A permanent downhole gauge system is of course more than the pressure- and temperature gauge;

  1. It is the downhole gauge carrier, or gauge mandrel as it is called by some, which is holding the sensor in place and providing a pressure channel (port) from the production stream.

  2. It is the gauge itself (see bottom of page, left side) with its cable connection.

  3. It is the cable going from the sensor to the wellhead system. This cable are also sometimes referred to as the TEC (tubing encased cable) or the “flat pack”.

  4. It is the cable protectors/clamps that secure the cable to the production tubing as well as protects it during wellbore installation. (Some “daredevils” are using Band-it metal straps/”metal tapes”, which I would only evaluate for very shallow and vertical wells.)

  5. It is the cable splice(s), if used.

  6. It is the packer feedthrough(s), if used.

  7. It is the downhole electrical or fiber optic couplers, if used.

  8. It is the penetration system with the electrical or fiber optic coupler through the wellhead system.

  9. It is the wellhead outlet assembly.

  10. It is the cable from the wellhead outlet to the data acquisition system, interface card, umbilical, etc.

  11. It is the software system obtaining, converting and transmitting the sensor signals.

  12. It is the total system required to sense and get the data to the desk of the engineer needing the data.

  13. And last, but no way the least important; It is the installation preparation and execution personnel and the workmanship at the wellsite!


Permanent monitoring can vary from a simple pressure- and temperature (P&T) sensor, P&T plus vibration monitoring, P&T plus distributed temperature sensing, P&T plus flow measurements, to P&T plus seismic measurements.


So when someone say that “The permanent gauge failed”, the gauge may be completely ok. But maybe it is only a surface connection that has been disconnected accidentally?

My hope is that before one say that a system has failed, that the installation company does its investigation first. And I also hope that all sensor installation companies are completely honest with their findings, and that they do not blame it on someone else just because that is the easiest exit. There is too many who has done that, and it never pays off in the long run! Honesty and respect, guys!


Now, so called DTS is also being included in the permanent gauge systems. See text below at left for further explanation of DTS.

 

I will only briefly touch onto that topic here, as there are a lot of information to be found about the value of these systems on the Internet. Also, you should look at some of the many very good SPE papers published.

But if you would like to have more on this than what I have below, ask me, and I will assemble some more stuff on why to use this technology in the various well and field types.


There are a number of reasons why one should install it, and close to zero reasons for not installing it.

Basically, the gauge systems give you improved reservoir management leading to increased daily production and increased total field drainage, better reservoir characterization, improved production optimization, better flow allocation and a real time tool for well diagnostics.

You will also experience significant cost savings in well testing. Not having a downhole gauge, you are basically working blindfolded.

As said in the SPE paper 102700 - “Reliability Evolution of Permanent Downhole Gauges for Campos Basin Sub Sea Wells: A 10-Year Case Study” (H.M. Frota & W. Destro, Petrobras):

“These systems are playing and increasingly important role in improving reservoir and well management. They are becoming an issue of paramount importance to forecast future well and reservoir performance.” Any reservoir- and production engineer understand the importance of forecasting; It’s simply the reality proof for any operating company and a indication on having a job or not in the next year. ;-)

They also list these justifications:

  1. Reduce ambiguity and uncertainties in the interpretation

  2. Detect the changes in reservoir properties, such as compaction

  3. Monitor skin, permeability and pressure draw down over time

  4. Evaluate the performance of stimulations or workovers

  5. Evaluate completion performance

  6. Identify well problems quickly

  7. Identify reservoir connectivity

  8. Detect drainage area change

  9. Evaluate operational efficiency

  10. Improve flow back time of new wells

  11. Obtain initial build-up data

  12. Assist reservoir simulation and history matching

Acronyms;

Permanent downhole gauge; PDG, PDHG, PG

Smart wells, intelligent completions, DIACS (downhole instrumentation and control systems), ICV (inflow control valve), smart valve, active completion systems, active inflow control valve, remotely operated sliding sleeves (ROSS), etc.

Why don’t we have a gauge system that survives high temperatures;

Quite simply because you are not willing to pay for it, or take the necessary actions to achieve it!

Many times I have been asked by operators if I can supply and successfully install gauges at very high temperatures. And then they kill it by stating that the gauge of course cannot be more expensive than a standard one. Or they go out on a bid, and a Mickey Mouse company without integrity gets the jobs due to low price. And the stuff fails again and again and again...

My view is that the operator should prepare for failing gauges in HT applications by implementing hardware and abilities to replace sensor when it fails. Fully possible today, but you need to be prepared to be open-minded.

Are fiber optic gauge systems better than electronic gauge systems?

In our industry there are basically two camps, being the electronic and the fiber optic groups. Both with very strong opinions and both with very different background and experience.

When the first development program was initiated by Shell and Alcatel in 1987 the reason was the then low reliability of electronic sensors and the need for systems surviving higher temperatures.

Some people use the traditional phrases, which some of us bite onto: “Fiber optics does not have electronics and therefore the technology will be more reliable” Well, do we really believe that one we need to be a bit naive...

Fiber optics are a fantastic technology where it will no doubt be the best choice for some type of installations, not at least when distributed sensing are required. But it still are not able to conquer electronic gauges on temperature or reliability. To perform better on reliability, the industry must first build up a decent track record. Let’s try it for some time first, and then give the judgement on that.

But going forward the two technologies will go hand in hand, and a split of the market between them will exist for many years to come.

One of the first uses of the so called “cable stripper tool”, which was developed to reduce time  removing the outer plastic encapsulation, but not at least to reduce number of personal injuries from using a sharp knife.

“But it is soooo expensive!” you may say. Well, most operators see the investment paid back in 1 to 3 months, and thereafter it is simply a money maker for them.


An example that has been publicized from Statoil’s Gullfaks field is that they increased production from 630 to 3145 BOPD on a well-by-well basis by installing permanent gauges. This was achieved as the operator was able to produce the wells balanced and controlled slightly above the bubblepoint pressure.


Want to read about the technologies until your eyes runs wet? Check out Risi Jadesola Omotosho’s brilliant report “Permanent Downhole Sensors in today’s petroleum industry” report.

ExxonMobil’s experience with electronic permanent gauge system reliability as of 2005. Note the improvements on recent systems (green line). From SPE paper 103213.

What is a “gauge”;

Often people say “the gauge”, but it is necessary to understand that this “gauge” most often consist of a pressure port arrangement having a buffer tube, a pressure sensing transducer, a temperature sensor,  electronics, a cable head and the other housing/packaging.

Very few of the permanent gauge installers actually manufacture the pressure transducer or temperature sensor themselves, simply because that does not make sense. There are several very good manufacturers supplying to a large client base, being used for downhole as well as surface applications.

Often one may expect that a quartz transducer is required, but in the majority of applications other types as for example sapphire or strain may be perfectly suitable.

What is a DTS;

DTS means distributed temperature sensing, using fiber optic cable. This method is based on monitoring light reflection in a fiber optic cable, being able to detect small temperature changes typically every meter. This is done without having any sensors implemented or connected to the cable - The entire cable is the sensing element.

Selecting the correct DTS surface system is crucial in obtaining value of logging system, and many E&P companies have been disappointed in DTS since it has not provided the data value they hoped for or that the supplier sold to them. Reason for this is that surface systems are different from supplier to supplier, and you need to select a system that gives you the resolution and accuracy you need for your application.

Doing steam injection efficiency monitoring may require a different system than you need for flow allocation in horizontal wells. If you want the system to provide most value its a pretty simple answer: Select the best system you can get!


Want to learn more about DTS and the value of using this downhole? Click here