Water Frac Provide Cost Effective Means

Copyright 2000, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the 2000 SPE/AAPG Western Regional Meetingheld in Long Beach, California, 1923 June 2000.

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.

AbstractThe low production rates of high viscosity crudes associatedwith wells in the Kern County California area lead todifficulty in achieving production enhancement through cost-effective well stimulation practices. The tight economics alsolead to difficulty in finding a stimulation technique that can beeffectively applied to injection wells associated with thesesame fields. Following the successful application of water-fracturing to increase the injectivity of a water injector well inthe Edison Field, water-fracturing was introduced to the TejonOil Field near Bakersfield California in hopes of providingstimulation to an oil well. Previous gel fracs in the Tejon OilField proved to be uneconomical due to high treatment costsassociated with increased equipment requirements, combinedwith poor results.

This paper describes how a small-scale water-fractreatment provided productivity improvements from 6 bopd toinitial rates of 30 - 50 bopd and sustained rates exceeding 20bopd for one well in the Tejon Oil Field. Comparison isprovided of the water-frac well performance over its first yearof production to a gel-frac in the same well, and two offsetopenhole completions (one gravel packed and one non-gravelpacked). The surface pumping equipment requirements for atreatment of this type are described, as are the procedures usedto obtain a successful treatment. The paper concludes with adiscussion of the geologic conditions that likely led to thesuccessful result achieved here, and suggests otherapplications where this technique should be attempted.

IntroductionThe Tejon Oil Field, located in the southern San JoaquinValley of California, is a mature field characterized by lowproduction rates of relative heavy crude. The reservoirconsists of multiple sands, which are produced independently.Average reservoir permeability is in the 100 150 md range,and the reservoir fluid consists of 18.9 API oil with aproduced GOR of approximately 100 SCF/bbl. Typicallywells in this field will experience initial productivity ofapproximately 25 30 bopd, and drop off to about 5 bopdafter a few months of production. Previously wells have beencompleted as both non-gravel packed and gravel packed eitherin open or cased holes.

In hopes of improving productivity of this field, hydraulicfracturing was attempted. Because of the elevated fracturegradient in this area, the hydraulic fracture treatment failed tobreakdown the formation. Therefore, very little proppant wasplaced in the formation. The result of this failed treatmentwas that the well productivity saw no improvement.

To remedy this situation, the fracturing process was furtherinvestigated and it was determined that the amount ofadditional surface pumping equipment to successfully fracturethis formation would be cost-prohibitive. For this reason, analternative was sought.

At about this time, the results of a previously performedwater-frac treatment on an injector well were brought toStockdales attention. This injector well had been fracturedusing brine about a year earlier. The water injector, completedin what has been described as a granite wash, saw injectivityincreases of 400 to 500 percent following the water-frac. Thiswell performance, coupled with the minimal amount ofsurface pumping equipment required for a water-fractreatment, led Stockdale to attempt a water-frac on the TejonOil Field well.

The treated zone was completed approximately 200 feetuphole from the gel frac treatment. The water-frac treatmentwas successful at not only fracturing the formation, but alsogenerating a fracture on the order of 25 30 feet in length.This fracture length, which was significantly greater than thetypical lengths of 5 to 10 feet associated with water-fractreatments in relatively high permeability formations, was

SPE 62521

Water-Fracs Provide Cost-Effective Well Stimulation Alternative in San Joaquin ValleyWellsStephen P. Mathis* (Baker Oil Tools), Gary Brierley, Kurt Sickles* (Stockdale Oil & Gas), and Don Nelson* (Hunter Trust),Rick Thorness (Baker Oil Tools)* SPE Member

2 MATHIS, BRIERLEY, SICKLES, NELSON, AND THORNESS SPE 62521

caused by improved fluid efficiency associated with the high-viscosity reservoir fluid. The resulting productivity increasebrought the well from being virtually non-productive (6 bopd),up to an initial rate of 30 50 bopd and sustained rates of 20 25 bopd for the first year. The fact that these rates arecontinuing to hold demonstrates the applicability of thisapproach.

Overview of the Water-Fracturing ProcessOver the past five years, water-fracturing techniques havebeen showing increased application in both hard, very lowpermeability formations, and soft high-permeabilityformations.Low-Permeability Applications:In 1995, Union Pacific Resources (UPR) pumped its firstwater-frac treatment in the low permeability (0.001 0.01 md)Cotton Valley formation of East Texas1,2. These treatmentswere likely better termed slick-water fracs in that light gelloadings were used (10 20 lbs./Mgal); however, sometimesonly a friction reducer was added for both the pad and slurrystages. For either case, the fracturing fluid viscosity and theproppant loading was much lower than the standard cross-linked gel fracture treatments previously used in that area.

These treatments consisted of 50% pad followed by aslurry of 0.5 ppa proppant, and gradually ramping proppant to2 ppa either in the last 5% of the job or over the entire slurrystage. Typically these jobs involved pumping less than halfthe proppant as compared to gel fracs, but total fluid volumewas often increased to yield increased fracture length1. Thenet result of these treatments were described as the water-fracwells exhibiting productivities very similar to the standardfractures at a cost of 50 80% less than a standardtreatment1,2. Similar results were also obtained from Pennzoil,Amoco,Valence Operating, and Mitchell Energy in the sameregion3.

The very low permeability of these formations does notseem to be applicable to fracturing with a low-viscosity carrierfluid. However, it is hypothesized1 that the reason for thegood performance of the water-fracs in these applications isthe fact that low viscosity fluid will tend to create fracturesthat are longer and narrower than those created with viscousfluids. Coupled with this, since fracture faces are not smooth,they can tend to be self-propping, especially in hard rock.This mechanism combined with very low reservoirpermeabilities leads to high dimensionless conductivity evenwith low proppant volumes. Another mechanism creditedwith good productivity is the fact that water-fracs will nothave the same level of proppant pack damage as do gel fracs.The reduced damaged will help to further increase theconductivity of water-fracs.High-Permeability Applications:During the same time period that UPR was developing water-frac technology for hard-rock applications in East Texas, thistechnique was also being applied in the frac-pack applicationsin unconsolidated formations worldwide. In soft formations,water-fracs are used in conjunction with a gravel pack toprovide bypass of near-wellbore formation damage, as well as

control of formation sand production. In this applicationwater-fracs consist of a non-viscosified pad (with a volume of50 100 gal/ft of perforations), followed by a slurry of 1 2ppa (pounds of proppant added per gallon of fluid) sandconcentration (also in a non-viscosified brine). These jobs aresized to generate a net pressure increase between 1,000 and2,000 psi, and place between 100 and 200 lbs. of proppant perfoot of zone.

In high-permeability applications, low-viscosity carrierfluids produce significantly shorter fractures than do gel fracs.The reason for the reduced frac length is the much higherleakoff (reflecting a lower fluid efficiency). However, sincethe purpose of these treatments is damage bypass, fracturelength is of minor importance. Rather, it is important to createsignificant near-wellbore fracture width. Generating a tip-screenout is key to creating significant fracture width. Sincetip-screenouts are induced by bridging proppant near theextremity of the fracture, the narrow fracture, and low fluidefficiency, associated with low viscosity carrier fluids isbeneficial. Once the proppant has bridged the tip of thefracture, additional proppant injection into the fracture mustincrease fracture volume by increasing fracture width. Whilethe improved proppant carrying capability of viscous fluidswill create higher insitu proppant concentration than water (8 12 lbs./sq.ft. for gel as compared to 4 6 lbs.sq.ft for water),field data indicate that the fracture created in a water-fracoperation is more than sufficient to bypass near-wellboreformation damage4,5,6,7. The main drawback to the slightlyreduced near-wellbore proppant concentration is the increasedlikelihood of having higher non-darcy skin in high-rate wells8.However, in moderate to low-rate completions this should notbe an issue.

Previous Completions at Tejon Oil FieldAs previously mentioned, the Tejon Oil Field is a mature oilfield near Bakersfield California in the southern San JoaquinValley. Stockdale Oil & Gas took over ownership of this fieldin 1993. The field currently is being produced from 3 of theoriginal wells, 5 still remaining idle. The original fielddevelopment consisted of cased and perforated completions.These wells all suffered with poor results due to sanding. Thefield consists of multiple horizons, we are dealing here withthe Reserve Sand from a depth of 4600 to 4950 feet TVD.These sands can be described as a series of stacked marinechannel sands, average permeability of 100 to 150 md, abottomhole temperature of 140 F, and a current reservoirpressure of approximately 1500 psi. This gross interval of 350feet exhibits approximately 100 feet of net thickness made upof individual 10 to 20 feet thick sand lobes.

When this field still had virgin reservoir pressure, theoriginal completions came on line at rates of approximately100 bopd. However, these wells all sanded up within the first30 60 days. Later completions typically exhibit initialproductivities ranging from 25 30 BOPD and then droppingto about 5 BOPD after a few months.

An attempt was made to improve this productivity byhydraulically fracturing an interval from 4895 - 4923 in Well

SPE 62521 WATER-FRACS PROVIDE COST-EFFECTIVE WELL STIMULATION ALTERNATIVE IN SAN JOAQUIN VALLEY WELLS 3

# 104. This treatment was planned to consist of pumping1,500 gal of 25-lb/1000 gal linear gel minifrac. This was to befollowed by 1,500 gal pad of cross-linked gel followed by4,800 gal of cross-linked gel carrying 30,000 lbs. of proppantat concentration ramped from 2 ppa 10 ppa. The pump rateplanned for this treatment was 12 bpm at 4000 psi. Uponinitial injection, the pressure approached 3600 psi (thewellhead limit) at a pump rate of only 6 bpm. Therefore thewell could not be fractured. The treatment was pumped at thisreduced rate, with the result being only 7500 lbs. of proppantbeing placed outside of the casing.

This failed fracture treatment also lead to unacceptableproductivity with a production rate of 6 bopd being achievedafter the treatment. Another attempt to fracture this well wasconsidered, but the increased equipment cost that would berequired could not be justified.

Injector Well TreatmentAbout 6 months prior to the gel frac in the Tejon Oil Field,Hunter Trust performed a water-frac treatment on a waterinjection well in the Edison field (also near BakersfieldCalifornia). Prior to performing the water-frac treatmentitself, a step-rate test was performed to determine bottomholefrac pressure and rate. Figure 1 illustrates the results of thistest. These results indicate that this formation could indeed befractured with brine, with a fracture initiation rate ofapproximately 3.5 bpm and a bottomhole fracture initiationpressure of 2200 psi.

The main treatment was performed by pumping down adedicated frac string, and consisted of a 20 bbl pad followedby slurry stages starting at 0.5 ppa and ramping up to 2 ppa.Pump rate for this treatment was 8 bpm, with the carrier fluidbeing lease water. Total sand pumped was 6000 lbs., with5771 lbs. being placed behind casing. With the perforationslocated from 2532 2572 ft, this equates to 144 lb./ft. Themaximum hydraulic horsepower required was 392 HHP, sothis treatment was easily performed with a single 600 HHPpump. Following the water-frac treatment, the excess gravelwas washed from the casing, the slotted liner assembly wasrun, and a circulating water-pack was performed.

Figure 2 illustrates the injectivity improvement thatresulted from the water frac treatment on this well (Well 5A).However, this plot does not tell the complete story. While theabsolute injectivity rates did quadruple as a result of thistreatment, it appears that this well still had less injectivity thanthe offset wells. To accurately assess this treatment, intervallength must also be considered. Since all three of these wellshave different open intervals (40 feet for Well 5A, 191 feet forWell 6, and 140 feet for Well 34), it is more meaningful tonormalize the injection rates based upon open interval. Thisadjustment has been made to Figure 3, which indicates that thewater-frac treatment brought Well 5A up to the level of one ofthe best injectors in the field.

Water-Frac at Tejon Oil FieldBased partially on the results from the performance of theinjector well described above, and partially on a desire to

stimulate the productivity of Well #104, Stockdale Oil & Gasdecided to attempt a water-frac treatment. The zone selectedfor recompletion was located from 4636 4682 feet TVD, theprevious gel frac on this well was performed from 4895 4923 feet TVD. The general completion procedure involved:

1. Reperforate lower zone from 4916 4924 (8 spf) and4890 4904 (12 spf).

2. Isolate @ about 4710 ft with wireline set retrievablebridge plug.

3. Perforate upper zone from 4672 4682 feet and 4636 4646 feet using 8 spf big hole (3/4 inch entry hole)guns.

4. Perform water-frac on upper zone using 2 7/8 inchfrac string and service packer.

5. Clean out to bridge plug and retrieve.6. Cleanout to TD7. Run gravel pack assembly, with 4.5-inch 12-gauge

wire-wrapped screen across perforations and 12-gaugesemi-slotted pipe between zones.

8. Pump circulating gravel pack.9. Return well to production.

This treatment was initiated by pumping a step-rate test toinsure that this formation could be fractured with brine.Figure 4 illustrates the results of this test which clearly show afracture was initiated at about 3 bpm and at a bottomholepressure of approximately 4519 psi (which corresponded toabout 3200 psi surface treating pressure). These results arequite interesting in light of the fact that the formation did notappear to fracture when a gel fluid was used and surfacepressures exceeded 3600 psi at 6 bpm. The reasons for thiscan be hypothesized as being:

1. The higher leakoff of the brine caused this fluid to act as apenetrating fluid which has been shown to lowerbreakdown pressure9.

2. The greater viscosity of the viscous fluid could have ledto higher pressure drop down the 2-7/8 inch tubing (evenwith the friction reducing nature of most gels).

Whatever the reason for the reduced surface breakdownpressure, the net result was that the formation was fracturedwith brine. This result can also provide some additionalinsight concerning the condition of the formation prior to thetreatment. Examination of Figure 5 (which represents theresults of Darcy Law calculations to estimate fracturing rate)indicates that for the fracture gradient determined through thestep-rate test, this interval would only have to have a skin of+5 prior to the fracture treatment to allow this 20 foot thickinterval be fractured with brine at 3 bpm. This implies that themeasured fracturing rate is about as expected.

With the fracturing pressures and rates established, themain water-frac treatment was pumped. The surface datarecorded during this treatment (as well as the calculatedbottomhole treating pressures) are shown in Figure 6. Thistreatment involved pumping a 34 bbl pad of 3% KCl followedby 127 bbls of 2.5 ppa slurry of 20-40 gravel pack sand in 3%


KCl into the fracture. The entire treatment was pumped atapproximately 8 bpm. This treatment resulted in 11,900 lbs.of gravel being placed behind pipe (approximately 300 lbs./ft).

The first step in analyzing this treatment was to determinefracture closure pressure and fluid efficiency. Figures 7 & 8are the Square-Root of Time Plot and the G-Function plot forthe pressure decline portion of the step-rate test. Theseanalyses agree that the closure pressure can be estimated to beabout 4080 psi. In addition, these analyses both yield a fluidefficiency of approximately 0.3 to 0.35. While this efficiencymay seem to be high for brine, the high viscosity of thereservoir fluid provides significant leakoff control.

With the actual pumping schedule determined, and aclosure stress estimated, a history match of the water-frac canbe accomplished. Figure 9 is a plot of the final Net Pressurematch, and Figures 10 & 11 are the corresponding fracturecross-section and insitu proppant concentration plots. Theseplots indicate an excellent net pressure match corresponding toa fracture length of approximately 30 ft and an averageproppant concentration of 3 lbs./sq.ft. The extended fracturelength is directly related to the relatively low leakoffcoefficient to achieve this match (0.0165 ft/min). Thisleakoff coefficient is very close to the theoretically calculatedvalue (0.0167 ft/min) based upon a 150 md formation, 18.9API oil with a GOR of 100 SCF/bbl, 140 F reservoirtemperature, and a 1 cP fracturing fluid. In addition, thisleakoff coefficient results in a fluid efficiency of 0.32, whichis in excellent agreement with the value derived from thepressure decline analysis. Based on all of this corroboratingevidence, a high level of confidence can be placed in thesesimulation results.

Resulting Well ProductivityFigure 12 illustrates the productivity of this well prior to andfollowing the gel frac as well as following this water-fractreatment. The significant improvement in productivityresulting from the water-frac treatment is evident. The benefitfrom this completion technique can also be highlighted whenoffset well performance from a slotted liner completion (non-gravel packed) is considered (Figure 13). This well showsinitial production rates in the range of 10 to 20 bopd, and thendropping to 5 to 8 bopd. This productivity curve is verytypical for this field. However, another offset openhole gravelpack completion is experiencing a sustained productivity ofapproximately 35 bopd. This implies that while waterfracturing may be a valid approach for cased-hole completionsin this environment, correctly performed openhole gravelpacks may provide even better productivity.

Equipment RequirementsIn addition to the productivity increases obtained with theapplication of water fracturing treatments in the San JoaquinValley, the overall success of this work was also related to thereduced equipment requirements as compared to a large-scalegel frac. The gel frac on the lower interval in this well wasplanned to be executed by pumping a 2,000 gal prepad,

followed by an 8,000 gal fracture treatment with a cross-linked gel, which was displaced by 1,300 gals of 25 lb/1000gal linear gel. The job entailed pumping 30,000 lbs of sand atconcentrations up to 10 ppa and rates of 12 bpm which was torequire 2 pumps, a frac blender, and a Mountain MoverSand system.

The water frac treatment required slightly more fluid (atotal of approximately 14,100 gals of 3% KCl for thepretreatment testing and the pumping treatment discussedherein). However, the job involved pumping only 14,000 lbsof sand at concentration up to 2 ppa. This required the use offive 3,000 lb. Super-Sacks of sand, and a High-Rate GravelINFUSER. In addition, because the treatment was pumped at8 bpm, only about 700 HHP was required. This was suppliedby two standard gravel pack pumps.

Applications for Water-FracturingAs stated previously, water fracturing has been successfullyapplied in both high-permeability unconsolidated formationsand in somewhat lower permeability formations in east Texas.When treating formations with permeabilities in the range ofhundreds of millidarcies, water tends to be an inefficientfracturing fluid that creates a fracture with a length of 5 10feet. In these situations, improved well performance isobtained by providing a highly conductive flow path throughthe near-wellbore damaged zone. However, when treatingformations containing high-viscosity crudes, the naturalleakoff control provided by the reservoir fluids cause the fluidefficiency to significantly increase. The result as shown inthis evaluation is a longer fracture that is better able tostimulate the reservoir.

In general, water-frac treatments can perform on par withgel fracs as long as excessive frac height is not desired, andwhere relatively low flow rates do not impose significant non-darcy flow effects. Since neither of these conditions existedhere, it is clear that water fracturing was a viable option. Thefact that the non-viscosified fluid is better able to penetrate thepores of this formation, led to lower breakdown pressures, andallowed the fracture treatment to be completed withoutexceeding surface pressure limitations.

Based on these results, it can be implied that water-fracturing is very applicable for cased-hole sand controlcompletions in other high permeability formations containingrelatively high-viscosity (17 20 API) crudes. However, ifthe wells are not to be cased, it is likely better to seek toprevent formation damage by employing proper drill-in anddisplacement techniques. With the need for damage bypasseliminated, the wells can be more successfully completed withopen hole circulating water packs.

ConclusionsThe use of water fracturing has been demonstrated to be aneconomic sand control option for use in the both producingand injecting wells in the heavy-oil regions of SouthernCalifornia. The ability to accurately design and modeltreatments of this type has been demonstrated, as have largeimprovements in well performance. Injectivity increases of


400 to 500 percent were observed when this technique wasapplied to a water injector well, and similar increases inproductivity were observed following a water fracturetreatment in a producing well. The increase in productivitywas achievable in a well where a previous attempt at a large-scale gel frac failed. Further proof of the success of thistechnique is that these levels of productivity and injectivityincreases have been maintained for over a year. In the past,any increase in productivity has been very short-lived.

However, even with the success of this technique in thecased hole environment, good performance in an offset openhole gravel pack completion indicates that for new wells bothopen hole gravel packs and cased-hole water fracs should beconsidered. If openhole gravel packs are selected, appropriatemeasures to insure a non-damaged wellbore (i.e., use of aproperly designed drill-in fluid to drill the reservoir section aswell as the use of proper hole cleaning techniques prior torunning the liner assembly) should be incorporated formaximum well performance.

AcknowledgmentsThe authors would like to first thank the management ofStockdale Oil & Gas, Hunter Trust and Baker Oil Tools forpermission to publish this paper. In addition, we would like tothank all of the field operations and technical supportpersonnel of all three organizations that helped to make thisproject a success.

References1. Mayerhofer, M.J., Richardson, M.F., Walker, R.N., Meehan,

D.N., Oehler, M.W., and Browning, R.R. Jr., Proppants? WeDont Need No Proppants, SPE 38611, 1997 SPE AnnualTechnical Conference and Exhibition, San Antonio TX, 5-8October 1997.

2. Mayerhofer, M.J., and Meehan, D.N., Waterfracs Results from50 Cotton Valley Wells, SPE 49104, 1998 SPE AnnualTechnical Conference and Exhibition, New Orleans, LA, 27-30September 1998.

3. Walker, R.N., Hunter, J.L., Brake, A.C., Fagin, P.A., andSteinberger, N., Proppants, We Still Dont Need No Proppants A Perspective of Several Operators, SPE 49106, 1998 SPEAnnual Technical Conference and Exhibition, New Orleans, LA,27-30 September 1998.

4. Mathis, S.P., and Saucier, R.J., Water-Fracturing vs. Frac-Packing: Well Performance Comparison and Completion TypeSelection Criteria, SPE 38593, 1997 SPE Annual TechnicalConference and Exhibition, San Antonio TX, 5-8 October 1997.

5. Patel, Y.K., Troncoso, J.C., Saucier, R.J., and Credeur, D., "HighRate Pre-Packing Using Non-Viscous Carrier Fluid Results inHigher Production Rates in South Pass Block 61 Field", SPEPaper 28531, 69th Annual Technical Conference and Exhibition,New Orleans, Louisiana, September 25-28, 1994.

6. Barrilleaux, M.F., Ratterman, E.E., and Penberthy, W.L. Jr.,Gravel Pack Procedures for Productivity and Longevity, SPE31089, 1996 SPE Formation Damage Control Symposium,Lafayette LA., 14-15 February 1996.

7. Claiborne E.B., Saucier, R.J., and Wilkinson, T.W., Water FracApplications in High Island 384 Field, SPE 36459, 1996 SPEAnnual Technical Conference and Exhibition, Denver CO., 6-9October 1996.

8. Powell, K.R., Hathcock, R.L., Mullen, M.E., Norman, W.D.,Baycroft, P.D., Productivity Performance Comparisons ofHigh-Rate Water Pack and Frac-Pack Completion Techniques,SPE 38592, 1997 SPE Annual Technical Conference andExhibition, San Antonio TX, 5-8 October 1997.

9. Howard, G.C. and Fast, C.R., Hydraulic Fracturing, SPEMonograph Volume 2, 1970, p. 21.

SI Metric Conversion Factorsft x 3.048* E-01 = min. x 2.54* E+00=cmlbm x 4.535924 E-01=kgpsi x 6.894757 E+00=kPabpd/psi x 2.305916 E-02=m3/day/kPabopd x 1.589873 E-01=m3/day

* Conversion factor is exact


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Figure 4: Step-Rate Test Results for Tejon Oil Field Well


DARCY'S RADIAL FLOW EQUATIONQ = [k x h x delta P] / [24 x 60 x 141.2 x Bo x u x (ln(re/rw)+S)]

delta P = Frac. pressure - reservoir pressureK = permeabilityh = formation thicknessB = formation volume factor of injected fluid (1 for water)u = viscosity of injected fluid (1 cp for water)re/rw = ratio of drainge radius radius to well radius, assume ln(re/rw)=8

BHP psi 1300TVD feet 4636Water Depth feet 0k md 150h feet 20B unitless 1.05 cp 1

unitless (0.25 if unknown) 0.28

ln(re/rw) unitless 7.87Skin unitless 5Frac. Grad. psi/ft 0.96 Known Frac Gradient 0.96Frac. Press. psi 4451 0 if unknownDelta P psi 3151Q to Frac. bpm 3.44

50 100 150 200 250 300 350md md md md md md md

Frac. Rate Frac. Rate Frac. Rate Frac. Rate Frac. Rate Frac. Rate Frac. RateThickness BPM BPM BPM BPM BPM BPM BPM

10 ft 0.61 1.22 1.83 2.44 3.04 3.65 4.2620 ft 1.22 2.44 3.65 4.87 6.09 7.31 8.5230 ft 1.83 3.65 5.48 7.31 9.13 10.96 12.7840 ft 2.44 4.87 7.31 9.74 12.18 14.61 17.0550 ft 3.04 6.09 9.13 12.18 15.22 18.26 21.3160 ft 3.65 7.31 10.96 14.61 18.26 21.92 25.5770 ft 4.26 8.52 12.78 17.05 21.31 25.57 29.8380 ft 4.87 9.74 14.61 19.48 24.35 29.22 34.09

Frac. Inj. Rate vs. Permeability For Varying Formation Thicknesses

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Figure 5: Fracturing Rate Estimation for Zone to be Treated by Water-Fracturing.


Figure 6: Surface Data From Water-Frac Treatment.

Figure 7: Square-Root of Time Plot of Pressure Decline Following SRT.


Figure 8: G-Function Plot of Pressure Decline Following SRT.

Figure 9: Net Pressure Match of Water-Frac Treatment.


Figure 10: Calculated Fracture Cross-Section.

Figure 11: Calculated Insitu Proppant Concentation Profile.


Average Daily Oil Production

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Figure 12: Productivity Increase Observed Following Water-Frac Treatment

Figure 13: Performance Plot From Offset Well - Slotted Liner Non-Gravel Packed Completion

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Water Frac Provide Cost Effective Means