As a part of their regulatory remit, BSEE is undertaking inspections to ensure the integrity of the structures and processing equipment on the OCS are properly maintained to continue safe operations with no harm to the environment. As a part of this undertaking both scheduled annual inspections, and periodic and unannounced inspections are performed.
In the pursuit to further understand the challenges faced by oil and gas operators, Viking has maintained a failure database capable of determining common failures and failure trends. This information provides insight to aid in preventing common failures and improving industry practices to reduce incident rates in addition to saving time and money.
In the last GATEKEEPER, we determined the top of line corrosion (TOLC) rate along with the top of line water condensation rate. Now its time to assess the TOLC risk and the corresponding locations in the system where TOLC may occur. From there we can determine the appropriate mitigation and control strategies.
A facility that processes hydrocarbons needs an inspection program not only to meet regulatory requirements, but also to protect its bottom line by actively managing risk. While this goal may be a foregone conclusion, its achievement is not. So, what goes into a well-designed inspection program? And what does it produce? How can the most value be derived from inspection dollars?
There are many production reservoirs that produce high levels of hydrogen sulfide (H2S). Some of these fields know before initial production that there will be high levels of H2S and thus are able to design and manage accordingly; however, some fields will begin producing an increasing amount of H2S following water injection. These fields are more difficult to manage and require a means of prediction to help make cost-effective project decisions. At GATE Energy, we have the technical knowledge and experience to apply our own approach to souring prediction which can enable design and operational decisions to be made to mitigate the risks associated with such H2S production.
Top of line corrosion primarily occurs in wet gas systems when water vapor condenses on the internal walls of the pipeline due to the heat exchange occurring between the pipe wall and the colder ambient medium. As the liquid condenses on the internal pipe wall, the concentration of the acid gases and organic acids (naturally present in the gas stream) in the liquid increases.
There are many projects that leverage water injection or waterflood (WF) as a secondary recovery tool to increase oil production returns. Many of these projects’ economic viability is intrinsically linked to the ability to inject large volumes of water into the reservoir as a means of oil drive and pressure maintenance. For these fields, it is vital that the integrity of the water injection system is maintained through fit-for-purpose material selection and asset integrity management processes.
ntegrity Management (IM) planning is a challenge that is currently center-stage with oil and gas operators as the downturn has led to focused attention on extending the life of existing assets while optimizing ongoing operating expenditure. This is particularly true in the deepwater basins of the world, where capital costs are high, the cycle time to deliver new facilities is long, and the life extension of existing assets to support hub and spoke tieback developments is often commercially favorable.
Operating a facility comes with multiple aspects of technical and business goals. One common goal is to maintain production at maximum while minimizing cost, and it is only achievable if the pertinent risks are properly assessed, whether it is aligned with an “operate-to-failure” or a “prevent-at-all-cost” philosophy.
Oil well stimulation is commonly undertaken using aqueous solutions of hydrochloric acid (HCl), hydrofluoric acid (HF), organic acids or mixture. The use of these acids will open new channels near the wellbore region for the oil and gas flow through and will result in increased production.
Blockage remediation methods vary widely depending on the nature and location of the blockage, available facilities, targeted outcome(s) and costs involved. In Blockage Remediation Part 1: Blockage Characterization and Detection, we discussed the importance of correctly understanding the nature of a blockage in order to formulate an effective remediation solution.
In spite of robust design, adequate infrastructure and a well planned and executed operating strategy, partial or fully blocked pipelines, with loss of production in many cases, is a reality. This series of two articles discusses the diagnosis, detection and remediation of oil and gas production system blockages in detail. The current issue focuses on blockage characterization and detection.
This book is an exploration of what decision theory has to say about these and other common engineering problems. Why seek the answer to these problems in decision theory? Because engineering is a decision making process.
GATE Systems Engineering Manager Howard Duhon has been developing this process for the past 20 years. The GATE Stream-based HAZOP process avoids these pitfalls via some novel modifications to the process.
American Petroleum Institute (API) 5CT high strength steels are extensively used for casing strings inwells subjected to high cyclic hydraulic fracturing loads. While non-sour grades of API steel such as P110 casing strings have been used satisfactorily for well construction, standard API P110 connections have seen higher rates of failures than pipe body failures in shale wells that require hydraulic fracturing.
Liquid loading is one of the major challenges faced by shale gas producers. This phenomenon occurs when the gas in-situ velocity is insufficient to carry the produced liquid, leading to liquid fallback in the well bore. Liquid Loading can occur during the flow back phase, the phase where the well is producing liquid from hydraulic fracturing, as well as the production phase, and is known to cause premature gas production decline.
Martensitic stainless steels continue to be one of the most widely used corrosion resistant alloys in oil and gas developments. Determining if a martensitic stainless steel is acceptable in an unproven environment requires testing to confirm, but predicting the outcome of a given test environment is often initially based on personal experience rather than a qualitative and quantitative assessment.
In the previous parts of this series, it was established that wax deposition is an issue that arises whenever an oil composition containing appreciable wax content encounters flow, temperature, and pressure that are conducive for solids formation. The effective development of wax management strategies during Front End Engineering Design (FEED) can serve to mitigate or perhaps even prevent the high costs associated with wax remediation.
Wax deposition modeling is essential to estimate the wax deposit thickness over time in support of wax management strategy development for susceptible systems. The objective of this GATEKEEPER is to provide a high-level overview of the model commonly used in the industry to estimate the wax deposition.
Wax deposition is an issue that arises whenever an oil composition containing appreciable wax content encounters flow, temperature, and pressure that are conducive for solids formation. Wax deposition can potentially occur anywhere in the system from the reservoir to the refinery.
Mercury is commonly found in gas processing systems (midstream) and oil and gas fields throughout the world. Mercury is toxic to life and can have deleterious effects to several alloys commonly used in oil and gas production and refining industries.
Methanol (MeOH) contamination of crude oil is a growing concern in the oil and gas industry, as pipeline and refinery quality requirements become more restrictive. MeOH is used in multiple applications in the offshore oil and gas industry, including:
A Decision Support Tool (DST) is an operational barrier used to achieve desired and predictable project outcomes as part of an overall integrated risk management strategy.GATE develops and implements DST’s to mitigate high risk exposure associated with project execution.
Offshore components often suffer from corrosion due to exposure to environments such as seawater, produced water, solvents, oxygen, CO2, H2S and other acids and abrasive particles. To protect equipment from degradation, coatings are applied to internal and external surfaces to provide electrical insulation, physical protection and corrosion and/or chemical resistance. Coatings can also provide thermal insulation, anti-slip, color coding, flame-retardant and anti-bio-fouling qualities to a given surface.
Triaxial evaluation of wellbore loads is used extensively for casing and tubing string design and analysis. A triaxial based collapse strength method was recently adopted by the American Petroleum Institute (API), and an addendum issued to API Technical Report 5C3 (TR 5C3).
Over 80% of major projects fail badly on cost, and/or schedule and/or production rate (1). The average cost overrun is 33%; on a $4 billion project that is $1.5 billion. Schedule overruns and production impairments cost at least that much again. Consequently, we are leaving billions of dollars on the table.
The natural decline in the reservoir energy will impact the flow rate of oil, gas or water, thereby creating instabilities and resulting in decreased production. Artificial lift is used in oil-dominated or liquid-loaded gas systems to increase and stabilize hydrocarbon production, as well as to minimize flow assurance and operational risks, such as slugging in the subsea production system.