EAGLE FORD: TECHNOLOGY Facilitating Success · EAGLE FORD: TECHNOLOGY ... (Image courtesy of Canrig...

The Eagle Ford Basin has been on the oil and gasindustry’s radar for some time, but explo-

ration activity didn’t really take off until a coupleyears ago, when operators began experiencinggreat success. As a latecomer, Eagle Ford has ben-efited from plenty of technologies proven in other

shale basins as well as new products designedspecifically for the region.

Today, 3-D seismic surveys are producing vastamounts of data, too much, it seems, to be viewedand interpreted in a timely manner, much less repro-cessing that seismic and other data to optimally

Technology is moving swiftly to improve efficiency.

Facilitating Success

By Jerry GreenbergContributing Editor

EAGLE FORD: TECHNOLOGY

Top-left: Cross section along well trajectory shows acoustic impedance in the background and gamma ray well log curves with indi-vidual frac stage gas production rates. Insets represent hyperlinked data showing results from geosteering and frac operations and adaily gas production rate chart. Lower-left: Before and after seismic cross sections show the results of the PCA conditioning, whichsignificantly suppresses the seismic noise and helps identify the internal stratigraphic complexity of the Eagle Ford. Right: 3-D crosssections along well trajectories combining amplitude seismic, gamma ray log curves, and frac stage gas production rate cylindersagainst a backdrop of stratigraphically sliced acoustic impedance. (Images courtesy of Knowledge Reservoir and Petrohawk)

place the next well bore or stimulation. Several oper-ators are taking recently acquired 3-D data andreprocessing it to optimally place the well bore forthe most productive stimulation job and later forthe most productive field development scenario.

Reprocessed seismic isn’t the only tool opera-tors and service companies use to drill the best welland stimulate it as efficiently as possible. Servicecompanies are using various formation evaluationtools, microseismic surveys, better frac fluids andproppants, and different fracture methods, includ-ing coiled tubing.

Drilling contractors also are entering the mix withproprietary software that results in their rigs drillingsmoother well bores for better stimulation jobs anddrilling wells faster and more cost efficiently than inthe past. Drill bit manufacturers are designing betterperforming, more durable bits specifically for EagleFord, some of which have resulted in record-settingruns, including one-bit runs in the vertical, curve,and lateral sections of the well.

Eagle Ford operators seem to be the lucky recip-ients of successful technologies that have alreadybeen tried and proven.

Enhanced integration Many companies exploring in shale basins do nothave the manpower or time to analyze seismic andother well and production data in an integratedworkflow. The problem grows with each new batchof well or seismic data. Exacerbating the issue isthat the expected ultimate recovery and totalreserves of one well can be significantly differentfrom another well only a couple thousand feet away.

“We see the same basic question coming backover and over again,” said Larry Denver, president ofKnowledge Reservoir. “Why is my recovery rangeso broad and based on that, what do I do about myupcoming drilling locations and spacing optimiza-tion? How many wells do I drill in a section?

“Operators are all struggling with limitedresources and trying to keep their heads above water,drill and hold acreage, collect the data, and get tothe next well,” Denver continued, “but they havevery little time to do any actual analysis on the datafrom drilled wells and these unconventional reser-voirs themselves.”

To help address this need, Knowledge Reservoiris collaborating with Austin-based AGM Inc. andHouston-based Geo-Texture Technologies to inter-pret and integrate a batch of recently acquired EagleFord 3-D seismic with well and production data.AGM’s Recon software supports advanced 3-D geo-logical modeling and interpretation and is espe-cially suited to environments requiring G&Gintegration with production data where horizontalwells are drilled. Geo-Texture specializes in volume-based seismic conditioning designed to reduce noiseand better deliver reservoir-scale seismic attributes.

Included in their typical deliveries are acousticimpedance volumes, multi-variate attribute analysis,and curvature analysis which have been proven effec-tive for illuminating fractures, faults, and other sub-tle features. The company also specializes in principalcomponent processing to reduce noise in seismicdata for better curvature computations, acousticimpedance inversion, and other post-stack process-ing. Seismic data should be as noise free and have thebroadest bandwidth possible. With its algorithms,Geo-Texture is able to produce higher-frequency (bet-ter vertical resolution) data with less noise than theoriginal input data. This allows interpreters to see lay-ering and stratigraphic relationships within the EagleFord that are not otherwise visible.

Using the enhanced seismic as part of the inte-grated depth model, the operator can better under-stand the reservoir and where to place wells withinthe formation to maximize production perform-ance. Reducing the data noise and improving thesignal allow the interpreter to see more interestingrock properties.

“When we look at something such as curva-ture, which helps us define fracturing or perhapsbrittleness or acoustic impedance, which helps toestablish lithology and fluid heterogeneity, thebetter we can stimulate and produce the reser-voir,” Denver explained.

The enhanced data and improved depth-basedwell placement along with other frac modeling canhelp to tell the operator how mechanically success-ful the completion was and what the reservoir rockis like along the completion. The operator is thenbetter able to determine the potential productivityof the reservoir and the completion. Hopefully, the


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operator can learn why two wells that are 2,000 ftapart are so different from each other in terms ofexpected ultimate recovery.

In the Eagle Ford, enough wells have been drilledand enough data collected and made available tocompanies like Knowledge Reservoir that certainindustry relationships are becoming clearer. In par-ticular, the industry knows it must be able to moreaccurately characterize such properties as matrixpermeability, frac length, rock brittleness, and claycontent. Integrated models of geology/geophysics,well data, and production results help to do so.

“We are now testing and building a workflow tobe applied to the Eagle Ford,” Denver said. “Good,solid integration with workflow, ideas, and tech-nology tailored for the particular area.”

Geosteering in the Eagle FordDenver emphasizes that, based on the company’sobservations, geosteering based solely on widely

spaced-type wells and log curvematching in areas with limited welldata and no seismic will be challeng-ing in plays like the Eagle Ford, whichcan change rapidly in thickness, rocktype, and structural dip. Compared toplays such as the Bakken, the EagleFord is more complicated to geosteereven though the thickness of theEagle Ford is much greater than thetarget area within the Bakken.

“Until now, Eagle Ford operatorshave oftentimes been without thequality or quantity of data theywould like to have to accurately placetheir wells and to be able to predictwell performance,” Denver said. “Tohelp accelerate the learning curve, webelieve the integrated data sets areparamount to unraveling the EagleFord curiosities.

“At the end of the day, even if thesereservoirs are unconventional, ourunderstanding of them will be basedon the same methods we have reliedon for complicated conventional reser-voirs,” Denver concluded.

As with completions discussed earlier, therecently available batch of seismic data is aiding inbuilding better well models. Unlike the BarnettShale, where operators used seismic mainly toavoid hazards downhole (don’t drill into or fracinto the Ellenburger or you’ll produce more waterthan gas, for example), in the Eagle Ford, due to itscomplexities and quickly changing formation char-acteristics, operators are learning how to use seis-mic to understand what part of the reservoir rockthey want to drill.

“A Bakken approach is not going to perform aswell in the Eagle Ford,” Denver explained. “The for-mula is more complicated and includes much morethan lateral length and number of frac stages.

“Given some time, our industry will eventuallyunravel the Eagle Ford complexities,” Denver con-tinued. “The main question to ask now is howcan we get there faster and reduce our costs alongthe way?”


Soft Torque software is designed to mitigate the effects of stick slip and downhole vibrationduring drilling, resulting in higher rates of penetration, increased bit life, and reduced toolfailure. (Image courtesy of Canrig Drilling Technology Ltd.)

Software for drilling efficiency Canrig Drilling Technology Ltd. offers several soft-ware applications that improve drilling efficiency,reduce drilling time, and save costs, according to thecompany. Canrig, an affiliate of Nabors DrillingUSA, has contracted with Shell to provide varioustechnology products for Nabors’ rigs operatingonshore for Shell in the lower 48 states and Canada,including the Eagle Ford. Most of Nabors’ rigs havethe various software programs installed.

Canrig’s Soft Torque Rotary System waspatented by Shell and licensed to third parties forcommercialization more than 10 years ago, accord-ing to Canrig. Shell has been working on the tech-nology for application on all of its rigs globally. Forvarious reasons, successful and consistent imple-mentation has been elusive until recently. Today,many of Nabors’ rigs contracted to Shell use SoftTorque as a result of Canrig’s involvement.

“We are in the early stages of commercialization,”said Scott Boone, vice president, Drilling Automa-tion for Canrig. “We have installed the technology onmost of the rigs for Shell and we will be commercial-izing it for use on Nabors rigs for other operators.”

The software is designed to mitigate the effects ofstick slip and downhole vibration during drilling.The result is higher rates of penetration (ROP),increased bit life, and reduced tool failure. The sys-tem integrates into a standard Canrig A/C top drivedrilling system to alert the driller of excessive down-hole vibration. It operates from the surface, does notrequire downhole equipment, and does not inter-rupt the drilling process. It is operated on demandfrom the driller’s top drive control screen and can beturned on or off by the driller.

The system operates like a torsional shock absorberfrom the top drive, eliminating fluctuations in down-hole bit speed. It detects stick slip and takes correctiveaction to resolve the problem. It is completely non-obtrusive to the drilling process, working from thetop drive instead of downhole. The driller has the abil-ity to enable or disable the system depending on therequirements of the well being drilled.

The system includes two monitors, one to helpevaluate its real-time performance while the other pro-vides historical views of data to help the driller and oth-ers evaluate the effectiveness of the system in

mitigating stick slip. Additionally, Soft Torque inte-grates with the company’s myWells.com software portal,allowing others to see how the tool is working fromanywhere in the world.

Directional drilling automation The company’s Rockit directional drilling automa-tion platform provides three tools to the directionaldrilling process when using motors and bent hous-ings. The software provides three unique functions,according to the company: oscillation control, tool-face orientation, and bearing offset control, all ofwhich contribute to more efficient drilling opera-tions. Additionally, two unique automation prod-ucts can be included with the system: Heads UpDisplay and Rockit Pilot.

“There are three values with the Rockit system,”Boone said. “Once the toolface is established, thepipe can be rocked back and forth to help break fric-tion and provide more consistent weight on bit. Sec-ond, when initially setting the toolface, the system isintegrated into the top drive, and it knows the posi-tion of the quill allowing for faster toolface setting.Third, when drilling a lateral, if the bit begins wan-dering the Rockit system can be used to bring it backto the correct position without coming off bottom ormaking changes that affect drilling efficiencies.”

The software can eliminate the manual orienting of the toolface that enables the drillerto steer through the well bore. Manually orientingthe toolface requires considerable experience and timing, not to mention having that certain“feel.” With the software, the computer controlsthe correct amount of rotation to maintain tool-face orientation.

To control the toolface, bearing offset controlallows the driller to nudge the toolface left orright while drilling, providing fine control of thetoolface orientation. These adjustments can bemade while drillstring oscillation is in progress.

The system can oscillate the drillstring fromthe surface to reduce downhole friction. Theoscillation or rocking can be programmed from afraction to several revolutions of the drillstring.The amount of oscillation right or left is adjustedby the driller to provide maximum drillstringrocking without affecting toolface orientation.



A case studyTypical wells in the Pinedale Anticline in Wyominghave shallow kickoff points around 200 to 300 ft, fol-lowed by approximately 1,000 ft of build to a maxi-mum inclination of 20°. The drop curve takes thewell bore back to vertical, and the wells are drilled ver-tically to a total depth of about 13,500 ft TVD. Thebuild curve is usually around 1,300 ft measured depth(MD) and the drop curve around 2,000 ft MD. Thesewells are drilled through the Fort Union and Lancesandstones of the Mesa Verde Group.

In executing these wellbore curves, the direc-tional driller used rotary drilling and slide drillingin the intermediate and production sections whendirectional control was needed. To determine howthe use of the Rockit software influences slidedrilling performance, a comparison of sliding ROPwhile using the technology was compared to that ofthree wells drilled previously in the same area. Over-all, the average sliding ROP increased from 49.83 to75.24 ft/hr with the addition of the Rockit system.

Understanding the reservoir Activity in the Eagle Ford Basin began only a fewyears ago and, consequently, there is limited his-torical information, public or otherwise, about long-term well productivity. That is beginning to change,

providing an opportunity for service companies toobtain information that can verify whether theirtechnologies and products optimized or enhancedthe well and its productivity.

By implementing its Understand the ReservoirFirst philosophy, examining the entire reservoirpackage, and becoming involved with the cus-tomer at an early stage, Baker Hughes is able tozero in on the reservoir and apply the correct frac-turing fundamentals required to maximize results.

“We are constantly working to optimize thesuccess of each well and maximize initial and long-term productivity,” said Tom Royce, BakerHughes, Pressure Pumping, South Texas Areatechnical manager. “We look at available produc-tion data and correlate it against how the wellwas treated, products pumped, and formation andarea data.”

The company uses this information to furtherenhance subsequent treatments in the immediatearea. Certain trends have evolved that provide bet-ter results, Royce noted, such as pumping largerfluid and proppant treatment volumes at higherrates and with more stages. Proppant type and meshalso can make a considerable difference.

Long-term scale inhibitors One solution with the potential to enhance long-term production is the BJ Sorb family of solid spe-cialty chemicals and inhibitors. BJ MultiSorbtechnology allows the combination of two or moreSorb chemical products in treatments designed toaddress multiple problems simultaneously. In theEagle Ford Shale, the technology has been used totreat paraffin, asphalt, and biocides, among otherissues. The company also has used liquid biocides infracture fluids and is preparing for its initial use of BJ BioSorb in the Eagle Ford.

When pumped with the proppant during the fracjob, the subsequent inhibitor desorption from theSorb solid product is relatively slow and results inmore consistent and longer-term inhibition. Residualshave been measured in production fluids at effectivelevels more than five years after the fracture, accordingto the company. As a result, in many cases, it saves theoperator from remedially retreating the well after thestimulation. Although the technology has been avail-


In many cases, BJ Sorb solid specialty chemicals and inhibitorscan save the operator from remedially retreating a well afterthe stimulation. (Photo courtesy of Baker Hughes)

able commercially for a number of years, it is a grow-ing application in the Eagle Ford Basin.

Ultra-lightweight proppantWith more favorable economics, many operators aregravitating toward oil-bearing Eagle Ford formations,which may only be a few thousand feet deep. At theseshallower depths, Baker Hughes has seen significantpotential for the application of their BJ LiteProp ultra-lightweight proppant, which provides improved trans-port properties in low- or no-polymer frac fluidsystems, thus minimizing residual damage and offer-ing greater effective frac length with maximum pro-ducing zone conductivity.

“[LiteProp] will allow us to get more proppant fur-ther into the fracture, resulting in a better distributionthan we can get currently with more conventional prop-pants that have the potential to improve production inshallow Eagle Ford reservoirs,” Royce said.

The low-density proppant (specific gravity of 1.08)provides a more uniform proppant distribution acrossthe entire fracture. The technology also allows theoperator to adjust several variables, such as pumpingrate and pressure, fluid viscosity, and proppant load-ing in different applications. The inherently slow set-tling rates can enhance proppant coverage, while theability to use lower viscosity fluids can enhance pene-tration and frac height containment. Post-treatmentproductivity analysis of wells fractured with low con-centrations of ultra-lightweight proppants indicatesthat a partial monolayer has been achieved.

Optimal fracture placementWith the merger of Baker Hughes and BJ Services,technology teams within the companies beganworking together to develop technologies that offerthe best stimulation results. These technologiesinclude optimized fracture placement, types of treat-ment, and completion strategies, among others.

“When talking about spacing frac treatments, forexample, the current convention is to break up thehorizontal into equal increments,” Royce said. “Weare starting to look at where to best place the frac-tures, the perforations, or ports for sliding sleeves.

“By maximizing available technologies, we canbegin to determine areas along the horizontal thathave greater potential production. There are some sec-

tions where we might put in more stages,” he added. “Conversely, there may be one long stage with

low potential production, so minimal treatmentsmay be needed, or there could be sections of the hor-izontal that would not benefit from stimulation,”Royce continued. “The idea is to combine tech-nologies and optimize the well.”

Developments in coiled tubing-based fracing Halliburton has used its CobraMax coiled tubingfracturing service in the Marcellus and the CanadianBakken basins with success and planned to beginusing the technology in the Eagle Ford by mid-2011. The service enables placement of a virtuallyunlimited number of frac stages in a horizontal section with the flexibility of on-demand, down-hole changes in proppant concentration.

“We have hydraulically fractured and stimu-lated [Marcellus and Bakken] wells with as goodor better production using half the footprint,half the trucks, half the equipment, and half thepersonnel,” said Stephen Ingram, technologymanager, Houston Business Unit and SouthTexas for Halliburton.

The recent development in CobraMax servicecombines coiled tubing-based fracturing, hydra-jet perforating, and downhole mixing and enablescompleting multiple intervals assuring that allintervals receive the designed proppant volumes,according to the company. CT is used to hydra-jetperforations and in the individual fracturingtreatments of each interval. The process does notrequire removing the coiled tubing from the wellbetween perforating and fracturing treatments, sounplanned events such as early screen-out can beremediated immediately with minimal impact onoverall completion costs and process efficiency.

The process enables managing the proppant con-centration at the perforations. A downhole mixingprocess combines a proppant concentrate (usually20 ppg proppant in water) being pumped down theCT with clean treatment fluid being pumped downthe annulus. By managing the pump rates, a mix-ture of the desired proppant concentration is cre-ated downhole immediately before entering theperforations. The process also enables unique and



aggressive treatment schedules such as pumping ahigh proppant concentration followed immediatelyby a low concentration (slug/sweep) to encouragediversion within the reservoir to enhance connec-tivity to a larger portion of the created fracture sys-tem. Proppant plugs are used at the end of eachfracture treatment not only to isolate previouslystimulated intervals but also to maximize near-well-bore conductivity.

The same CT and bottomhole assembly can beused to perform final wellbore cleanouts, makingthe system a single-trip completion operation. Treat-ing intervals individually substantially reduces thehydraulic horsepower required, reducing the equip-ment footprint, the carbon emissions, and the num-ber of personnel onsite.

A case studyAn operator in the Marcellus Basin wanted a methodto fracture 30 intervals with lower risks than conven-tional plug and perf. Halliburton used its CobraMaxservice with downhole mixing in the well. Theslug/sweep proppant schedule was successfully used toachieve diversion inside the reservoir. Indications ofearly screen-out were mitigated by high-rate, low-con-centration proppant slurry overflush of perforationsusing downhole mixing control, allowing the treat-ment to continue. One early screen-out did occur andwas mitigated by circulating the excess slurry to surfacewith a total impact on the process of less than sixhours.

Hydraulic horsepower requirements werereduced to 15,000 hhp compared with 30,000 hhprequired for a conventional plug and perf. Opera-tions were conducted in a continuous process witha single trip into the well bore, leaving the comple-tion cleaned out to TD and flowing up the casing.Time between treatments was reduced to about 40minutes compared with four hours per stage usingconventional plug and perf methods, which requirea trip in and out of the well.

Diverting agentsHalliburton has been using a biodegradable divert-ing agent during fracture operations in the BarnettField and recently began using the method in EagleFord. The company’s BioVert NWB near-wellboretemporary diverting agent is the industry’s firstchemical diverter proven to meet the requirementsof fracturing, according to the company. The agentprovides diversion by sealing perforations, then dis-solving and disappearing, leaving perforations, frac-tures, and well bores open.

“We are using BioVert diverter in the MaverickBasin where Eagle Ford’s heavier oil is located, help-ing operators create more effective fracture net-works,” Ingram said. “The diverting agent sustainshigher casing tubing pressures and more sustain-able production where it is challenged due to lowerbottomhole pressures.”

The diverting agent enables faster completionoperations at lower cost by reducing the number ofpumping stops during multistage fracturing. Theagent can provide temporary isolation of newlystimulated perforation clusters within the treat-ment interval. The material has two distinct parti-cle sizes. The larger size blocks the majority of aperforation, and the second smaller size bridges onthe larger particles to reduce permeability by 95% ormore. The perforations receiving the early fluid andproppant volumes of the treatment stages can betemporarily isolated, diverting further treatment toadditional sets of perforations. This procedure canfacilitate longer laterals, reducing the number ofperforating runs and frac plugs required.

A case studyBioVert NWB diverter had been used in the Bar-


Multiple particle sizes of BioVert NWB diverter help achieve bridging for a highly effective seal and diversion to another designed zone. (Image courtesy of Halliburton)

nett Shale prior to being introduced in Eagle Ford.During the original completion of one horizontalwell in Barnett, the casing in the vertical sectionparted with only 50% of the stimulation programcompleted. When the casing was patched, it pre-sented the dilemma of a restriction above the hori-zontal lateral and subsequently lowered the pressurerating for the entire casing string.

A redesign of the completion program wasrequired since the traditional pump down plugsand perforation guns could not pass through thecasing patch. The key to a successful completion wasto ensure the new perforations could be isolatedbelow the restriction. Also, any technique mustfunction at the reduced pressure rating of the cas-ing patch. The diverting agent was pumped in alow concentration as its own unique stage withinthe frac treatment.

During treatment the casing pressure dictatedpumping rates, sand volumes, and diverting stages.On-site real-time evaluation of the treatment’s effec-tiveness further optimized the sand volumes, divert-ing stages, and subsequent acid stages. The pressureresponse from one diverting stage was over 1,200psi, more than adequate to redirect subsequentstages. Once the well was cleaned out of bridgeplugs, it was brought online at production rates inthe upper 10% of the wells that make up this par-ticular production unit.

Record-setting bit runs“A year ago, a typical Eagle Ford well profile startedwith 14 3⁄4-in. hole, 9 7⁄8-in. intermediate, and then to8 3⁄4-in. curve and lateral,” said Guy Lefort, Hal-liburton’s U.S. Southern Region Drill Bit technol-ogy manager. “Today, operators have moved totwo-string wells with a 12 ¼-in. section and an 8 ¾-in. intermediate, curve, and lateral section.”

Operators have been somewhat successful indrilling the intermediate, curve, and lateral withone bit and one bottomhole assembly.

Halliburton’s Drill Bits and Services unit’s FXDmatrix body bits are more durable and erosionresistant than steel body bits, according to the com-pany. “We definitely have rate of penetration [ROP]leading performance using the matrix body bit inthe Eagle Ford,” Lefort said. “The matrix body bit

provides durability and design flexibility advan-tages as its tungsten carbide copper alloy matrix isvery erosion resistant and more durable, from ahydraulics standpoint.”

In one record-performance run, an 8 ¾-in.FXD54 bit drilled the entire vertical, curve, andlateral in a single run, setting the field record forthe fastest lateral and lowest cost per foot in EagleFord’s Briscoe Ranch Field in Maverick County.The bit drilled 8,595 ft in a single run at an aver-age ROP of 102.93 ft/hr. The bit drilled from thecasing shoe to TD through the abrasive OlmosFormation, built the curve at 7°/100 ft, anddrilled over 4,400 ft of lateral.

In another Eagle Ford well, an 8 ¾-in. FXD55Mbit drilled 8,701 ft in the vertical, curve, and lateralsections at an average ROP of 91.1 ft/hr whiledrilling the curve and building to 10°/100 ft at 64.6ft/hr. The bit lateral performance included 40% slid-ing to maintain the tight target window andrecorded instantaneous rates of penetration for 210to 250 ft/hr.

The company’s Design at the Customer Inter-face (DatCI) program helps achieve these record bitruns. DatCI is a continuous improvement loopthat uses a global network of trained ApplicationDesign and Evaluation (ADE) specialists who workdirectly with the customer to define application-specific bit solutions. The development process isgreatly speeded and reduces the chance of misin-terpreting the customer’s needs.

The ADE specialists have local knowledge as well asglobal experience and work with IBitS 3-D bit designsoftware to optimize the design and also provide theADE with a direct link to manufacturing. The ADE canwork in customers’ offices or at the rig site.

“We can fine-tune designs for specific applica-tions such as Eagle Ford and make bit designchanges quickly based on what we learn from pre-vious runs and at the local level,” Lefort explained.“We have the design specialist with the customer,looking at the bits being used, understanding anydeficiencies, and improving the next bit with first-hand knowledge.”

High build rate rotary steeringSeveral companies have developed high build rate



rotary steerable systems (RSS) that can kick offdeeper in the well and land earlier in the reservoir,extending the productive horizontal well section.The Schlumberger hybrid PowerDrive Archer highbuild rate RSS combines point-the-bit and push-the-bit steering and can drill the vertical, curve, andlateral sections in one run. The tool’s internal padspush against an articulated sleeve pivoted on a uni-versal joint to point the bit. It also enables openholesidetracking at any point in the well because ofreduced dependence on wellbore contact.

It can increase ROP and deliver a smoother bore-hole that allows easier casing runs, more uniformcementation, and improved stimulation programs.The PowerDrive Archer has built curves at morethan 17°/100 ft dog leg severity (DLS) with 8 ½-in.bit in the Eagle Ford. With all external parts of theRSS continuously rotating, even at such high DLS,hole cleaning is improved, thus reducing the risk ofstuck pipe. At press time, more than 30,000 ft hadbeen drilled in the Eagle Ford with this RSS.

Most wells in the Eagle Ford Basin are drilled usingconventional motors with a high percentage of slideintervals required to build curves up to 10°/100 ft. Asa result, ROP is reduced along with the potential riskof running casing problems due to high wellbore tor-tuosity in the curve and lateral sections. On the otherhand, continuous rotation greatly reduces microdoglegs and increases ROP by eliminating sliding inter-vals. In the Eagle Ford play, use of the RSS increasedROP by 85% and consequently reduced the cost perfoot by 27% compared to conventional motors.

In a multiwell project, the RSS improved the aver-age ROP in the curve, drilling 85% faster than con-ventional motors in 10 wells. Tortuosity in the curveand lateral was greatly reduced, and the operator foundfor the first time that casing could be run to bottomwithout rotating.

Channel fracturing Channel fracturing, offered by Schlumberger com-mercially in its HiWAY, flow-channel hydraulic frac-turing technique, involves mixing fibers withproppant to create channels through the fracturenetwork to enhance conductivity (Figure 1). Ratherthan leaving fracture flow dependant on proppantpack conductivity, HiWAY creates stable channels

for hydrocarbons to flow through, increasing theeffective fracture conductivity. In areas in whichfracture conductivity is not limiting, HiWAY alsoprovides for improved production by increasing theeffective area of contact with the reservoir, accord-ing to the company.

“There are four items critical to the success ofHiWAY,” said John Lassek, engineering managerfor North America Land. “The first is a pulsingtechnique that we use to create the channels. On thesurface we use specialized equipment to alternatelypump slurry and clean fluid, and we create thesepulses very rapidly.”

“Second is the fibers we use in the pulses in orderto keep the fractures coherent and prevent themfrom homogenizing. Third, we use fit-for-purposeperforation strategies to promote creation of thechannel network. Lastly, but not less important, isthe geomechanical modeling that goes into under-standing where this technique is applicable andwhere it is not.”

“Two key aspects that make HiWAY work arethe addition of fibers and understanding the dis-tance the channels are spaced,” said Matt Gillard,stimulation product line manager for North Amer-ica Land. “The fibers prevent everything from col-lapsing and assure the channels stay in place duringthe closing of the fractures. The second key aspect


Figure 1. The HiWAY technique creates highly conduc-tive flow channels so hydrocarbon flow is no longer lim-ited by proppant conductivity. (Image courtesy ofSchlumberger)

is understanding the spacing of the channels, thewidth of the channels, and how that is related to thegeomechanics of the well.”

The technique involves a unique combinationof placement methods, materials engineering, com-pletions techniques, and process control equipment,the company said. The stability of the flow channelsis ensured by using a proprietary fiber, which main-tains the structures from surface to reservoir untilthe fracture has closed and the in-situ stress of therock takes over.

The productivity of the fracture is decoupledfrom the actual permeability of the proppant used,so rather than flowing through the proppant pack,hydrocarbons flow through stable channels —meaning infinite fracture conductivity. Traditionallosses in proppant pack conductivity from crushing,fines, fluid damage, multiphase flow, and non-Darcy effects are eliminated, ensuring more fluidand polymer recovery.

A case studyPetrohawk wanted to improve production and esti-mated ultimate recovery from its Eagle Ford wells inthe Hawkville Field. The field has very high fracturegradients and high bottomhole temperatures at depthsbetween 10,000 and 13,000 ft. Since the discovery ofthis section of the Eagle Ford in 2008, the formationhas been stimulated typically with multistage hori-zontal completions with high-rate slickwater treat-ments. Recently, however, there has been a trend to usepolymer-base crosslinked and hybrid treatments,which led to a moderate improvement in production.

Petrohawk and Schlumberger implemented theHiWAY technique in two wells to build an assessment.Results from the two wells were compared with thosefrom valid offsets previously stimulated by conventionaltechniques. The results indicated that channel fracturinggave the first well fractured with the HiWAY techniquean initial rate of 14.5 MMcf/d, a 37% higher initial gasproduction than the best comparable offset well. Thetechnique gave the second well a maximum initial rate of820 b/d, a 32% higher initial oil production rate than thebest comparable offset. Additional wells have been com-pleted for Petrohawk and other companies using thechannel fracturing technique, and all have shown pro-duction trends consistent with the initial test wells,

according to Schlumberger. More than 800 HiWAYtreatments have been performed in the Eagle Ford Shalefor seven operators over the last 10 months.

Better stimulation“While most clients are still treating the Eagle Fordlike a geometric play with 250 ft to 300 ft stages anduniformly spaced perforation clusters, some clientsare beginning to design optimized completions,”Gillard said. “Using logging while drilling [LWD],real-time steering corrections can be made to assurethe well stays in zone.

“Additionally, the LWD measurements can beused to group frac stages in similar anisotropicmechanical property zones or avoid swelling clays,”Gillard continued. This increases the likelihood ofall perforation clusters contributing to production.A recent study of over 100 wells showed that nearlyone-third of perforation clusters don’t contributeand two-thirds of production comes from one-thirdof the perforation clusters.

“We use LWD as a cost-effective measure tounderstand how the reservoir quality changes alongthe well bore and use that information to intelli-gently place the fracture stages,” Gillard explained.“We are beginning to see the implications of thismethod in the Eagle Ford.”

“Most of our customers want to stimulate theentire lateral but to do that effectively the rock typeshave to be grouped together,” Lassek said. “So, likestresses will be together and like natural fractureswill be together, among other criteria.

“We have a fairly rigorous methodology where wegroup like rock together and complete them at thesame time to effectively complete the entire lateral,”Lassek added.

In the Eagle Ford, Schlumberger drilling tech-nologies are provided through PathFinder, which hasan extensive portfolio of tools to meet the variouswell evaluation needs. Real-time images for steering inthe lateral well section are typically obtained fromazimuthal GR or azimuthal density readings. For-mation stress along the lateral and minerologicalassessment obtained through multifunctional LWDtools give lateral log type and high-resolution resis-tivity imaging in waterbase muds from a wide rangeoffering of proprietary tools and technologies.



A combination of these measurements with anaccurate understanding of well placement is used toderive reservoir and geomechanical properties tooptimize the completion design and enhance thestimulation treatment.

A case studyAn operator drilling wells in the Eagle Ford ran LWDnuclear and acoustic tools with the intent of analyzingthe impact of formation heterogeneity along the lateral.This was done with a detailed well placement modelobtained through imaging, capturing standard triplecombo measurements, and calculating stress variability

along the well. These measurements were then used tocompute reservoir properties where an optimal casingcompletion design consisting of multilength stages andvariable perforation cluster spacing was recommended.Stages are selected such that similar rock properties aregrouped in each stage. Perforation clusters are chosenbased on the reservoir and completion qualities. Thisincludes stress profile and mineralogy from formationevaluation to optimize the fracturing strategy. This opti-mized design would improve the overall completioneffectiveness compared to conventional “geometric com-pletions” consisting of uniform stage lengths and fixedperforation cluster spacing.

Figure 2. This image shows a composite well assessment of one stage with perforation clusters selected from a geometriccompletion design indicated by black triangles and optimized completion design in green. The actual positioning of thestages is represented by yellow and blue shading in the bottom row with blue being a geometrically completed stage. Inthis case the maximum stress difference between the maximum and minimum stressed perforation cluster has been re-duced from 1527 psi to 235 psi. The ELAN volumes are an elemental analysis based on neutron, density, and resistivitymeasurements and show volumes of such things as clay, calcite, kerogen, and free oil. The next row is effective poros-ity. While there is some indication at depth x450 that the mineralogical volumes change it is quite clear from the effectiveporosity that there is variability. The next three rows: fracability, poisson ratio, and stress are derived from acoustic meas-urements and density. A geometric completion is a strictly mathematical division of the productive well section with noregards to formation changes. Note how the final row, perforations, has four evenly spaced perforation clusters placedat points of variable stress, mineralogy, and porosity. The green arrows indicate perforation points selected based onformation properties. (Image courtesy of Schlumberger)


The image in Figure 2 shows an analysis of acomposite log consisting of nuclear and sonic meas-urements. The stage shown is based on a geomet-rically planned completion with 19 equal stages,each 284 ft in length, and four perforation clustersper stage spaced at 71 ft. The location of the perfo-ration clusters is indicated with small rectangularsquares in the perforation row. The five greenarrows in the same row show optimized cluster posi-tion selected with consideration of stimulating sim-ilar stress points across each stage. Note that thestages as determined by the two selection processesbegin and end at different depths, perforation clus-ters are slightly shifted, and there is an additionalperforation cluster in the optimized casing com-pletion design. In this case, the stress differencebetween the maximum stressed perforation clusterand the minimum stressed cluster in the stage isreduced from 1,527 psi in the geometric completionto 235 psi in the optimized completion. Based onsimilarity in stresses, the company recommendedslightly larger stage lengths. This reduced the totalnumber of stages from 19 to 16 stages.

Figure 3 shows a comparison of maximum dif-ferential stress in each stage between a geometric

completion and that of the optimized casing com-pletion design. While the differences in stage lengthsmake a direct comparison of each stage impossible,it is clear that small adjustments in the perforationcluster positioning significantly reduce stress vari-ation across perforation clusters in a well bore. Thismethod eliminates large differential stresses duringcompletion of each stage and stimulates a greaterpercentage of perforation clusters.

Fracology program Exploration of the Eagle Ford Shale is fairly recent,having taken place in just the past couple years.“The jury is still out on the evolutionary processthat takes place to determine what frac method isthe best to apply to deliver the maximum produc-tion from the reservoir,” said Frank Zamora, direc-tor of Chemical R&D for Weatherford. “Most ofthe companies are not doing pre-frac or post-fracdue diligence to accurately analyze if one methodhad better results than another method.”

“Eagle Ford is complex and difficult because,first, it is a carbonate-based reservoir as opposed toquartz or clay-based reservoirs in other shales,” saidRay Miller, area engineer, South Texas for Weather-

Figure 3. This image compares the maximum and minimum stress perforation clusters across the entire well bore.Using an optimized completion resulted in lower differential stresses gave the completions team confidence in in-creasing the stage length. This resulted in a reduction of three stages and stimulates a greater percentage of per-foration clusters. (Image courtesy of Schlumberger)



ford. “Second, there are three different layers: anupper area that produces oil, a middle section thatproduces condensate and wet gas, and the deepestsection that produces dry gas.

“The reservoir also is non-uniform and not abasin-type pattern, with several up dips and downdips,” Miller continued, “and the thickness variesdramatically. The assumption that it is homoge-neous rock and homogeneous thickness along thehorizontal is a wrong assumption.”

To assess the entire stimulation process, Weath-erford uses its Fracology concept whenever it can.The goal of the concept is to gain as much infor-mation as possible to determine the best stimula-tion operation and the optimal frac placement,including using microseismic, real-time mud log-ging, laboratory analysis, and pressure measure-ments during and after the job to gain a betterunderstanding for the next frac.

Fracology’s four steps are evaluate, analyze, exe-cute, and verify.

The first step is formation evaluation involvinggeochemistry to determine organic richness;analysis of shale properties to measure porosity,permeability, mineralology, and other rock prop-erties; desorption and adsorption to identify gascontent, quality and storage capacity; and rockmechanics to determine the mechanical strength,Young’s modulus, Poisson’s ratio, and proppantembedment characteristics.

When drilling has begun, wellsite services, the sec-ond step, becomes an integral part of the information

loop. Wellsite services employ avariety of analytical tools includ-ing source rock analysis to measure available hydrocarboncontent, potential hydrocarbongeneration, total organic content,and thermal maturity and to aidin kerogen typing as well as con-version. Mud gas analysis charac-terizes formation gas samplesfrom the surface in real time. Theempirical data from these testshelps to determine hydrocarbonfluid types and contact points,identify pay zones, support

geosteering, determine reservoir characterization inhorizontal wells, and inform well placement and com-pletion operations based on brittleness.

When it’s time to execute the fracture, the processcan be fine-tuned for maximum hydrocarbon yield.Armed with data from the well site and continuousmicroseismic feedback, frac crews can plan the opti-mal fracture design and respond to geological struc-ture complexities and changing stress conditions asthe fracture operation proceeds.

In the final step, verification, real-time micro-seismic data gathered during fracing operationsand in-treatment-well microseismic surveys con-ducted on pilot wells can be used to not only mon-itor reservoir behavior but also to adjust fracturingparameters on the fly for optimum results. The dataprovides detailed information about the quality ofthe completion and provides the only 3-D view of awell’s drainage network.

Microseismic surveys form the key technologyfor maximizing the economic development of anunconventional reservoir. They can identify unex-pected fracture behavior and reduce the cost andtime of fracing operations. Microseismic can lead tohigher production rates, lower decline rates, andless water incursion. The company’s microseismicmonitoring service produces fracture maps and can“see” fluid-front movements during production.The monitoring service can also result in hydraulicfracturing mapping, enhanced recovery operations,carbon capture and storage, and production mon-itoring, among other applications. n

GC Tracer, a surfacegas detector system,enables operators

to make fast, knowledgeable decisions by

providing a full rangeof petrophysical and

geosteering data. (Illustration courtesy

of Weatherford)

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