ceramic membranes for wastewater

8/13/2019 Ceramic Membranes for Wastewater

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Copyright 2002, SPE ITOHOS/ICHWT conference.

This paper was prepared for presentation at the SPE International Thermal Operationsand Heavy Oil Symposium and International Horizontal Well Technology Conference heldin Calgary, Alberta, Canada, 47 November 2002.

This paper was selected for presentation by an SPE ITOHOS/ICHWT Program Committeefollowing review of information contained in an abstract submitted by t he author(s). Contents ofthe paper, as presented, have not been reviewed by the Society of Petroleum Engineers, thePetroleum Society of CIM/CHOA and are subject to correction by the author(s). The material,as presented, does not necessarily reflect any position of the Society of Petroleum Engineers,the Petroleum Society of CIM/CHOA, its officers, or members. Papers presented at SPEITOHOS/ICHWT meetings are subject to publication review by Editorial Committees of theSociety of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of

this paper for commercial purposes without the written consent of the Society of PetroleumEngineers is prohibited. Permission to reproduce in print is restricted to an abstract of not morethan 300 words; 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.

Abstract Nexen Petroleum International Ltd. (Nexen) has a 52 percentinterest and is operator of the Masila Block in the Republic ofYemen. Oil and water are produced mainly from the under

pressured Qishn Formation, a non-marine to marine clasticsequence of Lower Cretaceous Age, which is roughly 200 feetthick and lies at a depth of 5500 feet from surface. Currentlyoil production is 230,000 BOPD at a water cut of about 80

percent. The one million barrels of water produced each day

are currently reinjected under matrix injection pressures into24 vertical and 4 horizontal wells. These are completed in the

best quality sands (the S2/S3 members of the Upper QishnFormation) that have average porosity and permeability of20% and 3700 md, respectively.

Despite the exceptional disposal reservoir quality, injection problems continue to exist that have caused Nexen to studyand evaluate numerous methods of improving injectivity.After extensive laboratory core and field testing, hypotheseshave been developed to explain the behaviour of the waterdisposal wells including the so-called check-valve effect.Horizontal wells and proppant fractured wells were employed

to test the hypotheses and to improve injectivity.

This paper reviews the laboratory results and discusses the placement of horizontal injectors along with the drilling andcompletion details of the wells. The performance of thehorizontal disposal wells under matrix injection is comparedto conventional vertical disposal wells and proppant fracturedvertical wells. Produced water is expected to reach 1.5MMBWPD and improvements in disposal well performance

will reduce the number of wells that will need to be drilled tohandle this volume, thereby improving overall project value.

IntroductionThe Masila Block in the Republic of Yemen is operated by

Nexen Petroleum International Ltd. on behalf of its partnersOccidental Petroleum Ltd., Consolidated ContractorsCompany S.A.L. and the Government of the Republic ofYemen. Oil production from the block began in 1993 and

current field oil, gas and water production rates average230,000 BOPD, 7 MMSCFD and 1,000,000 BWPD. Figure 1shows the location of the block and Figure 2 shows thelocation of the 15 main producing fields, the central

processing facility (CPF) and the hydrocyclone installations atmain producing fields. These hydrocyclones are used toachieve initial separation of oil from water at the individual

pools remote from the CPF. The operation of the Masila project is described in an earlier paper with particular attention paid to disposal of produced water 1.

The majority of oil produced to date has been from the UpperQishn Formation, which is supported by a strong natural water

drive. Other producing horizons include the Lower QishnClastics, Upper Saar clastics, Saar carbonate, Madbilimestone, Basal sand and the fractured granitic Basement(Figure 3). Most produced water is currently reinjected intothe S3 and S2 members of the Upper Qishn Formation, and itis therefore worthwhile to review the geology of these 2members.

The S3, at the base of the Upper Qishn Formation, is anamalgamated fluvial channel sequence. As such, it appears onlogs to be a blanket sand, with little apparent variation insand or reservoir quality laterally or vertically. Data from theFMI tool shows that the paleoflow direction during S3 timewas generally from the west to the east. As such, permeabilityanisotropies should be anticipated along this axis. The S3comprises very clean quartz arenite, medium to coarse grainedsand, with little shale volume until the top 5 to 10 feet, whereshale volume typically increases slightly. The unit is 30 to 70feet thick, with an average thickness of 50 feet across theHeijah Field. The average NTG ratio in the S3 is 90%. TheS3 has the best reservoir characteristics of any of the

producing units at Heijah, with a median porosity permeabilityof 20.5% and 1900 mD respectively. The data are from wells

SPE/Petroleum Society of CIM/CHOA Paper Number 79007

Horizontal Water Disposal Well Performancein a High Porosity and Permeability ReservoirT. G. Harding, /Nexen Petroleum International Ltd., K. H Smith/Canadian Nexen Petroleum Yemen Ltd., B. Norris/ Nexen

Petroleum International Ltd.


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2 HARDING, SMITH & NORRIS SPE/Petroleum Society of CIM/CHOA 2002-79007

Heijah 1 to Heijah 17, after porosity and permeability cutoffsare applied (porosity greater than 10%; permeability greaterthan 10 mD).

Overlying the S3, the S2 is a fluvial sequence that ischaracterized by a more classic fining upward sequence onlogs. It comprises a series of identifiable channels, stacked

upward, but with poorer and poorer quality rock upwardstratigraphically, composed of small individual fining upwardcycles often only one or two feet thick. Thin shales can capthese cycles. The base of these cycles can begin with a scoursurface and channel lag deposit offering some of the cleanest,coarsest-grained and highest permeability rock in the section.In contrast to the S3, the S2 contains fine grained (e.g. mud)coastal plain sediments. The top of the S2 completely shalesout, with little sand present. As with the S3, FMI data indicatethat these channels were flowing from the west to the east.Fine to coarse grained quartz arenite is the dominant facies.More shale is present within the S2 compared with the S3, andmore marine influence can be seen in the core compared to theS3. The S2 varies from 40 to 100 feet gross thickness, andaverages 73 feet thick across the Heijah Field. The average

NTG in the S2 is 70%. After porosity and permeabilitycutoffs are applied (porosity greater than 10%; permeabilitygreater than 10 mD), the median porosity and permeability ofthe S2 sands is 19.4% and 1150 mD respectively (data fromwells Heijah 1 to Heijah 17).

Although porosity is generally consistent, there are significantvariations in permeability caused by differences in grain size,sorting and fines content. Injectivity can be reduced in somewells due to calcite partly occluding pore space and by the

presence of residual hydrocarbon. These materials are oftenfound at or just below the oil-water contact.

Injection BehaviourProduced water re-injection into the Upper Qishn sands has

been characterized by much lower injectivity than expected.There are two ways in which injectivity losses manifestthemselves.

The first type of injectivity loss is expressed as a substantialreduction of Injectivity Index compared to Productivity Indexupon completion of the well. This instantaneous loss isreferred to as the Check Valve Effect. Based on productivitymeasured during pump tests conducted immediately afterdrilling and completion of a disposal well, injectivity obtained

upon commencement of water injection is typically at least anorder of magnitude less than the measured productivity. TheCheck Valve Effect is thought to be caused by fines migrationand/or stresses created as a result of the perforation process.

The second type of injectivity problem is expressed as agradual decline in injectivity over time related to the volumeand quality of water injected. This long-term decline is aresult of solid particles found in the disposal water that resultin formation plugging. Laboratory results show that the

disposal water in the Masila Block contains calcite, quartz aswell as metal sulphides. This particulate matter is thought to

be caused by a combination of solids and oil carryover and the precipitation of calcite scale. Similar injectivity problems have been reported by others in the literature 2.

Filtration Systems

Nominal 10 micron cartridge filters are used within the MasilaBlock. These cartridges are placed in pot filters that hold 113individual cartridge filters. The cartridge filters have aneffeciency rating of 70%, meaning that 30% of all particlesthat pass through these filters are larger than 10 microns.Assuming a solid matter concentration of 5ppm, the fluidthroughput for a filter pot containing 113 cartridge filtersshould be in the range of 100,000 bbls of water. Lastly, thedesign specifications of the filter pots and cartridges call for awater throughput rate of no more than 35,000 bwpd.

Masila disposal water was analyzed to obtain the particulatematter size distribution (Figure 4), plotted against the filter

performance curve. The solids in the disposal water arecomposed mainly of iron sulphide corrosion products fromcorrosion of the surface lines and formation particulates

produced with the fluids from the wells. Treatments areconducted bi-monthly using a series of biocides to controlcorrosion in the surface piping. Concentrations of solids andoil in disposal water both average about 15 ppm.

It is important to understand this size distribution relative tothe pore throat distribution of the rock matrix that is beinginjected into. In brief, if particles are less than 1/7 the porethroat diameter, then little to no damage can be expected. If

particles are to 1/7 the pore throat diameter, deep damageoccurs. If particles are to equal to pore throat diameters,then sandface plugging results. Sandface damage can betreated readily, as it occurs at the wellbore. However, deepdamage is very difficult to correct, as it causes damage faraway from the wellbore and is therefore difficult to access.Further, the higher the permeabilty of the formation, thedeeper the particles travel into the formation away from thewellbore. It is the near wellbore damage that will have themost significant effect on injectivity.

The performance curves of the PX10 filters have been plottedwith the grain size distribution of the particulate mattercontained in the Masila disposal water (Figure 5), and thedifferent types of damage particle ranges are indicated. It can

be seen that considerable deep damage material (1/7 to porethroat diamter particulate matter) is passing through the filters,assuming that the filters are being operated within their designlimits. Under ideal conditions, it would appear that thesefilters would remove most of the sandface plugging material.It is a common practice in Masila to perform regular acidtreatments (a mixture of toluene and hydrochloric acid), whichoften has an immediate benefit of reducing wellhead pressuresand increasing injection rates. This strongly suggests sandface

plugging by acid soluble particulate matter. However, it is less


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79007 HORIZONTAL WATER DISPOSAL WELL PERFORMANCE IN A HIGH POROSITY AND PERMEABILITY RESERVOIR 3

likely that continued acid treatment can access the deepdamage material.

Ideal operating conditions for these filter pots do not existwithin the Masila Block, primarily due to the extremely highrates of injection that are achieved in the disposal wells(20,000 to 90,000 bwpd). Operationally, it is difficult to

perform the cartridge filter changes as required since eachfilter change takes a couple of hours to perform. For example,if a disposal well is taking 60,000 bwpd, two filter pots arerequired, and each filter pot should be changed every threedays. The only way around this operational reality would beto use a very different type of filtration system (e.g. a high rateabsolute filter system that would be extremely costly) or tofind another method to reduce damage and maintain highinjection rates. Field trials of more stringent wellhead filtrationwere also conducted but it proved impractical at the injectionrates typical of individual wells to filter to a smaller particlesize. Trials using 5 and 10 micron absolute filtration resultedin too frequent plugging of the filters to be operationallyfeasible.

Alternate Drilling and Stimulation OptionsThe majority of water disposal wells are vertical, cased and

perforated under-balanced. As part of an on-going effort toimprove injection capacity of the disposal wells, field trialsinvolving 4 horizontal water disposal wells and 4 proppedhydraulic fracture vertical disposal wells were conducted. Itwas hypothesized that both the horizontal and propped fracvertical wells would suffer less from injectivity loss due tofines migration by increasing near well bore area for fluidflow and thus reducing fluid velocity. It was also expected thatthe mean time between stimulation treatments would beincreased because of the larger rock surface exposed toinjected fluid and therefore the rate of plugging and injectivitydecline would be less than in vertical wells. The use ofhorizontal wells for productivity enhancement is well knownand while still somewhat rare, horizontal injection wells have

been proposed and implemented in a wide variety ofapplications 3-7. The technology of hydraulic fracturing of high

permeability formations is quite advanced and there is muchexperience from which to draw 8-15 .

The drilling, completion and operation of horizontal wells and propped fracture wells are presented and the performance ofthese wells is compared to unfractured vertical water disposalwells. These field trials are part of an on-going program to

enhance the water disposal capacity of the Masila operationand to develop a disposal system with sustainable capability of1.5 MMBWPD. It is imperative that the produced waterdisposal system operates efficiently in order to keep costs lowand to allow maximum oil production as field water-cutincreases.

Horizontal Drilling ProgramDesign parameters for the wells included the following:

Provide 500 to 1000 ft. of open hole section withinthe Qishn S3 reservoir.

Drill the horizontal leg along a north-south axis(perpendicular to channel flow direction) to intersectas many S3 channels as possible, rather than tracking

parallel to a single channel Provide 200-500 ft. of cased hole section in the

disposal zone to be perforated later as a back up toopen hole section if it plugged or collapsed.

The multidisciplinary asset team wanted to minimize the potential for drilling mud, fines or cuttings plugging the sandmatrix pore throats. After eliminating drilling mud orcompletion fluid chemicals as options, air drilling was chosenfor the open hole section. However, under balanced drillingcould not be maintained as the formation has a ProductionIndex (PI) exceeding 400 bbl/d/psia. The connate water influxfrom under balanced drilling would rapidly overcome the aircompressors ability to airlift the well. Therefore the openhole was drilled in a balanced condition with no directional

control. There was also a danger that air entrainment in theunderbalanced reservoir could induce a near well bore gasrelative permablility and result in a lower water injection rateinto the formation.

No pilot hole was drilled to fix formation depths for thehorizontal drilling. Therefore, the horizontal well would bedrilled until it penetrated the formation below the target, QishnS3, zone and then be steered back up into the target zone fordrilling the open hole section (see Figure 6).

The Heijah horizontal wells were drilled as stand alone wells.The Naar wells were drilled from the same lease but wouldenter the formation 4900 ft. apart so that there would not beinterference affects during injection.

Well schematics from Heijah-19, representing a typical openhole disposal well design and Naar 2, representing a typicalopen hole disposal well design with a slotted liner installed areshown in Figures 7 and 8.

The wells were air hammer drilled through the Umm ErRadhuma cap rock formation to approximately 1100-ft. usingair-foam in 12 hours. Set 13 3/8 surface casing approximately30 ft. into the Sharwayn formation. Then 12 hole wasrotary drilled vertically into the Harshiyat formation at ~ 3500ft.

From this depth the wells were directionally drilled with oil based gel 8.7 8.8 ppg chem mud. A build rate of 2 o/100 ft.until 25 o inclination is reached then 5 o/100 ft. until andinclination of 75 85 o from vertical is reached entering theQishn formation. When the well bore entered the Qishn S3sand the build rate was limited to 1.5 o/100 ft. until theintermediate casing point was reached in the bottom 1/3 of theUpper Qishn S3 formation. The well was pointed up towards


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the top 1/3 of the formation to allow for pitching the bit duringair drilling. This design was chosen because directionaldrilling steering equipment would not operate in air drillingenvironment. The final angle of the intermediate casing waschosen so that 500 to 1000 ft. of horizontal section could bedrilled before gravity pulled the drill bit back down to the

bottom of the formation. The well path from this design can

be seen in Figure 6. The hole was back reamed on everysingle on connections when using the steerable assembly. Atwhich point, the well was logged with a DLL-SP-BHC-LDT-CNL-NGT-GR log. The 9 5/8 casing was set.

While air drilling the open hole section, the major concern wasthe significant inflow of connate water at the casing shoe and alower annular velocity from air foam and water influx at the

bit. This could result in poor removal of drilling fines or inthe extreme case losses would occur at the bit. Losscirculation would not be apparent at surface, as aerated returnswould continue to flow. The air drilling equipment was thenhooked up and 8 hole was under balanced and balanceddrilled with a rotary speed of 80 rpm and air foam for 500 to1000 ft. with a build of 5 o/100 ft. The air package provided2100 to 3500 cfm of air and 30 gpm of water with 1-2% foam.

The open hole section was circulated clean with water toremove drilling fines. The open hole was then logged usingtough logging condition (TLC) equipment. The log suite wasan LDT-CNL-NGT-GR log. On the first horizontal thedrilling rig ran well the LDT-CNL-NGT-GR log. On thesubsequent wells, the log was run with the surface rig. Wellcompletions occurred about 30 days after rig release and thisredueced the entrained air in the open hole section the CNLwas still affected.

Cementing and Completion ProgramsSurface Casing

The surface casing is cemented with the following slurry usingthe following additives:

Density 15.8 ppgClass G cementGPS liquid anti-foam1% BWOC fluid loss additive0.08 GPS dispersant0.5% BWOC accelerator4.95 GPS H 2O

Intermediate Casing

The intermediate casing is cemented with the following twoslurries using the following additives:

Lead SlurryDensity 12.8 ppgClass G cementGPS liquid anti-foam2.5% BWOC bentonite extendor0.08 GPS diapersant0.25% BWOC fluid loss additive10.95 GPS H 2O

Tail Slurry (Enough volume to cover to Qishn Formation)Density 15.8 ppgClass G cement0.01 GPS liquid anti-foam0.08 GPS dispersant0.02 GPS retarder

4.95 GPS H 2O

Completion Program Run a CBL log to be sure there is isolation across the

Upper and Lower Qishn formations. Tag bottom to determine PBTD and make sure no

shale stringers have collapsed. Install an ESP to pump drilling fines out of the well

bore. Pump was capable of pumping about 25-30%of the volumes that could be lifted with the drillingair package. Pump was run until discharge water wasthe same quality as connate water. Full cleaning tothe horizontal toe could not be achieved because of

the high formation PI. Likely most of the cleaningaction occurred within feet of the 9 5/8 casing shoe. The well was shut-in for 24 hours to get a build up

test to determine its productivity index (PI). In Naar 2, the 5 slotted liner was run to PBTD to

prevent shale stringers from sloughing into the openhole section. The Naar 3 and Heijah wells werecompleted bare foot. The 7 injection string was runin the well and set at the top of the Qishn formation.The casing annulus was filled with inhibited fluid and

pressurized to 500 psi. The well was put on injectionat a rate of 5000 bwpd and ramped up in 5000 bwpdincrements every 6 hours until the well stabilized onthe 300 psi flow line pressure. The ramping up of thewell was done to reduce fine migration in the nearwell bore area that could plug the sand matrix porethroats.

Stimulation ResultsAs the wells injectivity performance deteriorates with time,

Nexen has tried several chemical and mechanical stimulationtechniques to maintain injectivity with limited results.Injectivity gains last on average 75 days though some wellshave deteriorated in as little as 10 days and lasted as long as245 days. Table 1 summarizes the results of 42 simulation

jobs completed in the Masila Block Disposal Wells over thelast four years.

Propped Fracture Stimulation of Vertical Wells In October and November of 2000, propped fracturestimulations were conducted on five Masila block injectionwells. The chosen fracture stimulation design was based onthe tip-screen-out frac pack method in hopes that theoptimum economical return is achieved with short, widefractures to reduce the skin factor to zero. 13 Four of thesewells were stimulated to raise injectivity for produced water


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disposal into the Upper Qishn S2/S3 zones. The other wellwas stimulated for water injection for pressure maintenanceand will not be discussed further. These were some of thehighest permeability wells in the world ever stimulated in thismanner. Also, these were the first fracture stimulation jobsconducted in the Republic of Yemen. All equipment andmaterials had to be mobilized from outside the country. The

fact that these are water disposal and not production wells alsomakes these stimulation jobs somewhat unusual.

Table 2 shows the perforated intervals in the four disposalwells that were given propped frac stimulations. All wells had

been initially perforated with 12 shots per foot using 66 gram,gravel pack charges with 135/45 degree phasing. Moderateunder balance during perforating was employed in order toobtain a back surge rate of about 500 BWPD/perforation toclean up perforation damage.

For the Upper Qishn S2/S3, results from parametric studiessupport the values of modulus of elasticity (E) derived fromdipole sonic logs and core measurements. Reasonable valuesof E range from 1 to 2 E6 psi for these sands. The minimumhorizontal stress gradient was determined from calibrationfracs to range between 0.48 and 0.5 psi/ft. for the Upper Qishnsands and there was a high degree of consistency across thefields.

Prior to conducting the proppant frac stimulations, there wereconcerns about the feasibility of creating sufficient fracturewidth in these high permeability sands to allow the proppantto enter. The combination of high moduli of elasticity (>1 E 6

psi) and high permeability (>2000 md) make the stimulationsunique. The challenge existed to create fractures with highconductivity that demonstrated long term benefits in thesehigh permeability sands.

Stimulation treatments were designed using Frac-Pack as a basis. Pad volume was selected in order to create a narrowfracture but with sufficient width to accept a low concentration

proppant slurry. The volume of proppant slurry was designedto cause tip screen-out at the leading edge of the fracture 13.Continued injection after tip screen-out began was done toincrease net fracture pressure and cause an enlarging of thefracture width. Following enlargement of the fracture, higherconcentration proppant slurry was injected to fill the fracturefrom the tip back towards the well.

Important design considerations included: ensuring high fluid leak-off rate during fracture fill-up to

allow sufficient slurry to be injected in such high permeability zones ensuring fracture

inflation and full packing of the fracture during the final stages, matching injection rate to

declining fracture leak-off rate efficient post-frac clean-up to ensure high fracture

conductivity through proppant

compatibility of frac fluid with reservoir rock and fluids

Design and execution of the fracture stimulations wereconducted in the following general manner:1. well data was gathered from the files and fracture

treatment modeled2. pre-frac acid stimulation was conducted to remove

damage from impurities in previously injected water3. pre-injection temperature log was run4. bottom hole pressure gauges were run on wireline and set

below the bottom set of perforations5. calibration fracs were performed and values determined

for closure stress, fluid efficiency, net frac pressure andfrac height

6. temperature profile logs run after calibration fracs wereused to calibrate the model and compare with frac heightcalculations

7. a 3-D frac simulator was matched to measured values of bottom hole pressure, net fracture pressure, fractureheight and rate of pressure decline

8. re-simulation of the stimulation treatments was done andmodifications made to the fracture program9. fracture stimulations were conducted as programmed10. well bore clean-out operations were carried out

Guar based fluid, cross linked with boric acid was employedwith fluid densities of 40#/Mgal and 30#/Mgal. These fluidsare fast cross linking, can be used in pH ranges from 8 to 12and have an upper temperature limit of about 250 F. Theyexhibit high friction losses and low shear degradation. Theyare salt tolerant and are easy to break with oxidizers, enzymesand low pH fluids. Ammonium persulfate, triethanolamine andDuran encapsulated breakers were employed. The breakerschedules used are shown in Table 3. Proppant used in allfracs was 20/40 Carbolite ceramic. Fracture pump scheduleswere prepared with 20% excess proppant slurry to ensure thatthe treatment was pumped to a complete screen-out conditionthus maximizing the near well bore fracture conductivity.Table 4 shows fluid volumes pumped. Post-frac well boreclean-outs were required and these were accomplished using abull-dog sand bailer to remove the excess proppant.

Table 5 summarizes results of the completed fracturetreatments. Modeling studies provided estimates of fracturedimensions and conductivity following the treatments. Forwells Camaal-30, Heijah-11, and Tawila-26 almost all of the

proppant pumped was successfully placed but in the case ofTawila-25, only 63% was placed in the fracture.

Table 6 compares injectivity indexes (II) over the life of thefour propped frac wells. IIs were calculated from injectiondata over approximately one month periods (the dates coveredare shown in brackets). IIs are given for the first month thewell was on injection, the month before the proppant fracturestimulation and at periods of 1, 3, 6 and 12 months followingthe treatment. In some cases, the post-frac IIs are affected by


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acid stimulation jobs conducted on the wells. Comparing pre-and post-frac IIs, it may be noted that all wells showed animprovement following the proppant frac. The Tawila-25stimulation showed a very small improvement after 1 monthof injection while the other 3 wells showed an average IIincrease of 3 fold. However, after 3 months, the average gainfor these 3 wells had dropped to 2 fold and after 1 year to 1.7.

Without the acid stimulations, the injectivity would havedeclined to pre-frac levels or lower after 6 months to 1 year.

Comparison of Horizontal, Propped Frac and VerticalDisposal Well Performance Figure 9 compares the performance of 20 cased and perforatedvertical water disposal wells with the 4 horizontal and 4vertical propped frac wells. The water injection rate is plottedagainst cumulative water injection. The water injection rate

plotted is the average for each of the well groups. Thecumulative volume injected is also an average for the wells ineach group. It should be noted that as time and cumulativevolume increase, the number of wells in each group maydecrease since some wells have longer history of injectionthan others and therefore larger cumulative injected volumes.Also, for data plotted on a cumulative scale, the best or highestrate disposal wells tend to dominate the data set at largecumulative volume injected.

The data plotted in Figure 9 clearly indicate that initially thehorizontal wells achieve much higher injection rates than thevertical wells as would be expected. This is because of thesignificantly greater wellbore area exposed to flow and thereduced fluid velocity which results in the near wellbore area.The injectivity of the horizontal wells declines steeply andeventually falls below the average performance of the casedand perforated vertical wells that have not been proppantfracture stimulated.

The proppant fracture stimulated well group starts onlyslightly higher than the non-proppant fracture stimulatedgroup. The propped frac wells also drop below the verticalnon-propped frac wells with increasing cumulative injectedvolume. The proppant frac wells have lower injection rate thanthe horizontal wells throughout their history and are the

poorest performing group. On the other hand, the non-fracturestimulated vertical wells actually show an improvement ininjection rate over time. This is thought to be due in part toincreases in water disposal system pressure but also to thesuccessful application of acid/solvent stimulation treatments.

It is also possible that the higher fluid velocities encounteredin the vertical wells carry fines and solid particulated in thedisposal water away from the near wellbore while in thehorizontal and propped frac wells there may be a tendency forthese to build-up more near the sand face causing greaterdeterioration in injectivity.

Figure 10 compares the injectivity performance of the 4horizontal disposal wells. It may be observed that the best

performing well is Naar-2 and that Heijah-21 is superior to

Heijah-19. Petrophysical logs indicate that the better performing wells encountered better quality sands in thehorizontal section. Figures 11 and 12 show injection data forHeijah-19 and Naar-2. The effect of acid stimulationtreatments on Heijah-19 is obvious on the injection plots aswell as the Hall and Hearn plots. However, the injection raterapidly deteriorates showing the effects of oil and fines in the

disposal water can be seen after the well has been stimulated.This deterioration in injectivity is most evident on the Hearn plot for Naar-2.

DiscussionAll types of wells generally experience declining injectivityrelated to total volume of fluid injected. This is thought to becaused by the impurities in the disposal water which consist ofoil carry over from the separation process, reservoir finescarried through the surface equipment and returned to thereservoir via the disposal wells and corrosion productsoriginating in the surface and downhole equipment. While theconcentrations of the materials are relatively low at about 15

ppm of oil and 15 ppm of total suspended solids, the volumesof water injected into individual disposal wells are largeenough, averaging 20,000 to 60,000 bwpd, to create plugging

problems if the majority of these impurities lodge in or nearthe formation face. The success of acid/solvent stimulationtreatments in restoring injectivity on vertical wells attests tothe fact that the impurities are indeed lodging in the near well

bore region. The acid/solvent stimulations tend to be short-lived in their benefit however. The stimulation treatments areeasier and less expensive to conduct on the vertical wellscompared to horizontal wells.

In general, while the application of horizontal and proppantfracture stimulated vertical wells held much promise to raiseinjection rates and injectivity, they have failed to perform aswell as the conventionally completed vertical wells. Becauseof the operational impracticality of filtering the disposal waterto a higher quality before injection, recent efforts havefocussed on bringing less water to surface through water shut-off techniques and anti-coning strategies. Investigation ofcontinuous high rate injection above formation parting

pressure has also been conducted. This latter method holdsmuch promise of being able to create small fractures in orderto break through near well formation plugging and therebymaintain continuous high rate injection. Variations in disposalwater quality caused by operational adjustments or problemson surface will have less detrimental effects on disposal well

performance under high pressure injection.

Conclusions1. For the high permeability sands of the Upper Qishn

formation in the Masila Block, there is no advantage tothe use of horizontal wells over conventionally completedvertical wells. The additional costs associated withdrilling, completing and stimulating horizontal wells arenot justified in this case.

2. The additional costs associated with proppant fracture


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stimulation of vertical water disposal wells are also not justified.

3. Given the high disposal rates within the Masila Block,conventional filtration systems are operationallyimpractical to prevent particulate matter entering theformation and causing both sandface plugging and deepdamage.

4. All of the water disposal wells are positively affected fora short time by repeated acid/solvent stimulation of thewells, which removes the material causing the sandface

plugging, but acid stimulation likely has little impact ondeep damage. However, since it is more difficult toworkover and selectively stimulate horizontal and

propped frac wells than vertical wells, in this applicationthe conventional cased/perforated vertical wellcompletions are favoured.

5. The most promising solution for more efficient waterdisposal appears to be the use of higher pressure injectionto exceed formation parting pressure, which likely breaksdown the ongoing near wellbore damage and minimizesthe effect of deep damage that cannot be effectivelyaccessed by acid stimulation.

6. Horizontal wells may not receive the benefit ofcontinuous breaking pressure due to the substantiallyincreased sandface, and therefore are more susceptible tolong-term degredation by formation damage mechanisms.

7. If disposal water cannot practically be filtered adequatelyfor the formation being injected into, then horizontaldisposal wells may not be a good choice.

AcknowledgementsThe authors thank Nexen Inc. and its partners OccidentalPetroleum Ltd., Consolidated Contractors Company S.A.L.and the Government of the Republic of Yemen for their

permission to present this material. The contributions of thefollowing individuals are recognized and appreciated: WendyHeuver for the particle size analysis and filter performancecharts, Wendy Busher for the well performance plots and BenWong for the drilling schematics.

References 1. Harding, T.G., Smith, K.H., Al-Hakimi, E., Al-Seyani, A.,

Wilkie, D.I., and Willson, N.D.: Produced WaterManagement: Masila Block Yemen, presented at the 2 nd International Yemen Oil and Gas Conference, Sanaa,Republic of Yemen, 24 - 25 June 2002.

2. Sharma, M.M., Pang, S., Wennberg, K.E., andMorgenthaler, L.: Injectivity Decline in Water InjectionWells: An Offshore Gulf of Mexico Case Study, SPE38180 , presented at the 1997 SPE European FormationDamage Conference in the Hague, Netherlands, 2 - 3June 1997.

3. Paige, R.W., Murray, L.R., Martins, J.P., and Marsh, S.M.:Optimising Water Injection Performance, SPE 29774

presented at the SPE Middle East Oil Show, Bahrain, 11 -14 March, 1995.

4. Graves, K.S., Valentine, A.V., Dolman, M.A., and Morton,E.K.: Design and Implementation of a Horizontal InjectorProgram for the Benchamas Waterflood Gulf ofThailand, SPE 68638 presented at the SPE Asia PacificOil and Gas Conference and Exhibition, Jakarta,Indonesia, 17 - 19 April 2001.

5. Huang, W-S., Kaetzer, T.R., and Bowlin, K.R.: Designand Performance of a Horizontal Well Waterflood Projectin New Hope Shallow Unit, Franklin County, Texas," SPE24940 presented at the SPE 67 th Annual TechnicalConference and Exhibition, Washington, D.C., 4 - 7October 1992.

6. Nasrulla, I.M.and Rana, L.A.: Planning of a HorizontalWell Offshore Qatar, SPE 21348 presented at the SPEMiddle East Oil Show, Bahrain, 16 - 19 November 1991.

7. Dake, L.P., Sutcliffe, P.G., and Tweedie, A.A.P.: ImprovingHydrocarbon Recovery Efficiency Utilizing HorizontalProduction and/or Injection Wells, 9 th EuropeanSymposium on Improved Oil Recovery, The Hague, TheNetherlands, 20 - 22 October 1997.

8. Smith, M.B. and Hannah, R.R.: High-PermeabilityFracturing: The Evolution of a Technology, SPE 27984presented at the Tulsa Centennial Petroleum EngineeringSymposium, Tulsa, OK, 29 - 31 August 1994.

9. Goo, J., Li, Y., and Zhao, J.: Simulation and Evaluation ofFrac and Pack Completion in High PermeabilityFormations, Paper 2001-055 presented at the PetroleumSocietys Canadian International Petroleum Conference2001, Calgary, Alberta, 12 - 14 June, 2001.

10. Davidson, B.M., Franco, V.H., Gonzalez, S., andRobinson, B.M.: Stimulation Program in High PermeabilityOil Sands Case Study, SPE 39050 presented at theSPE 5 th Latin American and Caribbean PetroleumEngineering Conference, Rio de Janeiro, Brazil, 30 August

3 September 1997.11. Soedarsono, G., Harding, C, Said, R. and Suchart, J.:

The Application of Fracturing to Bypass SevereFormation Damage in an Ultra-high PermeabilityFormation, Proceedings of the 23 rd Annual Convention ofthe Indonesian Petroleum Association , October 1994.

12. Hunt, J.L., Chen, C-C, and Soliman, M.Y.: Performanceof Hydraulic Fractures in High Permeability Formations,SPE 28530 presented at the SPE 69 th Annual TechnicalConference and Exhibition, New Orleans, Louisianan, 25 -28 September 1994.

13. Al-Haddad, S., Arbaugh, R., McKnight, D.: HydraulicFracturing in High Permeability Wells, SPE 40008 presented at the SPE Gas Technology Symposium,Calgary, Alberta 15 - 18 March 1998.

14. Dusterhoft, R.G., and Chapman, B.J.: Fracturing High-

permeability Reservoirs Increases Productivity, Oil & GasJournal , 20 June 1994, pp. 40 44.15. Aggour, T.M., and Economides, M.J.: Optimization of the

Performance of High-permeability Fractured Wells, SPE39474 presented at the SPE International Symposium onFormation Damage Control, Lafayette, Louisiana, 18 - 19February 1998.


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8 HARDING, SMITH & NORRIS 79007

Table 1Well Stimulation Results

StimulationType

Numberof Jobs

Average 15% HCl Treatment

Size(bbl)

Average Injection

Gain(bwpd)

Average Duration

of Gain(Days)

Horizontal

Heijah -19 Acid 3 1 100 10897 67

Heijah-21 Acid 4 2 90 13333 125Vertical

Average Acid 27 3

70 11026 102 Average Propped Frac 4 N/A 12867 187

Average Air Lift 4 4 N/A 14243 145

Notes:1 33 % of treatments used divertor agent.2 25 % of treatments used divertor agent.3 31 % of treatments used divertor agent.4

Well Type

5 Divertor agent did not deliver a statistically different result than bullheaded acid treatments.

Air lifting may appear better than other techniques but one job includedreperforating the well as well.


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79007 Horizontal Water Disposal Well Performance in a High Porosity and Permeability Reservoir 9

Table 2Masila Propped Frac Well Perforated Intervals

Well Zone PerforatedIntervals (ft. kB)

MPP(ft.kB)

ReservoirPressure at MPP

(psia)

ReservoirTemp( F)

S2 5820-5858Camaal-30S3 5876-5912

5867 1745 160

S2C 5746-5756S3 5766-5776S3 5786-5796

Heijah-11

S3 5806-5816

5781 1648 159

S3 6186-6195S3 6210-6214.3S3 6220-6232S3 6238-6247.5S3 6252.5-6264S3 6274-6281

Tawila-25

S3 6286-6292

6239 1817 167

S3 6185-6233S3 6255-6263

Tawila-26

S3 6278-6282

6233 1808 159

Table 3Breaker Schedules for Proppant Fracs

Breaker 40#/Mgal Breaker 30#/Mgal

A B C A B C

Pad 0.25 1 1 0.1 1 1

1 ppa prop 0.5 1 2 4 0.1 1 1

2 - 6 ppa 1.0 1 2 8 0.2 1 1 2

> 8 ppa 1.5 1 2 10 0.2 1 2 6

Breaker A ammonium persulfate (low temperature oxidizer)Breaker B TEA (triethanolamine) accelerates effect of Breaker ABreaker C Duran encapsulated breaker


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Table 4Proppant Frac Pump Summary

Well InjectionRate (bpm)

Fluid Type Pad Vol.(bbl)

SlurryVol. (lbs)

ProppantPumped (lbs)

ProppantPlaced (lbs)

Net FracturePressure (psi)

Camaal-30 55 30#/Mgal 420 258 55,200 44,000 1200+Heijah-11 51 40#/Mgal 426 371 62,000 60,800 150Tawila-25 50 30#/Mgal 380 334 89,000 56,000 1200+Tawila-26 55 40#/Mgal 440 306 48,500 45,300 1100

Table 5Predicted Geometry and Conductivity of Proppant Fracs

Well Zone Frac Length(ft.)

Frac Height (ft.) Frac Width (in) Frac Conductivity (md-ft)

Camaal-30 S2 60 42 1.2 30,000Heijah-11 S3 180 75 0.4 9,000Tawila-25 S3 80 50 1.0 25,000Tawila-26 S3 60 70 1.0 27,000

Table 6Masila Propped Fracture Stimulations

Post-Frac Injectivity Index(bwpd/psi)

Well Zone* FracDate

InitialInjectivity

Index(bwpd/psi)

Pre-FracInjectivity

Index(bwpd/psi)

1 Month 3 Months 6 Months I Year

Camaal-30 UQ S2/S3 3/11/0017.2

(02/07/99 to01/08/99)

28.6(30/09/00 to

30/10/00)

97.0(26/11/00 to

26/12/00)

59.4(26/01/01 to

25/02/01)

56.9 + (26/04/01 to

26/05/01)

33.6(26/10/01 to

25/11/01)

Heijah-11 UQ S2/S3 14/10/0045.9

(20/04/97 to20/05/97)

18.9(10/09/00 to

10/10/00)

41.6(10/11/00 to

10/12/00)

36.7(30/12/00 to

29/01/01)

29.7(10/04/01 to

10/05/01)

14.8(10/10/01 to

9/11/01)

Tawila-25 UQ S3 19/10/007.5

(17/11/99 to6/12/99)

19.0(15/9/00 to15/10/00)

21.4(17/11/00 to

17/12/00)

16.2(15/01/01 to

14/01/01)

20.7 + (19/04/01 to

19/05/01)

4.7(19/10/01 to

18/11/01)

Tawila-26 UQ S3 9/10/002.5

(19/11/99 to6/12/99)

12.0(1/09/00 to

1/10/00)

53.1(13/11/00 to

13/12/00)

28.6(15/01/01 to

14/02/01)

37.4 + (19/04/01 to

19/05/01)

52.2 + (9/10/01 to

8/11/01)

* UQ = Upper Qishn

+ following acid stimulation


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Figure 1. Project Area Location Map


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13/20


Figure 3. Generalized Stratigraphy of Masila Block


14/20


15/20


Proposed Directional Plan for Naar 2 Horizontal Well

Harshiyat

Qishn Carbonate

Red Shale

Qishn C3 Marker

Qishn S1AQishn S2

S3 Reservoir

Basement

LQ1

2250

2500

2750

3000

3250

3500

3750

4000

4250

4500

4750

5000

5250

5500

5750

60000.00 250.00 500.00 750.00 1000.00 1250.00 1500.00 1750.00 2000.00 2250.00 2500.00 2750.00

Vertical Section (ft.)

D e p

t h ( f t . )

Naar 2 Wellpath

Naar 3 SurfaceNaar 2 Surface

600' past csg. pt.

Co-ord. for heel

Co-ord. for heel(Int. Csg. Point)

1733750

1734000

1734250

1734500

1734750

1735000

1735250307500 307750 308000 308250 308500 308750 309000

Easting (m)

N o r t

h i n g

( m )

Figure 6. Typical Open Hole Horizontal Well Directional Drilling Plan Showing the Air Drilling Pitch

Air Drilled Open HoleSection


16/20


17/20


Figure 8. Well bore Schematic of Open Hole Horizontal Well with Slotted Liner Installed

Well Name: Naar 2 HZT (F15-5) Well Directional Plan: Horizontal1st Target: N: 1734826 E: 307932

Surface Location: North (m): 2nd Target:N: 1734997 E: 307994East (m):

Elevations: Surveyed GL:3312.7 Drilling AFE: Est'd GL: 3316.0

Est'd KB: 3345.0

Est'd Drilling Time (Days): Spud to TD:17.9 Spud to RR:19.6

Wellhead Equipment: Tubing Spool:

Wellhead Equipment: Casing bowl:Formations

* Primary ** Secondary

20" Conductor 20" Csg Shoe 40.0' 40.0'

Casing:UMM ER RADHUMA 165.0' 165.0' 13-3/8" Casing, Air Drill 18-1/4" Hole - None

54.5#, K-55 BTC

Cement:SHARWAYN 1221.0' 1221.0' 15.8 ppg Class 'G' + additives (see GDP)

13-3/8" Csg Shoe 1256.0' 1256.0' Surface - Casing PointMUKALLA 1305.0' 1305.0' Casing: Drill 12-1/4" Hole -

9-5/8" 47#, L-80, BTCSurface - ITD

FARTAQ 2355.0' 2355.0'HARSHIYAT 2525.0' 2525.0' 1st KOP at TLC Log

3700ft. Run 1: Supercombo with build rate at

2deg per 100 feet to1st end of build at

QISHN CARBONATE 4982.0' 4940.0' 4800ft. / 22 degRED SHALE MARKER 5367.0' 5250.0' Change build rate to Coring: QISHN C3 MARKER N/P N/P 5 None

* QISHN CLASTICS - S1A 5553.0' 5369.0' deg per 100 feet fromQISHN CLASTICS - S1B 5588.0' 5389.0' 4962ft. to 5900ft.QISHN CLASTICS - S1C 5610.0' 5401.0' at 72 deg Cement:QISHN CLASTICS - S2 5667.0' 5430.0' then to FT.D at Prelflush: As per GDP

QISHN CLASTICS - S2 Paleosol N/P N/P 7438ft. / 78 degQISHN CLASTICS - S3 5990.0' 5548.0' Lead: 12.8 ppg Class 'G' + additives (see GDP)

LOWER QISHN CLASTICS 1 6316.0' 5610.0' TOC: 300' into surface csgLOWER QISHN CLASTICS 2 UPPER SAAR CLASTICS 1 Tail: 15.8 ppg Class 'G' + additives (see GDP)UPPER SAAR CLASTICS 2 TOC: 500' above Qishn S1A top

SAAR CARBONATE

** BASEMENT ITD: 9-5/8" Csg Shoe

Casing: Drill 8-1/2" Hole -None

LWD GR Cement:

Coring: None

FT.D 7435 .0' 5610.0'

13-5/8" 2M x 11" 3M

to TD

None planned - cement plugspossible if well to be P&A

Terminate drilling 100' intothe Basement

Potential lost circulation inMukalla/Harshiyat

Terminate drilling 35' into theSharwayn

8-1/2"OpenHole with5 Slotted liner

12-1/4"Hole

18-1/4"Hole

Air/Fresh Water

13-3/8" X 13-5/8" 2M (SOW/stub nipple)

Gel/Chem 8.3-8.9 ppg; 10 -

13% oil to top ofRS Marker;

Nitrate Tracerfrom top of QC to

ITD

Air/foam

Well bore Schematic

MD (ft.)RKB

TVD (ft.)RKB

HoleSize Di rec ti ona l P la n Cas in g & C em en ti ng Dr il li ng Co ns id er at io ns We ll bo re Ev al uat ion Mud Properties

AFE#:

Not to scale

1734324 307750

340A13 SAP Ref#:

D&C: $1,388,200 $1,388,200 D&A:

TD: 5-1/2 Slotted liner


18/20


Figure 9. Comparison of Performance of Disposal Well Types

Figure 10. Comparison of Performance of Horizontal Water Disposal Wells


19/20


Figure 11. Injectivity Data for Heijah-19 Horizontal Well

02/10/2001 Acid Job

03/10/2000 Acid Job

06/30/2000 Acid Job

06/24/1999S2/LQ Disposal

09/14/2001 Acid Job

06/24/1999S2/LQ Disposal

09/14/2001 Acid Job

02/10/2001 Acid Job

06/30/2000 Acid Job

03/10/2000 Acid Job


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Figure 12. Injectivity Data for Naar-2 Horizontal Well

CPF WaterConversion to

H droc clone Water

ceramic membranes for wastewater

Documents