Exploration and appraisal well testing is not too popular among some companies. When the oil price is falling down, it is tempting to chase short term gains and reduce the costs by limiting the appraisal activities and well testing operations. This makes it even more critical to get the fewer well testing operations right and optimum, minimizing the rig cost without compromising the data quality and the subsurface objectives.
Some alternatives to acquire dynamic oil and gas data are also pursued at lower costs, but with some limitations. But are these short term gains worth it ? We need to be careful not to compromise the long term field development and production, when the oil price is likely to go up again.

Three main concerns with well testing : environmental, cost and safety

By looking at the picture below, it is easy to understand why well testing is not too popular among some of us…
Impossible to miss the big black smoke, isn’t it… ? First there is an environmental concern with the emissions of greenhouse gases and the risk of spills. In this photo, it seems there is also a sudden change of wind direction and they were about to switch to the opposite flare boom.
The second main concern is the cost, with a standard well testing operations hovering around 10s of millions. Clearly important to make sure that the subsurface objectives – the main and only reason these operations take place– are achieved with the best quality data.
Finally, there are also some safety concerns. While we take all precautions to keep the hydrocarbon in the ground while drilling and completing the well, we now deliberately bring the hazardous fluids from an unknown reservoir to surface through temporary facilities that were rigged up the week before. Looking at the picture, this rig also looks a bit old and rusty and you might not want to land there.

Are these concerns well founded ?

This is an old photo and things have changed now. Combustion is much more efficient with new burner heads such as the Expro Sea Emerald, Super Green burners or the Schlumberger EverGreen ones.
In addition, the gas emissions from well testing operations represent only a tiny portion of the total gas emissions from the rig. However, the well testing operations are highly visible with press releases in the media.
From a safety point of view, there are now some safety management systems in place, with risk assessments, HAZID and HAZOP, safety procedures, etc… So far no major incident occurred during well testing operations and we all need to work together to ensure no incident, no harm to people nor to the environment in the future.
Indeed, a well testing operations cost money, but if they are not performed, we may not spot in advance a compartmentalization problem or a well performance issue. Without sufficient data, the production facilities may not be properly designed. This would result in a production “train-wreck” and huge financial losses, probably more than what a standard well test costs… Well testing operations help to understand the well and reservoir performance, to detect any future problems in production and to design the processing facilities with some large and clean fluid samples.
Well testing helps to get some information over large connected volume, without having to drill more appraisal wells. In fact, well testing helps to appraise more of the reservoir with less number of appraisal wells.


The static log and core data are some critical pieces of information for reservoir characterization but are not an indication of the dynamic flow behaviour. As a result, some dynamic data need to be acquired during the exploration and appraisal stage. It is tempting to replace an expensive well test with another technique or alternative.

Other alternatives to acquire dynamic data ?

In addition to some log and core static data, some subsurface teams only acquire RFT/MDTs as the main dynamic exploration and appraisal data.

RFT / MDT (Repeat Formation Tester / Modular Dynamics Tester)

Performed open-hole, this technique uses a cable operated tool that withdraws some fluids via some sampling probes and measures pressure data.

With this test, we flow the well at a very low rate ~0.5 bbl/d for a couple of minutes and look at the drawdown and PBU mobility values. Fluid movement takes place around the probe, with a small connected volume. Below is the MDT pressure data versus time.

A “drawdown mobility” (Ks/μ) is determined as (Ks/μ) = q/ΔP x C with q the flow rate, 
ΔP the associated drawdown and C a coefficient dependent on the tool being used.
With this “drawdown mobility”, Ks is the spherical permeability and
The “drawdown mobility” and the spherical permeability may not be representative of the flow conditions in the reservoir and could be affected by the presence of the skin (well damage). In addition, the definitions above assume that the steady-state conditions are reached. However, the flowing pressure data are not stabilized for most of the tests and this can also be verified with the PBUs.
In general, with this technique, the PBUs are of bad quality, being too short or with a lot of noise, as shown in the picture below.
In theory, we should see the flow behaviour from a limited well entry: a radial flow regime across the limited open interval, a spherical flow towards the probe then a radial flow regime across the net contributing reservoir thickness. In practice, there is a lot of noise, and if you are lucky, you could distinguish a radial flow regime (with a noisy derivative, the superposition plot should be used to help you with the selection of straight line – to a certain extent…). There is also some uncertainty with the contributing net reservoir thickness, possibly 1 to 3 feet.
The main drawbacks with this technique are as follows:
  • The radius of investigation is very short, i.e. about 1 to 2 feet.
  • The data may be affected by the lack of a proper well clean-up and may not be representative.
  • There may be a limited lateral communication throughout the reservoir.
  • The fluid samples may be corrupted by contaminants such as drilling and completion mud.
  • There is a risk of getting stuck since this is a cable operated tool performed open-hole.
RFT/MDT data shouldn’t be used as the main method to capture some dynamic exploration and appraisal data.
Another option is to run a miniDST and a vertical interference test VIT. The companies Shell and Statoil are the leaders in this area.

MiniDST and VIT

Now we flow a bit more, a couple of barrels for a couple of hours. Maximum rates available are about 35 bbl/d.
As we flow with a limited entry, we expect to see radial flow regime across the open interval, a spherical flow regime and radial flow regime across the net contributing reservoir thickness. An observation probe (VIT) and some additional modelling can be used to reduce the uncertainty in the net reservoir thickness.
On some occasions, radial flow regime may not be visible and the total permeability and skin may not be fixed. This is the case with the derivative below.
We could reduce the uncertainty and range of possible KH and skin values with some modelling techniques.
The main drawbacks with this technique are as follows:
  • The radius of investigation is short, about tens of feet.
  • The pressure data may be affected by the lack of well clean-up and may not be representative.
  • Limited lateral communication throughout the reservoir.
  • There might be some issue with scale that could affect the permeability measurements.
  • The fluid samples may be corrupted by contaminants such as drilling and completion mud.
  • There is a risk of getting stuck since this is a cable operated tool performed open-hole.


Harmonic well testing is another interesting option but still has a limited radius of investigation.
A Mini Fall-Off (MFO), also called After Closure Analysis (ACA) or Decline Fracture Injection Test (DFIT) are other formation evaluation tools, particularly useful for tight gas reservoirs. Analysis can be complex due to a short injection period compared with the long shut-in period (limits of the well testing theory). Also, the results can be highly non-unique in case of a limited frac height and the absence of radial flow regime.
Water Injection tests were investigated in the past so as to stop flaring, but were not too successful. While these tests usually cost more, there can be some issues with a more complex analysis with thermal fracturing and multiphase flow in the reservoir.


Overall these techniques investigate the reservoir in a scale greater than the core and the log but still smaller than well testing (DST). In fact, there are no other alternatives than well testing to calculate the skin (well damage), obtain some large and clean fluid samples to reduce the PVT uncertainty and to investigate some large distances away from the well.
The radius of investigation could be between hundreds and thousands of feet. By investigating that far away from the well, the operator can then reduce the number of appraisal wells and therefore the costs.


Expertise to improve data quality, reduce costs and risks

An oil and gas company needs the best quality exploration and appraisal dynamic data and the expertise to analyse the data, spot potential compartmentalization problems and other production problems. Pressure transient analysis on good quality well test data will guarantee an optimum development plan, a right design for the processing plant and a higher recovery factor. The well test costs are a small price to pay in Exploration and Appraisal to avoid any major financial losses during Production. But the well test costs can be reduced with new techniques and technology.
Support can be provided to integrate design, operations and interpretation for E&A well testing and to investigate alternatives (MDTs, mini-DSTs, ACAs, harmonic testing, injectivity tests, etc) with the aim to minimize rig time and cost, without compromising the data quality and the subsurface objectives.
More value can also be extracted from reprocessing old data and re-interpreting past well tests using tools such as Deconvolution.
Finally, well test analysis can provide a cost-effective way to monitor the well and reservoir performance with opportunistic (free) shut-ins.


For more information or for a discussion, please don’t hesitate to contact us.