HYDRAULIC FRACTURE DIAGNOSTICS: RECENT ADVANCES ANDTHEIR IMPACT

ANALYSES DE LA FRACTURATION HYDRAULIQUE : PROGRESRECENTS ET LEUR IMPACT

Stephen L. WolhartGRI, United States

ABSTRACT

The use of hydraulic fracturing has grown tremendously since its introduction over 50 years ago.Most wells in low permeability reservoirs are not economic without hydraulic fracture stimulation.Hydraulic fracturing is also seeing increasing use in high permeability applications. The success ofthis technology can be attributed to the great strides made in three areas: hydraulic fracture theoryand modeling, improved surface and subsurface equipment and advanced fluid systems andproppants. However, industry still has limited capabilities when it comes to determining the geometryof the created hydraulic fracture. This limitation in turn places limits on the continued improvement ofhydraulic fracturing as a means to optimize productivity and recovery. GRIs Advanced HydraulicFracture Diagnostics Program has developed two new technologies, microseismic hydraulic fracturemapping and downhole tiltmeter hydraulic fracture mapping, to address this limitation. These twotechnologies have been utilized to improve field development and reduce hydraulic fracturing costs.This paper reviews these technologies and presents case histories of their use.

RESUME

Lusage du procd de fracturation hydraulique a pris normment dessor depuis son introduction il ya plus de 50 ans. La plupart des puits dans les gisements basse permabilit ne sont pas rentablessans une stimulation par fracturation hydraulique. La fracturation hydraulique connat galement unusage croissant dans les applications de haute permabilit. Le succs de cette technologie peut treattribu aux grands progrs accomplis dans trois domaines : la thorie et la reprsentation sousforme de modle de la fracturation hydraulique, lamlioration de lquipement de surface et desubsurface et les meilleurs moyens de soutnement et les micromulsions. Toutefois, lindustrie aencore des capacits limites quand il sagit de dterminer la forme gomtrique de la fracturationhydraulique cre. Cette limitation limite son tour lamlioration continue de la fracturationhydraulique comme moyen doptimiser la productivit et le rendement. Le programme avancdanalyses de la fracturation hydraulique institu par le GRI a dvelopp deux nouvelles technologies,ltude par microsismique de la fracturation hydraulique et le lev de la fracturation hydraulique laide dun inclinomtre de fond pour pallier cette limitation. Ces deux technologies ont servi amliorer le dveloppement des champs de gaz et rduire les cots de la fracturation hydraulique.Cet article examine ces technologies et prsente des tudes de cas de leur utilisation.

1. INTRODUCTION

The use of hydraulic fracturing has grown tremendously since its introduction over 50 yearsago. During 1997 industry invested more than $US 2,000,000,000 fracture stimulating gas and oilwells worldwide. This includes almost $US 1,300,000,000 spent fracturing approximately 30,000 wellsin North America. Most low permeability sandstone gas wells are not economic without hydraulicfracture stimulation. Hydraulic fracturing is also seeing increasing use in high permeability applicationsoffshore and for the disposal of drilling and other oilfield waste.

The success of this technology can be attributed to the great strides made by industry in threeareas: hydraulic fracture theory and modeling, improved surface and subsurface equipment, andadvanced fluid systems and proppants. However, the industry still has limited capabilities when itcomes to determining the geometry of the hydraulic fractures created during this process. Thisshortcoming in turn places limits on continued improvement of hydraulic fracturing as a means foroptimizing productivity and recovery.

GRI has focused recent research on developing methods to image hydraulic fracturegeometry through its Advanced Fracture Diagnostics Program This program has produced twofracture mapping technologies downhole tiltmeter mapping and microseismic mapping. This papersummarizes these new technologies presents cases histories of their use.

2. DIAGNOSTICS NEEDED TO OPTIMIZE COMPLEX PROCESS

Hydraulic fracturing is a complex process with complicated fluid systems, advancedproppants and sophisticated mechanical equipment, often applied in heterogeneous reservoirs.Further complicating this situation is the task of trying to optimize a process where one must useindirect measurements such as treating pressure or production data to estimate the results. Themodels and mechanisms for hydraulic fracturing are controversial and estimates of fracture geometryfor a given treatment can vary widely (Ref. 1). All these factors combine to make it difficult to optimizeindividual fracture treatments and therefore field development, in areas where hydraulic fracturing isan important part of production economics.

Fracture diagnostics can be very important in guiding well placement to avoid drillingunnecessary wells or leaving gas in place. Knowing the height, length and complexity of a hydraulicfracture are absolutely necessary to knowing if a reservoir is optimally developed. Figures 1a-eillustrate the importance of determining hydraulic fracture geometry. For example, one operator ineast Texas is evaluating whether to reduce the spacing on hydraulically fractured tight gas sand wellsfrom 80 acres to 40 acres. Credible knowledge about the length of the fractures and therefore thedrainage area of the existing wells is a key part of this decision. Reducing the spacing would requiredrilling 500-600 new wells at a total cost of $250 million, while not fully depleting the reservoir couldleave reserves unproduced and revenue unrealized.

Figure 1a. Importance of Knowing Fracture Azimuth

Figure 1b. Importance of Knowing Fracture Length

AssumedFrac

Azimuth

ActualFrac

Azimuth

Compartment Boundaries

Well Drainagewith Frac

UndrainedReservoir

Under Predict Frac Length - DrillUnnecessary Wells

Over Predict Frac Length - Leave Gas inPlace

Fracture MappingAllows Optimization ofField Development/Well

Spacing

Figure 1c. Fracture Length How much more length (more revenue) do I get for a bigger treatment (higher cost)?

Figure 1d. Fracture Height Does the frac cover the entire pay, or much more or less than that?

Unconfined Fracture Growth

Confined Fracture Growth

increase treatment size

Fractures TooSmall

Fractures Too Big Optimized FracDimensions

Figure 1e. Multiple Pay Zones Did my treatment stimulate all the pay zones?

3. HYDRAULIC FRACTURE DIAGNOSTICS: STATE OF THE ART

The list of current fracture diagnostic techniques is short (Table 1). The most commontechniques differ in the fracture attributes they measure, the certainty of the measurement andwhether they provide a far-field or simply a near-wellbore look at the fracture. Emerging technologiessuch as microseismic and downhole tiltmeter fracture mapping are shown along with moreconventional techniques such as surface tiltmeter, fracture modeling, tracers and production dataanalysis.

Technique Azimuth Height Length Width Asymmetry RangeProduction Data Anal. Far

Well Testing FarFracture Modeling FarTemperature Log Wellbore

RA Tracer WellboreTiltmeters (Surface) Far

Tiltmeters (Downhole) FarMicroseismic Far

- High Certainty - Low Certainty

Table 1: Hydraulic Fracture Diagnostic Techniques

While the mainstream techniques are valuable, they typically provide only a limited amount ofinformation on far-field fracture geometry (Ref. 2). Surface tiltmeters measure far-field fractureazimuth and dip with a high degree of certainty, however the mainstream techniques as a whole arenot as reliable for determining fracture length and height. For example, while fracture treatingpressure analysis and production data analysis are powerful tools for engineers optimizing frac jobs,

OR

Pay zones

they can have non-unique solutions and require experienced engineers who fully understand theirlimits. Radioactive tracers are useful in determining whether a zone took stimulation fluid, but theyprovide only a near wellbore look at fracture height. Microseismic and downhole tiltmeter mappingadd valuable new tools for optimizing field development and hydraulic fracturing.

4. ADVANCED HYDRAULIC FRACTURE DIAGNOSTICS

4.1 Technology Development

Developing the technology foundation for hydraulic fracture mapping has been the goal ofGRIs Advanced Fracture Diagnostics Program. This program was started in 1993 using the GRI/DOEM-Site as a field laboratory to study fracture diagnostics and hydraulic fracturing. What has emergedfrom the work done there by GRI and others are two technologies that show promise in measuring far-field fracture geometry: microseismic fracture mapping and downhole tiltmeter fracture mapping.

M-Site has served as a field laboratory where GRI could develop, test and verify advancedhydraulic fracture diagnostics and study hydraulic fracture mechanics and theory on a field scale (Ref.3). Jointly supported by GRI and the Department of Energy (DOE), M-Site was located at the formerMultiwell Experiment in the Piceance Basin, Colorado in the United States. The wells and theirassociated equipment were used to perform microseismic fracture mapping and downhole tiltmeterfracture mapping. Deviated wellbores were designed to intersect hydraulic fractures. Testing at M-Sitewas conducted from 1993 to 1996, and in addition to providing the foundation for emerging fracturemapping technologies, it also provided a number of surprising findings on fracture propagation andgrowth (Ref. 4), including:

1) Significant differences in fracture sizes as a result of fracture fluid system changes,2) Unexpectedly large residual deformation/width measurements for unpropped fractures,3) Multiple fracture strands and complex fracturing such as secondary and t-shaped fracs,4) Unexpected fracture containment not fully explained by in-situ stress differences,5) Evidence of complex proppant placement.

These findings should result in changes in how fracture treatments are designed andpumped. For example, injections at M-Site with simple, linear gels achieved longer fracture lengthsthan similar sized injections pumped with complex, crosslinked fluids. Also, there was evidence at M-Site of residual deformation, possibly indicating residual fracture width even without proppant. Therecent success of waterfracs in East Texas, wherein fracture treatments are pumped with treatedwater and very low proppant concentrations, may be proof of greater fracture lengths and residualwidth as indicated by M-Site results (Ref. 5).

4.2 Microseismic Hydraulic Fracture Mapping

Microseismic fracture mapping uses sensitive seismic sensors placed in an offset well todetect microseisms (micro earthquakes) generated during the treatment (Figure 2). The location ofthese microseisms is determined and used to create an image of the hydraulic fracture (Ref. 6). Forseveral years GRI efforts have been based on using multiple seismic receivers placed in a singleoffset well. The objective is to evaluate the data from the seismic sensors with automated processingmethods so fracture mapping can be done in real-time in the field. Sandia National Laboratories andothers are carrying out development of microseismic fracture mapping for GRI.

Figure 2. Microseismic Hydraulic Fracture Mapping

The formation is stressed during a hydraulic fracture treatment because of leakoff inducedpore pressure increases and due to net treating pressures. This stressing affects the stability ofplanes of weakness, such as bedding planes and natural fractures, in the formation near the hydraulicfracture. This leads to shear slippages which are similar to earthquakes along faults although withmuch lower amplitude. These shear slippages (microseisms) emit elastic waves which can bedetected by sensitive seismic receivers (accelerometers or geophones). The microseisms are locatedand result in maps of the created hydraulic fracture geometry (Figure 3).

Figure 3. Microseisms generated by shear slippages around the hydraulic fracture arelocated to generate a map of the fracture

DATAPROCESSING

DATAHANDLINGFiber-optic Wireline

5-Level, 3CTool String

FracWell

Fracture Map

MicroseismicEvent

4100

4200

4300

4400

4500-600 -400 -200 0 200 400 600

DISTANCE ALONG FRACTURE (ft)

DE

PT

H (

ft)

INJECTION 6CMWX-2

C SAND

0

100

200

300

400

500

600

-700 -500 -300 -100 100 300 500

WEST-EAST (ft)

SO

UT

H-N

OR

TH

(ft

)

INJECTION 6C

MWX-2

MWX-3

MONITOR WELL

91 m91 m 122 m 122 m

TIPREGION

LEAKOFFREGION

HYDRAULICFRACTURE

Plan View Side View

There are two methods to analyze microseismic data. The first uses seismic receiverslocated in several (two or more) offset wells. Events can then be located using triangulation as istypically done with earthquake analysis. However, the limited availability of several offset wells andthe cost of multiple wells and several receiver arrays hinders the practical use of the method. Thesecond method uses a vertical, multiple-array of receivers in a single offset well. The receivers arewidely spaced, up to 60 meters (200 feet) between each receiver, to provide a wide aperture arrayleading to improved accuracy. This method is more practical for routine field use. GRI has focusedon developing the second method. The current specifications for the microseismic array aresummarized in Table 2. An advanced array is under development with deployment by mid-2000. Sofar, GRI and Sandia have mapped almost 40 frac jobs in the United States and Mexico using theprototype array.

Prototype Array Advanced ArrayReceiver Levels 5 5Receiver Spacing Variable: 60 meters max (200 feet) Variable: 60 meters max (200 feet)Instruments Accelerometers AccelerometersOperating Depth 2100 meters (7,000 feet) 4550 meters (15,000 feet)Max. Temperature 1250 C (2600 F) 1500 C (3000 F)Max. Pressure 35 MPa (5,000 psi) 52.5 MPa(7,500 psi)

Table 2: Microsesimic Array - Specifications

4.3 Downhole Tiltmeter Hydraulic Fracture Mapping

Another new technology for hydraulic fracture mapping employs downhole tiltmeters (Ref. 7).As with microseismic monitoring, multiple instruments (tiltmeters in this case) are run on wireline in anoffset well to measure the earths tilt due to the hydraulic fracture (Figure 4). The mapping principle isquite simple: creating a hydraulic fracture involves parting the rock and deforming the reservoir.Downhole tiltmeter mapping involves measuring the fracture-induced deformation in offset well(s)versus time and depth (Ref. 8). A tiltmeter is a very sensitive carpenters level that can detect tiltsdown to one nanoradian. The data is inverted to obtain created fracture dimensions. Fracture height,length and width can be determined from analysis of this data. The principle is the same for surfacetiltmeter mapping, but the different array geometry makes downhole tilmteters very sensitive tofracture dimensions and less sensitive to fracture orientation just the opposite of surface tiltmeters.

First accomplished at M-Site with downhole tiltmeters cemented in an offset well, thetechnology is now being used to field a downhole tilt system that can be deployed on wireline.Development of downhole tiltmeter fracture mapping has been being carried out by PinnacleTechnologies. The current specifications for downhole tiltmeters are summarized in Table 3. So far,downhole tiltmeters have been used to map over 200 frac jobs. Downhole tilts have been deployed inseveral basins in the United States as well as Mexico and Canada. Development is underway toextend the capabilities of downhole tiltmeters to higher temperatures (up to 1650 C). Deployment inthe treatment well and in horizontal/deviated wells is also being investigated.

Downhole Tiltmeter ArrayElectronic Communication Single conductor or slickline# tiltmeters/array 6-15Maximum Temperature 1250 C (2600 F)Maximum Pressure 70 Mpa (10,000 psi)Tool O.D. 73mm (2.875 inch)Coupling to Wellbore Standard oil-field centralizersAnalysis Capability Real-timeLength & Height Resolution ~10% of offset well distance

Table 3: Downhole Tiltmeter Array - Specifications

Figure 4. Tilt field due to a hydraulic fracture

In the near future, both microseismic and downhole tiltmeter fracture mapping techniques will becapable of providing real-time measurements of fracture geometry. The next step is to integrate thesetechniques with hydraulic fracture models in real-time in order to exercise true process control overfracture treatments. This will allow the engineer to make decisions in the field to change rates, adjustfluid properties, change proppant schedules or adjust pad size in order to optimize the frac job while itis being pumped. Eventually, this control can be combined with an improved understanding ofhydraulic fracture mechanics to allow the engineer to control fracture geometry.

5. CASE HISTORIES

5.1 Cotton Valley Frac Imaging Project

Hydraulic fracture treatments using treated water and very low proppant concentrationsreferred to as waterfracs, have recently been successful in the East Texas Cotton Valley formation. Ina waterfrac the total fluid volume pumped is similar to that for a conventional sand frac but theproppant concentration is only 0.5 ppg but 5-8 ppg. Total proppant volumes are reduced 70% ormore. Exactly why this process works as well as the estimated long-term production from thesewaterfracs are topics of industry debate (Ref. 5). What is known is the significant cost savings (50% to70%) of waterfracs versus conventional sand fracs (Ref. 9). The Cotton Valley Fracture ImagingConsortium, a joint industry project has investigated this process. A combination of conventionalfracture diagnostics techniques (modeling, tracers, well testing and production data analysis) andhydraulic fracture mapping have been used to evaluate waterfracs and conventional fracturetreatments.

In the first phase of the project, led by Union Pacific Resources (UPR), conventional fracturetreatments were evaluated using microsesimic mapping, frac modeling, tracers and production dataanalysis (Ref. 10). In the second phase of the project, led by GRI, waterfracs were evaluated usingdownhole mapping, frac modeling, well testing, tracers and production logging. Field tests wereconducted in the three wells in Carthage Gas Unit in the East Texas Basin. Production in these wellsis from the Cotton Valley Formation, a low permeability sandstone. Overall, ten fracture treatments

we mapped and analyzed during this project. Some results are still confidential but the generalconclusions are summarized below:

1) Sand frac and waterfrac dimensions are roughly similar,2) Fracs were more contained (both types) than expected raising concerns about zonal coverage,3) Waterfrac and sand frac production is similar,4) Cost savings are 30% to 70%.

Other operators in the area have begun using waterfracs in the Cotton Valley Formation (Ref. 11)and they have also been used successfully in the Barnett Shale.

5.2 Mounds Drill Cuttings Injection Project

Another joint industry project managed by GRI is the Mounds Drill Cuttings Injection Project. Deepwell injection is becoming an attractive option for disposing of drill cuttings and other types of oilfieldwaste. Drilling waste injection has been implemented in the North Sea, Gulf of Mexico, North Slope ofAlaska and many other areas. Deep well injection can be more economical and environmentally saferthan transporting the waste to landfills and is potentially a significant new market for hydraulicfracturing technology. One of the most critical issues with waste injection, especially onshore, isensuring that the waste material is contained within a selected zone below protected drinking watersources. This issue is a major hurdle in obtaining injection permits from environmental regulatorybodies.

The Mounds Drill Cuttings Injection Project was aimed at providing an improved understanding ofdrill cuttings injection and hydraulic fracture mechanics and modeling. This project was conductedduring 1998-99 and included multiple injections of drill cuttings slurry which were monitored usingmicroseismic, surface tiltmeter and downhole tiltmeter mapping. Conventional methods includingfracture modeling and tracers were also applied. Finally, directional well were drilled to core throughthe created zone of hydraulic fractures. Figure 5 shows fracture maps for three consecutiveinjections. As can be seen, the mapping shows changing fracture azimuth and dimensions with eachinjection.

Figure 5. Mounds Project Injection 1

2400

2500

2600

2700

2800

2900

3000-400 -300 -200 -100 0 100 200 300 400

Xf, ft

Tiltmeter MappedFracture

Plan View(FractureAzimuth)

-100

-75

-50

-25

0

25

50

75

100

-200 -175 -150 -125 -100 -75 -50 -25 0 25 50 75 100 125 150 175 200

91 m 91 m

820 m

760 m

880 m

Figure 6. Mounds Project Injection 2

Figure 7. Mounds Project Injection 3

Detailed findings from the Mounds Project are available (Ref. 12), general findings aresummarized below:

1) Periodic injections resulted in complex, multiple fractures,2) Multiple-fracture concept is realistic for the multiple injection process,3) Frac dimensions are overestimated when use a single-fracture concept for the multiple injectionprocess,

2400

2500

2600

2700

2800

2900

3000

-400 -300 -200 -100 0 100 200 300 400Xf, ft

-100

-75

-50

-25

0

25

50

75

100

-200 -175 -150 -125 -100 -75 -50 -25 0 25 50 75 100 125 150 175 200

91 m 91 m

820 m

760 m

880 m

Injection 1

Injection 2

2400

2500

2600

2700

2800

2900

3000-400 -300 -200 -100 0 100 200 300 400

Xf, ft

-100

-75

-50

-25

0

25

50

75

100

-200 -175 -150 -125 -100 -75 -50 -25 0 25 50 75 100 125 150 175 200

Injection 3

91 m 91 m

820 m

760 m

880 m

4) Frac models when calibrated by frac mapping can be use to design/evaluate injections.

The results from the Mounds Project are being used by the consortium members to developrecommendations for the safe and efficient disposal of drilling waste.

5.3 Arcabuz-Culebra Project

In 1998, GRI worked with Pinnacle Technologies, GeoMechanics International and Branagan &Associates to help Pemex Exploration and Production study the Arcabuz-Culebra Field (Ref. 13). Theobjective was to improve hydraulic fracturing and field development in the Arcabuz-Culebra Field inMexico. The economic development of low permeability, over-pressured reservoirs such as thosefound in the Arcabuz-Culebra Field requires the efficient application of hydraulic fracturing andeffective well spacing and location. Production in Arcabuz-Culebra is from the same Wilcox sandsthat extend in South Texas and make up the prolific Wilcox/Lobo Trend.

Hydraulic fracture mapping was performed with tiltmeters (surface and downhole) andmicroseismic imaging. Fracture mapping was accompanied by 3-D fracture modeling andgeomechancial modeling. Hydraulic fracture mapping was performed in the southern part of the field(Culebra). Hydraulic fractures were mapped in one well (two frac jobs) using surface and downholetiltmeters. Hydraulic fractures were mapped in a second well (two frac jobs) using microseismicimaging. Fracture azimuth was determined in the northern part of the field (Arcabuz) based onanalysis of wellbore breakout data. Treating pressure and build-up test data were also analyzed.Results from the fracture mapping and fracture modeling are summarized in Table 4.

Well Prop

(Mlbs)

Stress

(psi/ft)

FractureGeometry from

Modeling

Avg.Prop.Conc.(lb/ft2)

FractureDirection from

Mapping

FracDipfromSTM

FractureGeometry from

Mapping

Lf(m)

Hf(m)

Lf(m)

Hf(m)

C88D-W4 300 0.62 216 35 2.3 N31oE W82o 250 40C88D-W3 230 0.89 241 142 0.7 N71oE S85o 250 150C644-W4 320 0.75 174 48 2.3 N18oE - 210 134C644-W2 250 0.87 91 199 1.0 N23oE - 180 134

Table 4: Summary of Results

The results of the study showed changing hydraulic fracture direction. Hydraulic fractures innorthern part of the field (Arcabuz) parallel the major adjacent faults. Hydraulic fractures in thesouthern part of the field (Culebra) generally followed the regional trend of the stress field. Wellspacing and location are controlled by the in-situ stress state (which controls fracture geometry anddirection), reservoir permeability, and the distribution and orientation of faults. Local variations in porepressure due to compartmentalization and/or offset well production can result in large variations instress that can significantly impact reservoir production, fracture geometry, and fracture direction.Changes in in-situ stress due to greater depletion in the northern part of the field probably caused thevariance in fracture azimuth.

Fracture mapping showed confined fracture growth for the Wilcox 4 and less confined growthin the Wilcox 2 and 3. This was also probably due to greater depletion in the Wilcox 4 leading toincreased stress contrast compared to bounding zones. The fracture model was calibrated based onthe results of the fracture mapping. Fracture engineering studies using this calibrated model indicatethat frac jobs could be optimized by reduced treatment size and changing to a lower strengthproppant. The study has determined the following:

1) Fracture geometry changed from one area of a field to another. This should be considered whenplanning well spacing and location. Production could be reduced by as much as 0.5 bcf due toineffective well placement.2) Re-fracturing potential may exist for some wells in Arcabuz-Culebra with the opportunity to increaseultimate recovery.3) Fracture treatments could be modified resulting in potential cost savings of up to $110,000 perfracture treatment.

6. CONCLUSIONSHydraulic fracture mapping with microseisms and downhole tiltmeters provides the petroleum

industry with tools that will allow engineers to evaluate the placement of hydraulic fractures. Theimpact of this capability on the economics of oil and gas production from resources where hydraulicfracturing is essential will be significant. The right combination of hydraulic fracture diagnostics canprovide answers to many questions important to optimizing field development and fracture treatments.In most applications the combination of several diagnostic techniques will result in a betterunderstanding of fracture behavior and more reliable conclusions as compared to using a singlediagnostic technique. The benefits to the petroleum industry of improved fracture diagnostics will bereflected in increased reserves and lower production costs.

7. ACKNOWLEDGEMENTSI would like to thank Pemex Exploration and Production, the Mounds Drill Cuttings Injection

Consortium and the Cotton Valley Frac Imaging Consortium for permission to publish information fromtheir projects. Thanks go to the many individuals working for Sandia National Laboratories, PinnacleTechnologies, Branagan & Associates and other companies that have contributed to the developmentof microseismic and downhole tiltmeter mapping technologies. Thanks to GRI, DOE and industry forsupporting the development of these technologies.

8. REFERENCES

1 - Warpinski, N.R., et al. (1994). Comparison Study of Hydraulic Fracturing Models - Test Case: GRIStaged Field Experiment No. 3. SPE Production and Facilities, February.

2 - Warpinski, N.R. (1996). Hydraulic Fracture Diagnostics. SPE Journal of Petroleum Technology,October

3 - Peterson, R.E., et at. (1996). Fracture Diagnostics Research at the GRI/DOE Multi-Site Project.SPE paper 36449 presented at the SPE Annual Technical Conference and Exhibition held in Denver,Colorado, October.

4 - Warpinski, N.R., et al. (1998). An Interpretation of M-Site Hydraulic Fracture Diagnostics Results.SPE paper 39950 presented at the SPE Rocky Mountain Regional/Low Permeability ReservoirsSymposium held in Denver, Colorado, April.

5 - Mayerhofer, M.J., et al. (1997). Proppants? We Dont Need No Proppants. SPE paper 38611presented at the SPE Annual Technical Conference and Exhibition held in San Antonio, Texas,October.

6 - Warpinski, N.R., et al. (1998). Mapping Hydraulic Fracture Growth and Geometry UsingMicroseismic Events Detected by a Wireline Retrievable Accelerometer Array. SPE 40114 presentedat the SPE Gas Technology Symposium held in Calgary, Alberta, Canada, March.

7 Warpinski, N.R., et al. (1999) Method and Apparatus for Monitoring Underground Fracturing.U.S. Patent No. 5,934,373.

8 - Wright, C.A., et at. (1998). Downhole Tiltmeter Mapping: Finally Measuring Hydraulic FractureDimensions. SPE 46194 presented at the SPE Western Regional Conference held in Bakersfield,California, May.

9 Mayerhofer, M.J. (1998). Waterfracs Results from 50 Cotton Valley Wells. SPE 49104presented at the SPE Annual Technical Conference and Exhibition held in New Orleans, Louisiana,September.

10 - Walker, R.A.. (1997). Cotton Valley Hydraulic Fracture Imaging Project. SPE paper 38577presented at the SPE Annual Technical Conference and Exhibition held in San Antonio, Texas,October.

11 Walker, R.A., et al. (1998). Proppants, We Still Dont Need No Proppants A Perspective ofSeveral Operators. SPE 49106 presented at the SPE Annual Technical Conference and Exhibitionheld in New Orleans, Louisiana, September.

12 GRI, et al. (1999). Mounds Drill Cuttings Injection Project. GRI-99/0173.

13 Wolhart, S.L., et al. (2000). Use of Hydraulic Fracture Diagnostics to Optimize Fracturing Jobs inthe Arcabuz-Culebra Field. SPE 60314 prepared for presentation at the SPE Rocky MountainRegional/Low Permeability Reservoirs Symposium held in Denver, Colorado, March.

HOMEWOC1 PRESENTATIONP-106 HYDRAULIC FRACTURE DIAGNOSTICS: RECENT ADVANCES AND THEIR IMPACTABSTRACTRESUME1.INTRODUCTION2.DIAGNOSTICS NEEDED TO OPTIMIZE COMPLEX PROCESS3.HYDRAULIC FRACTURE DIAGNOSTICS: STATE OF THE ART4.ADVANCED HYDRAULIC FRACTURE DIAGNOSTICS5.CASE HISTORIES6.CONCLUSIONS7.ACKNOWLEDGEMENTS8.REFERENCESHELPQUIT