Taking an Inside Look at Wellhead Monitoring and Metering
The industry is taking a closer look at its production monitoring and surveillance to drive decisions and optimize existing fields while reviewing past performance to plan for future operations. Did the approach work or are adjustments needed? Capital and personnel constraints call for rethinking and the consideration of technologies suitable for achieving production and safety goals.
M-Flow Chief Executive Officer Giles Edward talks about the transfer of laboratory experience to the field and future directions in monitoring.
There are a wide variety of people who want greater accuracy, reliability, and lower life cycle costs from wellhead measurement equipment. There are few doubters that continual data are the key to better management and higher returns from reservoir assets. We see huge potential with unconventional operators, such as those in the lower 48 and Canada, where operators are looking for an edge through lean cutting-edge processes. However, we are also working with international oil companies seeking to solve longstanding field management issues or driven by a desire to squeeze the extra 20% of production from their assets and reduce their in-field costs.
How are sensors protected from production fluids?
“The decisions we make in risk management should be driven by data. Decisions are based on single points of information such as production declining or changing water cut and also in comparing that information to history and models. Is my well doing what the last well did 2 months ago? What does this tell me about what happens next? That should be a numerical process.”
The way we do that is by taking a high-strength, high-pressure, and corrosion-resistant carbon fiber/polymer pipe and embedding sensors within the wall. Because the pipe wall is made from nonmetallic materials, it’s transparent to sensing methods such as microwave. Sensors that would normally have to be inside the pipe wall, and therefore in the fluid flow, are no longer in contact with the fluids—meaning they aren’t being touched by corrosive fluids, eroding sands, waxes, etc.
The design removes the need to maintain, clean, and often replace the sensors. This means that we have almost zero operating costs, better production uptime and revenue, and no HSE risks because nobody needs to go into the field or break the integrity of the pipe.
What are some of the production-related risk and cost concerns to consider in the field applications?
The giant of science Lord Kelvin once said, ‘“When you can measure what you are speaking about and express it in numbers, you know something about it; when you cannot express it in numbers, your knowledge is of a meager and unsatisfactory kind.”
First, we need to define what we mean by risk. It comes in two forms in oilfield development. The version everybody understands is the risk of something going wrong such as production shut-in and dangerous anomalies in production. But there’s a strategic risk for asset owners in that they may not maximize their investment. Poorly designed wells leave oil in the ground or cost more than they should.
The decisions we make in risk management should be driven by data. Decisions are based on single points of information such as production declining or changing water cut and also in comparing that information to history and models. Is my well doing what the last well did 2 months ago? What does this tell me about what happens next? That should be a numerical process.
Finally, the data have to get to the decision makers in a usable form, and consequently, we focus on the whole solution. The data communications and analysis tools that enable decisions are a key part of our products. The solution is wellhead to desktop.
What were the oilfield needs targeted by the introduction of the technology?
Our first products were aimed at accurately measuring residual water in oil pipelines and tankers. In this area we’ve had products running reliably in the field for 4 years, proving the concepts of long-term accuracy with zero maintenance and recalibration. From there we’ve moved the same technology into the wellhead environment, where understanding water-cut changes drives understanding of reservoir development, as well as removing production bottlenecks in processing facilities. Failure to understand water production has historically been a handicap to long-term reservoir optimization; almost every operator has an example of a field that disappointed or needed early re-drilling owing to bad management of reservoir water flows.
What results have been seen in the field?
We’ve had meters installed in the field since 2014. The first one was north of Fort St. John, British Columbia—just off the Alaska Highway—so it has regularly seen temperatures lower than -25°F. Over the 4 years it has been sitting out there in the open, it hasn’t missed a beat or needed to be recalibrated once.
Though what made me happiest about that installation was how simple it was to get up and running. A guy who had never seen it before configured it all by himself, and 2 weeks prior hadn’t even heard of us. The engineer just took it out of the suitcase, hooked it up, and talked to me on the phone for 10 minutes to confirm a couple of details. We didn’t see it in action until we visited 6 months later.
Since then we have carried out long-term accuracy validations with an international oil company in the US, showing the technology delivers results in the field as it does in the lab to the sort of accuracy required for custody transfer.
Most recently we have made wellhead installations where again we have seen an excellent transfer of laboratory experience to the field, with water-cut accuracies around ±1%.
How are wellhead-monitoring solutions adaptable to individual field situations?
A key part of our design philosophy is that the wellhead devices have to work across a wide operating envelope. For example, if the measurement is too sensitive to flow regime, studies are needed to specify the meter in advance, and then site tuning is required. That pushes up costs, but also imposes a workload that fundamentally prevents installation on hundreds of wells (in the way that the US onshore industry needs). That requires some compromise. We have to accept some limitation on the range of measurements we take, but we can install our meters in most situations and have them work out of the box.
Sometimes the site-specific tuning for meters is associated with changing fluid types, which change data processing parameters. But those sorts of changes are made through remote login to the meters or by pulling the raw data offsite and doing data processing in the back office where computing power and expert understanding can be deployed.
The fundamental principle is that we have one set of products. It could be 10 installations or 10,000 installations and it’s still no maintenance, repairs, or additional staffing-hours. The hardware is an inline pipe spool and accurate data are delivered straight to a laptop 24/7, anywhere in the world.
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