Formation Testing: Part I of III
Posted by D Nathan Meehan March 26, 2011

I am going to take a small break from the continuing series of blog entries on economics and risk analysis to address a specific technology.  This is in response to multiple requests, so if there is a topic you want to address, please don’t hesitate to contact me.

Wireline and LWD formation testing while drilling has numerous advantages over drill stem testing and conventional testing of completed wells. In this and the following two blog entries we will discuss these powerful tools.  In this entry I will give an overview of the technology and discuss the theory for interpreting permeability and other pressure transient analysis derived properties. In the next blog entry I will go over some of the extremely powerful techniques available to evaluate hydrodynamic parameters including identification of in-situ fluid gradients, identifying the location of fluid contacts and determining if any two formation intervals (in a single well or separate wells) are in hydrodynamic equilibrium.  There are many more uses of these tools including during the course of depletion, optimizing waterfloods, and in hydraulic fracturing diagnostics.

Reservoir evaluation during the drilling and completion process involves many tools including mud logs, Logging While Drilling (LWD), open hole logs, coring, etc. Estimates of reservoir permeability and productivity along with pore fluid contents usually require some sort of flow test to achieve a desired level of accuracy. Most of the pressure transient analysis methods discussed so far are applied to completed wells or to a conventional drill stem test (DST).

One of the most powerful well testing tools in newly drilled wells is the formation tester (FT) which allows operators enormous flexibility during the drilling of a well. It can be conveyed on wireline or on the drillstring using advanced LWD technology. The latter is particularly important when it is difficult to convey the tool to the desired depth using wireline such as in steep directional wells, horizontal laterals or in difficult downhole environments.  Wireline FT tools may be deployed in such difficult downhole environments using pipe-conveyed technologies; however, advances in LWD formation testing such as Baker Hughes’ TesTrak™ LWD formation-pressure testing service have offered operators greater flexibility.

FT devices offer the operator a chance to measure pressures at many locations in a well accurately and efficiently. They can be verified by repeat measurements and are valid over a wide range of mobilities. With advanced pressure transient techniques, directional permeabilities can be measured quantitatively offering improved reservoir characterization and the ability to correlate petrophysical properties with permeability and productivity measures.

Example of Formation Tester (Reservoir Characterization Instrument (RCI), courtesy Baker Hughes)

FT devices offer the operator the chance to recover representative formation fluids captured and maintained above saturation pressures, preserving concentrations of non-hydrocarbon diluents[1] such as H2S and CO2 with minimal contamination. Advances in downhole measurements allow rapid estimation of in-situ PVT properties including density, viscosity, GOR, FVF, bubble point pressure, sulfur content and compressibility along with fluid typing and identifying drilling fluid contamination. Other advanced applications include Mini-DSTs and determination of parameters vital to hydraulic fracturing using Micro-Fracs.

Formation testers use one or more snorkels that are pushed flush into the formation face at a desired depth by backup arms on the opposite side of the tool. They may or may not have straddle packers adjacent to them to provide isolation. The snorkel can allow a small amount of fluids into the tool for pressure identification or larger volumes of fluids that can allow clean samples of reservoir fluids to be analyzed and/or recovered to surface. In either case, high resolution quartz crystal pressure gauges are used for accurate transient testing and pressure measurements.

The following figure shows the conceptual design of such a tool along with the measured pressures as a function of time.


Most of the pressure transient analysis techniques discussed so far have been applicable for production or injection wells that have been completed and “cleaned up.” DSTs and FTs require the reservoir engineer to ensure that the correct reservoir conditions are being identified. Invasion of mud filtrate during the drilling process may cause an excessively high pressure in the near wellbore region called “supercharging.”  It occurs in environments where the mudcake does not adequately isolate the wellbore pressure from the formation. The supercharging is a bigger problem in LWD environment where active mud circulation limits filtrate cake growth. As a result, the leak-off rates are higher in dynamic mud conditions in LWD than in wireline where mud condition is static. Supercharging is larger if mud cake permeability Km is high and formation permeability Kf is low. It is commonly observed both with wireline and LWD measurements if the permeability of the formation is less than 1 mD.

Flow analysis

Flow towards a single point in a reservoir typically results in spherical flow. In a layered reservoir this may give way over time to cylindrical flow. In an FT, flow is restricted due to the probe and results in semi-hemispherical flow.

Various analysis techniques have been borrowed from the conventional well testing studies to analyze the FT derived data. The “Drawdown Mobility” calculation incorporates the pressure drawdown corresponding to the piston drawdown rate in Darcy’s equation to calculate the near wellbore mobility. 


Sgeom : Flow geometry effect due to hemi-spherical flow

kdd : Drawdown permeability

qdd : Drawdown piston rate

rp : Probe radius

rw : Wellbore radius

µ : Viscosity

There is a drawback in this analysis particularly in very low permeability formations where transitional behavior of pressure with respect to the piston rate becomes more significant due to tool storage effect. In low permeability formations the flow rate from the formation can be different from the piston drawdown rate.

Mobility calculation by Formation Rate Analysis (FRA)1,2,3,4 accounts for the tool storage effect by calculating the system compressibility during the drawdown within the fixed tool volume. In FRA, the formation flow

rate is calculated from the piston drawdown rate using Darcy’s equation and the material balance in the tool 

The subscripts for flow rate q represent accumulation, formation flow and piston drawdown and implicitly assume a small density variation. D’arcy’s law for this system becomes


Go : Geometric factor (4.67)

rp : Probe radius (in cm)

k   : Permeability, md

µ : Viscosity, cp

Adding the mass balance with respect to time and liquid accumulation rate

We can then solve for pressure as a function of time as follows:

A plot of P(t) vs. formation rate should approach a straight line with negative slope and intercept P* at the P(t) axis and the  mobility is calculated from the slope. The FRA plot should yield identical slopes for both buildup and drawdown if there was constant compressibility. Compressibility effects can be resolved using multi-linear regression techniques.

Thanks to Sefer Coskun, Reservoir Engineering Manager with Baker Hughes RDS in the Global Geoscience group for assistance with this and the two following blog posts.

[1] FT devices constructed of non-reactive metals such as titanium are required to maintain H2S concentrations.
10 responses | Add Yours


Rohit Singh Negi says:

This is surely my favorite topic. I have done my interns on the same and I believe whatever I learned will never go off my mind.

D Nathan Meehan says:

Well then you are going to enjoy the next two posts (they are scheduled every two weeks). We will be looking at more information on the formation testers including using them for reservoir characterization beyond permeability, pressure, skin, boundaries, etc.

Ali says:

Thank you for this topic. I realy enjoy it and wait impatiently for the next post!


Rodolfo Galecio says:

Let me mention two remarks: first in order to arrive to the final expression for P(t) the right member ‘s signs of the previous equation need to be interchanged; second and for the sake of simplicity can we rewrite the last equation:
P(t) = P* – (u/(k.Go.ri)).Qf
to better expressing the relationship between P(t) and Qf

D Nathan Meehan says:

I am always impressed with the “eagle eyes” of my readers and appreciate their help. I will try and make the corrections and simplifications suggested in the next week, but Rodolfo is correct in spotting my typo and in suggesting the simplification. Good catch.

Pradeep Singh says:

This is great, good place to learn more about the Formation tester methods, I have been trying to acquire formation pressure with normal formation tester modules like RCI/MDT. The one approach was to give small multiple drawdown with the final as drawndown also a smaller one with 30/cc permin drawn down it gave a positive result. Is there any other method which can be applied for tight reservoir with permeability of less than 1 md.

D Nathan Meehan says:

It is very difficult to conduct pressure tests in very low permeability rocks such as 0.1 mD or less. The probe’s surface area open to the flow is very small. This causes huge pressure DD during the flow and results in very long time for a stabilized pressure buildup. Therefore, the main objective in low perm zone is to reduce the pressure-DD by applying low flow rate (RCI can apply as low as 0.1 cc/s piston rate).

Probes with larger area open to the flow would help in lowering pressure-DD for a given rate compared to the conventional probes.

Another important consideration is the small system volume of the flow lines. In low permeability environment the flow capability of the formation is usually lower than the piston drawdown rate of the pump. As a result, the storage within the tool becomes an important factor in duration of the pressure buildup

D Nathan Meehan says:

I have updated the equations to reflect the correction of the transposed signs and to show the simplification suggested.

Camiel van Soest says:

For tighter reservoirs is there any experience with obtaining reservoir pressures from injection testing with the RCI. Controlling injection rates is easier than controlling production rates. For pressure transient interpretation, injection testing is same as drawdown testing, sign of flow rate is only inverted. Offcourse the RCI would require a tank with clean fluid rather than mud and multiphase flow will play a role as injected fluid differs from reservoir fluid/mud filtrate? Just a question out of interest.

D Nathan Meehan says:

Yes, tighter reservoirs obviously require longer times. Injection testing even to the point of microfracturing (data fracs) are excellent sources of initial pressures. When many tight layers are present, very small injections and falloffs can be used — I have done this in the past with very tight gas.

You must be logged in to post a comment.

We’re here to help
D Nathan Meehan