_A,

DFIT (Diagnostic Fracture Injection Test)SWPLA Meeting May 16, 2012

Mike MayerhoferDirector, Fracturing Center of

ExcellencePinnacle a Halliburton Service

2 2011 HALLIBURTON. ALL RIGHTS RESERVED.

Diagnostic Fracture Injection Test (DFIT)

Simple, cost-effective alternative method for estimating reservoir pressure and permeability (kh) for low permeability reservoirs that would otherwise not flow prior to a hydraulic fracture treatment.

In addition, the test also provides an estimate of fracture gradient (ease of fracturing), fracture closure pressure (minimum rock stress), fluid efficiency and possibly deviatoric stress.



Both reservoir properties and fracturing properties are critical inputs for proper fracture design and optimization, reservoir characterization and infill drilling strategies.

Concepts developed about 17 years ago



Quality of Permeability and Pore Pressure Estimate

Low High

Log/Core DFIT Flow Test with PBURFT

DFIT adds fracturing parameters


Limitations

Performed under injection conditions. Permeability will tend to be higher than under drawdown conditions (stress sensitive permeability). Depending on size of frach may be more representative than prefrac flow test.

Short tests will provide upper bound for pore pressure

Low pressure reservoirs problematic for surface pressure monitoring. Would need bottomhole shut-in and gauges (costly).


Limitations

Pressure transients complicated with dynamic fracture propagation and deviations from ideal assumptions

Most tight reservoirs have to be analyzed with linear flow regimes, radial flow regime never reached (especially shales)

High net pressure, complex fracturing situation challenging to interpret (Stiffer system ~ Higher E-modulus)

Higher permeability oil reservoirs sometimes challenging due to rapid transients


Applications

Pinnacle has analyzed a total of about 400 tests Halliburtons Denver Tech Team about 25,000 tests since

1998 Rocky Mountains Lance formation East Texas Cotton Valley West Texas Canyon Sands Marcellus Shale Canadian Montney Eagleford Shale Emerging Shales


Treatment Data

Time (min)

Surf Press [Csg] (psi) Slurry Flow Rate (bpm)

1818 2513 3209 3904 4599 5294-45.32

1564

3173

4782

6391

8000

0.0

2.000

4.000

6.000

8.000

10.00

Fracture-Injection/Falloff Sequence DFIT

Small Volume Injection Treated Water Gas

Injection Rate Sufficient To Propagate a Hydraulic Fracture

Injection


Treatment Data

Time (min)

Surf Press [Csg] (psi) Slurry Flow Rate (bpm)

1818 2513 3209 3904 4599 5294-45.32

1564

3173

4782

6391

8000

0.0

2.000

4.000

6.000

8.000

10.00

Fracture-Injection/Falloff Sequence Data Analysis Before-Closure

Shut-in Period Pressure Decline Two Distinct Regions

Before Fracture Closure After Fracture Closure

Analyzed for Leakoff Type Permeability Pore Pressure

Before Fracture Closure

After Fracture Closure


Estimating Permeability & Pore Pressure Using DFITs

Flow tests & PBUs are most reliable but rarely done in tight reservoirs (expensive, time consuming, loss of production)

Diagnostic injections are now quite common as they also provide key frac data in addition to perm such as closure (Shmin), efficiency, tortuosity, net pressure and possibly deviatoric stress etc.

Very useful in multi-zone layered reservoirs with uncertain pore pressures and perm eliminating uneconomic zones, pore pressure data for infill drilling strategies.


How are Test Performed and Data Collected?

Perforate the well (small interval or full set). Load hole with water and additives as needed (avoid clay swelling etc). The test should be performed several days prior to the hydraulic fracture treatment to allow for changes to the actual fracture design (if data indicates that changes are necessary).

Install high-resolution surface electronic memory gauges on wellhead. The gauges should have 1-psi resolution or less and data should be recorded in 1 to 2 second intervals for first day; intervals can be extended thereafter for long tests in shales

Start recording before pumping starts and end recording after the falloff is complete. It must be possible to isolate the electronic gauges from the injection pump so that they are not affected by the rig down of the pump and will record surface pressures continuously without interruption.

The test can be performed with one high-pressure pump (e.g. acid pump truck or frac pump).



The injection rate should be high enough to breakdown the perforations and create a small fracture. Typical rates are about 5 to 7 bbls/min. A basic pumping procedure is to first breakdown the formation, followed by a constant rate injection (5 to 7 bbls/min). The total volume should be about 20 bbls to 80 bbls (20 to 30 bbls typical in most shales) depending on zone thickness, using 2% KCl-water and surfactants.

Shut-down the pump and record total volume pumped (total volume is the minimum required input to calculate average rate during test). Best case scenario would also include a electronic rate history from pump.

Rig down the pumping equipment without disturbing the isolated electronic gauges, which are continuously recording the pressure falloff data. Ensure that the well stays shut-in without any disturbances for the entire falloff period.



After falloff is complete, download pressure data from the gauges. If surface pressure falls to zero in less than the planned falloff time the test can be terminated earlier.

Provide Ascii files of pressure and rate data (if available)versus time (Two files: one is from pump truck, the other from isolated electronic gauges). In addition client should provide well logs, estimates of petrophysicalproperties (porosity, water saturation, net pay) and PVT information to injection test analyst. Also provide a report of any unusual problems during the injection and falloff.

Pup Joint with Quartz Gauge or Gauges Electronic Memory Recorder (EMR)set at 1 second interval with 0.01 psi or 0.001 psi measurements.

Pressure Transducer to Pump Unit

Lo-Torque Valves

To PumpUnit w/

Pressure and Rate recorder

Record Pump rate, volume, and pressure during breakdown and injection with Electronic recorder.Close lo-torque valves to isolate pumping equipment and continue to record wellhead pressure afterinjection test is complete.

SPIDR


Test Methodology

Two ways:

Quick Way: Diagnostic water injection in conjunction with standardfrac (all frac equipment- minifrac) at frac rates (at little cost) ( will onlygive upper bound for pore pressure if decline data is observed toclosure only; Perm estimates may not be as rigorous- before closureonly).

Comprehensive Way: Separate injection consisting of small volumeof water (e.g. 2 % KCl with 20 to 100 bbls) @ 3 to 7 bbls/min withone pump truck (surface gauges usually sufficient). Shut-ins of 12 hrsto 10 days (shale) allow estimate of pore pressure and more rigorousperm (kh) estimates in conjunction with after-closure data

- Done before mobilization allows for changes in frac strategy(no frac at all, foam frac etc.)


Before-Closure Analysis (Mayerhofer Method)

M-Method modified by Valko and Economides for high perm and Halliburtons David Craig ~ very similar to original with a few subtle differences & simplifications but useful additions to improve analysis (known as Modified M-Method).

Techniques are based on concepts from pressure transient analysis (transient flow (leakoff) in the reservoir with a varying fracture face skin effect = filter cake + invaded zone).


Before Closure Pressure Disturbance: Transient Linear Flow with Fracture Face Skin

Filtercake

Reservoir Linear FlowPermeability

Invaded Zone


After-Closure Technique (ACA)

Ken Nolte developed after-closure techniques (wait for pseudo-radial flow = high perm OK - long wait for low p* and low kh). Based on dissipation of pressure transient disturbance from injection. Significant transitional flow regimes present as stream-lines rotate. While fracture is mechanically closed is it really hydraulically closed?

Noltes techniques were then used and modified by David Craig to improve before closure analysis resulting in Combo technique for linear flow regimes.

If sufficient after-closure data is available (comprehensive way), pore pressure can be determined separately from after-closure PLF data and is used as input for before closure analysis (if after-closure data not available pore pressure estimate must be estimated from some other source)

Other work by Barree et al., Chipperfield et al. and Soliman et al.


ACA: Pseudo-Linear Flow

Closed Fracture (Mechanically but hydraulically?)

Pressure Disturbance


ACA: Pseudo-Radial Flow

Closed Fracture- Small Compared to Pressure Disturbance

Pressure Disturbance


How the Analysis Works (Comprehensive Way)

1. First step is estimating closure pressure using a combo of G-function analysis (Barree and Nolte) and log-log plots., Also useful for diagnosing complexities such as height recession, PDL, additional extension.


DFIT: Fracture Closure Analysis

G Function Time

Meas'd Btmh (psi) (d/dG) Meas'd Btmh (psi)(Gd/dG) Meas'd Btmh (psi)

0.00 2.56 5.12 7.68 10.24 12.80 0

1900

3800

5700

7600

9500

0

600

1200

1800

2400

3000

0

400

800

1200

1600

2000

BH Closure Stress: 7098 psiClosure Stress Gradient: 0.716 psi/ftSurf Closure Pressure: 2830 psiClosure Time: 24.2 minPump Time: 10.7 minImplied Slurry Efficiency: 55.1 %Estimated Net Pressure: 1027 psi

Step 1 Closure Analysis

Closure



2. Next step is to determine when after-closure pseudo-linear flow occurs.


After-Closure Diagnostic Plot

DFIT: Reservoir Permeability Estimate (Mayerhofer Method)

Squared Linear Flow Time Function

Pressure Difference (psi) (Td/dt) Pressure Difference (psi)

0.010 0.100 1.000 100

1000

10000

Start Pseudo-Linear Flow: 0.189End Pseudo-Linear Flow: 0.0743Start of Predicted Pseudo-Linear Flow: 0.171End of Predicted Pseudo-Linear Flow: 0.118

Start Pseudo-Radial Flow: 0.0467End Pseudo-Radial Flow: 0.0275

Pseudo-Linear Flow

Possible Pseudo-Radial Flow

Unit Slope

Half-Slope



3. Once PLF region identified pore pressure estimated from linear plot similar to Horner


After-Closure Estimate of Pore Pressure

DFIT: Estimate of Pore Pressure (Pseudo-Linear Flow)

Linear Flow Time Function

Meas'd Btmh (psi)

0.000 0.200 0.400 0.600 0.800 1.000 0

1800

3600

5400

7200

9000


Estimated Reservoir Pressure: 5374 psi

Pore Pressure



4. Using the pore pressure as input, perm is now estimated from before-closure technique by history matching decline data


Before-Closure Permeability Analysis (Mayerhofer-Method)


Time (min)

Delta Pressure (psi) (Td/dt) Delta Pressure (psi)Modeled Delta Pressure (psi) (Td/dt) Modeled Delta Pressure (psi)

0.034 0.339 3.393 33.93 10

100

1000

10000Pay Zone Perm: 0.017 mDFrac Half Length: 37.0 ftFrac Face Resistance: 0.10 ft/mD



5. Last step is to cross-check before-closure perm estimate with after-closure data and modify uncertain parameters in before-closure analysis (e.g. fracture height) to make before-closure perm estimates consistent with after-closure emergence of PLF.


Crosscheck of Before-Closure Analysis with After-Closure Data



Pressure Difference (psi) (Td/dt) Pressure Difference (psi)

0.010 0.100 1.000 100

1000

10000


Start Pseudo-Radial Flow: 0.0467End Pseudo-Radial Flow: 0.0275

Pseudo-Linear Flow

Possible Pseudo-Radial Flow

Unit Slope

Half-Slope


Pseudo-Radial Flow Example


Meas'd Btmh Press (psi)

0.000 0.200 0.400 0.600 0.800 1.000 0.0

1600

3200

4800

6400

8000

Start Pseudo-Radial Flow: 0.0173 (392.2 min)End Pseudo-Radial Flow: 0.0115 (590.8 min)

Estimated Reservoir Pressure: 4559 psi

Permeability: 0.045 mD


Integrating MSM and BH Pressure Gauge

Core Area Barnett Shale

FracStage#

InitialBHPatstartoffrac

FinalBHPatendoffrac

DeltaPressure

(psi) (psi) (psi)1 3950 4003 532 3999 4070 713 4060 4234 1744 4130 4311 1815 4282 4600 3186 4344 4390 467 4340 4312 28

TABLE 2 - INITIAL AND FINAL BHP VALUES IN WELL 2H DURING THE FRACTURE COMPLETION OF WELL 1H

Pressure increases in Well 2H duringthe completion of Well 1H

Marcellus Shale Example

Conjugate Fracture Sets


DFIT Results (Well 1H S1) Stage 1)

G Function Time

Meas'd Btmh Press (psi) (d/dG) Surf Press [Csg] (psi)(Gd/dG) Surf Press [Csg] (psi)

0.00 12.84 25.68 38.52 51.36 64.20 0.0

1700

3400

5100

6800

8500

0.0

80.00

160.0

240.0

320.0

400.0

0.0

180.0

360.0

540.0

720.0

900.0

BH Closure Stress: 5362 psiClosure Stress Gradient: 0.890 psi/ftSurf Closure Pressure: 2799 psiClosure Time: 297.3 minPump Time: 7.2 minImplied Slurry Efficiency: 88.3 %Estimated Net Pressure: 1820 psi

Closure

End of PDL

~330 psi PDL Net PressureShmax Shmin is low ~165 psi

Pc = 5,362 psi (0.89 psi/ft)Pnet = 1,820 psiP*= 3,929 psi (0.65 psi/ft)k= 0.0007 md

Easy to open conjugate fractures


Conjugate Fracture Sets


Production Interference

Core Area Barnett Shale

- Shut-ins cause corresponding rate increase in other well- Interference indicates effective xf of at least 500 ft in some

parts of inter-well area



Non-Unique Pressure Build-Up Analysis (1st Buildup)

Core Area Barnett ShaleHigh Perm; Short frac

DFIT Perm; Long fracDual Porosity Slab



PBU Analysis (2nd Buildup)

Core Area Barnett ShaleCleanup; Longer Frac (3,500 ft well total ~ 500 ft per stage)



Closing

Simple technique can provide essential data to optimize fractures and field development at fairly small cost

Provides one piece of puzzle

Benefit of obtaining both fracture and reservoir properties

Understand the limitations


DFIT References

Peer-Reviewed Publications

Mayerhofer, M.J., Economides, M.J., and Ehlig-Economides, C.A.: Pressure-Transient Analysis of Fracture Calibration Tests, Journal of Petroleum Technology (March 1995) 229.

Mayerhofer, M.J. and Economides, M.J.: Fracture Injection Test Interpretation: Leakoff Coefficient vs. Permeability Estimation, SPE-Production and Facilities (November 1997) pp. 231-236.

Barree, R.D., Barree, V.L., and Craig, D.P.:"Holostic Fracture Diagnostics: Consistent Interpretation of Prefrac Injection Tests Using Multiple Analysis Methods," SPE Prod & Opers Journal (August 2009).

Craig, D.P., Eberhard, M.J., Ramurthy, M., Odegard, C.E., and Mullen, R.:"Permeability, Pore Pressure, and Leakoff-Type Distributions in Rocky Mountain Basins," SPEPF (February 2005) 48.


DFIT References

Barree, R.D., Barree, V.L., and Craig, D.P.:Synopsis of "Holostic Fracture Diagnostics,"JPT (March 2008) 67-68.

Craig, D.P. and Odegard, C.E.:"Identifying Bypassed and Ineffectively Stimulated Layers In A Well With Commingled Production From Multiple Layers: Mesaverde Case History," paper SPE 114777 presented at the 2008 SPE Unconventional Reservoirs Conference, Keystone, Colorado, 10-12 February 2008.

Barree, R.D., Barree, V.L., and Craig, D.P.:"Holostic Fracture Diagnostics," paper SPE 107877 presented at the 2007 SPE Rocky Mountain Oil & Gas Technology Symposium, Denver, Colorado, 16-18 April 2007.

Craig, D.P. and Blasingame, T.A.:"Application of a New Fracture-Injection/Falloff Model Accounting for Propagating, Dilated, and Closing Hydraulic Fractures," paper SPE 100578 presented at the 2006 SPE Gas Technology Symposium, Calgary, Alberta, Canada, 15-17 May 2006.

Craig, D.P. and Blasingame, T.A.:"A New Refracture-Candidate Diagnostic Test Determines Reservoir Properties and Identifies Existing Conductive or Damaged Fractures," paper SPE 96785 prepared as an alternate for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, Texas, 09-12 October 2005.

Soliman, M.Y., Craig, D., Bartko, K., Rahim, Z., and Adams, D.:"After-Closure Analysis to Determine Formation Permeability, Reservoir Pressure, and Residual Fracture Properties," paper SPE 93419 presented at the 2005 SPE Middle East Oil & Gas Show and Conference, Bahrain, 12-15 March 2005.

Craig, D.P., Eberhard, M.J., Ramurthy, M., Odegard, C.E., and Mullen, R.:"Permeability, Pore Pressure, and Leakoff-Type Distributions in Rocky Mountain Basins," paper SPE 75717 presented at the 2002 Gas Technology Symposium, Calgary, Alberta, Canada, 30 April 02 May 2002.

Craig, D.P., Odegard, C.E., Pearson, W.C., Jr., Schroeder, J.E.: Case History: Observations From Diagnostic Fracture Injection Tests in MultiplePay Sands of the Mamm Creek Field, Piceance Basin, Colorado, paper SPE 60321 presented at the 2000 SPE Rocky Mountain Regional/Low Permeability Reservoirs Symposium, Denver, Colorado, 12-15 March 2000.

Craig, D.P., Eberhard, M.J., Barree, R.D.: Adapting High Permeability Leakoff Analysis to Low Permeability Sands for Estimating Reservoir Engineering Parameters, paper SPE 60291 presented at the 2000 SPE Rocky Mountain Regional/Low Permeability Reservoirs Symposium, Denver, Colorado, 12-15 March 2000.

Craig, D.P. and Brown, T.D.: Synopsis of Estimating Pore Pressure and Permeability in Massively Stacked Lenticular Reservoirs Using Diagnostic Fracture Injection Tests, JPT (November 1999) 52-53.

Craig, D.P. and Brown, T.D.: Estimating Pore Pressure and Permeability in Massively Stacked Lenticular Reservoirs Using Diagnostic Fracture Injection Tests, paper SPE 56600 presented at the 1999 SPE Annual Technical Conference and Exhibition, Houston, Texas, 3-6 October 1999.

Date post:	04-Sep-2015
Category:	Documents
Upload:	vastaguen
View:	1 times
Download:	0 times

_A,

Documents