799

Kirk Barto

Ken Lizak

Frank Self

Guillermo Izquierdo

Mohammed Al-Mumen

Ken Lizak is a Senior Production Engineer with ShellInternational Exploration and Production. His experienceincludes over 19 years for Halliburton with variousassignments around the globe, including Venezuela,Colombia, Argentina, Houston and Saudi Arabia. Hereceived a BS in petroleum engineering from Texas Techin 1985. He has authored and coauthored several SPEand OTC papers.

Kirk Bartko is a stimulation consultant with SaudiAramco’s Petroleum Engineering Support Division. Heholds a BS in Petroleum Engineering from the Universityof Wyoming, Laramie. Kirk joined Saudi Aramco in 2000and he develops and supports new stimulation andcompletion technologies across Saudi Arabia. He is nowsupporting the South Ghawar Gas Development Project.For 19 years prior to joining Saudi Aramco, Kirk waswith ARCO in Texas, Alaska, Algeria and the ResearchTechnology Center, supporting U.S. and internationaloperations. He has authored and coauthored more than adozen technical papers on well stimulation, holds a patenton monitoring fracture pressures, and has been an SPEmember since 1977.

Frank Self is employed by Halliburton.Guillermo Izquierdo is a Senior Account

Representative in Production Enhancement, working forHalliburton in Saudi Arabia since December 2005. Hisexperience includes over eight years with Halliburton inColumbia where he was involved in acidizing,conformance and fracturing technology applications, theintroduction of new technologies, was a leading

NEW ANALYSIS OF STEP-RATEINJECTION TESTS FOR IMPROVEDFRACTURE STIMULATION DESIGN

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8 SAUDI ARAMCO JOURNAL OF TECHNOLOGY SPRING 2006

technical support in production optimization, and was amember of interdisciplinary teams working on wellstimulation candidate selection. He has a degree inPetroleum Engineering.

Mohammed Al-Mumen is a Senior Technical Professionalwith Halliburton Energy Services. He received a BS inMechanical Engineering from King Fahad University ofPetroleum and Minerals in 1997. Mohammed has over sixyears of experience with Halliburton in Saudi Arabia.

ABSTRACT

Pre-hydraulic fracture diagnostic pumping analysis hasrecently improved with the use of new analysis techniquessuch as G-Function derivative plots, after closure analysis,and step-rate tests. This paper analyzes various types andcombinations of step-rate injection tests, from manydifferent formations around the world, to determine theusefulness of these tests. The analysis included uses wellswith both surface and bottom hole gauge data, and in someinstances, compares the results of the two. The final resultsof the stimulation treatments are also compared to the pre-frac analysis. While the results of these tests provideinformation on the presence of excess near-wellbore frictionor tortuosity, what is often not taken into account is thatthis tortuosity often destroys the usefulness of these step-rate tests in providing much sought-after data such asaccurate fluid efficiency and closure pressure numbers.

The focus of this paper will be on step-up and step-downanalysis, with the result being a new type of graph thatprovides an in-depth look at the quality of these tests in anygiven well. Often these tests are performed and erroneouslyanalyzed because of the effects of tortuosity, with the endresult being either the data is ignored or discarded.Techniques are provided for analyzing these tests andsuggestions are given to improve the results obtained fromthese tests.

INTRODUCTION

Oil and gas wells of different permeabilities and lithologiesoften need to be effectively fracture stimulated to provideoperators with sufficient economic return on investment. Inan effort to ensure that a stimulation treatment can beplaced, injection tests or fracture stimulations withoutproppant or with minimal amounts of proppant have beenemployed to test a formation’s capacity to receive atreatment and to help optimize the final treatment design.The design of these injection tests, usually called“minifracs” or “datafracs” is based on the type ofinformation the operator or stimulation designer seeks from

these tests. Information that can be obtained or inferredfrom these tests includes the following: closure stress orminimum stress, bounding stresses, fracture geometry,presence of natural fractures, permeability, leakoffcoefficient, fluid efficiency, pore pressure, fracture gradient,fracture extension pressure, net pressure and excessfriction1-3. Variations that can be made in these testsinclude the following: injection rate, fluid type, fluid lossadditives, proppant type, proppant volumes and concen-trations and finally, combinations of the various diagnosticinjections. The order in which these tests are performed canalso have an influence on the outcome of the analysis andfinal treatment design.

One such test is the “step-up” step-rate test. In this test,injection into a formation is begun at a slow rate for a fixedamount of time, and the rate is then increased and againheld for the same amount of time. This is repeated in anattempt to achieve three matrix injection rates and threefracture injection rates. A graph of rate vs. bottom holepressure is then made at the stabilized points, and fracture-extension pressure is indicated as the point where thepressure “breaks over” or large increases in rate providesmall increases in bottom hole treating pressure. As will bediscussed, a plot of bottom hole pressure vs. injection rateprovides a myriad of useful information, provided thatthere is good communication between the wellbore and theformation. It will also be shown that the presence oftortuosity virtually destroys this test, and while it has beenproposed that near-wellbore friction can be mathematicallyremoved from this test, the supplied analysis demonstratesthat this is rarely the case.

Another rate-dependent test is the “step-down” step-ratetest. It has been proposed and is now generally acceptedthat this test can provide a rate dependent friction value fortortuosity and perforation friction, and can differentiatebetween the two. The main requirements of this test arethat the test should be sufficiently rapid, or slow in the caseof formations with very low leakoff, so that the fracturegeometry does not change during the step-down test, andthat a displacement fluid with known friction values orbottom hole pressure is accurately determined from bottomhole gauges or a live annulus.

For step-down tests in low-permeability reservoirs it hasbeen recommended that each rate or step should be largeenough so that the fracture growth stops during the step. Ithas been proposed that a period of time of up to 10% ofthe injection time can be used for this test. While this maybe possible in extremely tight rock, in virtually all of theexamples provided, regardless of how short or long that thesteps, it appears that some change in fracture geometryoccurred. These examples indicate that it is also important

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SAUDI ARAMCO JOURNAL OF TECHNOLOGY SPRING 2006 9

that either bottom hole gauge data be used or that a fluid isused in which the friction numbers are very wellunderstood. Another limit to this test is that tortuosity canvary based on injection history, which includes the amountof fluid that has been pumped into the formation, injectionrate variations, and with any injected proppant volumes (ashas been reported in literature). Examples providedillustrate this effect.

STEP-UP TESTS

The most common documented reason to perform a step-uptest is to obtain an upper limit for fracture-closure pressure(FCP) that is identified as fracture-extension pressure (FEP).The idea behind this test is that by slowly increasing theinjection rate in steps of equal time, a fracture will initiateand begin to grow, which will then produce minimalincreases in bottom hole-injection pressure with increasing

rate. Often this test is performed erroneously by extendingeach rate step until the pressure “stabilizes.” Based on theauthor’s experience, and as described by Nolte4, each stepshould be for a fixed period of time. By plotting rate vs.pressure, it is possible to interpolate this point5-7. Anexample of this test and its analysis are shown in Fig. 1. Asshown in this figure, and for simplicity in this discussion,the first line that runs through the lower rate pointsdetermined before the pressure “breakover,” or FEP, isobtained will be designated as the “matrix line.” Thesecond line that runs through the points drawn after thepressure breaks over or levels off will be referred to as the“fracturing line.” While not investigated in this paper, it isconceivable that the slope of the “fracturing line” isproportional to the width and height of the hydraulicfracture.

Once this point is known, maintaining the bottom holepressure above the extension pressure helps ensure that the

Pump

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Fig. 1. Example of typical step-rate test on the left and analysis on the right.

Fig. 2. Example test on the left and generalized analysis of a step-down test shown on the right.

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fracture continues to grow. The injection rate at the FEP isthe minimum rate needed to maintain open a fracture in agiven formation. Field experience indicates that to obtainuseful data, the well must be (1) broken down, and (2)exceptional communication between the fracture and thewellbore must be obtained. It may be necessary for an acidjob, gel breakdown, additional perforations, or proppantslugs to be pumped to allow usable data to be obtained. Itis often the case that tortuosity cannot be removed evenwith combinations of these techniques. Step-up tests inwells with good wellbore-to-fracture communication canprovide good estimates of closure pressure and porepressure.

A better definition of this plot when it provides usabledata would be “fracture reopening pressure” because thewell should be “broken down” before this test. If a step-uptest is the first injection into a well, often the pressure thatwill be obtained will not be the fracture extension pressure,but rather the breakdown pressure. This behavior is notlimited to hard rock fracturing, and has been reported insoft rock high, permeability fracturing as well8. An initialhigh-rate injection with thick fluid is typically needed toovercome the perforation damage effects, formation ofmultiple fractures, drilling induced stresses, or any cementand mud damage. Failure to sufficiently “break down” awell can result in the presence of residual near-wellborefriction or tortuosity that will cause the fracture extensionpressure to be above the initial shut-in pressure (ISIP) of theinjection test or minifrac. This negates any benefit onemight obtain from this test because the most importantinformation obtained is an upper limit for closure. To bebeneficial, this point should fall between the ISIP and theclosure pressure.

If the extension pressure is above the ISIP, the operator orstimulation engineer has two options. The first option is touse the ISIP as the fracture extension pressure and realizethat the well has significant tortuosity effects, which may

adversely effect the placement of the treatment. In thesecond option, steps could be taken to remove the tortuositysuch as reperforating, pumping an acid treatment, use cross-linked gel slugs or proppant slugs and then attempting torepeat the step-rate test to obtain usable information. Theauthors have witnessed numerous treatments around theworld that contain instances where the FEP was calculatedfar in excess of the ISIP of the treatments.

If the FEP obtained from the test is above the ISIP, thenno usable data has been obtained from the stepping up ofthe rate, other then proof that near-wellbore friction ispresent in the well. The decline of this test can be analyzedto produce closure and net pressure. Fluid efficiency can beestimated, but since these tests are often preformed withfluids other than the fracture treatment fluid, this value maynot be useful.

Errors in analysis of this test are often caused by the useof different displacement fluids, which can vary in density,fluid loss properties or frictional properties. Operatorsfocused on cost reductions will often want to cut corners bymix displacement fluids, for example, by switching from thedisplacement fluid to the next treatment fluid, using onlycross-linked gel, or under-displacing the step-rate test toreduce displacement fluid volumes. Even when real-timebottom hole pressure is available, all of these short cutsshould be avoided.

All step-rate test (and all injection test) fluids should be(1) uniform in consistency, viscosity, and density, and (2)filtered to prevent perforation plugging. While discussinginjection fluids, it is often the case that linear gel will be usedto perform a datafrac or minifrac prior to a cross-linkedinjection test. While correlations exist for using the leakoffobtained from different fluids, they are often field andpermeability specific, and should be avoided when possible.

Another problem often observed, especially in older

Fig. 3. Poorly designed step-rate test surface and bottomhole pressureresponses.

Fig. 4. Fracture geometry modeling of a step-up/step-down test. Notice that thefracture geometry significantly changes during the step-down test, losing a thirdof its length and height.

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fields, is low bottom hole pressure. Accurate analysis usingsurface data is virtually impossible as depletion lowers thefracture gradient. Typically, a well that will go on a vacuumin minutes indicates that the formation is being fracturedwith just the hydrostatic weight of the fluid. Bottom holegauges can be invaluable in the analysis of these wells. Careshould be used in this type of analysis; as once the fluidlevel begins to fall below the surface (the well goes on avacuum), there will be flow into the formation that mayrequire specialized analysis.

STEP-DOWN TESTS

Step-down tests are designed to determine the presence ofnear-wellbore friction and to allow this friction to bedivided into a tortuosity value and a perforation value9. Anexample of this type of test is shown in Fig. 2. While anysudden drop of bottom hole pressure from a correspondingdrop in the injection rate indicates excess near-wellborefriction, this test is designed to allow the tortuosity valueand the perforation friction value to be separated so aspecific remedial action can be taken to help ensure asuccessful stimulation treatment placement. Equations 1 and2 are used to differentiate between perforation friction andtortuosity. A well with no near-wellbore or perforationfriction would appear as a straight line on the X-axis; at allrates, the excess friction would be zero.

Pperf=C*Q2 (1)

Ptortuosity=C*Q1/2 (2)

The most important characteristic of this test is that thefracture geometry not change during the test. In otherwords, the fracture should have neither significant growth,nor loss of length or height, during the rate step down. Inmany instances, this cardinal rule is violated. Changes ingeometry would affect the net pressure in the fracture andsubsequently the pressures used in the step-downcalculations. High permeability or depleted formations willneed small, rapid steps. Micro-Darcy formations may needup to 10% of the injection time for fracture growth to stop.Another important consideration is the well should haveeither (1) only one fluid with known friction andhydrostatic properties, or (2) a bottom hole pressure gauge.

An example of a poorly designed step-down test is shownin Fig. 3. In this example, the injection rate was steppeddown seven times, taking almost five minutes to complete.A net-pressure match was made of this test using a popularfracture modeling software. The stresses were adjusted tothe values obtained from both in the step-rate test and theminifrac. When the final match was run for the step-rate

test, the results indicated that both the length and heightchanged by at least 30% during this test (Fig. 4). In thisfigure, the fracture dimensions are plotted vs. time alongwith the bottom hole pressure and the injection rate. Thisreduction in fracture geometry would also cause the netpressure or pressure inside the fracture to fall, which wouldappear as additional friction in the step-down analysis. Thematch indicated that the net pressure in the fracture fellfrom approximately 600 psi to less than 200 psi during thestep-down test.

To improve the step-down test results from this high-permeability oil well, fewer steps of less duration wouldhave helped. A simple prejob model, using any fracturesimulator, would have shown that there were too manysteps in a duration that was too long. It would also havebeen beneficial to use a more efficient fluid, such as thefracturing fluid. The use of bottom hole pressure gaugeswould also have been extremely valuable in this analysisbecause this was a 15,000 ft well with 3.5-inch tubing.

SURFACE VS. BOTTOM HOLE PRESSURE

Fig. 5 is a comparison of a job in which a bottom hole

Fig. 6. Step-up and step-down tests using bottom hole gauge data.

Fig. 5. Step-rate test analysis comparing surface versus bottom hole gauge data.

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gauge was run to within 40 ft of the perforations and aseparate step-rate test followed by a minifrac thatincorporated a proppant slug and a step-down test. A chartof the breakdown, step-rate test and minifrac is shown inFig. 6. A “hard” or high-rate breakdown was used becausethis technique is often used to reduce near-wellbore frictionor tortuosity. As shown, there is insignificant differencewhen comparing the two treatments. In this example, thelower- and higher-rate steps have good agreement, while themid-range rates have the most error. As can be seen, toensure proper analysis, it is critical to use bottom holegauges and/or a fluid with well-understood frictionproperties.

The step-down test was also analyzed for near-wellborefriction using both surface and bottom hole data. Theresulting friction using the two data sets was within 50 psi.The total friction was calculated at 1,478 psi, of which1,122 psi was perforation friction. Because of the highperforation friction, the top 10 ft of the zone of thepreviously perforated 60 ft zone of interest was re-perforated and the minifrac repeated. The fluid used in thissecond minifrac contained 25 lb/Mgal of 100-mesh sand tohelp reduce the near-wellbore friction. The results seen inFig. 7, show that 1,000 psi of near-wellbore frictionremained. This result is clearly indicated by the abruptpressure drop in the bottom hole gauge pressure when thepumping is stopped. Because no step-down test wasperformed, it is difficult to determine whether the 100-meshsand or the reperforating was more beneficial.

An alternative to using bottom hole-gauge pressure hasbeen proposed. The idea is to take an ISIP or instantaneousshut-in pressure at the end of each rate in a step-up test.This ISIP would then be converted to bottom hole pressureby the addition of hydrostatic pressure and then analyzed,typically by being plotted vs. the injection rate just beforethe ISIP was taken. A surface chart of this method is shown

in Fig. 8 and the analysis is shown in Fig. 9. It appears thatthis method is viable; however it can be difficult to select anISIP, especially if the presence of near-wellbore frictiondampens the pressure response (as in this case). The methodis also very rough on the equipment and tubulars, especiallyin high-treating pressure areas, and requires a veryexperienced crew to repeatedly achieve the rapid injectionrate stops and starts.

In the analysis shown in Fig. 9, the last two points appearto fall away from the fracture length trend. This may becaused by (1) the shut-in times allowing the previous fluidvolumes to leak off, or (2) the selections of the ISIPs werenot precise. It is possible that longer stages are needed at thehigher rates using this type of analysis. Interestingly, thesame trend was observed and identical results were obtainedusing the calculated bottom hole pressure.

COMBINED STEP-RATE TEST ANALYSIS

In analyzing many of these different types of tests, it becameapparent that a very useful tool for diagnostic pumping

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Fig. 7. Second minifrac of the above well after reperforating. The 1000-psipressure drop in the bottom hole gauge pressure is the remaining near-wellboreor perforation friction.

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could be made by combining the step-up, step-rate test witha step-down, step-rate test. The analysis of the two couldthen be plotted on a single graph and a clear picture couldbe instantaneously obtained on the quality of the tests. In awell with no near-wellbore friction, the pressures obtainedfrom diagnostic pumping should fall in the following order:breakdown > ISIP > fracture extension > closure > pseudoradial > reservoir. This pressure sequence should occur in allinjection test analysis. Diagnostic tests that do not followthis order would indicate problems with the near-wellborearea or pipe friction. A conceptual drawing of this analysisis shown in Fig. 10. Using this graphical method, the ISIPand fracture extension pressure would be obtained directly.The breakdown pressure would have to be obtained from aprevious injection. The closure pressure and pseudo-radialpressure would have to be obtained from traditional falloffanalysis, and the reservoir pressure would have to comefrom a Horner analysis or previous reservoir test.

With the extension pressure above the closure and belowthe ISIP, it provides an upper limit for closure. Any wiggles,squiggles, inflections or bends that would fall between theISIP and the fracture extension pressure can then be omittedwhen selecting the fracture closure pressure. Closure willalways be below the extension pressure. Obtaining thecorrect closure pressure is the key to determining fluidefficiency and minimum stress for fracture modeling.

A good example of an actual job with a combined step-up and step-down step-rate test is shown in Fig. 11. Thiscarbonate formation was broken down with a small acidtreatment before starting this test. Only surface data wasavailable, and the test was performed using 20 lb/Mgallinear gel. At the beginning of the test, it can be seen in Fig.12 that the early injection steps do not fall on the straight-line portion of the matrix line. This is caused by a previousbreakdown injection that left the near wellbore region

“super-charged” with the wellbore fluids. Even with theeffects of the previous injection, the test was successful.

In Fig. 12, the data points from the analysis not only fallin the correct order, but when the matrix line that is drawnthrough the points (before fracture extension), areextrapolated to zero rate, they intersect at approximatelythe reservoir pressure10. In early use of step-rate tests inwater injection wells, the matrix line was always drawnthrough the reservoir pressure. If this method is used in anarea where the reservoir pressure is not known, this testprovides an upper limit for the reservoir pressure. Likewise,when the lines drawn through the points, after the FEP orthe “fracturing line,” are extrapolated to zero rate, theyintersect at the closure pressure as selected from the declinecurve analysis. These two checks provide an excellent quicklook at the quality of the test. To provide a completeanalysis, additional points should be added to the graphsuch as breakdown pressure, the step-up and step-downrates and pressures, treatment ISIP, FEP, closure pressure,pseudo-radial pressure and reservoir pressure.

An example of where there are problems with the data isshown in Fig. 13. In this example, the FEP is above the ISIP.

Fig. 10. Analysis of a combined step-up and step-down test with no near-wellbore friction.

Fig. 12. Analysis of the actual treatment shown in Fig. 11, a combined step-upand step-down test with no near-wellbore friction.

Fig. 11. Combined step-up and step-down test.

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This is most likely caused by near-wellbore friction orperforation friction. This type of response is often seen inwells that have not been previously broken down. Ideally,all of the step-down points would be above the step-upanalysis and form a straight line parallel to the X-axis asseen in Fig. 12.

FIXING STEP-UP TESTS WITHSTEP-DOWN DATA

There have been attempts to “fix” or remove the near-wellbore friction from these tests by using the step-downdata to adjust the pressures in the step-up data. Thecorrection is simple and logical. The bottom hole orcalculated bottom hole step-down pressure is plotted vs.injection rate. As previously discussed, if there were nonear-wellbore friction, all the points would fall on the X-axis. A best-fit line is drawn through the points, and theexcess friction at any given injection rate can then be readdirectly from the graph. An example of the graphicalanalysis of a step-down test with a best-fit line is shown in

Fig. 14. The excess friction would then be subtracted fromeach point in a step-up step-rate test. In theory, this idea tocorrect the step-up test using step-down results seemsplausible and should provide improved results.

This method of repairing or fixing step-rate tests wasattempted in over 50 Middle East wells. In each case, thecorrection appears excessive in the higher rate region,causing the fracturing line to have a negative slope. Thiswould indicate that net pressure is dropping, an indicationthat the fracture is getting smaller with increasing rate. Anexample of this effect is shown in Fig. 15 where both thecorrected and uncorrected step-rate values from an actualtest are plotted. Obviously, the fractures do not usuallybecome smaller with increasing rate. The most likely reasonfor this pressure response is that the near-wellbore regionhas changed between the step-up and step-down tests.Changing fracture geometry from a test that exhibited toolong, too short or erroneous friction pressure could alsoadversely affect this test.

Taking an ISIP after each rate has been proposed as amethod to eliminate any friction effects, both near-wellboreand tubular. As previously discussed, this method introducesits own limitations:

• It may be difficult to obtain a good ISIP in cases withsevere near-wellbore friction.

• Geometry changes may be severe.• Mechanical difficulties are inherent in this type of test.

COMBINING DIFFERENT INJECTION TESTS

Because it appears that tortuosity and near-wellbore frictionare dependent on injection history, combining the resultsfrom different injections would not appear to be a goodidea. Fig. 16 shows an example where a KCl water step-ratetest and a step-down test from a minifrac are plottedtogether and appear to provide useful data. In this instance,

Fig. 14. Graph and best fit line equation to be used to remove tortuosity effectsfrom step-rate test.

Fig. 13. Example step-rate test where ISIP falls below fracture extensionpressure due to tortuosity effects. Note how the extrapolated fracturing linewould indicate that the fracture closure is also above the ISIP.

Fig. 15. Step-rate test as shown in Fig. 13 with a corrected set of data points.When corrected for tortuosity, the bottom hole pressure falls with increasingrate as seen in the fracturing line.

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the well had very high near-wellbore friction; as can be seenthe ISIP of the step-down test is over 1,000 psi below thefracture extension pressure. This graph is made with bottomhole gauge pressure. Also, note the highly negativeinclination of the step-down test, which is another indicationof near-wellbore friction. In this case, a conservative proppedfracture treatment was successfully placed, leading off withlarge early stages of low proppant concentration to helperode or clean up the near wellbore region.

The authors do not have sufficient case histories todetermine whether combining different injections into asingle analysis would provide the most useful informationto use a single step-up and step-down for this analysis. Thecase provided indicates that different injections can be used.High near-wellbore friction, if present in one test andeliminated in another test, could complicate the analysis.

ADDITIONAL EXAMPLES

A good case for the use of the graphs presented here isshown in Fig. 17. In this case, the well was displaced fromgas to water, broken down, a step-rate test was performedwith both a step-up and step-down test, and the well wasthen treated with a large acid fracture treatment at rates ofup to 70 bbl/min. A second step-rate test was then pumped,and finally the well was treated with a closed-fractureacidizing treatment11. The second step-rate test wasperformed to compare results to the first test and determinewhat effects the acid fracture treatment may have had onformation properties such as FEP and closure. Determiningclosure pressure is important in these wells because it isused to establish the injection rate of the closed-fractureacidizing treatment.

The typical step-rate test analyses for the two tests areshown in Figs. 18 and 19. These figures show how the testswould be analyzed by simply drawing a best-fit line throughthe matrix injection rates to obtain the matrix line, andthen doing the same after the breakover for the fracturing

line. In these analyses, no attempt was made to place thematrix line through the reservoir pressure at zero rate. If thereservoir pressure was not known, this method wouldprovide an upper limit of about 8,000 psi. A FEP of 12,400psi is obtained. Notice in Fig. 19 that it is virtuallyimpossible to determine the FEP or whether the well waseven fractured because it appears that virtually all thepoints fall along the matrix line.

Figs. 20 and 21 then show the same two tests with the

Fig. 17. Acid fracture treatment with pre and post job step-rate tests.

Fig. 18. Initial analysis of first step-up and step-down test.

Fig. 19. Initial analysis of second step-up and step-down test. Without placingthe matrix line through the reservoir pressure, it appears that the zone did notfracture even at rates above 60 bpm.

Fig. 16. KCl water “step-up” step-rate test plotted with a step-down test froma crosslinked gel minifrac in red.

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first line or matrix line drawn through the reservoir pressure.In this case, the pressure was known from offset wellinformation. An FEP of 12,100 psi is observed that wouldhave lowered the horsepower requirements for the acidfracturing treatment. In Fig. 20, the effect of even the smallvolume of fluid that was used to break down the formationcan be seen from the first injection points that fall above thematrix line. The analysis determined that the fractureextension rate was 6 bbl/min at this time. Extrapolating thefracturing line gives a closure of ~11,100 psi.

Once the matrix line in Fig. 21 is drawn through thereservoir pressure, the analysis becomes very clear. Theeffect of the 110,000-gal acid fracture treatment can beeasily seen. The graphical analysis of Fig. 21 gives an FEPof ~12,100 psi, exactly as observed in the pre-treatmentstep-rate analysis. The fracture extension rate increasedsignificantly to 48 bbl/min. The closure, which is in goodagreement with the prejob step-rate test and the minifrac, isagain 11,100 psi. Even with the large amount of reactivefluids used in these tests, the closure and FEP remainedvirtually the same. The step-down test rates are falling,

which would indicate either near-wellbore friction or highfluid leakoff. After the large acid fracture treatment thatwas placed in this well, it is most likely the result of highleakoff to the stimulated interval. Both step-rate tests werepumped using only KCl water.

The advantages of the step-up and step-down testcombined with correct analysis provides a wealth ofinformation about the formation and the effectiveness of thestimulation treatment.

CONCLUSIONS

A plot has been developed that graphically demonstrates thequality of a step-rate test and diagnoses the presence ofnear-wellbore friction. The use of this graph indicates whena step-rate test would need to be repeated because of anerroneous FEP caused by near-wellbore friction.

When there is limited near-wellbore friction, and no largeinjections in front of a test, step-rate tests can provide agreat amount of information about the reservoir, includingreservoir pressure and closure pressure.

Matrix lines should always be drawn through thereservoir pressure, if known. If the reservoir pressure is notknown, extrapolation of the matrix line to zero rate willprovide an upper limit to the reservoir pressure.

Fracturing lines, extrapolated to zero rate, approximatethe closure pressure in wells with low near-wellbore friction.

Analysis indicates that injection tends to reduce the near-wellbore friction that could complicate the combination ofinjections preformed at different times to make a graphicalanalysis.

Most step-down tests are performed too slowly, allowingfracture geometry and net pressure to change. A fracturesimulator can be used to model a treatment and providelimits to stage lengths and rates.

Trying to correct step-up, step-rate tests for near-wellborefriction using step-down tests has not been successful.

While bottom hole pressure data is preferred, in most casesa valuable analysis was obtained from surface data. Goodfriction correlations are essential for these tests to work.

Linear estimates of near-wellbore friction from an ISIP,without stepping down the rate, provide the total near-wellbore friction. This may be a more accurate test becausethe effects of fluid leakoff and geometry change are limited.The friction cannot be separated into its near-wellbore andperforation components.

ACKNOWLEDGEMENTS

The authors would like to thank the management of SaudiAramco and Halliburton for permission to write this paper.

Fig. 20. Revised analysis of first step-rate test using known reservoir pressureas first point in matrix injection rate line.

Fig. 21. Revised analysis of second step-rate test using known reservoirpressure as first point in matrix injection rate line. Excellent agreement is nowobtained between the fracture extension pressures in the pre- and post-treatment tests.

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NOMENCLATURE

Pperf perforation friction, psiC constantQ rate, bpmPtortuosity tortuosity friction, psi

REFERENCES

1. Cipolla, C.L. and Wright, C.A.: “Diagnostic TechniquesTo Understand Hydraulic Fracturing: What? Why? AndHow?” SPE 75359, SPE Production and Facilities(February 2002), 23-35.

2. Barree, R.D., Fisher, M.K. and Woodroof, X.X.: “APractical Guide to Hydraulic Fracture DiagnosticTechnologies,” SPE 77442, presented at the SPE AnnualTechnical Conference and Exhibition, San Antonio, TX,USA, Sept 29 – Oct 2, 2002.

3. Thompson, J.W. and Church, D.C.: “Design, Execution,and Evaluation of Minifracs in the Field: A PracticalApproach and Case Study,” SPE 26034, presented atthe Western Regional Meeting, Anchorage, Alaska,USA, May 26-28, 1993.

4. Nolte, K.G.: “Fracture Design Considerations Based onPressure Analysis,” SPE 10911, presented at the 1982SPE Cotton Valley Symposium, Tyler, TX, USA, May20, 1982.

5. Felsenthal, M. and Ferrell, H.H.: “Fracturing Gradientin Waterfloods of Low-Permeability, Partially DepletedZones,” Journal of Petroleum Technology, (June, 1971),727-730.

6. Felsenthal, M.: “Step Rate Tests Define Safe InjectionPressures in Floods,” Oil and Gas Journal (October 28,1974) 49-54.

7. Economides, M.J. and Nolte, K.G.: ReservoirStimulation, second edition, Prentice-Hall, Inc.,Englewood Cliffs, New Jersey (1991).

8. Stewart, B.R., Mullen, M.E., Brown, J.E. and Norman,W.D.: “Step-Rate, Calibration Injection and TreatingPressure Anomalies in Soft Rock High PermeabilityFormations: An Explanation Based on Bottom HolePressure and Production Results,” SPE 29444, presentedat the Production Operations Symposium, OklahomaCity, Oklahoma, USA, April 2-4, 1995.

9. Wright, C.A.: “On-Site Step-Down Analysis DiagnosesProblems and Improves Fracture Treatment Success,”Hart’s Petroleum Engineer International (January1977).

10. Dozier, G.C. and Sutton, T.W.: “Real-Time PressureDiagnostics Used to Improve Pretreatment Frac Design:Case Studies in the Antrim Shale,” SPE Production andFacilities (February, 2000), 20-26.

11. Fredrickson, S.E.: “Stimulating Carbonate FormationsUsing a Closed Fracture Acidizing Technique,” SPE14654, presented at the East Texas Regional Meeting ofthe Society of Petroleum Engineers, Tyler, TX, USA,April 21-22, 1986.

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