150 years ago, when the oil and gas industry first started, the instrumentation available was very rudimental and almost inexistent. In order to have an element of control, visibility and avoid unplanned shutdowns and accidents, samples were frequently taken from different points across the production and processing line.
The most relevant point to take sample was at the wellhead (just downstream of the christmas tree), because it was, and still is today, the point where you can experience the largest variability of physical / chemical characteristics of the production fluid (e.g., pressure, temperature, density, flow rate, fluid composition, water %, etc.). These variabilities are found not only through the life of the filed, but also within the same day of operation.
Today, despite the availability of a wide range of instrumentation, sampling is still utilized to monitor the performance of individual wells and critical process equipment like vessels and separators.
In this blog article you can read about what sampling is, why sampling is outdated, and what options you have to move on from this old type of information / data generation technique.
What is Sampling?
As an operator, you already know that it is not possible to physically see what’s within the pipes of the production line with the naked eye. To be able to analyze the product in any specific point of the production and processing line, you need to take samples to anticipate any potential problems.
When the sample is taken, the fluid is sent to the lab for analysis and final reporting.
As opposed to 150 years ago, oil and gas fields today are more challenging to develop and process, while securing an efficient production. The variability of the field characteristics, the production, the flow rate, the pressure, the temperature, the density and fluid composition, are definitely more challenging now compared to 150 years ago. Thus the rapid change in conditions typically force the operator to do more and frequent samplings.
An old technique applied to modern challenges doesn’t work. Let’s have a look at the consequences of doing sampling the old way:
Demands a lot of people
Sampling is a labor-intensive activity as the operator has to physically go to the sampling point, take the sample, bring it back to the lab, and possibly repeat this once a week, once a day, maybe several times a day depending on the behaviour of the process fluid that you want to monitor. And remember, all this is required just for a single sampling point.
Typically, any upstream production and processing facility has multiple sampling points (imagine an onshore field with 500 or more wells requiring sampling). This demands a lot of people on the field, that go back and forth from the lab.
The lab gets easily overwhelmed
Sending an increased number of multiple samples to the lab as often as several times per day, leads to the lab being overwhelmed with workload, thus you might not get your results until three to seven days later.
Naturally, the delay between the moment in which you take the sample and the moment in which you get back the analysis results, can lead to wrong decisions as the changes in the process could happen very fast.
It is like taking pictures with an analogue camera, where after taking the picture, you have to send the film roll to a special photographic processing studio and wait several days before you have the printed copy and see the real picture. Only then will you know if it was well taken or not.
Changing process conditions
When retrieving the sample, the fluid has a process temperature higher than the ambient temperature (somewhere between 50-150 degrees). For this reason, during transportation of the sample to the lab and while waiting for the analysis, the sample temperature tends to reduce.
Also, putting the fluid sample within a bottle, eliminates the natural fluid mixing present in the pipe and leads to a natural separation process.
Thus, the lab analysis is not analyzing the exact fluid characteristics as it is in the pipe, but instead a fluid that is colder and with many of its components already separated.
Modern labs are able to remix and rewarm the fluid sample before to get analyzed, however these activities introduce additional uncertainties to the analysis itself.
Considering what we know today, this type of sampling is outdated. Instrumentation can do the analysis online, in real time and in an accurate way.
There are numerous technologies capable of analyzing gases, liquids, measuring salinity, temperature and pressure, flow (both multi-phase and single-phase) - and then there are the water cut meters monitoring water in hydrocarbons.
Water is definitely the most critical element in the fluid and typically the one to be monitored.
When measuring water in the various steps of the production and processing line, you reduce its impact and its variability, because you control the outcome in each step.
With the ongoing digital revolution with its wide range of instruments available, the operator has one major task – selecting the best instruments for the application. This is done in the engineering phase, and by utilizing the right instruments you will receive a lot of powerful information, accurate, in real time, in a continuous way, 24/7.
You avoid the uncertainty of sampling, as well as its cost and safety risk. From a cost and efficiency point of view in fact, it’s a no-brainer, in particular considering that the transportation and lab costs will continue to go up, while the instrumentation cost is going down.
Looking into the future, you should reduce the need of sampling to only limited extreme / critical cases.