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Diagnostic Fracture Injection Testing (DFIT) in Unconventional reservoirs


 

Diagnostic Fracture Injection Testing (DFIT) in Unconventional reservoirs Related Terms

Diagnostic Fracture Injection Testing (DFIT) in Unconventional reservoirs, DFIT, Frac Monitoring, Surface Pressure Transient Testing

By Rod Kelly – PetraCat Energy Services & Jean Beriault – WTA Services

The DFIT test has become the primary transient test for the ultra-low permeability shales being developed in the USA today.  The DFIT goes by many names:  mini-frac, mini fall-off, datafrac, et cetera; but all refer to the act of injecting small volumes of a clear fluid (usually 2 or 3% KCL water) at low rates to create a fracture before the wellhead is shut-in and the pressure allowed to fall-off naturally.  The fluid contains no proppant so that the fracture can relax and close naturally when pressure is released.  Most unconventional zones are overpressured reservoirs that can support a column of fluid in the wellbore.  In those cases, upwards of 90%+ of all unconventional reservoirs, the accepted practice is to utilize surface pressure measurements.  Multiple direct comparison runs with downhole gauges have confirmed that the DFIT test can be performed using a high quality surface measurement system.  This alternative not only produces equally accurate data but is also significantly lower in cost and risk-free. 

Conventional pressure transient testing (pressure build up and drawdown/production testing) depends on “transients” or changes in flow rates occurring relatively quickly.  Pressure transient testing can be applied from initial completion to the economic producing life of the well.  The permeability of the reservoir is the primary determining factor of the duration of the pressure transient test.   Because the permeability in shale formations is extremely low, the opportunity to perform pressure transient analysis is severely restricted due to time limitations.  For most operators, waiting the requisite time for the transitions in “analyzable” flow regimes to take place is not economical.  While a reservoir with a permeability estimated to be 50 md may require less than 24 hours of shut-in time to determine formation properties; a nano permeability reservoir such as the shales might require months or possibly years for this transition to take place.  This reality further demonstrates the impracticality of traditional testing methods for these types of ultra-low permeability, unconventional formations.

The oil and gas industry is a dynamic industry and continues to create processes that boost productivity and yield better accuracy while also being more cost and time effective.  Knowing this, a pressure fall-off analysis method for the DFIT was developed by Nolte to provide estimates for fluid efficiency, fracture closure pressure or minimum in-situ stress, fluid leak-off coefficient, and fracture gradient, among other important frac calibration parameters.  This was followed with a process called after-closure analysis (ACA) to assist in the identification of flow regimes and ultimately to calculate reservoir transmissibility (kh/µ) and initial pressure with results comparable to conventional methods such as pressure buildups and drawdown/production testing.  This analysis technique has multiple uses but is routinely employed in ultra-low permeability reservoirs and can be used for reservoir characterization and for successful fracture treatment, evaluation, and design.  The ACA technique is comparable to the pressure transient analysis (PTA) technique utilized in conventional higher permeability reservoirs; although, PTA is a technique less preferred. 

DFIT Analysis

While monitoring pressure decline, the analyst is looking for two key intervals; the time it takes for the fracture to close and the time it takes to transition into a pseudoradial flow regime.  It is important when performing an ACA that one inject into an undisturbed reservoir and measure the volume of the fluid being pumped accurately.  Time to pseudoradial flow may be approximated in the case of conductive hydraulic fractures.  This interval is proportionate to the square of the fracture half-length over a given effective reservoir permeability.  However, this requires using expected fracture half-lengths and in-situ effective permeability.

Net pay, porosity, water saturation, viscosity, reservoir temperature, gas/oil/condensate and fluid injection properties, injection data (rates and volume), and downhole configuration are required from the licensed operator.   If applicable, effective horizontal well length may also be required.  A holistic diagnostic or interpretation is conducted based on the various techniques performed by industry experts.

The Total Test plot below shows the calculated bottomhole pressure data at datum as well as injection rates.  (See Fig. 1)

Fig_1

Fig. 1

The Total Test plot is magnified to view the injection period and the first few hours of the pressure decline.  The instantaneous shut-in pressure is then determined.  (See Fig. 2)

Fig_2

Fig. 2

The G-Function derivative approach utilizes a dimensionless fall-off time which relates shut-in time (t) to total pumping time (tp).  The G-Function plot assists in providing leak-off characteristics as well as providing estimates for fracture closure time (tc), corresponding closure pressure (Pc), fracture closure gradient, injection fluid efficiency, and net fracture pressure (∆pnet) based on the ISIP and Pc. (See Fig. 3)

Fig_3

Fig. 3

The G-Function plot and Sqrt(t) plot function equivalently.  The Sqrt(t) plot is utilized to verify the closure pressure and closure time selected on the G-Function plot.  The fracture closure corresponds to the peak of the first derivative on the Sqrt(t) plot. (See. Fig. 4)

Fig_4

Fig. 4

The Log-Log Derivative plot is used for After Closure flow regime identifications and to also further verify the closure pressure and closure time.  The shape of the derivative type curve illustrates linear flow from the induced fractures (+1/2 slope), followed by closure.  A transition is then observed into a trend of approximate -1/2 slope signifying linear flow from the formation.  This was followed by an approximate -1 slope signifying the presence of pseudoradial flow.  Closure time and ACA flow regimes are also confirmed utilizing other available PTA-based techniques. (See. Fig. 5)

Fig_5

Fig. 5

The objective of the mini-frac after-closure diagnostic is to obtain initial estimates for permeability and initial pressure.  If linear flow is observed, leak-off coefficients may also be obtained.  A straight line is placed on the late-time Radial Flow plot.  This is used to provide an estimate for reservoir permeability, based on the provided net pay.  Extrapolation of the late-time Radial Flow plot allows for an initial estimate of reservoir pressure.  (See Fig. 6)

Fig_6

Fig. 6

When formation linear flow is observed, a straight line is also placed on points identified as linear flow on the Log-Log Derivative plot.  This is used to provide estimates for Total Fluid-Loss/Leakoff Coefficient (CT) and Reservoir Fluid-Loss/Leakoff Coefficient (CR).  (See Fig. 7)

Fig_7

Fig. 7

The initial estimates from the above conventional analyses are used as starting parameters for simulation.  The subsequent plots illustrate the simulation match using a fracture model.  The model is only used to match the late-time data since mini-frac models do not account for fracture closure and are only designed for analysing after closure data.  Initial reservoir pressure, and ultimately reservoir transmissibility, (kh/μ) are determined with an excellent simulation match. (see Fig. 8)

Fig_8

Fig. 8


PetraCat’s DFIT system

In PetraCat‘s experience of performing DFITs in unconventional completions throughout the country, the time required to reach pseudoradial flow has shown distinct variability.  For the majority of DFIT tests performed by PetraCat, such as the Utica and Marcellus shales, for example, pseudoradial flow has been achieved in less than 10 days of fall-off time with several occurring in less than 5 days.  While in other shales the time period observed can be significantly longer.  One tends to think of shales as being homogeneous, but these tests indicate the variability of pressure response that approximates what you would expect from a conventional sandstone reservoir…heterogeneity.  In continuing process improvements to reduce time to closure and thus pseudoradial flow, the operator can decrease injected volumes (<15 Total BBLS) in an effort to provide the formation every opportunity to provide the maximum amount of data possible given your time constraints for the fall-off period.

Historically the aversion to performing pressure transient tests has been a result of the requirement to shut-in a producing well, a less than attractive method for obtaining wellbore & reservoir parameters.  Conversely, the DFIT test takes place during that “dead” period between casing/cementing the well and before the frac spread arrives on location.  Because the fall-off time has proven to be limited, as in the case of the Utica and Marcellus shales especially, the engineers can move forward without hindrance to perform the DFIT.  In addition, a trend of relatively shorter fall-offs has been noted in the Wolfcamp and Bone Springs formations where the transition from linear to pseudoradial flow was consistently witnessed in time periods a few days longer than those observed in the Utica and Marcellus tests.  It is worth noting that these shales are clearly not homogenous and fall-off times can be subject to variability owing to the relatively large range of permeabilities within these shale groups.

Observing the notable advantages of pressure transient testing previously discussed, PetraCat provides an economical method for capturing DFIT data with no disruption of production.  The instrumentation to capture DFIT data consists of a high quality quartz surface gauge capable of capturing 1 second sample intervals and a resolution of 0.01 psi.  In the PetraCat system, the gauge is connected directly to the needle valve (see Fig. 9) rather than thru a long 1/16” capillary tubing system as some other systems do (see Fig. 10). 

Fig_9

Fig. 9

Fig_10

Fig. 10

The capillary tubing system was designed for surface transient tests of gas or gas condensate producers and to maintain a safe distance between a hot wellhead and a sensitive quartz gauge that acts as a thermometer.  In a DFIT you are pumping an ambient temperature fluid; therefore hot wellbore fluids are not a concern.  Experience demonstrates the probability of ambient temperature (daytime/nighttime) fluctuations and freezing problems associated with small diameter capillary tubing used in DFIT tests, thus our recommendation is to avoid them for DFIT and any type of injection testing applications.

A further step to provide a complete data set is an option to capture injection rate and injected volume on the gauge memory card in conjunction with pressure & temperature.  The system utilizes a magnetic pickup device affixed to the turbine meter and cabled back to the pressure gauge to record revolutions of the turbine and internally calculating injection rate in barrels per minute and a total injected volume in barrels (see Fig. 11).

IMG_3534

Fig. 11

The gauge sight glass allows for real-time  viewing of the pressure, temperature, injection rate, and cumulative pumped volume as an added benefit.  A further step to enhance the complete DFIT package is the incorporation of a 2” 1502 Turbine meter (1-9 BPM) with magnetic pickup.  Procuring and offering a turbine meter for these small volume/low rate tests was born in response to customer feedback expressing the difficulty to consistently source a functioning and accurate turbine meter.  Turbine meters are hardy instruments that are seldom checked for blade wear or broken shafts, etcetera.  In the small volume jobs run, we have already observed in returned turbine meters broken shafts and foreign material wrapped around the shaft preventing free movement.  Fig. 12 below provides a glimpse of the data set from a DFIT that incorporates the magnetic pickup and a turbine meter. 

Fig_12

Fig. 12 

Having the injection/volume data to plot directly against the pressure provides good insight and a quality control measure of the pump-in operation where the pressure data alone might not reveal the full story.  This complete equipment package can be sent out via Fed-Ex for self-installation or field operators can install and oversee the pump in and fall-off, whichever the operator prefers.

There are several advantages to capturing surface pressure for the DFIT test.  An important one is having the ability to pull and observe the data set at any time during the fall-off in order to understand the current flow regime and if it has entered into pseudoradial flow.  Once pseudoradial flow has been identified the test can be terminated and the next step in the completion process can then be undertaken.  This can be a valuable service to the operator and reduces speculation as to the progression of the test while confirming whether sufficient data has been captured to terminate the test or if continuation of data capture is required during the fall-off.

The DFIT analysis requires injection rates and volume.  This information can be captured with the pumping truck instrumentation and then combined with the pressure data.  This will require additional steps and a level of complexity due to file manipulation and the occasional unavailability of the pump file when needed.

Also, when performing a “step up” or “step down” test to understand frac extension pressure or perforation friction losses, the use of the rate/volume magnetic pickup serves us well.  In addition, we have also found that there can be a significant delay to obtain the pumping data file from the pumping company owing to their activity levels, etcetera.  The surface gauge can easily be modified to receive the injection rate/volume information with cabling from the gauge to the turbine meter via a magnetic pickup. The injection rate and pumped volume (along with pressure and temperature) can be viewed on the sight glass of the gauge in real time during the pumping period and then rigged down during the fall-off portion of the test.  Having the ability to glance at the pressures directly from the gauge during the fall-off or even monitoring injection rates/volumes during the breakdown provides an added value.  Because the gauge can capture the injection rate/volume via the magnetic pickup system, the operator has the option to utilize pumping services that can achieve the required breakdown pressure and pump at the rate sufficient to “get away” the desired volume without sophisticated instrumentation, thus reducing costs.  This can serve to save the operator additional funds because the 2nd and 3rd tier pumping companies can easily handle these low rate / volume jobs.

In summary, the DFIT has proven to be a valuable service in the initial phases of development.  The data captured can serve to determine the best landing zone for the lateral, map pressures and permeabilities, and allows for a better understanding of the variability of the unconventional shales for frac calibration purposes going forward in full scale development.

When you can perform a pressure transient test that does not interfere or defer production during a “dead” period, a test that provides no wellbore risk, has a minimal financial impact to the cost of the wellbore yet has the opportunity to yield a “treasure trove” of both frac calibration parameters and formation characteristics, why wouldn’t you want to move forward full speed with implementation of this procedure for all of your wells?


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