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.

Direct electric heating: an environmentally friendly flow-assurance tool

2013 ◽  
Vol 53 (2) ◽  
pp. 448
Author(s):  
Ingebjørg Lien
Keyword(s):  
Oil And Gas ◽  
Environmentally Friendly ◽  
Electric Heating ◽  
Oil And Gas Industry ◽  
Electrical Circuit ◽  
Flow Assurance ◽  
Critical Temperatures ◽  
Gas Industry ◽  
Field Development ◽  
Hydrate Plug

In subsea flowlines, water in the line can form an ice-like structure called a hydrate plug. Wax appearance in flowlines also is a common flow assurance issue. Hydrate and wax appearance can reduce or stop production for weeks. Preventing hydrate and wax in pipelines is a major concern for the oil and gas industry. Direct electric heating (DEH) is a modern and environmentally friendly flow-assurance tool that can reduce capital expenditures (CAPEX) and operating expenditures (OPEX) in field development, reduce the probability of pollution, and reduce handling of toxic disposals as a result of traditional chemical flow assurance methods. DEH is based on using the pipeline as part of the electrical circuit, generating losses in the steel pipe to keep the pipeline and its content above the critical temperatures. Use of DEHs also increases the efficiency at the process plant after planned or unplanned production stops. For marginal fields and fields with heavy or waxy oil, DEH is a flow-assurance method that can enable these fields to be developed profitably. DEH is now a mature technology used for 13–14 years on the Norwegian continental shelf and technology implemented and used in West Africa recently. How successful this technology has been can be summarised by the Tyrihans field where Statoil quoted that they—on this project alone—saved about $USD175 million by implementing DEH. Wärtsilä has been part of the DEH development in Norway since the 90s, and undertakes design and supply of the complete topside power package in addition to electric and optical protection specially developed for DEH systems.

Surfactant Effect of Promoting Research on Hydrate Formation

2015 ◽  
Vol 1092-1093 ◽  
pp. 220-225
Author(s):  
Lei Wang ◽  
Shu Li Wang ◽  
Tian Tian Kang
Keyword(s):  
Gas Hydrates ◽  
Induction Time ◽  
Oil And Gas ◽  
Formation Rate ◽  
Technical Problem ◽  
Hydrate Formation ◽  
Oil And Gas Industry ◽  
Research Direction ◽  
Equal Concentration ◽  
Observation Method

Gas hydrates are a major concern in oil and gas industry, Gas hydrates form in small amounts of water, gas, and the appropriate pressure and temperature conditions. Gas hydrate storage and transportation technology starts a new way for energy storage and transportation industry. The most critically technical problem is how to improve the hydrate formation rate, storage capacity and form continuously. The influences of surfactants on induction time in three types of solution with equal concentration were studied by means of visual hydrate experimental equipment, and generalized induction time was measured by direct observation method. Specific effects of different surfactants on hydrate formation were summarized, as well as the hydrate formation mechanism of surfactants . The lack of research and the research direction of the future were concluded . The further study of surfactant mechanism and build kinetics model containing surfactant have important theoretical value . The result shows that the gas molecules saturated due to the solubilization of surfactant, which promotes the progress of mass transfer in the hydrates. And driving force is provided for the complexation of host molecules and guest molecules during the formation progress of gas hydrates.

Implementation of a Pipeline Integrity Management System at TIGF (France): The Added Value of the Pipeline Threats and Mitigations Module

2008 ◽  
Author(s):  
Karine Kutrowski ◽  
Rob Bos ◽  
Jean-Re´gis Piccardino ◽  
Marie Pajot
Keyword(s):  
Management System ◽  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Management Plan ◽  
Point Of View ◽  
Added Value ◽  
Specific Information ◽  
Transmission Grid ◽  
Integrity Management ◽  
Corrective Actions

On January 4th 2007 TIGF published the following invitation for tenders: “Development and Provision of a Pipeline Integrity Management System”. The project was awarded to Bureau Veritas (BV), who proposed to meet the requirements of TIGF with the Threats and Mitigations module of the PiMSlider® suite extended with some customized components. The key features of the PiMSlider® suite are: • More than only IT: a real integrity philosophy, • A simple intuitive tool to store, display and update pipeline data, • Intelligent search utilities to locate specific information about the pipeline and its surrounding, • A scalable application, with a potentially unlimited number of users, • Supervision (during and after implementation) by experienced people from the oil and gas industry. This paper first introduces TIGF and the consortium BV – ATP. It explains in a few words the PIMS philosophy captured in the PiMSlider® suite and focuses on the added value of the pipeline Threats and Mitigations module. Using this module allows the integrity analyst to: • Prioritize pipeline segments for integrity surveillance purposes, • Determine most effective corrective actions, • Assess the benefits of corrective actions by means of what-if scenarios, • Produce a qualitative threats assessment for further use in the integrity management plan, • Optimize integrity aspects from a design, maintenance and operational point of view, • Investigate the influence of different design criteria for pipeline segments. To conclude, TIGF presents the benefits of the tool for their Integrity Management department and for planning inspection and for better knowledge of their gas transmission grid.

Tanks Assurance and Endorsement Extension Strategy

2021 ◽  
Author(s):  
Sahar Abdul-Karim Khattab ◽  
Marwa Sami Alsheebani
Keyword(s):  
Corrosion Protection ◽  
Oil And Gas ◽  
Extended Period ◽  
Oil And Gas Industry ◽  
Corrosion Monitoring ◽  
Storage Tanks ◽  
Major Overhaul ◽  
Gas Industry ◽  
Future Challenges ◽  
Tank Bottom

Abstract The objective of this paper is to study various methods that can be implemented on existing or new tanks to achieve an extended endorsement period (e.g. 20 years plus) for Crude Oil Floating Roof Storage Tanks. This extended period is necessary in order to overcome anticipated future challenges in tank availability due to (i) increased production and loading, (ii) stretched major overhaul (MOH) duration due to unforeseen delays in MOH works, (iii) corrosion in bottom plates, etc. An extensive research based on international API Standard 653 "Tank Inspection, Repair, Alteration, and Reconstruction" was conducted to achieve this extended period. Initially, some COS tanks aspects were assessed based on API SPEC 653 (2014, Addendum 2, May 2020) to achieve this new Tanks Endorsement Vision, such as: (a) studying the currently applied Corrosion Protection Barriers to the COS tanks and their effectiveness to the endorsement period, (b) the adequacy of commonly applied Corrosion Protection Barriers with respect to the endorsement period, and (c) exploring possible enhancements on COS Tanks Corrosion Protection Barriers, and Monitoring systems to extend tanks endorsement period. Based on API SPEC 653 (2014, Addendum 2, May 2020), currently applied tank safeguards were found inadequate to achieve the 20 years plus tank endorsement period requirement. In order to extend tanks endorsement period, additional safeguards shall be implemented, with special attention to tank bottom plates (soil side), since corrosion problems are mostly exhibited in tank bottom plates from the soil/oil side. Multiple solutions for corrosion safeguards were explored and recommended as part of this study such as the installation of a CP system under COS tanks, as well as installation of a corrosion monitoring system, and performing routine in-service inspections for COS tanks (internal and external) as per API SPEC 653 (2014, Addendum 2, May 2020), etc. Overall, this paper provides an insight on the calculation method of tanks endorsement period, and possible tank corrosion safeguards and controls that can be implemented to extend the COS tanks endorsement period to at least 20 years. Results and recommendations studied in this paper will benefit the Oil and Gas Industry and help in overcoming future challenges.

scholarly journals The Oil and Gas ROFR: Understanding Current ROFR Issues from the Point of View of the Transactional Lawyer, the Litigator, and In-House Counsel

2017 ◽  
Author(s):  
Donald G. MacDiarmid ◽  
Sean J. Korney ◽  
Melanie Teetaert ◽  
Julie J.M. Taylor ◽  
Robert Martz ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Point Of View ◽  
Economic Consequences ◽  
Complex Nature ◽  
Gas Industry ◽  
Industry Standard ◽  
The Law ◽  
To Come ◽  
Corporate Lawyers

Rights of first refusal and other preferential or pre-emptive rights (together, ROFRs, and individually a ROFR) routinely find their way into oil and gas industry agreements. Disputes often arise because of the complex nature and significant economic consequences of ROFRs. In recent years, a number of reported cases, either relating directly to ROFRs or more generally relating to contractual interpretation, have clarified (or at times muddied) the waters surrounding the use, application, and interpretation of ROFRs. However, most ROFR disputes never result in a reported decision because the parties typically negotiate solutions long before trial.The authors consider current trends involving ROFRs in oil and gas agreements, and how they believe the law and legal practice surrounding ROFRs might continue to evolve in the years to come. The authors do not attempt to rehash the fundamentals of the law surrounding ROFRs; instead, they focus on how the courts have dealt with ROFRs in recent cases as well as how corporate lawyers and in-house counsel grapple with ROFRs day-today. The authors utilize the ROFR provisions found in industry standard contracts to analyze outstanding areas of uncertainty as well as what lawyers should contemplate prior to including a ROFR in an agreement. Additionally, the article examines the implications of recent rulings on the duty of good faith that may affect ROFRs. Finally, the article considers selected subjects of topical interest, including ROFRs in the context of busted butterfly transactions, insolvency proceedings, and package deals.

scholarly journals Application of the CL-systems technology for water injection wells at an oil and gas field

2021 ◽  
Vol 19 (3) ◽  
pp. 848-853
Author(s):  
Liliya Saychenko ◽  
Radharkrishnan Karantharath
Keyword(s):  
Oil And Gas ◽  
Water Injection ◽  
Oil And Gas Industry ◽  
Field Studies ◽  
High Water ◽  
Injection Wells ◽  
Gas Field ◽  
Water Breakthrough ◽  
Oil And Gas Field ◽  
High Water Cut

To date, the development of the oil and gas industry can be characterized by a decline in the efficiency of the development of hydrocarbon deposits. High water cut-off is often caused by water breaking through a highly permeable reservoir interval, which often leads to the shutdown of wells due to the unprofitability of their further operation. In this paper, the application of straightening the profile log technology for injection wells of the Muravlenkovsky oil and gas field is justified. In the course of this work, the results of field studies are systematized. The reasons for water breakthrough were determined, and the main ways of filtration of the injected water were identified using tracer surveys. The use of CL-systems technology based on polyacrylamide and chromium acetate is recommended. The forecast of the estimated additional oil produced was made.

Utilizing Pseudo Well Connections to Simulate Multi-Stage Hydraulic Fracturing - Example Based On the Study of a Tight Gas Asset

2021 ◽  
Author(s):  
Aamir Lokhandwala ◽  
Vaibhav Joshi ◽  
Ankit Dutt
Keyword(s):  
Hydraulic Fracturing ◽  
Oil And Gas ◽  
Flow Simulation ◽  
Oil And Gas Industry ◽  
Development Plan ◽  
Hydraulic Fractures ◽  
Tight Gas ◽  
Gas Field ◽  
Field Development ◽  
Fracture Modeling

Abstract Hydraulic fracturing is a widespread well stimulation treatment in the oil and gas industry. It is particularly prevalent in shale gas fields, where virtually all production can be attributed to the practice of fracturing. It is also used in the context of tight oil and gas reservoirs, for example in deep-water scenarios where the cost of drilling and completion is very high; well productivity, which is dictated by hydraulic fractures, is vital. The correct modeling in reservoir simulation can be critical in such settings because hydraulic fracturing can dramatically change the flow dynamics of a reservoir. What presents a challenge in flow simulation due to hydraulic fractures is that they introduce effects that operate on a different length and time scale than the usual dynamics of a reservoir. Capturing these effects and utilizing them to advantage can be critical for any operator in context of a field development plan for any unconventional or tight field. This paper focuses on a study that was undertaken to compare different methods of simulating hydraulic fractures to formulate a field development plan for a tight gas field. To maintaing the confidentiality of data and to showcase only the technical aspect of the workflow, we will refer to the asset as Field A in subsequent sections of this paper. Field A is a low permeability (0.01md-0.1md), tight (8% to 12% porosity) gas-condensate (API ~51deg and CGR~65 stb/mmscf) reservoir at ~3000m depth. Being structurally complex, it has a large number of erosional features and pinch-outs. The study involved comparing analytical fracture modeling, explicit modeling using local grid refinements, tartan gridding, pseudo-well connection approach and full-field unconventional fracture modeling. The result of the study was to use, for the first time for Field A, a system of generating pseudo well connections to simulate hydraulic fractures. The approach was found to be efficient both terms of replicating field data for a 10 year period while drastically reducing simulation runtime for the subsequent 10 year-period too. It helped the subsurface team to test multiple scenarios in a limited time-frame leading to improved project management.

Challenges of Developing Marginal Fields in the Current Climate of Oil and Gas Industry

2021 ◽  
Author(s):  
Amina Danmadami ◽  
Ibiye Iyalla ◽  
Gbenga Oluyemi ◽  
Jesse Andrawus
Keyword(s):  
Oil And Gas ◽  
Dynamic Environment ◽  
Poor Performance ◽  
Oil And Gas Industry ◽  
Economic Benefits ◽  
Gas Industry ◽  
Field Development ◽  
Quality Technology ◽  
Indigenous Participation ◽  
Marginal Field

Abstract Marginal field development has gained relevance in oil producing countries because of the huge potential economic benefits it offers. The Federal Government of Nigeria commenced a Marginal Fields program in 2001 as part of her policy to improve the nation’s strategic oil and gas reserves and promote indigenous participation in the upstream sector. Twenty years after the award of marginal fields to indigenous companies to develop, 50% have developed and in production, 13% have made some progress with their acquisition while 37% remain undeveloped. The poor performance of the marginal field operators is due to certain challenges which have impeded their progress. A review of challenges of developing marginal fields in the current industry climate was conducted on marginal fields in Nigeria to identify keys issues. These were identified as: funding, technical, and public policy. Considering the complex, competitive and dynamic environment in which these oil and gas companies operate, with competition from renewables, pressure to reduce carbon footprint, low oil price and investors expectation of a good return, companies must maintain tight financial plan, minimize emissions from their operations and focus on efficiency through innovation. The study identifies the need for a decision-making approach that takes into consideration multi criteria such as cost, regulation, quality, technology, security, stakeholders, safety and environment, as important criteria based on which to evaluate the selection of appropriate development option for marginal fields.

Three-Phase Flow Profile Determination of A Horizontal Well in Offshore by Tracer Technology

2021 ◽  
Author(s):  
Alexander Katashov ◽  
Igor Novikov ◽  
Evgeny Malyavko ◽  
Nadir Husein
Keyword(s):  
Oil And Gas ◽  
Horizontal Wells ◽  
Oil And Gas Industry ◽  
World Market ◽  
Dynamic Mode ◽  
Flow Profile ◽  
Offshore Platforms ◽  
Field Development ◽  
Coiled Tubing ◽  
Three Phase

Abstract Over the past few years, the oil and gas industry has faced a situation of high fluctuations in hydrocarbon prices on the world market. In addition, the trend for the depletion of traditional hydrocarbon reservoirs and the search for new effective solutions for the management and control of field development using horizontal and multilateral wells is still relevant. The most common method for horizontal wells testing is production logging tools (PLT) on coiled tubing (CT) or downhole tractor, which is associated with HSE risks and high cost, especially on offshore platforms, which limits the widespread use of this technology. The solution without such risks is the method of marker well monitoring, which allows obtaining information about the profile and composition of the inflow in a dynamic mode in horizontal wells without well intervention. There are several types of tracer (marker) carriers and today we will consider an approach to placing marker monitoring systems as part of a completion for three-phase oil, water and gas monitoring.

Quantifying Economic Uncertainties and Risks in the Oil and Gas Industry

2021 ◽  
pp. 154-184
Author(s):  
Sorin Alexandru Gheorghiu ◽  
Cătălin Popescu
Keyword(s):  
Business Performance ◽  
Oil And Gas ◽  
Water Injection ◽  
Oil And Gas Industry ◽  
Oil Field ◽  
Gas Industry ◽  
Field Development ◽  
Drilling Rig ◽  
Oil Field Development ◽  
Oil Gas

The present economic model is intended to provide an example of how to take into consideration risks and uncertainties in the case of a field that is developed with water injection. The risks and uncertainties are related, on one hand to field operations (drilling time, delays due to drilling problems, rig failures and materials supply, electric submersible pump [ESP] installations failures with the consequences of losing the well), and on the other hand, the second set of uncertainties are related to costs (operational expenditures-OPEX and capital expenditures-CAPEX, daily drilling rig costs), prices (oil, gas, separation, and water injection preparation), production profiles, and discount factor. All the calculations are probabilistic. The authors are intending to provide a comprehensive solution for assessing the business performance of an oil field development.

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