Is the skin always representative of well damage?
Well AC-2 is a gas vertical well with a permanent downhole gauge at about 650mTVDss from the top perforations. This well started production a few weeks ago and a baseline/initial PBU test was acquired to monitor the well and reservoir performance over time.
The PBU test from the permanent downhole gauge is shown in the derivative plot below.
It is worth noticing the large hump in the derivative, indicative of a high skin.
The derivative stabilization from 0.6 to 2 hours could represent radial flow regime in the horizontal plane. In this case, KH= 1,059 mD.ft and the total skin S= +23.8 from a simple straight line analysis. A more detailed well test analysis needs to be performed at this stage but this is outside the scope of this post.
Even if we don’t see a spherical flow regime (negative slope on the derivative), the high skin could be indicative of partial penetration or limited perforations, as shown in the post on the Skin Factor. This pressure transient response may also reveal some issue with formation damage. As a result, the operator could be tempted to perform a specialist study, inject some chemicals or re-perforate the well.
A PLT was executed to understand this performance deviation. When performing a PLT, the team should take the opportunity to acquire a PBU test with the logging tool at a static position, just above the top perforations. Then the PBU could be compared between the PLT and the downhole gauge to spot any wellbore phase redistribution or significant friction loss. These factors could render some part of the data or the entire PBU useless.
The figure below shows a comparison between the permanent downhole gauge DHG and the PLT gauge during the shut-in period.
The PBU data from the shallow DHG and the deep PLT gauge are shown in the log-log plot below.
Some observations could be made from the above figure:
The derivative data from both gauges are consistent. There doesn’t seem to be any issue with wellbore phase redistribution at shut-in (a lucky one…).
The PBU data that were acquired with the PLT gauge show a much lower skin (ΔP), compared to the DHG.
The difference in skin is in fact due to the friction loss in the tubing between the permanent downhole gauge and the deeper PLT tool.
In the above figure, a straight line analysis shows a total skin S= +0.4, when using the deeper gauge pressure data. The well is not damaged.
By using the Darcy Law, we can arrive to the same conclusion:
With x= 2.066 A0.5/RW (from a detailed well test analysis), reservoir temperature T= 717.7 °R, gas viscosity μ= 0.029 cp and factor Z= 1.04.
Using the permanent downhole gauge, we have:
Pr= 6,170 psi and Pwf= 5,645 psi according to figure 2.
Hence the total skin: S= +23.1, using the permanent downhole gauge data and the Darcy Law for a gas vertical well.
Using the PLT gauge, we have:
Pr= 6,372 psi and Pwf= 6,227 psi according to figure 2.
Hence the total skin: S= +0.2 using the deeper pressure gauge data.
Some simple calculations using the Darcy law equation and the observed drawdown also support the observations from pressure transient analysis.
The permanent downhole gauge is too shallow, at 650 mTVDss from the top perforations. As a result, the skin is amplified by the additional friction loss in the tubing below the gauge. While the shallow DHG reveals some high skin value, the well is in fact not damaged, as shown by the deeper memory gauge.
We know from this post and training video that a shallow pressure gauge can render the flowing and PBU data useless due to wellbore phase redistribution, also called phase segregation. Indeed, the fluid weight below the gauge is likely to keep changing over time and the gauge pressure would no longer be a direct measurement of the pressure at the bottom of the well.
The other risk to the data is that the skin is no longer representative since it accounts for the friction loss in the tubing below the shallow gauge. A well may appear damaged and could trigger some expensive studies and well interventions, when in fact the skin and pressure data are simply misleading due to the position of the gauge.
Downhole pressure gauges should be placed as close as possible to the perforations for the data to be representative of the well and reservoir performance.
How to correct the skin and turbulence factor ?
We first need to build a well performance model, in particular the Vertical Lift Performance VLP or tubing intake curve, using for example the Prosper software. The focus is on the part of the tubing between the pressure gauge and the perforations.
There are several methods that could be used to correct the skin and turbulence factor:
The entire gauge pressure data could be converted to perforation depth using the VLP curve and the rate data. With Prosper software, an Openserver excel file was created to automatically interact with the well file and convert the gauge pressure to bottom-hole.
If we are only interested in the total skin (and not turbulence), a simpler route is to only convert the first PBU pressure point using the VLP and convert the rest of the PBU data using the hydrostatic term. The first data point is the only one affected by the tubing friction loss during the PBU test.
With the VLP curve, we can calculate the friction loss using the rate data before the PBU test. This value can then be converted into a skin using the equation below:
Interesting article! Thank you.
I would like to know what is the software used to produce the pressure derivative plots (figure 2).
Should there be wellbore phase redistribution phenomenon during the PBU, such that could affect severely our data, how could we still analyse this particular data without having to discard it?
What makes Phase redistribution different from Liquid loading phenomenon? Please recomend me a software that would be suitable to model one of these wellbore phenomena.
Thanks for your comment. The software that we used is called PIE, it is very handy to prepare the data and compare different gauges. Please send us an email to [email protected] if you’d like more information on that software.
We could try to extract more value out of an existing PBU test but we need to be careful when wellbore phase redistribution is present. Some part of the data may not be affected by this phenomenon and could be analyzed. Experience and derivative overlays will also help in this case. There are some techniques to try to minimize wellbore phase redistribution, some are mentioned in the training course called “Factors that complicate well test analysis”.
Liquid loading phenomenon is considered to be the same as phase redistribution: the fluid weight below the pressure gauge changes over time due to the accumulation of a heavier fluid at the bottom of the well. Sometimes, the liquid cushion may get re-injected into the reservoir due to gas expansion or gravity, and this could take several days. This means that the PBU would not be reliable for several days…
You could have a look at OLGA from Schlumberger to try to model this phenomenon, it is a dynamic multiphase flow simulator. If you have any interesting results / observations, it would be great if you could share them to the Well Testing Group!
We hope this helps.
The TestWells team
Thank you very much for this valuable insight. I had been absent for a year. I will try and access OLGA for the purpose and see how it goes.
Thanks for the very useful article. I wonder in what case b >0 in the equation S(friction) = aq+b . As far as I understand that @ zero rate (q) S friction should be zero as well
S friction = KH * dP / (141.5 q m B).
Because if b=0 , then D corrected = D- S (friction)/q
Thanks for your great comment.
b can be a value other than 0, but the term S(friction) that we used here is misleading. We should have called it S(tubing) instead.
The pressure drop should be DP (tubing), as the pressure drop between the shallow gauge and the perforations. (This is not only due to the friction). The pressure drop can then be converted into a corresponding value of tubing skin factor with S(tubing)=KH*DP(tubing)/(141.5qBu)= aq + b.
We hope this helps.
The TestWells team
Hello TestWells team,
Really interesting articles on the site. Lot of good learning material for well testing. Thank you!
I would like to learn about the PTA / Well test analysis before and after acid stimulation of long horizontal wells. The wells are completed with limited entry liner (line with holes) and matrix stimulation is done to improve the skin. Do you have some examples of well test analysis done to check the improvement after such matrix stimulation. Any useful tips to share based on your experience.
Apology for the late reply. We have been working on some similar cases and there are some few SPE papers on that topic, including one about the Machar field in the North Sea.
We would highly recommend a PBU test before the stimulation treatment if you can, to understand the impact on the vertical radial flow, linear flow and skin. With long horizontal wells, you may not see the radial flow regime in the horizontal plane, but Deconvolution should help to reduce the non-uniqueness (more info is available in the advanced horizontal well session: http://testwells.com/advanced-horizontal-well-pta)
We hope this helps.
The TestWells team