SPE47247, Stress Measurement for Sand Control

Copyright 1998, Society of Petroleum Engineers, Inc.

This paper was prepared for presentation at the SPE/ISRM Eurock 98 held in Trondheim,Norway, 810 July 1998.

This paper was selected for presentation by an SPE Program Committee following review ofinformation contained in an abstract 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 an abstract of not more than 300words; illustrations may not be copied. The abstract must contain conspicuousacknowledgment 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.

AbstractProduction of sand from a reservoir is a well known problemin the oil industry. Classically, it is solved by a gravel-pack orfrac-and-pack type of completion. This approach, althoughresolving the sand production problem, has the importantdrawback of severely reducing the output of the completedwell. Recently, two types of completions have been proposedfor sanding prone reservoirs: slotted liners for horizontalwellbores and hydraulic fracturing without gravel packing invertical wellbores. These completions have a less negativeimpact on reservoir production, but require high quality dataacquisition to complete successfully. This paper focuses onhow a combination of sonic measurements and stress testscarried out with the micro-hydraulic fracturing techniqueenabled the design of a successful hydraulic fracturingtreatment for sand control offshore California.

Hydraulic fracturing specialists believe that a hydraulicfracture alone can successfully perform sand control if one hasproper knowledge of the stresses acting over the zone ofinterest. The direction of the maximum principal stress isneeded to ensure that all perforations are connected to thehydraulic fracture and therefore protected against sandproduction 1. Magnitudes of the minimum principal stress areneeded for the proper design of the hydraulic fracturing joband, in particular, to ensure proper placement of the proppantwhich will stop the produced sand from reaching the wellbore.

Such an approach was successfully applied to a sanding-prone turbidite sand-shale reservoir. Critical knowledge of thestresses was acquired by first determining the azimuth of thepreferred fracture plane from anisotropy processing of thesonic logs. This direction was validated from local knowledgeof the active fault system. It is recognized that stress

magnitudes are best measured with the micro-hydraulicfracturing technique2. Thus, a special cased hole program wasdesigned to measure the magnitude of the minimum principalstress with a wireline testing tool. Measurements wereobtained in the two reservoir sands and three bounding shalelayers. These measurements were then used to calibrate astress log obtained with the processing of a sonic log. Thisprovided a profile of minimum stress magnitudes along thezone of interest.

Analysis of the micro-hydraulic fracturing tests showedvery little stress contrast existed between the reservoir rockand the bounding layers. This gave the client an option todesign a single hydraulic fracturing treatment for the twolayers, more efficient that the two separate treatments initiallyproposed. The interpretation also confirmed from a hydraulicfracturing standpoint that the azimuth derived from acousticanisotropy was indeed that of the preferred fracturing plane.This allowed the client to orient the perforations withconfidence.

The unique combination of measurements described in thispaper enabled the client to design and successfully carry out ahydraulic fracturing treatment for sand control.

IntroductionCompletion methods that allow sand-prone reservoirs to beexploited often severely reduce production efficiency. Thus,the challenge is to complete wells to keep formation sand inplace without restricting productivity. The controlling factorsthat may create mechanical rock failure include the inherentrock strength, existing earth stresses, and stress created bydrilling, completion and or production. Once the formation hasmechanically failed, sand grains can be dislodged andtransported by the producing fluids. An aggravating factorincludes the influx of water, which reduces capillary pressureholding sand grains together 3.

Techniques employed to prevent sanding include: gravelpacking, slotted liners and prepacked screens, resin injection,and frac-and-pack completions. In the higher technologyschemes for sand control, slotted liners and prepacked screensare common for horizontal wells and frac-and-packcompletions have become prevalent for shorter completionintervals. The question remains, can hydraulic fracturing alonebe employed to prevent unconsolidated reservoirs from

SPE 47247

Stress Measurements for Sand ControlJ. Desroches, SPE, Schlumberger Dowell and T. E. Woods, SPE, Schlumberger Wireline and Testing

2 J. DESROCHES, T.E. WOODS SPE 47247

sanding? The temptative conclusion of this paper is yes, onceproper knowledge of stress values and their direction over thezone of interest are known whereby the perforations will beprotected from sanding by the propped fracture.

Currently, combinations of sonic, bulk density and porepressure data are used to generate a stress profile, and it isrecently accepted that this data must be calibrated to aphysical stress measurement such as a Data Frac. A recentalternative to measuring the minimum principal stress is withthe use of a wireline testing tool. This method presents severaladvantages which have been reported elsewhere4. This paperwill focus on the process of gathering and interpreting the highquality log data used to implement a fracturing treatment on areservoir that is prolific to sanding, with an emphasis ondetermining the crucial piece of information that is the state ofstress.

Background: the Wilmington field, Los Angeles, CAThe measurements described within have taken place in theoffshore Wilmington Field, Los Angeles, CA. TheWilmington Field, 4th largest in the Continental U.S., is alarge anticline consisting of 6 distinct reservoirs separated byseveral major faults. In 1965, four man-made islands wereconstructed in the Long Beach Harbor, which providesoperations of 1300 wells that have produced over 800 millionbbls of oil since inception. The operation is currently ownedby Arco and operated by THUMS.

The most prolific reservoir within the field is the RangerZone. The Ranger Zone is 220 feet thick and approximately3000 feet in depth. The reservoir is a turbidite sand-shalesequence that is finely laminated, sand stringers of 1 inch to 2inches in thickness are common. The Ranger has undergonewaterflooding for the past 30 years; therefore, resultantwatercuts of 90 % are normal, and the reservoir is alwaysprone to sanding. Permeabilities range from 100 to 1000mDarcy with an average porosity of 30 p.u. Recentcompletions have consisted of slotted liners for horizontalwells and conventional gravel packing on more verticalwellbores.

The goal of this case study was to perform the firsthydraulic fracture treatment in the Ranger Zone on a verticalwellbore utilizing open hole and cased hole data sets.

A wireline tool for stress measurementsVarious techniques have been proposed to measure the in-situstress5. The micro-hydraulic fracturing technique is, however,the best known technique to measure stresses at great depth5,although it can be used in conjunction with other methods foradded completeness. This technique uses the pressureresponse obtained during the initiation, the propagation andthe closure of a hydraulic fracture to determine the state ofstress.

Test procedure. It has been proposed that a modular wireline

testing tool with a downhole pump and a straddle-packerarrangement could be the ideal wireline candidate for a stresstool using the micro-hydraulic fracturing technique4.

The following procedure is used to carry a stress test. Theinterval to be tested is isolated with a straddle packerarrangement (Fig. 1). Fluid is then injected in the interval at aconstant flow rate. The wellbore is pressurized up to theinitiation of a tensile fracture. In open-hole, the fractureinitiates and propagates perpendicular to the direction of theminimum principal stress. The stress acting on the fracturesurface (closure stress) is therefore an estimate of theminimum principal stress acting on the tested formation. Afterthe initial breakdown which signals that a fracture wasinitiated, fluid injection continues until the pressure stabilizes.The injection is then stopped and the pressure allowed todecay. A schematic pressure response can be found in Fig. 2.A series of such injection/fall-off cycles follows to reopen,further propagate and close the fracture, allowing to bothcheck that the test is repeatable and possibly to change theinjection parameters (flow rate and injected volume). Once theoperator is satisfied that good quality data was acquired,packers are deflated and the tool is moved to the next interval.A typical test can take from 20 minutes to one and the halfhours, depending on the number of injection cycles that areperformed.

The current limitations of the tool are linked to theperformance of the packers (temperature and differentialpressure) and to the maximum flow rate that the pump candeliver. If clean fluid is used as the fracturing fluid, themaximum permeability of the formation to be tested is 50micro-Darcy. If drilling mud is used as the fracturing fluid, thepermeability range is controlled by the properties of the mudcake.

Interpretation methodology. A variety of techniques havebeen developed to estimate the magnitude of the minimumprincipal stress from the pressure record. The method used bythe authors consists in first separately analyzing eachhydraulic fracturing cycle, determining the followingquantities (if they exist): Breakdown Pressure, PropagationPressure, Instantaneous Shut-In Pressure (ISIP), ClosurePressure, Reopening Pressure and Rebound Pressure. This isfollowed by a ``reconciliation phase'' where all quantities forall cycles are considered together in order to determine themagnitude of the minimum stress. The process is illustrated byselected analyses of one of the stress tests reported here.

The breakdown pressure is the pressure at which thefracture is first created. It is not used to determine the value ofthe minimum stress but is recorded for quality controlpurposes. If the pressure during the propagation of the fractureis close to being flat, a propagation pressure is also recordedfor quality control purposes during the reconciliation phase.

The instantaneous shut-in pressure (ISIP), i.e. the pressurein the interval when pumping has just stopped, was often taken

SPE 47247 STRESS MEASUREMENTS FOR SAND CONTROL 3

as a good approximation of the stress acting on the fracture,especially when such low flow rates are used to propagate thefracture. An example of a hydraulic fracturing cycles with abreakdown, a propagation pressure and an ISIP is presented inFig. 3.

The closure pressure is the pressure at which the fractureclosed completely after shut-in. It is currently taken as themost accurate measure of the stress acting normal to thefracture surface6. In permeable formations, closure pressure ismeasured at the point at which the pressure during shut-indeviates from a linear dependence on the square root of theshut-in time (cf. typical analysis in Fig. 4).

The reopening pressure is the pressure at which apreexisting fracture opens up. It can be an upper or a lowerbound of the stress acting on the fracture7. This corresponds toa change in the stiffness of the tested interval. In low leak-offsituations, it is identified as the point at which the pressureduring pressurization deviates from a linear dependence on theinjected volume. A typical analysis is presented in Fig. 5.

During a flowback/pressure rebound test, fluid is quicklywithdrawn at the end of the fracture propagation in order toclose the fracture in the vicinity of the wellbore. The fractureis then allowed to produce back to the wellbore. If themaximum pressure attained during the rebound phase(rebound pressure) is above hydrostatic, it is a good qualityindicator that a fracture has indeed been created. Forimpermeable shales, the rebound pressure is the best estimateof the stress acting on the fracture8.

No single parameter (closure pressure, ISIP, etc...)determined on a single event is a good enough estimate for thestress acting normal to the fracture surface or closure stress.Once each event has been analyzed separately comes then thetask of interpreting the stress test record in its entirety todetermine the best possible estimate closure stress. Allestimates are plotted for every event along the time axis in aso-called ``reconciliation plot''. This is a new method whichhas, to the best knowledge of the authors, never been proposedanywhere in the literature. The underlying hypothesis is thatone tests a fracture which grows from one cycle to the next.This growth process may induce trends in the data but shouldalso ensure consistency from one event to the next. Inparticular, if no consistency is found over the entire record,one can question whether a fracture has really been opened,and hence doubt the validity of the test (or at least that of theinterpretation).

Another interest is to recognize possible outliers, i.e.events interpreted in such a way that the results do not makesense compared to the other events. When this is identified, itallows the user to go back and reinterpret that particular eventin a manner which is consistent with the rest of theinterpretation.

Finally, the reconciliation plot allows the user to quicklyidentify trends in the data. In particular, it allows the user toanswer whether the fracture has propagated far enough into

the formation to be mostly influenced by the far field stress.Indeed, when this is achieved, closure and reopening pressureshould show minimal variations from one cycle to the next.

Once the user is satisfied with the interpretation of eachevent in the light of the other events, the next step consists ofselecting a band where the closure stress is likely to be. This isachieved by graphically picking a lower and an upper boundfor that band. This band is representative of the confidence theuser has in the measurement. A value for the closure stress canthen be chosen within that band and taken as a measure of theminimum principal stress. A simple example is presented inFig. 6.

Cased hole stress tests.The formations in the zone of interest are mechanically weak:the sandstones are sanding prone, and the shales exhibit up to60% porosity on the logs. Such formations could neverwithstand the pressure exerted by the packers during stresstesting without failing and ensuring the tool string to staystuck in the wellbore. It was therefore decided to attemptstress testing in cased hole, which had never been done beforewith this tool.

Test procedure. A Cement Bond log was ran in the 7 inchcasing to evaluate the cement quality. Cement bondthroughout the interval was excellent. Subsequently, fivedepths were selected in the zone of interest which consists oftwo reservoir sands separated by a shale layer. Station 0 at3083 ft is located in the shale just below the bottom sand,Station 1 at 3027 ft in the bottom sand, Station 2 at 2962 ft inthe middle shale, Station 3 at 2934 ft in the top sand andStation 4 at 2856 ft in the cap shale just above the top sand.

If one wishes to measure the minimum principal stress bydetermining the closure stress from the methodology describedin the previous section, one needs to ensure that the fracture isperpendicular to the direction of the minimum principal stress.This condition is automatically satisfied in open-hole,provided the wellbore is close to being vertical. In a casedhole situation, however, the fracture will initiate at theperforation and closure pressure will reflect the stress normalto that direction (which has no reason to be equal to theminimum principal stress!). Two perforations, 180 degreesapart, were therefore shot for each station along the directionof the preferred fracturing plane N 54 E (as determined fromprocessing the sonic data for anisotropy). Note that, as thewellbore was vertical, a wireline gyro in conjunction withTCP services were used to shoot these perforations.

A new mud system (11.0 ppg consisting of water, KCl,barite and bentonite with a fluid loss characteristic of less than6 ml/30 min) was mixed prior to the test, so that it could beused as the fracturing fluid. This was dictated by the largepermeability of some of the formation to be tested (severalhundreds of milliDarcys).

Five stress tests were carried out, each comprising several


hydraulic fracturing cycles. For the sake of conciseness, onlythe salient points of the interpretation will be presented foreach station. In accordance with the methodology outline inthe previous subsection, not only was a value provided for theminimum principal stress, but also a lower and an upperbound.

Test interpretation

Station 0. This test, carried out in the bottom shale, clearlyshows that the tested formation is layered: there is evidence ofmultiple closure points with different amounts of leak-off. Inparticular, the first two cycles show no leak-off at all, whereasthe next three cycles show a non-negligible amount of leak-off. Fig. 7 shows the first hydraulic fracturing cycle: note howflat the pressure is after only 10 seconds after shut-in,indicating an impermeable formation. In contrast, the thirdhydraulic fracturing cycles is presented in Fig. 8 clearlyindicating a strong leak-off situation. The layer bearing thehighest stress is, however, dominating the overall pressureresponse.

Station 1. This test, carried out in a 400 mDarcy sand, didnot exhibit any breakdown. A clear closure can, however, bedetermined for the last hydraulic fracturing cycle (Fig. 9). Thepressure record, compared with those acquired at the otherstations, does not positively demonstrate the existence of afracture. Analyzing the shut-in part of the two injection cycleswith classical reservoir engineering techniques (Fig. 10)determined that a 2.5 ft fracture had been created after the firstcycle and a 5 ft fracture after the second injection cycle(whereas no match could be easily found without a fracture),which confirms that a fracture was indeed created during thistest.

Station 2. Three different layers, each bearing a differentminimum stress, can be identified for this test carried out inthe intermediate shale section. The first hydraulic fracturingcycle exhibits a single closure pressure. The hydraulic fracturethen breaks into a layer with a higher stress (resulting inmultiple closure and multiple reopening pressures) beforebreaking into a layer with a lower stress. The pressure recordof the third hydraulic fracturing cycle is presented in Fig. 11and closure pressure indicated for the three zones.

Station 3. This test, carried out in the top sand, showedvery consistent results from one cycle to the next. Results havetherefore been used to illustrate the section on interpretationmethodology. This consistency also demonstrates that thepresence of the wellbore has virtually no effect on the resultsor, alternatively, that the fractures created by this techniqueare big enough to sample the far field stress. Also note that, asa whole, no detrimental effect due to the perforations could bedetected for any of the stations.

Station 4. This test, carried out in the top shale, is the onlyone which shows a larger ``tensile strength'', i.e. a largedifference between the breakdown pressure and thepropagation pressure. This layer may therefore act as atoughness barrier. Apart from the first cycle, all estimates aregrouped in a narrow band (Fig. 12) which is characteristic ofan isotropic stress situation.

Test results. The final results are presented in Table 1. Asthree different layers were sensed during the testing of themiddle shale, three different values were reported for thatstation.

Using sonic logs, pore pressure and stressmeasurements to build a stress modelThe stress measurements can now be used in conjunction withother wireline measurements to build a model of thedistribution of the minimum principal stress versus depth inthe zone of interest. Ideally, this model can be used to designthe main hydraulic fracturing treatment. As for the casepresented here, it will be used to interpret the main hydraulicfracturing treatment.

Building a stress model from logs in order to get apredicted stress profile along the entire wellbore alwaysinvolves two steps: choosing a physical model that governs thebehavior of stresses versus depth and calibrating it againststress measurements9, 10, 11.

Choosing the stress model. The geological setting of the fieldleads to two possible choices as far as the physical modelgoverning the stress behavior: uniaxial (gravity) loading,typical of relaxed basins, or Mohr-Coulomb, typical of rockmasses at failure. A simple trend analysis showed that thebehavior of the stresses was influenced by n /(1- n ) (where n isthe Poisson's ratio of the material as measured by the soniclogs) and pore pressure only. No effect of Young's modulus orfriction angle could be found. The ratio n /(1- n ) ischaracteristic of gravity loading and led us to choose theuniaxial loading model.

The simplest expression for the gravity loading model is:

s

n

n

sh v* *

=

-1(1)

where s h* is the minimum horizontal stress, s

v

* is the

vertical stress and the star indicates effective stresses.The water flooding of the field for years induced an

increase of pore pressure in the sands. The thin layering of thesands is associated here with large contrasts of mobility withina single sand formation (defined here by not being interruptedby a shale layer). This results in large variations of porepressure within a single sand formation, as evidenced by thepore pressure measurements (Table 2). In turn, variations ofpore pressure induce a change in stresses that needs to be


taken into account in our model.

Calibrating the stress model. We shall consider thefollowing expressions for the vertical and minimum horizontalstresses. We shall consider that the vertical effective stress s

v

*

is simply proportional to the true vertical depth z by aconstant K to be determined:

s

*= K z (2)

Furthermore, we shall consider that there is a one to oneeffect of pore pressure P on the minimum horizontal stresss h , which translates into:

s sh h P*

= - ..(3)Although elasticity predicts a ratio of 0.4 to 0.8 for an infinitemedium, the thin horizontal layering of the formation inducesa geometrical effect which dictates a ratio close to 1.

Assuming that equation (1) holds to describe the state ofstress, the final expression chosen for the minimum horizontalstress as a function of depth is:

s

n

n

h K z P=-

+1

(4)

It was assumed that the pore pressure in the shale layers(Stations 0, 2 and 4) was equal to the virgin pore pressure. Anormal pore pressure gradient of 0.434 psi/ft was considered.Pore pressure in the sands (Stations 1 and 3, together with twolayers sensed by Station 2) was taken from the pore pressuremeasurements (Table 2).

It was also assumed that the difference between dynamicPoisson's ratio (as measured by the sonic logs) and the staticPoisson's ratio as needed per equation 3 is small enough to beneglected.

The only parameter to be adjusted is K . The best fit wasfound to be K =0.706 psi/ft. A comparison between thecomputed and the measured stresses can be found in Fig. 13.The maximum difference between computed and measuredvalues is found to be less than 50 psi. This is not only anoutstanding agreement but also validates our approach ofhaving a single parameter to calibrate with 7 measurements.

Note that no tectonic strain was found to be necessary todescribe the state of stress. This can be justified by the welllocation on the flat top of the anticline.

A log of stresses versus depth. One can now use thecalibrated stress model to obtain a log of minimum horizontalstress versus depth.

Six shale zones have been identified between 2800 and3150 ft. A layer was considered a zone to be a shale when thepetrophysical computation yielded a quartz fraction of lessthan 10 %. For these zones, the minimum horizontal stresswas computed following equation 3 assuming virgin porepressure. Results are plotted in Fig. 13 as a dotted line.

As for the sand zones, a value for the minimum horizontalstress was computed only where the current pore pressure wasknown. As the water flooding process induces large variationsof pore pressure within the same formation, no attempt wasmade to interpolate the pore pressure, as Table 2 does notshow any clear short scale correlation between pore pressureand mobility. Results are plotted in Fig. 13 as open circles,whereas the stress measurements are reported as crosses forreference. Following the results of the calibration, the value ofthe stresses should be accurate within 50 psi.

Analysis of the hydraulic fracturing treatmentThe stress measurements showed that very little stress contrastexisted between the two pay zones and the shale layer betweenthem: 2300 psi in the top sand, 2540 psi in the bottom sandand 2190 to 2490 psi in the shale in between. As the middleshale layer would not behave as a stress barrier, it was decidedto hydraulically stimulate the two reservoir layers with asingle treatment. A single 60 ft interval (between 2940 and3000 ft) was thus perforated. Curable resin proppant was used:once cured, the resin maintains the grains of sand together,forming a solid artificial sandstone which isolates theformation from all perforations linked to the hydraulicfracture. This proppant pack, although allowing fluid to flowwith little resistance, stops the formation sand to reach theperforation, and hence the production head. Perforations wereshot at a density of one shot per foot with 180o phasing,oriented N 54 E (the preferred hydraulic fracturing plane asfrom the sonic anisotropy) so as to have all perforations linkedto the hydraulic fracture and hence protected from producingformation sand.

Analysis of the data fracs. A series of three small injectioncycles above breakdown pressure (data-fracs) were performedprior to the main treatment. Analysis of the shut-in part similarto that carried out on the stress tests shows multiple closure ofthe fracture.

Three closure pressures can be determined for the firstcycle (Fig. 15): the fracture closes on a first layer at 2340 psi,then on a second layer at 2290 psi and finally on a third layerat 2170 psi. This is to be compared with the stressmeasurements of station 3 (at 2962 ft) which showed theexistence of three layers bearing a minimum stress of 2490,2300 and 2190 psi. Although the hydraulic parameters(injection rate and injected volume) were radically differentfor the stress test and the data frac, they both not only showthe existence of stress variations around 2960 ft but also yieldvery similar numbers. This cross-check is a powerful qualitycontrol for the stress measurements.

As the fracture size increases from the first to the secondcycle, analysis of the shut-in part of the second cycle yieldsonly two closure instances of the fracture at 2380 and 2330 psirespectively, whereas the third cycle -where the fracture isbiggest- possibly yields a single value for the closure pressure


of around 2230 psi. The fracture has grown enough at the endof the third pumping cycle so that the measured closurepressure now corresponds to an average of the closure stressacting on the various layers that surround the fracture.

Analysis of the main treatment. The main treatment wasdesigned with a constant stress acting on all layers of interest.14,000 gallons of linear gel (40 lbs/1000 gallons of guar) werepumped at 30 bbls/min, placing a total of 60,000 lbs of 20/40mesh curable resin coated proppant. Radioactive tracer sandwas pumped with the proppant in order to measure fractureheight growth after the treatment.

Only surface pressure was available. Bottom hole pressurewas compute, accounting for fluid friction in the tubing and inthe perforations. The pressure in the fracture never exceeded2600 psi whereas the pressure at the crack mouth at the end ofthe treatment was only 2250 psi (Fig. 16).

Examining the stress log (Fig. 14) shows that the predictedminimum stress is above 2600 psi below 3002 ft, sometimessignificantly: waterflooding resulted in the sand layer between3000 and 3024 ft to be supercharged and act as a stress barrier.According to the stress log, the pressure never reached a highenough value to enable the fracture to grow down. This iseasily checked by observing the azimuthal gamma ray log runafter the treatment (Fig. 17). It clearly demonstrates that, inthe vicinity of the wellbore, most of the proppant was placedbetween 2960 and 3010 ft. The fracture grew only 10 ft belowthe perforated interval.

The predicted minimum stress above the perforationinterval lies between 2100 and 2400 psi, clearly allowing thefracture to grow above the perforated zone. The top of thesand layer at 2900 ft is supercharged and bears a predictedstress of 2400 psi, which is above the crack mouth pressure atthe end of the treatment. It can therefore act as a stress barrier,stopping fracture height growth. Indeed, the azimuthal gammaray log shows that the fracture grew upwards and stoppedgrowing at 2900 ft. It is concluded from these observations:the main hydraulic fracturing treatment behaves according tothe proposed stress model.

How successful was the treatment? The well was put on-line and showed some initial solidsproduction (2-6 % during the first 2 weeks)12, but very little oilrate decline with no solids produced afterwards. No sample ofthe produced solids was taken, and no production log was run.It is therefore difficult to judge whether this is standardproppant flowback, which may happen even with resin curedproppant, or if some perforations were not adequately linkedto the hydraulic fracture, allowing some formation sand toflow into the wellbore.

Although the single fracture treatment did not encompass90 feet of the best pay below the perforated interval, themethod used proved to be a viable alternative for sand control.A more aggressive design based on the stress model presented

in this paper could consist of two treatments with a tipscreenout, one for the top sand and one for the bottom sand,ensuring proper packing of all the perforations and adequateheight coverage of the producing layers. In addition, theresults of this well have proven significantly better than thehorizontal well that was simultaneously completed with aslotted liner throughout the same interval.

On the use of sonic logs for profiling stressesThe experience gathered from the analysis of the datapresented in this paper clearly demonstrates the need for directstress measurements to adequately select the model which willbe used to predict the stresses versus depth in conjunction witha log of elastic properties. It also shows that a singleparameter, the gradient of vertical effective stress, can be usedto accurately calibrate the resulting stress log rather thanresorting to a multiplicity of correlations.

The orientation obtained by processing of the sonic datafor anisotropy corresponds to that of the far-field principalstresses. This is supported by the stress test data as follows.The direction of the perforations was that indicated by theshear wave anisotropy. If it had not been that of the preferredhydraulic fracturing plane, the created hydraulic fractureswould have turned to gradually reorient themselves parallel tothe direction of the preferred fracturing plane. In the process,the closure stress would have decreased as the fracture turns,which is a trend easily picked up by the reconciliation plot.This was not observed in any of the stress tests. On a verydifferent scale, this direction corresponds with the direction ofthe major fracture set affecting the field. The geologicalsetting (offshore Southern California) justifies that the stressfield orientation indicated by the major fractures is current.

The absence of any tectonic effect in the stress model,itself validated by the analysis of the main hydraulicstimulation, implies a low contrast of current horizontalstresses. The sizable amount of anisotropy still observed onthe sonic log (between 8 and 12 % based on the timedifference) can, however, be explained by the fact that theeffect of stress on sonic wave propagation tends to beexaggerated in weaker rocks.

ConclusionsThe main conclusion of the case study presented here showsthat a successful fracture treatment for sand control can beperformed without a screen, but requires the series ofmeasurements reported here to comprehend the stresses actingwithin the zone of interest.

Because of both the thin layering of the formation and itspoor mechanical strength, acquiring the stress magnitudes byany other means than using the micro-hydraulic fracturingtechnique in a cased hole situation would not have allowed usto adequately profile the stresses as a function of depth,jeopardizing the entire stimulation program. Indeed, theconvenience of performing a stress test in cased hole cannot


be overlooked. The advantages seen in this case were:controlling borehole fluid loss in order to test highpermeability formations, large fractures could be opened forgood data repeatability without the concern of fractureextension beyond span of packers, workover rig rates areinexpensive, and no tool damage was seen or expected.

Finally, extensive interpretation of all the data has allowedus to build a simple but very accurate stress model whichshould be easily applicable to another well placed at the top ofthe same structure. It would not require another series of stresstests to be used. Pore pressure measurement would, however,be necessary. Indeed, the stress data revealed that, in this area,pore pressure has a major influence on the minimum stress. Inparticular, the overpressured sands, contrary to conventionalwisdom, are acting as stress barriers.

AcknowledgementsThe authors would like to thank Dick Plumb, Tom Plona, andMarc Thiercelin with Schlumberger, Carl Montgomery withArco and Eric Upchurch with THUMS for useful discussions.

References1. Fletcher, P.A., C. Montgomery and G.G. Ramos, `Òptimizing

Hydraulic Fracture Length to Prevent Formation Failure in Oiland Gas Reservoirs'', Proceedings of the 35th U.S. Symposiumon Rock Mechanics, 293-298, Balkema, 1995.

2. Haimson, B., ``The Hydraulic Fracturing Method of StressMeasurement: Theory and Practice'', in J. Hudson (editor),Comprehensive Rock Engineering, Chapter 14, Pergamon Press,1993.

3. Davies, D.R., C.J. Kenter, A.P. Kooijman and C.A.M Veeken,Sand Production Prediction Review: Developing an IntegratedApproach, SPE paper 22792, Proceedings of the 66t h SPEAnnual Technical Conference, Dallas, TX, 1991.

4. Thiercelin, M., R.A. Plumb, J. Desroches, P.W. Bixenman, J.K.Jonas and W.R. Davie, `À New Wireline Tool for In-SituStress Measurements'', SPE Formation Evaluation, 19-25,March 1996.

5. Cornet, F.H., ``Stresses in Rocks and Rock Masses'', inComprehensive Rock Engineering, J. Hudson Ed., 3, 297-328,1994.

6. Nolte, K.G., Fracture Design Considerations Based on PressureAnalysis, SPE Paper 10911 presented at the 1982 SPE CottonValley Symposium of the SPE, Tyler, May 20, 1982.

7. Desroches, J., ``Stress Testing with the Micro-HydraulicFracturing Technique: Focus on Fracture Reopening'', 35th U.S.Symposium on Rock Mechanics, 4-7 June 1995, Lake Tahoe,NE, USA, 217-224, 1995.

8. Thiercelin, M., J. Desroches, A. Kurkjian, `Òpen Hole StressTests in Shales'', SPE 28144, SPE/ISRM Conference on Rock

Mechanics in Petroleum Engineering, Eurock'94, Delft, TheNetherlands, 29-31 August 1994, pp. 921-928, 1994.

9. Stage Field Experiment nb 2, Edited by CER Corporation andS.A. Holditch Associates, Gas Research Institute, Volume 1,Report GRI-89/0140, 1989.

10. Ahmed, U., M.E. Markely, S.F. Crary and O. Liu, `ÈnhancedIn-Situ Stress Profiling Using Microfrac, Core and Sonic LogData'', SPE paper 19004, Proceedings of the joint SPE RockyMountain Regional and Low-Permeability ReservoirsSymposium, Denver, Colorado, March 1989.

11. Thiercelin, M. and R.A. Plumb, `À Core Based Prediction ofLithologic Stress Contrasts in East Texas Formations'', SPEpaper 21847, Proceedings of the joint SPE Rocky MountainRegional Meeting and Low-Permeability ReservoirsSymposium, Denver, Colorado, April 15-17, 1991.

12. Upchurch, E.R., C.T. Montgomery, B.H. Berman and E.L. Rael,A Systematic Approach to Developing Engineering Data forFracturing Poorly Consolidated Formations, SPE paper 38588,Proceedings of the 72nd SPE Annual Technical Conference,San Antonio, TX, 1997.

SI Metric Conversion Factorscp x 1.0* E-03 = Pa . sft x 3.048* E-01 = m

md x 9.869 233 E-04 = m m2psi x 6.894 757 E+00 = kPa

*Conversion factor is exact.

Station Depth Lower Bound Upper Bound Selected Value(ft) (psi) (psi) (psi)

0 3083 2080 2460 24001 3027 2420 2546 25402 2962 2150 2206 21902 2962 2263 2380 23002 2962 2454 2495 24903 2934 2273 2300 23004 2856 2377 2500 2400Table 1: Minimum principal stress values from the micro-hydraulic fracturing tests.

Zone Mobility Pore Pressure Zone Mobility Pore PressuremD/cp psi mD/cp psi

1 124 1329 5 2 14002 188 1127 6 150 12832 370 6 416 12903 126 1167 6 404 12674 250 1238 6 150 14474 130 1257 6 33 13935 170 1235 6 19 14005 208 1311 7 140 1346

Table 2: Pore Pressure and Mobility data.


Fig. 1 A wireline testing tool as a stress tool.

Fig. 2 Pressure response obtained during hydraulic fracturing.

Fig. 3 First hydraulic fracturing cycle at 2934 ft.

Fig. 4 Shut-in analysis of the first hydraulic fracturing cycle at2934 ft.

Fig. 5 Reopening analysis of the third hydraulic fracturing cycleat 2934 ft.

Fig. 6 Reconciliation plot for the stress test at 2934 ft.


Fig. 7 First hydraulic fracturing cycle for Station 0.

Fig. 8 Third hydraulic fracturing cycle for Station 0.

Fig. 9 Shut-in analysis of the second hydraulic fracturing cycleof Station 1.

Fig. 10 Transient analysis of the shut-in part of the secondhydraulic fracturing cycle of Station 1.

Fig. 11 Third hydraulic fracturing cycle for Station 2.

Fig. 12 Reconciliation plot for Station 4.


Fig. 13 Comparison between predicted and measured minimumhorizontal stress.

Fig. 14 Predicted minimum horizontal stress versus depth.

Fig. 15 Shut-in analysis of the first data frac injection cycle.

Fig. 16 Reconstructed bottom hole pressure during mainhydraulic fracturing treatment.

Fig. 17 Azimuthal Gamma-Ray Log acquired after the mainstimulation treatment. A Gamma-Ray image (SPPL and GMAP) isunwrapped on tracks 2 and 3.

Documents

SPE47247, Stress Measurement for Sand Control