3_SPE-98098 Neww Analysis of SRIT for improved frac Stim Design.pdf

8/10/2019 3_SPE-98098 Neww Analysis of SRIT for improved frac Stim Design.pdf

1/17

SPE 98098

New Analysis of Step-Rate Injection Tests for Improved Fracture Stimulation DesignK.F.Lizak, Shell; K.M.Bartko, Saudi Aramco; and J.F. Self, G.A.Izquierdo, and M. Al-Mumen, Halliburton EnergyServices Group

Copyright 2006, Society of Petroleum Engineers

This paper was prepared for presentation at the 2006 SPE International Symposium andExhibition on Formation Damage Control held in Lafayette, LA, 1517 February 2006.

This paper was selected for presentation by an SPE Program Committee following review ofinformation contained in a proposal submitted by the author(s). Contents of the paper, aspresented, have not been reviewed by the Society of Petroleum Engineers and are subject tocorrection by the author(s). The material, as presented, does not necessarily reflect anyposition of the Society of Petroleum Engineers, its officers, or members. Papers presented atSPE meetings are subject to publication review by Editorial Committees of the Society ofPetroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paperfor commercial purposes without the written consent of the Society of Petroleum Engineers isprohibited. Permission to reproduce in print is restricted to a proposal of not more than 300words; illustrations may not be copied. The proposal must contain conspicuous

acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O.Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

AbstractPrehydraulic fracture diagnostic pumping analysis has recently

improved with the use of new analysis techniques such as G-

Function derivative plots, after-closure analysis, and step-ratetests. This paper analyzes various types and combinations of

step-rate injection tests from many different formations around

the world to determine the usefulness of these tests. The

analysis uses wells with both surface and bottomhole gauge

data, and in some instances, compares the results of the two.The final results of the stimulation treatments are also

compared to the prefrac analysis. While the results of these

tests provide information on the presence of excess near-wellbore friction or tortuosity, what is often not taken into

account is that this tortuosity often destroys the usefulness of

these step-rate tests in providing much sought-after data suchas accurate fluid efficiency and closure pressure numbers.

The focus of this paper will be on step-up and step-down

analysis, with the result being a new type of graph that

provides an indepth look at the quality of these tests in any

given well. Often these tests are performed and erroneouslyanalyzed because of the effects of tortuosity, with the end

result being either the data is ignored or discarded. Techniques

are provided for analyzing these tests and suggestions are

given to improve the results obtained from these tests.

IntroductionOil and gas wells of different permeabilities and lithologiesoften need to be effectively fracture stimulated to provide

operators with sufficient economic return on investment. In an

effort to ensure that a stimulation treatment can be placed,

injection tests or fracture stimulations without proppant or

with minimal amounts of proppant have been employed to testa formations capacity to receive a treatment and to help

optimize the final treatment design. The design of these

injection tests, usually called minifracs or datafracs isbased on the type of information the operator or stimulation

designer seeks. Information that can be obtained or inferred

from these tests include closure stress or minimum stress

bounding stresses, fracture geometry, presence of natura

fractures, permeability, leakoff coefficient, fluid efficiency

pore pressure, fracture gradient, fracture extension pressurenet pressure, and excess friction.1-3 Variations that can be

made in these tests include injection rate, fluid type, fluid loss

additives, proppant type, proppant volumes and

concentrations, and finally, combinations of various diagnosticinjections. The order in which these tests are performed can

also have an influence on the outcome of the analysis and finatreatment 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 fixed

amount of time, and the rate is then increased and again held

for the same amount of time. This is repeated in an attempt to

achieve three matrix injection rates and three fracture injectionrates. A graph of rate vs. bottomhole pressure is then made at

the stabilized points, and fracture-extension pressure is

indicated as the point where the pressure breaks over orlarge increases in rate provide small increases in bottomhole

treating pressure. As will be discussed, a plot of bottomhole

pressure vs. injection rate provides a myriad of usefu

information, provided there is good communication betweenthe wellbore and the formation. It will also be shown that the

presence of tortuosity virtually destroys this test, and while i

has been proposed that near-wellbore friction can be

mathematically removed from this test, the supplied analysis

demonstrates that this is rarely the case.Another rate-dependent test is the step-down step-rate

test. It has been proposed and is now generally accepted that

this test can provide a rate dependent friction value fortortuosity and perforation friction, and can differentiate

between the two. The main requirements of this test are that i

be sufficiently rapid, or sufficiently slow in the case oformations with very low leakoff, so that the fracture

geometry does not change during the step-down test, and thaa displacement fluid with known friction values or bottomhole

pressure is accurately determined from a live annulus or

bottomhole gauges.For step-down tests in low-permeability reservoirs it has

been recommended that each rate or step be large enough to

stop fracture growth during the step. It has been proposed thata period of up to 10% of injection time can be used for this

test. While this may be possible in extremely tight rock, in

virtually all of the examples provided, regardless of how shor

or long the steps, it appears that some change in fracturegeometry does occur. These examples indicate that it is also

important that either bottomhole gauge data be used or that a


2/17

2 SPE 98098

fluid be used in which the friction numbers are well

understood. Another limit to this test is that tortuosity can vary

based on injection history, which includes the amount of fluidthat has been pumped into the formation, injection rate

variations, and injected proppant volumes (as reported in

literature). Examples provided illustrate this effect.

Step-Up TestsThe most common documented reason to perform a step-up

test is to obtain an upper limit for fracture-closure pressure(FCP), which is identified as fracture-extension pressure

(FEP). The idea behind this test is that by slowly increasing

the injection rate in steps of equal time, a fracture will initiate

and begin to grow, which will then produce minimal increases

in bottomhole-injection pressure with increasing rate. Often

this test is performed erroneously by extending each rate stepuntil the pressure stabilizes. Based on the authors

experience, and as described by Nolte,4 each step should be

for a fixed period of time. By plotting rate vs. pressure, it ispossible to interpolate this point.5-7 An example of this test and

its analysis are shown in Fig. 1. As shown in this figure, andfor simplicity in this discussion, the first line that runs through

the lower rate points determined before the pressure

breakover, or FEP, is obtained will be designated as the

matrix line. The second line that runs through the points

drawn after the pressure breaks over or levels off will be

referred to as the fracturing line. While not investigated inthis paper, it is conceivable that the slope of the fracturing

line is proportional to the width and height of the hydraulic

fracture.Once this point is known, maintaining the bottomhole

pressure above the extension pressure helps ensure that the

fracture continues to grow. The injection rate at the FEP is theminimum rate needed to maintain an open fracture in a given

formation. Field experience indicates that to obtain usefuldata, the well must be (1) broken down, and (2) exceptional

communication between the fracture and the wellbore must be

obtained. It may be necessary for an acid job, gel breakdown,

additional perforations, or proppant slugs to be pumped toallow usable data to be obtained. It is often the case that

tortuosity cannot be removed even with combinations of thesetechniques. Step-up tests in wells with good wellbore-to-

fracture communication can provide good estimates of closure

pressure and pore pressure.A better definition of this plot when it provides usable data

would be fracture reopening pressure because the well

should be broken down before this test. If a step-up test is

the first injection into a well, often the pressure obtained willnot be the fracture extension pressure, but rather the

breakdown pressure. This behavior is not limited to hard rockfracturing, and has been reported in soft rock, high-

permeability fracturing as well.8An initial high-rate injection

with thick fluid is typically needed to overcome theperforation damage effects, formation of multiple fractures,

drilling induced stresses, or any cement and mud damage.

Failure to sufficiently break down a well can result in the

presence of residual near-wellbore friction or tortuosity thatwill cause the fracture extension pressure to be above the

initial shut-in pressure (ISIP) of the injection test or minifrac.

This negates any benefit one might obtain from this test

because the most important information obtained is an uppe

limit for closure. To be beneficial, this point should fal

between the ISIP and the closure pressure.If the extension pressure is above the ISIP, the operator or

stimulation engineer has two options. The first option is to use

the ISIP as the fracture extension pressure and realize that the

well has significant tortuosity effects that may adversely effec

the placement of the treatment. In the second option, stepscould be taken to remove the tortuosity, such as reperforating

pumping an acid treatment, use crosslinked gel slugs or

proppant slugs and then attempting to repeat the step-rate testo obtain usable information. The authors have witnessed

numerous treatments around the world in which the FEP was

calculated far in excess of the ISIP of the treatments.If the FEP obtained from the test is above the ISIP, no

usable data has been obtained from stepping up the rate other

than proof that near-wellbore friction was present in the well

The decline of this test can be analyzed to produce closure and

net pressure. Fluid efficiency can be estimated, but becausethese tests are often performed with fluids other than the

fracture treatment fluid, this value may not be useful.Errors in analysis of this test are often caused by the use of

different displacement fluids that can vary in density, fluid

loss properties, or frictional properties. Operators focused on

cost reductions often will want to cut corners by mixing

displacement fluids, for example, by switching from the

displacement fluid to the next treatment fluid, using onlycrosslinked gels, or underdisplacing the step-rate test to reduce

displacement fluid volumes. Even when real-time bottomhole

pressure is available, all of these shortcuts should 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 discussing injectionfluids, it is often the case that linear gel will be used to

perform a datafrac or minifrac prior to a crosslinked injectiontest. While correlations exist for using the leakoff obtained

from different fluids, these are often field and permeability

specific, and should be avoided when possible.Another problem often observed, especially in older fields

is low bottomhole pressure. Accurate analysis using surface

data is virtually impossible as depletion lowers the fracturegradient. Typically, a well that will go on a vacuum in minutes

indicates that the formation is being fractured with just the

hydrostatic weight of the fluid. Bottomhole gauges can be

invaluable in the analysis of these wells. Care should be usedin this type of analysis because once the fluid level begins to

fall below the surface (the well goes on a vacuum), there will

be flow into the formation that may require specializedanalysis.

Step-Down TestsStep-down tests are designed to determine the presence of

near-wellbore friction and to allow this friction to be dividedinto a tortuosity value and a perforation value.9An example of

this type of test is shown in Fig. 2. While any sudden drop of

bottomhole pressure from a corresponding drop in theinjection rate indicates excess near-wellbore friction, this test

is designed to allow the tortuosity value and the perforation

friction value to be separated so that a specific remedial action

can be taken to help ensure a successful stimulation treatment


3/17

SPE 98098 3

placement. Equations 1 and 2 are used to differentiate between

perforation friction and tortuosity. A well with no near-

wellbore or perforation friction would appear as a straight lineon the X-axis; at all rates, 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 other words,

the fracture should have neither significant growth, nor loss of

length or height, during the rate stepdown. In many instances,

this cardinal rule is violated. Changes in geometry often affect

the net pressure in the fracture and subsequently the pressures

used in the step-down calculations. High permeability ordepleted formations will need small, rapid steps. Micro-Darcy

formations may need up to 10% of the injection time for

fracture growth to stop. Another important consideration isthat the well have either (1) only one fluid with known friction

and hydrostatic properties during the test, or (2) a bottomhole

pressure gauge.An example of a poorly designed step-down test is shown

in Fig. 3. In this example, the injection rate was stepped down

seven times, taking almost 5 minutes to complete. A net-

pressure match was made of this test using a popular fracture

modeling software. The stresses were adjusted to the valuesobtained from both the step-rate test and the minifrac. When

the final match was run for the step-rate test, results indicated

that both the length and height changed by at least 30% duringthe test (Fig. 4). In Fig. 4, fracture dimensions are plotted vs.

time along with bottomhole pressure and injection rate. This

reduction in fracture geometry would also cause the net

pressure or pressure inside the fracture to fall, which would

appear as additional friction in the step-down analysis. Thematch indicated that the net pressure in the fracture fell from

approximately 600 psi to less than 200 psi during the step-

down test.To improve the step-down test results from this high-

permeability oilwell, fewer steps of less duration would have

helped. A simple prejob model, using any fracture simulator,would have shown that there were too many steps in a

duration that was too long. It would also have been beneficial

to use a more efficient fluid, such as the fracturing fluid. The

use of bottomhole pressure gauges would also have beenextremely valuable in this analysis because this was a 15,000-

ft well with 3.5-in. tubing.

Surface vs. Bottomhole PressureFig. 5compares a job in which a bottomhole gauge was run to

within 40 ft of the perforations and a separate step-rate test

was followed by a minifrac that incorporated a proppant slug

and a step-down test. A chart of the breakdown, step-rate testand minifrac is shown in Fig. 6. A hard or high-rate

breakdown was used because this technique is often used to

reduce near-wellbore friction or tortuosity. As shown, there is

insignificant difference when comparing the two treatments.In this example, the lower- and higher-rate steps have good

agreement, while the mid-range rates have the most error. As

can be seen, to ensure proper analysis, it is critical to use

bottomhole gauges and/or a fluid with well-understood friction

properties.

The step-down test was also analyzed for near-wellborefriction using both surface and bottomhole data. The resulting

friction using the two data sets was within 50 psi. The tota

friction was calculated at 1,478 psi, of which 1,122 psi was

perforation friction. Because of the high perforation friction

the top 10 ft of the zone of the previously perforated 60-ftzone of interest was reperforated and the minifrac repeated

The fluid used in this second minifrac contained 25 lb/Mgal of

100-mesh sand to help reduce the near-wellbore friction. Theresults seen in Fig. 7 show that 1,000 psi of near-wellbore

friction remained. This result is clearly indicated by the abrup

pressure drop in the bottomhole gauge pressure when the

pumping is stopped. Because no step-down test was

performed, it is difficult to determine whether the 100-meshsand or the reperforating was more beneficial.

An alternative to using bottomhole-gauge pressure has

been proposed. The idea is to take an ISIP or instantaneoushut-in pressure at the end of each rate in a step-up test. This

ISIP would then be converted to bottomhole pressure by the

addition of hydrostatic pressure and then analyzed, typicallyby being plotted vs. the injection rate just before the ISIP is

taken. A surface chart of this method is shown in Fig. 8and

the analysis is shown in Fig. 9. It appears that this method is

viable; however, it can be difficult to select an ISIP, especially

if the presence of near-wellbore friction dampens the pressureresponse (as in this case). The method is also very rough on

the equipment and tubulars, especially in high-treating

pressure areas, and requires a very experienced crew torepeatedly achieve the rapid injection rate stops and starts.

In the analysis shown in Fig. 9, the last two points appear

to fall away from the fracture length trend. This may becaused by (1) the shut-in times allowing the previous fluid

volumes to leak off, or (2) the selection of ISIPs that were notprecise. It is possible that longer stages are needed at the

higher rates using this type of analysis. Interestingly, the same

trend was observed and identical results were obtained using

the calculated bottomhole pressure.

Combined Step-Rate Test AnalysisIn analyzing many of these different types of tests, it became

apparent that a very useful tool for diagnostic pumping could

be made by combining the step-up, step-rate test with a step-

down, step-rate test. The analysis of the two could then beplotted on a single graph and a clear picture could be

instantaneously obtained on the quality of the tests. In a well

with no near-wellbore friction, the pressures obtained fromdiagnostic pumping should fall into the following order

breakdown > ISIP > fracture extension > closure > pseudoradial > reservoir. This pressure sequence should occur in all

injection test analyses. Diagnostic tests that do not follow this

order would indicate problems with the near-wellbore area orpipe friction. A conceptual drawing of this analysis is shown

in Fig. 10. Using this graphical method, the ISIP and fracture

extension pressure would be obtained directly. The breakdown

pressure would have to be obtained from a previous injection

The closure pressure and pseudo-radial pressure would have to

be obtained from traditional falloff analysis, and the reservoi


4/17

4 SPE 98098

pressure would have to come from 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 the

ISIP and the fracture extension pressure can then be omitted

when selecting the fracture closure pressure. Closure will

always be below the extension pressure. Obtaining the correctclosure pressure is the key to determining fluid efficiency 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. This

carbonate formation was broken down with a small acid

treatment before starting this test. Only surface data was

available, and the test was performed using 20 lb/Mgal lineargel. At the beginning of the test, it can be seen in Fig. 12that

the early injection steps do not fall on the straight-line portion

of the matrix line. This is caused by a previous breakdown

injection, which left the near-wellbore region super-chargedwith the wellbore fluids. Even with the effects of the previous

injection, the test was successful.In Fig. 12, data points from the analysis not only fall in the

correct order, but when the matrix line is drawn through the

points before fracture extension and is extrapolated to zero

rate, they intersect at approximately the reservoir pressure.10In

early use of step-rate tests in water injection wells, the matrixline was always drawn through the reservoir pressure. If this

method is used in an area where the reservoir pressure is not

known, the test provides an upper limit for the reservoir

pressure. Likewise, when the line drawn through the pointsafter the FEP or the fracturing line are extrapolated to zero

rate, they intersect at the closure pressure as selected from

decline curve analysis. These two checks provide an excellent

quick look at the quality of the test. To provide a complete

analysis, additional points should be added to the graph suchas breakdown pressure, the step-up and step-down rates and

pressures, treatment ISIP, FEP, closure pressure, pseudo-radial

pressure, and reservoir pressure.An example of potential problems with the data is shown

in Fig. 13. In this example, the FEP is above the ISIP. This is

most likely caused by near-wellbore friction or perforationfriction. This type of response is often seen in wells that have

not been previously broken down. Ideally, all the step-down

points would be above the step-up analysis and form a straight

line parallel to the X-axis, as seen in Fig. 12.

Fixing Step-Up Tests with Step-Down Data

There have been attempts to fix or remove the near-wellborefriction from these tests by using the step-down data to adjust

the pressures in the step-up data. The correction is simple andlogical. The bottomhole or calculated bottomhole step-down

pressure is plotted vs. injection rate. As previously discussed,

if there were no near-wellbore friction, all the points wouldfall on the X-axis. A best-fit line is drawn through the points,

and the excess friction at any given injection rate can then be

read directly from the graph. An example of the graphical

analysis of a step-down test with a best-fit line is shown inFig. 14. The excess friction would then be subtracted fromeach point in a step-up step-rate test. In theory, this idea to

correct the step-up test using step-down results seems

plausible and should provide improved results.

This method of repairing or fixing step-rate tests wasattempted in over 50 Middle East wells. In each case, the

correction appears excessive in the higher rate region, which

causes the fracturing line to have a negative slope. This would

indicate that net pressure is dropping, an indication that the

fracture is getting smaller with increasing rate. An example ofthis effect is shown in Fig. 15in which both the corrected and

uncorrected step-rate values from an actual test are plotted

Obviously, the fractures do not usually become smaller withincreasing rate. The most likely reason for this pressure

response is that the near-wellbore region has changed between

the step-up and step-down tests. Changing fracture geometry

from a test that exhibited too long, too short, or erroneous

friction pressure could also adversely affect this test.Taking an ISIP after each rate has been proposed as a

method to eliminate any friction effects, both near-wellbore

and tubular. As discussed, this method introduces its ownlimitations:

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 TestsBecause it appears that tortuosity and near-wellbore friction

are dependent on injection history, combining the results from

different injections would not appear to be a good idea. Fig

16shows an example in which a KCl water step-rate test and astep-down test from a minifrac are plotted together and appear

to provide useful data. In this instance, the well had very high

near-wellbore friction; as shown, the ISIP of the step-downtest is more than 1,000 psi below the fracture extension

pressure. This graph is made with bottomhole gauge pressure

Also, note the highly negative inclination of the step-down

test, which is another indication of near-wellbore friction. In

this case, a conservative propped-fracture treatment wassuccessfully placed, leading off with large early stages of low

proppant concentration to help erode or clean up the near

wellbore region.The authors do not have sufficient case histories to

determine whether combining different injections into a single

analysis would provide the most useful information to use asingle step-up and step-down for this analysis. The case

provided indicates that different injections can be used. High

near-wellbore friction, if present in one test and eliminated in

another test, could complicate the analysis.

Additional ExamplesA good case for use of the graphs presented is shown in Fig

17. In this case, the well was displaced from gas to water

broken down, a step-rate test was performed with both a stepup and step-down test, and the well was then treated with a

large acid-fracture treatment at rates of up to 70 bbl/min. A

second step-rate test was then pumped, and finally, the welwas treated with a closed-fracture acidizing treatment.11 The

second step-rate test was performed to compare results to the

first test and determine what effects the acid-fracture treatmen


5/17

SPE 98098 5

may have had on formation properties such as FEP and

closure. Determining closure pressure is important in these

wells because it is used to establish the injection rate of theclosed-fracture acidizing treatment.

The typical step-rate test analyses for the two tests are

shown in Figs. 18 and 19. These figures show how the tests

would be analyzed by simply drawing a best-fit line through

the matrix injection rates to obtain the matrix line, and thendoing the same after the breakover for the fracturing line. In

these analyses, no attempt was made to place the matrix linethrough the reservoir pressure at zero rate. If the reservoir

pressure was not known, this method would provide an upper

limit of about 8,000 psi. A FEP of 12,400 psi is obtained.

Notice in Fig. 19 that it is virtually impossible to determine

the FEP or whether the well was even fractured because it

appears that virtually all the points fall along the matrix line.Figs. 20 and21show the same two tests with the first line

or matrix line drawn through the reservoir pressure. In this

case, the pressure was known from offset well information. AFEP of 12,100 psi is observed, which would have lowered the

horsepower requirements for the acid-fracturing treatment. In

Fig. 20, the effect of even the small volume of fluid used tobreak down the formation can be seen from the first injection

points that fall above the matrix line. The analysis provides the

fracture extension rate of 6 bbl/min at this time. Extrapolating

the fracturing line gives a closure of ~11,100 psi.Once the matrix line in Fig. 21 is drawn through the

reservoir pressure, the analysis becomes clear. The effect of

the 110,000-gal acid fracture treatment is easily seen. The

graphical analysis of Fig. 21 gives a FEP of ~12,100 psi,exactly as observed in the pretreatment, step-rate analysis. The

fracture extension rate increased significantly to 48 bbl/min.

The closure, which is in good agreement with the prejob step-

rate test and the minifrac, is again 11,100 psi. Even with the

large amount of reactive fluids used in these tests, the closureand FEP remained virtually the same. The step-down test rates

fall off, indicating either near-wellbore friction or high fluid

leakoff. Because of the large acid-fracture treatment placed in

this well, it is most likely the result of high leakoff to thestimulated interval. Both step-rate tests were pumped using

only KCl water.The advantages of the step-up and step-down test

combined with correct analysis provides a wealth of

information about the formation and the effectiveness of the

stimulation treatment.

Conclusions

A plot has been developed that graphically demonstrates thequality of a step-rate test and diagnoses the presence of near-

wellbore friction. The use of this graph indicates when a step-rate test would need to be repeated because of an erroneous

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 a great

amount of information about the reservoir, including reservoir

pressure and closure pressure.Matrix lines should always be drawn through the reservoir

pressure, if known. If the reservoir pressure is not known,

extrapolation of the matrix line to zero rate will provide an

upper limit to the reservoir pressure.

Fracturing lines extrapolated to zero rate approximate the

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 of

injections performed at different times to make a graphical

analysis.

Most step-down tests are performed too slowly, allowing

fracture geometry and net pressure to change. A fracturesimulator can be used to model a treatment and provide limits

to stage lengths and rates.Trying to correct step-up, step-rate tests for near-wellbore

friction using step-down tests has not been successful.

While bottomhole pressure data is preferred, in most cases

valuable analysis was obtained from surface data. Good

friction 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 because the effects

of fluid leakoff and geometry change are limited. Howeverthe friction cannot be separated into its near-wellbore and

perforation components.

AcknowledgementsThe authors would like to thank the management of Saud

Aramco and Halliburton for permission to write this paper.

References1. Cipolla, C.L. and Wright, C.A.: Diagnostic Techniques

to Understand Hydraulic Fracturing: What? Why? and

How? SPE 75359, SPE Production and Facilities(February 2002), 2335.

2. Barree, R.D., Fisher, M.K. and Woodroof: A PracticaGuide to Hydraulic Fracture Diagnostic Technologies,

paper SPE 77442, presented at the 2002 SPE Annua

Technical Conference and Exhibition, San Antonio, TX29 Sept2 Oct.

3. Thompson, J.W. and Church, D.C.: Design, Executionand Evaluation of Minifracs in the Field: A PracticalApproach and Case Study, paper SPE 26034 presented a

the 1993 Western Regional Meeting, Anchorage, Alaska

2628 May.4. Nolte, K.G.: Fracture Design Considerations Based on

Pressure Analysis, paper SPE 10911 presented at the

1982 SPE Cotton Valley Symposium, Tyler, TX, 20 May.5. Felsenthal, M. and Ferrell, H.H.: Fracturing Gradient in

Waterfloods of Low-Permeability, Partially Depleted

Zones, Journal of Petroleum Technology, (June, 1971)

727-730.6. Felsenthal, M.: Step Rate Tests Define Safe Injection

Pressures in Floods, Oil and Gas Journal(Oct. 28, 1974)49-54.

7. Reservoir Stimulation,second edition, Economides, M.Jand Nolte, K.G., Prentice-Hall, Inc., Englewood Cliffs

New Jersey (1991).

8. Stewart, B.R., Mullen, M.E., Brown, J.E. and NormanW.D.: Step-Rate, Calibration Injection and TreatingPressure Anomalies in Soft Rock High Permeability

Formations: An Explanation Based on Bottom Hole

Pressure and Production Results, paper SPE 29444


6/17

6 SPE 98098

presented at the 1995 Production Operations Symposium,

Oklahoma City, Oklahoma, 24 April.

9. Wright, C.A.: On-Site Step-Down Analysis DiagnosesProblems and Improves Fracture Treatment Success,

Harts Petroleum Engineer International(January 1977).

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, paper

SPE 14654 presented at the 1986 East Texas Regional

Meeting, Tyler, TX, April 21-22.

Nomenclature

Pperf = perforation friction, psi

C = constant

Q = rate, bpmPtortuosity = tortuosity friction, psi


7/17

SPE 98098 7

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

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


8/17

8 SPE 98098

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

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


9/17

SPE 98098 9

Fig. 5Step-rate test analysis comparing surface vs. bottomhole gauge data.

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


10/17

10 SPE 98098

Fig. 7Second minifrac of the above well after reperforating. The 1,000-psi pressure drop in the bottomhole gauge pressure is remainingnear-wellbore or perforation friction.

Fig. 8Taking an ISIP at the end of each rate has been proposed as an alternative step-rate test to eliminate near-wellbore friction and theneed for bottomhole pressure gauges.


11/17

SPE 98098 11

Fig. 9Analysis of the step-rate test shown in Fig. 8, using the ISIPs for the analysis.

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


12/17

12 SPE 98098

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

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


13/17

SPE 98098 13

Fig. 13Example step-rate test where ISIP falls below fracture extension pressure due to tortuosity effects. Note how the extrapolatedfracturing line would indicate that the fracture closure is also above the ISIP.

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


14/17

14 SPE 98098

Fig. 15Step-rate test as shown in Fig. 13 with a corrected set of data points. When corrected for tortuosity, the bottomhole pressure fallswith increasing rate as seen in the fracturing line.

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


15/17

SPE 98098 15

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

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


16/17

16 SPE 98098

Fig. 19Initial analysis of second step-up and step-down test. Without placing the matrix line through the reservoir pressure, it appears thatthe zone did not fracture even at rates above 60 bbl/min.

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


17/17

SPE 98098 17

Fig. 21Revised analysis of second step-rate test using known reservoir pressure as first point in matrix injection rate line. Excellentagreement is now obtained between the fracture extension pressures in the pre- and post-treatment tests.

Documents

3_SPE-98098 Neww Analysis of SRIT for improved frac Stim Design.pdf