽  
Wang Li ◽  
Jing Gong
Keyword(s):  
High Pressure ◽  
Low Temperature ◽  
Management Strategy ◽  
Oil And Gas ◽  
Management Strategies ◽  
Hydrate Formation ◽  
Optimal Dosage ◽  
Well Testing ◽  
Slurry Flow ◽  
Gas Well

Low temperature and high pressure conditions in deep water wells and sub-sea pipelines favour the formation of gas clathrate hydrates which is very undesirable during oil and gas industries operation. The management of hydrate formation and plugging risk is essential for the flow assurance in the oil and gas production. This study aims to show how the hydrate management in the deepwater gas well testing operations in the South China Sea can be optimized. As a result of the low temperature and the high pressure in the vertical 3860 meter-tubing, hydrate would form in the tubing during well testing operations. To prevent the formation or plugging of hydrate, three hydrate management strategies are investigated including thermodynamic inhibitor injection, hydrate slurry flow technology and thermodynamic inhibitor integrated with kinetic hydrate inhibitor. The first method, injecting considerable amount of thermodynamic inhibitor (Mono Ethylene Glycol, MEG) is also the most commonly used method to prevent hydrate formation. Thermodynamic hydrate inhibitor tracking is utilized to obtain the distribution of MEG along the pipeline. Optimal dosage of MEG is calculated through further analysis. The second method, hydrate slurry flow technology is applied to the gas well. Low dosage hydrate inhibitor of antiagglomerate is added into the flow system to prevent the aggregation of hydrate particles after hydrate formation. Pressure Drop Ratio (PDR) is defined to denote the hydrate blockage risk margin. The third method is a recently proposed hydrate risk management strategy which prevents the hydrate formation by addition of Poly-N-VinylCaprolactam (PVCap) as a kinetic hydrate inhibitor (KHI). The delayed effect of PVCap on the hydrate formation induction time ensures that hydrates do not form in the pipe. This method is effective in reducing the injection amount of inhibitor. The problems of the three hydrate management strategies which should be paid attention to in industrial application are analyzed. This work promotes the understanding of hydrate management strategy and provides guidance for hydrate management optimization in oil and gas industry.

Real-Time Estimation and Management of Hydrate Plugging Risk During Deepwater Gas Well Testing

SPE Journal ◽  
2020 ◽  
Vol 25 (06) ◽  
pp. 3250-3264 ◽  
Author(s):  
Jianbo Zhang ◽  
Zhiyuan Wang ◽  
Wenguang Duan ◽  
Weiqi Fu ◽  
Baojiang Sun ◽  
...  
Keyword(s):  
Pressure Drop ◽  
Real Time ◽  
Hydrate Formation ◽  
Dynamic Effect ◽  
Time Estimation ◽  
Gas Production ◽  
Well Testing ◽  
Gas Well ◽  
Wellhead Pressure ◽  
Real Time Estimation

Summary Hydrate formation and deposition are usually encountered during deepwater gas well testing, and if hydrates are not detected and managed in time, a plugging accident can easily occur. In this study, we demonstrate a method for estimating and managing the risk of hydrate plugging in real time during the testing process. The method includes the following steps: predicting the hydrate stability region, calculating the hydrate formation and deposition behaviors, analyzing the effect of the hydrate behaviors on variations in wellhead pressure, monitoring the variations in wellhead pressure and estimating the hydrate plugging risk in real time, and managing the risk in real time. An improved pressure-drop calculation model is established to calculate the pressure drop in annular flows with hydrate behaviors, and it considers the dynamic effect of hydrate behavior on fluid flow and surface roughness. The pressure drops calculated at different times agree well with experimental and field data. A case study is conducted to investigate the applicability of the proposed method, and results show that with the continued formation and deposition of hydrates, both the effective inner diameter of the tubing and the wellhead pressure decrease accordingly. When the wellhead pressure decreases to a critical safety value under a given gas production rate, a hydrate inhibitor must be injected into the tubing to reduce the severity of hydrate plugging. It is also necessary to conduct real-time monitoring of variations in wellhead pressure to guarantee that the risk of hydrate plugging is within a safe range. This method enables the real-time estimation and management of hydrate plugging during the testing process, and it can provide a basis for the safe and efficient testing of deepwater gas wells.

A Coupled Hydrate and Compositional Wellbore Simulator: Understanding Hydrate Inhibition from Associated Brines in Oil and Gas Production

2021 ◽  
pp. 1-15
Author(s):  
Fernando M. C. Coelho ◽  
Kamy Sepehrnoori ◽  
Ofodike A. Ezekoye
Keyword(s):  
Oil And Gas ◽  
Production Systems ◽  
Hydrate Formation ◽  
Oil And Gas Industry ◽  
Gas Production ◽  
Gas Industry ◽  
Oil And Gas Production ◽  
Gas Molecules ◽  
Flow Simulator ◽  
Do So

Summary Hydrates are ice-like solids composed of a water-based lattice “encaging” gas molecules. They form under conditions of high pressure and low temperature. In the oil and gas industry, where these conditions are easily met, hydrate formation may cause pipe blockages and severe financial implications, making its prevention (and remediation) one of the main flow-assurance concerns. Desired hydrate inhibition may come from electrolytes naturally dissolved in the water that is produced in conjunction with the hydrocarbon stream, or alcohols can be deliberately injected for such a purpose. When trying to predict hydrate conditions in real-world production systems, computer simulation should ideally integrate hydrate and multiphase-flow calculations. Failing to do so [by performing a decoupled analysis with a flow simulator and a separate pressure/volume/temperature (PVT) package for example] may generate misleading results under certain flow conditions. This paper presents an integrated wellbore simulator to deal with this issue. A hydrate model is added to verify hydrate formation for specific pressure, temperature, and composition of each gridblock. Integration with a geochemical package allows consideration of electrolyte inhibition coming from the associated brine. After successfully comparing results with the available simulators and the experimental data, it is demonstrated that when flowing gas/water ratios (GWRs) exceed 105 scf/STB, water condensation throughout the flow may dilute the beneficial effect arising from the brine composition, thus reducing electrolyte inhibition. Conversely, mineral precipitation along the flow path has shown a nearly negligible impact on this effect.

A Step Change in the Digital Oilfield Arena: Cloud Computing and Workflow Integration for Production Operations Solutions

2021 ◽  
Author(s):  
Aditya Kotiyal ◽  
Guru Prasad Nagaraj ◽  
Lester Tugung Michael
Keyword(s):  
Oil And Gas ◽  
Dimensional Change ◽  
Oil And Gas Industry ◽  
Gas Production ◽  
System Stability ◽  
Production Data ◽  
Oil And Gas Production ◽  
Common Domain ◽  
Digital Oilfield ◽  
Workflow Orchestration

Abstract Digital oilfield applications have been implemented in numerous operating companies to streamline processes and automate workflows to optimize oil and gas production in real-time. These applications are mostly deployed using traditional on-premises systems; where maintenance, accessibility and scalability serves as a major bottleneck for an efficient outcome. In addition to this challenge, the sector still faces limitations in data integration from disparate data sources, liberation of consolidated data for consumption and cross domain workflow orchestration of that data. The dimensional change brought by digital transformation strategies has paved a path for the Cloud- based solutions, which have recently gained momentum in the oil and gas industry pertaining to their wider accessibility, simpler customization, greater system stability and scalability to support larger amount of data in a performant way. To address the challenges mentioned earlier, we have embarked on a journey with Production Data Foundation which brings together production and equipment data from across an organization. In this paper, we will highlight how Production Data Foundation, hosted on the cloud, provides the underlying infrastructure, services, interfaces required to support and unify production data ingestion, workflow orchestration, and through the alignment of the common domain and digital concepts, improve collaboration between people in distinct roles, such as production engineers, reservoir engineers, drilling engineers, deployment engineers, software developers, data scientists, architects, and subject matter experts (SME) working with production operations products and solutions.

Challenges in Hydrate Plug Prevention in Pipelines Seen Over the Lifetime of a Field

2009 ◽  
Author(s):  
Casper Hadsbjerg ◽  
Kristian Krejbjerg
Keyword(s):  
Oil And Gas ◽  
Formation Rate ◽  
Hydrate Formation ◽  
Extended Period ◽  
Oil And Gas Industry ◽  
High Water ◽  
Point Of View ◽  
Field Development ◽  
Hydrate Plug ◽  
Subsea Pipelines

When the oil and gas industry explores subsea resources in remote areas and at high water depths, it is important to have advanced simulation tools available in order to assess the risks associated with these expensive projects. A major issue is whether hydrates will form when the hydrocarbons are transported to shore in subsea pipelines, since the formation of a hydrate plug might shut down a pipeline for an extended period of time, leading to severe losses. The industry practices a conservative approach to hydrate plug prevention, which is the addition of inhibitors to ensure that hydrates cannot form under pipeline pressure and temperature conditions. The addition of inhibitors to subsea pipelines is environmentally unfriendly and also a very costly procedure. Recent efforts has therefore focused on developing models for the hydrate formation rate (hydrate kinetics models), which can help determine how fast hydrates might form a plug in a pipeline, and whether the amount of inhibitor can be reduced without increasing the risk of hydrate plug formation. The main variables determining whether hydrate plugs form in a pipeline are: 1) the ratio of hydrocarbons to water, 2) the composition of the hydrocarbons, 3) the flowrates/flow regimes in the pipeline, 4) the amount of inhibitor in the system. Over the lifetime of a field, all 4 variables will change, and so will the challenge of hydrate plug prevention. This paper will examine the prevention of hydrate plugs in a pipeline, seen from a hydrate kinetics point of view. Different scenarios that can occur over the lifetime of a field will be investigated. Exemplified through a subsea field development, a pipeline simulator that considers hydrate formation in a pipeline is used to carry out a study to shed light on the most important issues to consider as conditions change. The information gained from this study can be used to cut down on inhibitor dosage, or possibly completely remove the need for inhibitor.

Who Is Winning in Energy Transition?

2021 ◽  
Vol 73 (06) ◽  
pp. 34-37
Author(s):  
Judy Feder
Keyword(s):  
Alternative Energy ◽  
Oil And Gas ◽  
Peer Group ◽  
Energy Transition ◽  
Oil And Gas Industry ◽  
Gas Production ◽  
Business Strategies ◽  
Field Energy ◽  
Carbon Intensity ◽  
Oil Companies

We talk about “the energy transition” as if it were some type of unified, global event. Instead, numerous approaches to energy transitions are taking place in parallel, with all of the “players” moving at different paces, in different directions, and with different guiding philosophies. Which companies are best positioned to survive and thrive, and why? This article takes a look at what several top energy research and business intelligence firms are saying. What a Difference a Year Makes Prior to 2020—in fact, as recently as the 2014 bust that followed the shale boom—the oil and gas industry weathered downturns by “tightening their belts” and “doing more with less” in the form of cutting capital expenditures and costs, tapping credit lines, and improving operational efficiency. Adopting advanced digitalization and cognitive technologies as integral parts of the supply chain from 2015 to 2019 led to significant performance improvements as companies dealt with “shale shock.” Then, in 2020, a strange thing happened. Just as disruptive technologies like electric vehicles and solar photovoltaic and new batteries were gaining traction and decarbonization and environmental, social, and governance (ESG) issues were rising to the top of global social and policy agendas, COVID-19 left companies with almost nothing to squeeze from their supply chains, and budget cuts had a direct impact on operational performance and short-term operational plans. To stabilize their returns, many oil and gas companies revised and reshaped their portfolios and business strategies around decarbonization and alternative energy sources. The result: The investment in efforts toward effecting energy transition surpassed $500 billion for the first time in early 2021 ($501.3 billion, a 9% increase over 2019, according to BloombergNEF) despite the economic disruption caused by COVID-19. According to Wood Mackenzie, carbon emissions and carbon intensity are now key metrics in any project’s final investment decision. And, Rystad Energy said that greenhouse-gas emissions are declining faster than what is outlined in many conventional models regarded as aggressive scenarios. In Rystad’s model, electrification levels will reach 80% by 2050. A Look at the Playing Field: Energy Transition Pillars In a February 2021 webinar, Rystad discussed what leading exploration and production (E&P) companies are doing to keep up with the energy transition and stay investable in the rapidly changing market environment. The consulting firm researched the top 25 E&P companies based on their oil and gas production in 2020 and analyzed how they approach various market criteria in “three pillars of energy transition in the E&P sector” that the firm regards as key distinguishers and important indicators of potential success (Fig. 1). The research excludes national oil companies (NOCs) except for those with international activity (INOCs). Rystad says these 25 companies are responsible for almost 40% of global hydrocarbon production and the same share of global E&P investments and believes the trends within this peer group are representative on a global scale.

Challenges and Opportunities for Green Hydrogen Power Supply in Oil and Gas Remote Facilities

2021 ◽  
Author(s):  
Salvador Alejandro Ruvalcaba Velarde
Keyword(s):  
Renewable Energy ◽  
Power Supply ◽  
Oil And Gas ◽  
Hydrogen Generation ◽  
Oil And Gas Industry ◽  
Gas Production ◽  
Energy Carrier ◽  
Low Carbon ◽  
Cost Constraints ◽  
Supply Systems

Abstract The energy transition to renewable energy and hydrogen as an energy carrier, along with low-carbon footprint production targets in the oil and gas industry act as a catalytic for exploring the role of hydrogen in oil and gas production. For upstream and midstream operations, potential opportunities for using hydrogen as an energy carrier are being developed both in hydrogen generation (X-to-hydrogen) as well as in hydrogen consumption (hydrogen-to-X), but not without series of technical and economical challenges. This paper presents potential use cases in upstream and midstream facilities for hydrogen generation and consumption, be it both from hydrocarbon processing resultant in what is called "blue hydrogen" or from integration with renewable energy to form what is called "green hydrogen". It also explains process integration requirements with diagrams for full-cycle green hydrogen use from generation to consumption and its interaction with renewable energy technologies to achieve low to zero-carbon emission power supply systems. Different hydrogen generation and conversion technologies are reviewed as part of the modeling process. Green hydrogen feasibility is assessed in terms of operational efficiency and cost constraints. Hybrid hydrogen and renewable energy power supply systems are simulated and presented according to the intended applications of use in oil and gas facilities. This paper provides a feasibility analysis and hydrogen technology integration potential with renewable energy for applications in oil and gas remote facilities power supply. It also shows emerging hydrogen technologies potential for use in upstream and midstream applications.

STUDY OF CHEMICAL REAGENTS AGAINST CORROSION PROCESSES IN THE CONDITIONS OF THE UZEN FIELD

2021 ◽  
Vol 73 (1) ◽  
pp. 185-195
Author(s):  
U. Zh. Tazhenbayeva ◽  
◽  
Ye.O. Ayapbergenov ◽  
G. Zh. Yeligbayeva ◽  
◽  
...  
Keyword(s):  
Corrosion Inhibitors ◽  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Freezing Temperature ◽  
Gas Production ◽  
Localized Corrosion ◽  
Laboratory Research ◽  
Oil And Gas Production ◽  
Field Equipment ◽  
Long Run

One of the biggest challenges in oil and gas production projects is dealing with the various types of corrosion to which certain parts of field equipment are exposed. Selecting the right corrosion inhibitor for the specific environment is extremely important. Choosing inhibitors for a particular location can be a difficult task because there are many factors to be considered. Understanding the corrosion problems that can arise is important in the oil and gas industry, and knowledge of which inhibitors to use to deal with general and localized corrosion will save time and money in the long run. This article presents the results of studies of various brands of domestic and foreign corrosion inhibitors for use in the Uzen field: physical and chemical characteristics (density, viscosity, freezing temperature, mass fraction of active substance, compatibility with field waters, amine number), efficiency of corrosion inhibitors in laboratory conditions and on a bench simulating field reservoir conditions, taking into account pressure, temperature, fluid flow rate, as well as aggressive components - hydrogen sulfide and carbon dioxide. In addition, studies of corrosion inhibitors' effect on the process of preparation of production are also given. The works were carried out in the center of scientific and laboratory research of KMG Engineering branch " KazNIPImunaygas" LLP.

scholarly journals Performance of Waterborne Polyurethanes in Inhibition of Gas Hydrate Formation and Corrosion: Influence of Hydrophobic Fragments

Molecules ◽  
2020 ◽  
Vol 25 (23) ◽  
pp. 5664
Author(s):  
Roman S. Pavelyev ◽  
Yulia F. Zaripova ◽  
Vladimir V. Yarkovoi ◽  
Svetlana S. Vinogradova ◽  
Sherzod Razhabov ◽  
...  
Keyword(s):  
Corrosion Inhibitor ◽  
Oil And Gas ◽  
Hydrate Formation ◽  
Oxygen Demand ◽  
Oil And Gas Industry ◽  
Dual Function ◽  
Structure Property ◽  
Tert Butyl ◽  
Waterborne Polyurethanes ◽  
Gas Hydrate Formation

The design of new dual-function inhibitors simultaneously preventing hydrate formation and corrosion is a relevant issue for the oil and gas industry. The structure-property relationship for a promising class of hybrid inhibitors based on waterborne polyurethanes (WPU) was studied in this work. Variation of diethanolamines differing in the size and branching of N-substituents (methyl, n-butyl, and tert-butyl), as well as the amount of these groups, allowed the structure of polymer molecules to be preset during their synthesis. To assess the hydrate and corrosion inhibition efficiency of developed reagents pressurized rocking cells, electrochemistry and weight-loss techniques were used. A distinct effect of these variables altering the hydrophobicity of obtained compounds on their target properties was revealed. Polymers with increased content of diethanolamine fragments with n- or tert-butyl as N-substituent (WPU-6 and WPU-7, respectively) worked as dual-function inhibitors, showing nearly the same efficiency as commercial ones at low concentration (0.25 wt%), with the branched one (tert-butyl; WPU-7) turning out to be more effective as a corrosion inhibitor. Commercial kinetic hydrate inhibitor Luvicap 55 W and corrosion inhibitor Armohib CI-28 were taken as reference samples. Preliminary study reveals that WPU-6 and WPU-7 polyurethanes as well as Luvicap 55 W are all poorly biodegradable compounds; BODt/CODcr (ratio of Biochemical oxygen demand and Chemical oxygen demand) value is 0.234 and 0.294 for WPU-6 and WPU-7, respectively, compared to 0.251 for commercial kinetic hydrate inhibitor Luvicap 55 W. Since the obtained polyurethanes have a bifunctional effect and operate at low enough concentrations, their employment is expected to reduce both operating costs and environmental impact.

Sign in / Sign up

Export Citation Format

Share Document