The XLe Spirit from Forum Subsea Technologies is the first observation-class ROV to utilize the comp ... Clock Spring Co. announced a technology licensing and distribution agreement for the Pipeotech AS De ... The S88 pH sensors from ECD are one part of the Model S88 Intelligent Sensors product line of sensor ... Allweiler GmbH’s OptiFix is a pump designed for wastewater treatment applications. It can be disasse ... The Tri-Strakes Combi from Trelleborg is a vortex-induced vibration suppression system for risers an ... InsightCM from National Instruments is application software for condition monitoring with full acces ... FieldCare from Endress + Hauser is a universal software program for configuring field devices in a f ... Siemens’ Revive oily water membrane systems replace filtration and flotation with a single step, eli ... LMI’s Liquitron 7000 Series controller provides multi-parameter monitoring and control for metering ... PlantSight from Siemens and Bentley Systems mirrors the ...
Corrosion downhole in oil and gas wells and surface equipment constructed from carbon steel, generally occurs due to the presence of acidic gases (H2S and CO2) or organic acids in the production streams. In addition, solids can cause erosion-corrosion of downhole tubulars and surface pipework if sufficient gas or liquid velocity exists. Surface or topsides pipework and separation equipment can also suffer from corrosion due to bacteria activity. To control downhole and surface corrosion, several technologies are available including corrosion resistant alloys, coatings, biocides, H2S scavengers, and corrosion inhibitors. This session will discuss key lessons learnt in mitigating corrosion and erosion-corrosion downhole in oil and gas wells as well as surface facilities.
The pipeline system that conveys the individual-well production or that of a group of wells from a central facility to a central system or terminal location is a gathering pipeline. Generally, the gathering pipeline system is a series of pipelines that flow from the well production facilities in a producing field to a gathering "trunk" pipeline. Gathering systems typically require small-diameter pipe that runs over relatively short distances. The branch lateral lines commonly are 2 to 8 in. Gathering systems should be designed to minimize pressure drop without having to use large-diameter pipe or require mechanical pressure-elevation equipment (pumps for liquid and compressors for gas) to move the fluid volume. For natural-gas gathering lines, the Weymouth equation can be used to size the pipe. "Cross-country" transmission pipelines will collect the product from many "supply" sources and "deliver" to one or more end users. Transmission pipelines will generally require much larger pipe than gathering systems. Transmission systems normally are designed for long distances and will require pressure-boosting equipment along the route. Many factors must be considered when designing, building, and operating a pipeline system. Once the basic pipe ID is determined using the applicable flow formula, the other significant design parameters must be addressed. For U.S. applications, gathering, transmission and distribution pipelines are governed by regulations and laws that are nationally administered by the U.S. Dept. of Transportation (DOT).
When product vapor pressure is greater than 0.5 psia (more in some states) but less than 11.1 psia, the U.S. Environmental Protection Agency permits the use of a floating-roof as the primary means of vapor control from the storage tank. Floating-roof tanks are not intended for all products. In general, they are not suitable for applications in which the products have not been stabilized (vapors removed). The goal with all floating-roof tanks is to provide safe, efficient storage of volatile products with minimum vapor loss to the environment. Design requirements for external floating roofs are provided in Appendix C of the API Standard 650.
Liquid loss from a storage tank is generally caused by localized material failure in the form of localized corrosion. Tank bottom leaks can be a result of improper foundation design or operating a tank outside the recommended design pressure or temperature boundaries. Product liquid leakage remains a significant environmental concern. Any tank used to contain a hydrocarbon product can be prone to develop leaks sometime during the service life. Tank design options that reduce the risk of a leak can be considered, or in the event of a leak, any product that escapes is contained and detected in a realistic time frame.
Most threats to safety from production involve the release of hydrocarbons; therefore, the analysis and design of a production-facility safety system should focus on preventing such releases, stopping the flow of hydrocarbons to a leak if it occurs, and minimizing the effects of hydrocarbons should they be released. Ideally, hydrocarbon releases should never occur. Every process component is protected with two levels of protection: primary and secondary. The reason for two levels of protection is that if the first level fails to function properly, a secondary level of protection is available. If hydrocarbon releases occur (and, in spite of our best efforts, they sometimes do), inflow to the release site must be shut off as soon as possible. The problem should not be exacerbated with the continued release of additional hydrocarbons. Protective shut-in action is achieved by both the surface safety system (SSS) and the emergency support system (ESS). Shut-in systems are discussed in more detail in Sec. When hydrocarbons are released, their effects should be minimized as much as possible. This can be accomplished through the use of ignition-prevention measures and ESSs (i.e., the liquid-containment system). If oil spills from a process component, a release of hydrocarbons has occurred. A spill is never good, but component skids and deck drains (if offshore) minimize the effect of a bad situation when the spill would otherwise go into a freshwater stream or offshore waters. A hazard tree identifies potential hazards, determines the conditions necessary for a hazard to exist, determines sources that could create this condition, and breaks the chain leading to the hazard by eliminating the conditions and sources. Because complete elimination is normally not possible, the goal is to reduce the likelihood of occurrence.
Fixed-roof tanks should have a quick opening gauge hatch in the roof, which allows the operator access to the tank to "gauge" the tank, determine if water is present, measure the height of the oil/water interface, and take samples of the crude oil. Standards for manual gauging of petroleum and petroleum products are given in the API Manual of Petroleum Measurement Standards, Chap. When a volatile product is stored in a freely ventilated fixed-roof tank, the concentration of volatile vapors in the vapor space can vary depending on the tank operating conditions. During holding periods, when no liquid is added or removed from the tank, the vapor space comes to equilibrium conditions based on product temperature and vapor pressure. Emissions during holding are generated by the vapor space breathing process.
The component located below the lowest pump section and directly above the motor, in a standard electrical submersible pump (ESP) configuration, is the seal-chamber section. API RP 11S7 gives a detailed description of the design and functioning of typical seal-chamber sections. The seal-chamber section is basically a set of protection chambers connected in series or, in some special cases, in parallel. This component has several functions that are critical to the operation and run-life of the ESP system, and the motor in particular. Figure 1 shows the seal-chamber section of the ESP unit and its component parts.
Corrosion of metal in the presence of water is a common problem across many industries. The fact that most oil and gas production includes co-produced water makes corrosion a pervasive issue across the industry. Age and presence of corrosive materials such as carbon dioxide (CO2) and hydrogen sulfide (H2S) exacerbate the problem. Corrosion control in oil and gas production is reviewed in depth in Treseder and Tuttle, Brondel, et al., and NACE, from which some of the following material is abstracted. Iron is inherently (thermodynamically) sufficiently active to react spontaneously with water (corrosion), generating soluble iron ions and hydrogen gas. The utility of iron alloys depends on minimizing the corrosion rate. Corrosion of steel is an "electrochemical process," involving the transfer of electrons from iron atoms in the metal to hydrogen ions or oxygen in water. This separation of the overall corrosion process into two reactions is not an electrochemical nuance; these processes generally do take place at separate locations on the same piece of metal. This separation requires the presence of a medium to complete the electrical circuit between anode (site of iron dissolution) and cathode (site for corrodant reduction). Electrons travel in the metal phase, but the ions involved in the corrosion process cannot.
The following definitions are used in this section of the Handbook. Crude oil is a liquid hydrocarbon produced from a reservoir. Condensate is liquid hydrocarbon that condenses from the gas as pressure and temperatures decrease when the gas is produced from the reservoir up the tubing and out the wellhead choke. Starting with the lightest molecular weight, they are methane (CH4), ethane (C2H6), propane (C3H8), butane (C4H10), pentane (C5H12), hexane (C6H14), and so on. As the ratio of carbon to hydrogen atoms increases, the molecules become "heavier" and have a greater tendency to exist as a liquid rather than a gas. An oilfield facility is a collection of equipment that is used to separate the fluids that come out of an oil or gas well into separate streams that can then be sold and sent to a gas plant or refinery for further processing. A process simulation is a calculation, usually done with a computer program that predicts how the components that make up the well fluids react to changes in pressure and temperature as they are processed through the facility. This is not a chemical reaction, but rather a simple phase change as liquids flash to vapor or vapors condense into liquid.