Sensors and automation as profit enablers

Ian Verhappen
Industrial Automation Networks Inc.

Production optimization, marginal field development and flow assurance all have one thing in common – sensors and automation as a means to make them possible.

Understanding the characteristics of the reservoir is critical to both marginal field development and production optimization, because fluid mechanics and thermodynamics fundamentals dictate that if you do not know the basics of pressure and temperature it will be impossible to estimate what phase fluid is present. This, in turn, affects whether you will have a gas or liquid product; or at least what ratio of the two will be present.

Pressure and temperature, along with composition, will allow you to accurately model fluid behaviors. Composition is normally determined from laboratory samples as it tends to change slowly over time from each well or location. Other characteristics, such as water cut and gas/liquid ratio (often considered as composition), can change rapidly; and are therefore normally also continuously measured.

Traditional measurement techniques required separation of the three fluid phases (gas, hydrocarbon, water) and then recombination of at least the gas and hydrocarbon streams for transmission to onshore production/processing facilities. However, three-phase separators require sufficient real estate on the platform to separate the hydrocarbon and water phases, which depending on the specific gravity of the hydrocarbon phase can sometimes be quite large. The development of online water cut measurement now makes it possible to separate the gas only for measurement purposes (a much simpler and smaller separator requirement), and then use the resulting measurement for custody transfer and production allocation.

Adding to the complexity of measurements in the offshore environment is that the production fluids often change state between the wellhead and the production platform. For this reason, it is important to have accurate measurements both on the sea floor and surface. When taken with confidence, these measurements can be used to model the expected flow rates at the surface and configure the inlet separation equipment to manage the gas/liquid ratio when it arrives.

For example, if the models predict a potential slug forming, the inlet vessel level can be lowered so there is sufficient volume available to handle the expected "extra" liquid when the slug arrives. Most flow correlations model two-phase (not three-phase) flow and are very sensitive to density, viscosity, and surface tension. All three of these properties are difficult to measure in real time, especially in a multiphase flow stream. They can, of course, be measured for each phase after separation. However, the resulting measurement must then be recombined for both the downhole conditions as well as mixed versus separated states – once again requiring accurate models. Presence or absence of liquid is one of the most important inputs to flow correlations. The definition of significant liquid in multiphase flow models is as little as 1 bbl/MMscf (5.6 cu m/106 cu m), not the relative amounts of liquids. For gas/water flows, it is also necessary to determine how much water is liquid and how much is in the vapor state. And, because water is a polar molecule while hydrocarbons are non-polar, the resulting models are often quite complex. These models form the basis from which flow assurance can be built.

Flow assurance is making sure the gas/oil/water from the wells makes it to the delivery location. All aspects of production from the reservoir through to the plant inlet need to be measured and understood. This includes pressure loss, heat loss, slugging, phase behavior and viscosity, blockages due to hydrates, wax, scale, sand, and mechanical integrity (corrosion, erosion). With this data, offshore oil and gas companies can be confident that their facilities are operating within constraints. Leak and failure detection is therefore one of the key criteria for flow assurance. So, a good understanding of the expected flow characteristics of the production riser has the added benefit of allowing you to quickly detect potential leaks or other system failures as well.

Flow assurance also involves effectively handling any solid deposits such as gas hydrates, and other components such as wax and asphaltenes that might settle out due to changing conditions in the process piping or pipeline. What compounds the flow assurance task even further is that these solid deposits can interact with each other and can cause catastrophic blockage formation.

Measurements are a vital component of a reliable leak detection system; and, of course, they are also the basis for custody transfers and hence payment for materials received. You only get paid for what you can measure; and the better your measurements, the less material you as a producer will be "giving away" without payment.

Accurate measurements require a combination of many sciences, including physics. This is true whether the measurement involves capacitance or frequency for pressure; milliVolts or resistance for temperature; or some other property to make the raw measurement. This signal must then be converted to a scalar measurement and then transmitted to the control system, generally the realm of electronics and communications, while also being compatible for the environment in which it is operating. Sensor environmental conditions drive the selection of the proper metallurgy (for example 316 stainless and saltwater do not agree with each other) as well as the necessary protection for temperature (cold water), pressure (static head of water for submerged sensors), and water resistance.

Most people take control systems for granted, even more so the field sensors on which they depend for information. This is in part because these systems usually work reliably despite the harsh conditions in which they are placed. However, just like the story of the battle lost because of a horseshoe nail, without these measurement systems we would be "flying blind." Without them and the information they deliver, we would be unable to develop and profitably operate offshore production facilities. This is especially true of the new fields being examined, in deepwater and other harsh environments, which are stretching the limits of technology.

The author

Ian Verhappen, P. Eng., is an ISA Fellow, ISA Certified Automation Professional, and a recognized authority on Foundation Fieldbus and industrial communications technologies. Verhappen operates a global consultancy Industrial Automation Networks Inc. specializing in field level industrial communications, process analytics and hydrocarbon facility automation.