54 Oilfield Review

The Cutting Edge in Drilling-Waste Management

Thomas GeehanAlan GilmourQuan GuoM-I SWACO Houston, Texas, USA

For help in preparation of this article, thanks to Jim Redden,M-I SWACO, Houston, Texas.FracCADE is a mark of Schlumberger. Brookfield is a mark ofBrookfield Engineering Laboratories. Fann 35 and Marsh aretrademarks of Fann Instrument Company. RECLAIM is a markof M-I LLC. 1. For more on multilateral wells: Fraija J, Ohmer H,

Pulick T, Jardon M, Kaja M, Paez R, Sotomayor GPG and Umudjoro K: “New Aspects of Multilateral Well Construction,” Oilfield Review 14, no. 3 (Autumn 2002): 52–69.

As borehole complexity increases, operators struggle to comply with stringent waste-

discharge guidelines while meeting drilling-performance demands. Today, advances

in drilling fluids and cuttings-management techniques are allowing operators to use

the most efficient drilling-fluid systems while effectively removing drilling waste from

the environment.

An unfortunate side effect of the quest forhydrocarbons is an accumulation of debris thatwas removed to access those resources. Moderndrilling operations generate several wastestreams varying from contaminated runoff waterto material packaging; however, the majority ofthe waste is associated with the excavatedmaterial, or cuttings, from the borehole. Untilthe 1980s, little thought was given to the disposalof cuttings and excess drilling fluids. Typically,these materials were discharged overboard inoffshore operations or buried when drilling inland-based locations. In the 1980s and 1990s,global environmental awareness increased andthe oil and gas industry, along with its regulators,began to understand and appreciate thepotential environmental impact of drilling waste.

During this same period, advances indirectional-drilling technology ushered in a newage in wellbore construction. Although previousgenerations of drillers often found it difficult todrill vertical wellbores, by the 1990s, the trend inwell trajectories had changed from vertical tohorizontal. Rapid technological improvementssoon brought horizontal drilling to the forefront.Operators realized significant improvement inwell economics by drilling multiple directionalwells from a single platform or by drillingcomplex multilateral wells from one borehole.1

These advances reduced surface footprints,improved well construction economics, consumedfewer materials, and increased production fromeach well.

The combination of increasing environmentalawareness, new discharge regulations andchallenging drilling situations led the oil and gasindustry to develop new drilling-fluid and waste-management technologies to support theseadvanced wellbore designs, while at the sametime promoting environmental stewardship. Inthis article, we explore technologies developed to remove drilling wastes from the environmentby placing them in hydraulically generatedfractures deep beneath the Earth’s surface. Wealso describe new technologies that are helpingto reduce waste by recovering costly nonaqueousdrilling fluids.

Oil Muds—More Common Than Ever BeforeOil-base muds (OBMs) came into general use inthe oil field in 1942. Early oil-external fluids werecomposed primarily of asphalt and diesel fuel.These muds helped drillers stabilize water-sensitive shales, provided lubricity for coringoperations and minimized reservoir damage.

As the directional-drilling era took hold inthe late 1980s, OBMs demonstrated a superiorability to reduce friction between drillpipe andformation. Rotary torque and drag weresignificantly reduced from levels commonlyobserved when using water-base muds, allowingdrillers to reach farther and drill trajectorieswith greater tortuosity.

Winter 2006/2007 55

The inhibitive quality of OBMs also helpeddrillers reduce the risk of borehole failureassociated with long horizontal boreholes. AnOBM owes its inhibitive quality to its oil-wettingnature—water contact with formation clays iseliminated in an oil-wet environment. As such,formations drilled with oil-base drilling fluidtend to experience less chemical dispersion thanthose drilled with water-base muds. Just asimportant, this inhibitive quality minimizes thedissolution of cuttings as they are being pumpedfrom the bit to the surface. Providing that holecleaning capacity is adequate, in oil mud, ornonaqueous environments, cuttings typically

arrive at the surface in much the same conditionas they left the bit. Surface solids-controlequipment is more efficient with larger cuttings,and the dilution volume required to reduce finesolids content in the drilling fluid is minimized.Ultimately, the total project waste volume issignificantly reduced.

The advantages of OBMs came at a price. Asmentioned previously, the 1980s and 1990s werea time of environmental awakening for the oiland gas industry. Regulators began to discouragedischarge of mud and cuttings, while manycountries prohibited the discharge of oil-wetcuttings and waste-oil mud altogether.

From the 1990s to the present, the drillingindustry has witnessed a revolution in OBM andoily-waste management. Less toxic and moreenvironmentally acceptable synthetic-base muds(SBMs) have replaced diesel and mineral-oilmuds in many areas. Operators now have thebenefits of nonaqueous drilling fluids coupledwith technologies that help to manage cuttingsand excess oil- and synthetic-base muds. ModernSBMs offer the nonaqueous qualities of tradi -tional OBMs but with less toxicity and higherdegrees of biodegradability. In some areas,depending on environmental regulations, cut -tings coated with SBMs are buried, discharged tothe sea or made environmentally benign throughbioremediation processes.2 However, not all areasare suitable for this type of waste management,and more advanced processes are required toprotect the environment while drilling (left).

Putting Oily Waste in Its PlaceOn any drilling project, operators must achieve abalance between minimizing environmentalimpact, maintaining borehole stability andmaximizing drilling efficiency. Since 2001, theuse of nonaqueous drilling fluids, both oil- andsynthetic-base, has increased on average by 2%per year, a trend that is likely to continue (nextpage, top). Some formations are more easilydrilled using nonaqueous drilling fluids,hereafter referred to as oil-base fluids, owingprimarily to the inherent inhibitive andlubricative qualities of these fluids.

When oil-base drilling fluids are used in thedrilling process, rock cuttings carried by thedrilling fluid through the borehole becomecoated with a residual layer of the oil. Even whendrilling with water-base mud, cuttings from oil-rich shales and sands are transported to thesurface for proper disposal. In many areas,stricter environmental legislation and increasesin the cost of cuttings-cleaning techniques haveeliminated the option of discharging oil-wet oroil-containing cuttings and related drilling wasteto the sea.

56 Oilfield Review

2. Young S and Rabke S: “Novel Fluid Design Can EliminateOBM-Cuttings Waste,” paper SPE 100292, presented atthe SPE Europec/EAGE Annual Conference andExhibition, Vienna, Austria, June 12–15, 2006.

3. Moschovidis ZA, Gardner DC, Sund GV and Veatch RW:“Disposal of Oily Cuttings by Downhole PeriodicFracturing Injections, Valhall, North Sea: Case Study andModeling Concepts,” paper SPE 25757-PA, presented atthe SPE/IADC Drilling Conference, Amsterdam,February 22–25, 1993; also in SPE Drilling & Completion 9,no. 4 (December 1994): 256–262.

> Philosophy of cuttings reinjection (CRI). The modern oil field is rapidly moving away from thetraditional methods for disposing of drilling waste. In a more “cradle to grave approach,” manyoperators are choosing to return drilled cuttings back to their origin deep beneath the Earth’s surface.Although various placement methods are available, many inject cuttings and other drilling waste intononproductive or depleted reservoirs. Injection zones are most often located above the producingreservoir as shown here.

Caprock formation

Injection zone

Reservoir

50-in. conductor

Riser

Wellhead

Riser

WellheadPlatform

Cuttings separated, slurrifiedand injected from the surface

Impermeable caprock(salt, chalk or sandstone)prevents fractures from

propagating to the seabed

30-in. conductor

New wellbeing drilled

13 3⁄8-in. casing13 3⁄8-in. casing

9 3⁄8-in. casing9 3⁄8-in. casing

7-in. liner Drill bit

Production andreinjection well90

0 m

Cuttings slurryProduced oilDrilling fluid

Winter 2006/2007 57

An example of stricter environmentaldischarge regulation occurred in the North Seain late 1990. Two years prior to regulatorychanges, the Norwegian State Pollution ControlAgency announced a tightening of regulations foroffshore disposal of drilled cuttings. EffectiveJanuary 1, 1993, the allowable oil on cuttingsdisposed by discharge to the sea was reducedfrom 6 to 1 percent by volume. Technologyavailable at the time could not reduce oil oncuttings to such a low level.3

BP, then Amoco Production Company, beganpreparing for this regulatory change in theValhall field by first evaluating the options.Engineers considered transporting oil-wetcuttings to shore for processing, drilling withwater-base rather than OBM, processing thecuttings offshore and disposing of cuttings bysubsurface injection.

Initial studies indicated that cuttingsreinjection (CRI) would have the least impact onthe environment while providing an economicalsolution to cuttings and oily-waste disposal. In atypical CRI operation, cuttings are mixed withseawater, processed by grinding or othermechan ical action to form a stable viscous slurry,pumped down a dedicated disposal well orthrough the annulus between casing strings onan active well, and forced under pressure into

formations (below). This process creates ahydraulic fracture in the formation thateffectively contains the slurry. At the end of theinjection program, the well or annulus is typicallysealed with cement.

Before investing in this new technology,Amoco initiated an extensive testing program to assure that periodic injections would bepossible and to gather pressure-response data

during and after injection for modeling andmodel calibration.

Cuttings were prepared for injection by firstmixing with water in a 50-bbl [8-m3] tank, thenrecirculating the slurry through a centrifugalpump modified with carbide-tipped impellers togrind the cuttings at a rate of 5 to 10 bbl/min [0.8 to 1.6 m3/min]. Cuttings were added to aseawater-base slurry to achieve a density of

> Options for CRI. Cuttings (red) can be injected into wells of many configurations. Shown are injection into a 20 x 133⁄8-in. annulus; a 133⁄8 x 95⁄8-in. annulus;reinjection above the reservoir, then drilling to TD and producing; injection inside a 6-in. redundant well; and injection into a dedicated well. In each ofthese examples, the wells have been cased, cemented and in some cases perforated, to facilitate cuttings injection and isolate other parts of theborehole from the injection process.

Annular Injection IntoExisting Production Well

Annular Injection IntoExisting Production Well

Annular Injection Drill andReinject Simultaneously

Tubing Injection InsideExisting Redundant Well

Tubing Injection InsideDedicated Reinjection Well

20 in.

13 3⁄8 in.

9 3⁄8 in.

20 in.

13 3⁄8 in.

Injectionzone

Injectionzone

9 5⁄8 in.

20 in.

13 3⁄8 in.

Injectionzone

9 5⁄8 in.

7 in.

Reservoir

20 in.

13 3⁄8 in.

Injectionzone

9 5⁄8 in.

6 in.

ReservoirInjectionzone

9 5⁄8 in.

6 in.Cement

20 in.

> Increasing use of nonaqueous fluid. Statistics provided by M-I SWACOindicate an increased use of nonaqueous fluids since 2001. These fluidsinclude both conventional and synthetic muds.

20

22

24

26

28

30

32

34

36

Non

aque

ous

fluid

s, %

Year200320022001 2004 2005

10 lbm/galUS [1,198 kg/m3]. Mixing continueduntil the slurry was homogeneous and the slurryhad a Marsh funnel viscosity of 45 to 60 s/qt[approximately 45 to 60 s/L].4 This process wasrepeated until a total of 1,000 bbl [159 m3] hadbeen prepared. The total volume was theninjected into a formation at a depth of almost8,000 ft [2,438 m] TVD.

Data gathered during multiple injections intoa shale-capped sandstone formation showedstable pressure behavior with each injectionsequence, indicating that the periodic injectionshad created multiple or branched fractures inthe same region of the reservoir rather than onecontinuous fracture. The data also indicated thatperiodic fracturing injections changed the in-situclosure stress of the formation. Engineerstheorized that the cuttings introduced into theformation created a local volume. Because the

cuttings remain localized in what became knownas the disposal domain, changes in closure stresscould be expected to be permanent and repeat -able.5 Stress changes resulting from thermo -poroelastic stress effects were also noted. Theseconcepts will be discussed in more detail later.

Data gathered during these tests supportedthe theory that misfit strains caused by theperiodic placement of cuttings in fracturesintroduced into an elastic field, such as reservoirrock, can be calculated using basic elastic-theoryequations. This helped Amoco engineers developmodels to better understand and predict fractureand disposal-domain behavior related to cuttings-injection processes.

During the multiyear evaluation program,engineers injected fluids ranging from water andsand in early tests to actual cuttings in latertests. By the end of the evaluation project, morethan 340,000 bbl [54,000 m3] of injection slurry

containing more than 76,000 bbl [12,000 m3] ofcuttings were pumped into injection wells.

In these early tests, Amoco demonstratedthat the injection of cuttings can be a cost-effective means of oily-waste disposal whencompared with onshore disposal.

At the time, engineers estimated aUS$550,000 cost-savings per Valhall well usingcuttings-injection processes compared with land-based or other cuttings-disposal techniques.6

Disposal cost is not always the driver behindthe use of CRI technology. In remote orenvironmentally sensitive areas, drilling-wastemanagement can be challenging. Treatmentfacilities are often either unavailable or logisti -cally inaccessible and costly. In these situations,the injection of cuttings and other associatedwaste streams into underground formations mayoffer the only environmentally acceptable

58 Oilfield Review

4. Marsh funnel viscosity is the time in seconds for onequart of fluid to flow through a Marsh funnel. This is nota true viscosity, but serves as a qualitative measure ofhow thick a sample of fluid is. The funnel viscosity isuseful only for relative comparisons.

5. For more on the disposal domain: Peterson RE,Warpinski NR, Lorenz JC, Garber M, Wolhart SL andSteiger RP: “Assessment of the Mounds Drill Cuttings

Injection Disposal Domain,” paper SPE 71378, presentedat the SPE Annual Technical Conference and Exhibition,New Orleans, September 30–October 3, 2001.

6. Moschovidis et al, reference 3.7. Guo Q, Geehan T and Pincock M: “Managing

Uncertainties and Risks in Drill-Cuttings Reinjection inChallenging Environments—Field Experience fromSakhalin,” paper SPE 93781, presented at the

SPE/EPA/DOE Exploration and Production EnvironmentalConference, Galveston, Texas, March 7–9, 2005.

8. Minton RC: “The Pneumatic Collection, Handling andTransportation of Oily Cuttings—Two Years of FieldExperience,” paper SPE 83727, presented at theSPE/EPA/DOE E&P Environmental Conference,San Antonio, Texas, March 10–12, 2003.

> Containing injected fluids. Poorly designed reinjection projects risk waste materials leaking back to the surface through natural fractures, along faultplanes or following a poorly cemented path up the borehole (left). Depending on the specific gravity of the injected waste, some material may rise to thesurface. With proper engineering and a suitable caprock formation, waste is contained within the injection zone (right).

Suitable caprock prevents naturalor induced fractures

from propagating to seabed

Shale ShaleChalk

Fault

Hydraulically inducedfractures

Naturalfractures

Fractures FracturesFractures

Winter 2006/2007 59

method of disposal. For example, in extremenorthern and southern climates, where harshwinter weather can virtually eliminate onshoretreatment options and year-round drillingoperations, CRI may offer the only practicalsolution for cuttings and drilling-waste disposal.7

The Risks of ReinjectionAs with all E&P operations, CRI has risks. Mostoften, injection programs proceed withoutserious mishap. However, particularly in the earlydays of this technology, there were instanceswhere the path to the disposal formation, downeither casing or an annulus, became blocked,effectively shutting down CRI operations. Onrare occasions, injection slurries have migratedthrough natural fractures, hydraulically induced

fractures or poorly cemented sections of the well,then back to the seabed. This event results in arelease of injection slurry to the seafloor(previous page).

Failures such as these not only are costly inenvironmental terms, but also pose seriouseconomic risks such as operational downtime,injection-well remediation, or in the worst-casescenario, a need to drill a new injection well. CRIoperations can be jeopardized by many factorssuch as mechanical failures at the surface orundercapacity of the disposal system, causingcostly delays to the drilling project. To minimizethese risks, engineers use advanced pneumaticcollection, transportation and storage systemslike those developed by M-I SWACO to decoupledrilling and CRI operations (above left).

During times of CRI equipment failure orwhen cuttings are generated faster than they canbe processed, these pneumatic systems canrapidly move waste and oily cuttings dischargedby solids-removal equipment to storage tanks forlater processing.8 The pneumatic system cantransfer the cuttings over distances greater than100 m [328 ft] and vertically between decks of aplatform, so storage tanks can be sited at adistance from the drilling package. This avoidsthe crowding problems associated with addi -tional equipment on the drilling platform.

Downhole risks are less obvious and oftenmore complicated. Plugging of the tubing,annulus or perforations can threaten the successof a CRI operation. Solids in suspension naturallysettle during stagnant periods between injectionphases. The rate of settling is a function of time,particle size and the low shear-rate viscosity ofthe fluid. Larger particles, typically greater than300 microns, are screened out at surface to helpreduce settling potential.

However, in CRI operations, problems withsettling are often complicated by boreholedeviation and the loss of carrier-fluid viscosity atelevated downhole temperatures. Under thesecircumstances, particles settle on the low side ofthe wellbore, forming a bed that ultimatelybecomes unstable and slides downhole (above).As injection is initiated, solids in the bed arecompacted and form a solid plug, preventing

> Cuttings on the move. The flow of drilling mud helps move cuttings from the bit to thesurface. At surface, they must be removed from the mud system before the fluid is pumpedback downhole. Various solids-control equipment such as shale shakers (top left) helpseparate solids from liquid. Once captured, cuttings are typically moved around the rig byauger or pneumatic cuttings transport systems. In some cases, cuttings are stored in cuttingsboxes or storage tanks (top right) for later processing and injection. Processing equipmentsizes, grinds and slurrifies the cuttings that are then pumped into the cuttings-injection wellunder high pressures, creating storage fractures deep beneath the surface (bottom right).

Cuttings-reinjection

zone

Cuttingsblower

Cuttingsstorage

tanks

Injectionwellhead

Slurrificationunit

Strainer

Cuttingsclassifying

shaker

High-pressureinjectionpumps

Flow-controlvalve

Flow-controlvalve

Shale shaker

Cuttings box handler

> Cuttings bed slides. At angles between about35 and 70 degrees, solids (gray) that settle to thelower side of the wellbore may slide down understatic conditions, resulting in the plugging ofinjection perforations.

Cuttings bed sliding

further injection. Clearing blockages, reper fo -rating the tubing at a shallower depth or movingto another injection well are costly steps thatthreaten the efficiency of the drilling operation.

Cognizant of these reinjection risks, SakhalinEnergy Investment Company (SEIC) nonethelesschose CRI technology for drilling-wastemanagement in the harsh offshore SakhalinIsland drilling environment. CRI was selected asthe most effective drilling-waste managementapproach offshore Sakhalin Island for severalreasons. First, the discharge of drilling wastes isno longer allowed and second, shore-baseddrilling-waste management facilities are notavailable.9 Further, the area is ice-free only aboutsix months of the year; even if onshore optionsexisted, shipping to shore would limit the drillingoperational window. By contrast, drilling-wastemanagement using CRI would allow year-rounddrilling operations.

Although CRI presented the only practicalsolution for drilling-waste disposal, a previousannular injection well had become plugged,requiring a new well to be drilled for cuttingsinjection. In addition to the loss of this first well,the operator faced significant risks related to thelack of historical operational data and experi -ence, and the potential for solids dropout andsubsequent injector plugging in the newly drilleddirectional well.

The new injection well served two purposes;it would be the primary injection well duringdrilling operations, and would later be used as afield-development well. As such, it was signifi -cantly deviated and had a much larger diameterthan the typical disposal well. Both the wellborediameter and its deviation increased the risk ofcuttings settling on the low side of the injectiontubing, a situation that could potentially plug thedisposal well.

Risk management was a crucial factor forsuccess, so monitoring and quality-assuranceefforts focused on slurry design and optimization,pumping procedure design and optimization,solids-transport modeling and assurance ofappropriate shut-in intervals between batches.

Engineers selected the primary through-perforations injection point at 2,062 to 2,072 m[6,765 to 6,798 ft] MD with a backup injectionpoint of 1,756 to 1,766 m [5,761 to 5,794 ft] MD.The injection tubing was 51⁄2-in. tubing fromsurface to 1,756 m MD, and 41⁄2-in. tubing from1,756 m MD to the injection zone. Wellboreinclination varied from approximately 55° over amajor portion of the borehole to around 33°across the primary injection zone.

The injection-tubing volume of approximately150 bbl [24 m3] took three slurry batches todisplace. Limitations in slurrification tankcapacity limited the amount of slurry volume that could be mixed at one time to around 80 bbl [13 m3]. Since the tubing volume could not be displaced with one batch of slurry,cuttings in suspension could remain in theinjection string for some time. Engineers wereconcerned that the long residence time and thedeviated nature of the wellbore might cause thecuttings-laden slurry to settle and form beds ofwaste material along the low side of the injectiontubing. These cuttings beds might slide down and

plug the well during the shut-in intervalsbetween batches. Because of the high risk ofplugging, quality-control requirements for slurryrheology were critical.

Marsh funnel viscosity is a key indicator ofCRI slurry quality. For this well, engineers wereconcerned that the normal injection-slurryviscosity range of 60 to 90 s/qt [60 to 90 s/L]might not be adequate. Since gel strength andlow shear-rate viscosity (LSRV) contribute torheology characteristics that affect staticsuspension, further tests were performed on theslurry using a Fann Model 35 viscometer andLSRV analysis using a Brookfield low-shear-rateviscometer. Solids-settling tests, at a room

60 Oilfield Review

> Preinjection simulations to help predict fracture growth. This example (top) shows fracture or wastecontainment due to a stress barrier that occurs when the overlying rock is stronger or stiffer than theinjection zone. The varying color represents the fracture width in inches. In this simulation, at afracture height of around 150 ft, fracture up-growth is contained by a stress barrier, in this case, ashale with a fracture propagation pressure that is 200 psi [1.38 MPa] higher than the stress in theinjection zone. The simulator generates a probability graph (bottom) that indicates the most likelyfracture length taking into account known and unknown variables. In this case using 1,000 simulations,the probability of a fracture length less than 504 ft is no more than 5%, and the probability of a fracturelength greater than 635 ft is less than 5%. The data indicate a 50% probability that the fracture lengthwill be 570 ft.

0

50

25

75

100

0

250

750

500

1,0001,000 trials–994 displayed

Prob

abili

ty, %

Freq

uenc

y

Certainty is 90% from 504 to 635 ft

Forecast: Fracture Length (One Wing)–Cumulative Chart

466 519 573 626 679

0–200

–100

0

100

200

300

100 200 300Fracture half-length, ft

Frac

ture

hei

ght,

ft

400 500 600

0.1

Width, in.

0.2 0.3 0.4 0.5 0.6 0.7 0.9 1.0 1.1 1.20.8

Winter 2006/2007 61

temperature of l7°C [63°F] and at the estimateddownhole temperature of 60°C [140°F] were alsoperformed. Based on these data, an initial Marshfunnel minimum viscosity requirement was set at120 s/qt [approximately 120 s/L]. Engineers laterreduced the requirement to 90 s/qt afterexperience was gained with the injection system.

Critical to a successful operation wasdetermining how long slurry could be left in theinjection tubing without solids dropping out andpotentially plugging the disposal well. Engineersused gel-strength and LSRV data and a numericalmodel to predict cuttings transport, settlingvelocity and the maximum allowable residencetime. Simulation software was also used toensure optimization of operational proceduresand of the slurry rheology and solids-suspensioncharacteristics—both for periodic injection andfor shut-in stability between batches.

The simulator divided the injection-wellconfiguration into small segments. Then, funda -mental physical relationships helped numericallydetermine local solids concentrations, cuttings-settling rate, bed formation, bed sliding anderosion, and solids accumulation at the bottom ofthe well.

Engineers assumed that 80-bbl slurry batcheswould be pumped at a rate of 4 bbl/min[0.64 m3/min] and that the shut-in time betweenbatches would be four hours. The numericalsimulations demonstrated that injection at a rateof 4 bbl/min would erode any solids bed thatmight have formed in the 41⁄2-in. tubing.Simulations also showed that after four hours ofshut-in between batches, the upper solids bed(above the 51⁄2-in. tubing) would slide from 1,756to 1,935 m [5,761 to 6,348 ft] along the tubing.Since this is still approximately 125 m [410 ft]above the top of the perforations, a shut-ininterval of four hours was allowed.

CRI proved to be the most effective drilling-waste management option for SEIC’s drillingoperations offshore Sakhalin Island. Optimizationand risk-management procedures were successfulin reducing the uncertainties associated with thiscritical cuttings-injection well. The drillingwindow was extended to year-round operations,and logistical constraints associated with ship-to-shore disposal were resolved. By achieving a zero-discharge operation, this project demonstratedthat cuttings reinjection is an economically sound,environmentally friendly, long-term solution forcuttings disposal in remote and environmentallysensitive areas.

Advances in CRI ModelingOnce surface procedures and plugging risk havebeen properly assessed and managed, engineersturn their attention to fracture propagation. Theplanning phase of most CRI projects usesnumerical models to predict the propagationbehavior of the fracture relative to the injectedvolume (previous page). For productionengineers, modeling fractures is a key process tooptimize hydrocarbon recovery in low-permeability reservoirs. Today, CRI engi neers usesimilar processes to design waste-injectionprograms, reducing risk to the operator andassuring a smooth, efficient drilling process.

In CRI operations, safe containment of theinjected waste must be ensured. The extent andpropagation properties of the fracture networkcreated during fracturing operations must bepredicted with confidence; this is oftenaccomplished with three-dimensional hydraulicfracturing simulators.10 Typically, large volumesof waste are injected, creating large fracturenetworks. Waste-containment mechanisms must be evaluated during feasibility studies toidentify possible disposal zones and fracture-contain ment zones (below).

Three fracture-containment mechanisms areparticularly important in selecting a disposalformation. Formations with fracture gradientslarger than those in the target injection zone canoften prevent the fracture from propagatingbeyond the design bounds. Overlying formationswith increased fracture gradients, such as saltforma tions, are also ideal containment or sealingforma tions. A fracture may also be contained by a high-permeability formation even though its frac -ture gradient is lower. As carrier fluid leaks offinto the high-permeability formation, solid parti cles are left behind, preventing the fracturefrom growing in the high-permeability zone.

Lastly, a fracture may be contained by aharder or stiffer formation with a higher elasticmodulus. Once the fracture approaches or entersthe harder or stronger formation, the width ofthe fracture in and near the stiffer formation isreduced; thus, the frictional pressure isincreased, preventing or slowing fracture growthinto the formation. Since these fracturecontainment formations are not difficult torecognize, appropriate injection and contain -ment zones can easily be identified.

9. Guo et al, reference 7.10. Guo Q, Geehan T and Ovalle A: “Increased Assurance

of Drill Cuttings Re-Injection—Challenges, RecentAdvances and Case Studies,” paper IADC/SPE 87972,

presented at the IADC/SPE Asia Pacific DrillingTechnology Conference and Exhibition, Kuala Lumpur,September 13–15, 2004.

> Modeling fracture confinement. Advanced fracture simulators helpengineers visualize the extent and orientation of induced fractures. Injectionzones are most often capped at the top, and sometimes on the bottom, byshales or evaporite formations; this helps in containing the vertical growth of the fracture network.

Shale

Sand

Understanding the storage mechanisms incuttings-injection operations is another keyprocess for predicting the disposal capacity of aninjection well. Experts in the field tend to agreethat multiple fractures are created fromintermittent cuttings-slurry injections. In a recentlaboratory evaluation, a series of color-codedslurries was injected into several 1-m3 blocks ofdifferent types of rocks.11 Afterwards, the blockswere split and the fractures were analyzed.Results showed that slurry injection createdsubparallel fractures. Field-pilot drill-cuttingsinjections with real-time seismic and tiltmetermonitoring and subsequent coring into thepredicted fracture networks also proved that CRIprocesses created multiple fractures. A consistentfinding of these programs is that repeated slurry

injections create multiple or branched fractures;these fractures character istically occupy anevolving region, or disposal domain.

The reason that new fractures are createdfrom repeated slurry injections is that shut-inperiods between injections allow the disposalfractures to close onto the cuttings and dissipateany pressure buildup in the disposal formation.The presence of the injected cuttings causes aredistribution of the local stresses, resulting inthe creation of new fractures with subsequentinjections. The new branch fracture will not bealigned with the azimuths of previous existingfractures; instead, a network of fractures iscreated from periodic slurry injections.

On CRI projects, the drilling-waste manage -ment plan is generally in place before drillingcommences, so modeling of uncertainties andrisks is particularly important for CRI design andengineering. Risks can be reduced by usingnumerical simulators to model uncertainties. Forexample, on a well in South America, littleinformation was available on formation proper -ties such as permeability and Young’s modulus.At the time of the disposal-well design, thedrilling program had not yet been finalized.

Therefore, the cuttings generation and requiredslurry-injection volume and rates were undefined.Because of these uncertainties, the extent of the fractures created from CRI operations was predicted as a range rather than a singlevalue (above).

Since each uncertainty has a differentdistribution and impact on CRI operations, aprobabilistic approach helped engineersgenerate a risk-based result. For example, risk-analysis results based on fracture simulationsand ranges of uncertainties helped developprobabilistic predictions of fracture extent fromthe wellbore. Simulations indicated that therewas a 90% chance that the fracture extent fromthe wellbore would be larger than 230 ft [70 m]and smaller than 270 ft [82 m], while the 50%probability value of the fracture extent would be250 ft [76 m]. Based on this result, engineersdetermined that a well spacing of 300 ft [91 m]would be adequate to avoid drilling a live wellinto a disposal fracture.

This risk-based approach can be applied tomodeling of other important CRI parameterssuch as disposal capacity. Simulations indicated

62 Oilfield Review

11. Guo et al, reference 10.12. G-function analysis is a technique to describe fracture

pressure-decline behavior. It is a nondimensionalfunction of postshut-in time normalized by the pumpingtime. Variance in fracture shape can be identified bychanges in pressure decline after shut-in that isidentified by this specialized time function. For more on the G-function: Gulrajani SN and Nolte KG: “Fracture Evaluation Using Pressure Diagnostics,” inEconomides MJ and Nolte KG: Reservoir Stimulation,3rd Edition. Chichester, England: John Wiley & Sons Ltd(2000): 34–46.

> Fracture-length sensitivity analysis to help predict fracture length. A fracture sensitivity study canidentify which uncertainty has the greatest impact on results. With this knowledge, plans can bemade to obtain data during drilling or logging operations to help reduce risk and improve modelingaccuracy. High (H), low (L) and baseline values (top) offer a starting point for the simulations,providing the operator with a general idea of how much waste material might be injected into theproposed zone. In this case, risk-based modeling indicates an 80% certainty that the fracture lengthwill be between 226 and 272 feet (bottom).

H

L

L

L

Leakoff

Fracture-Length Sensitivity

Batch size

Injection rate

Young’s modulus

L

H

H

H

Baseline

0

50

25

75

100

0

250

750

500

1,0001,000 trials–996 displayed

Prob

abili

ty, %

Freq

uenc

y

Certainty is 80.30%from 225.62 to 271.93 ft

Forecast: Fracture Length (One Wing)–Cumulative Chart

202.61 224.46 246.30 268.14 289.98

Winter 2006/2007 63

that there was a 90% chance that at least31,000 bbl [4,929 m3] of cuttings could be safelyinjected into this well. Assuming 20% cuttings byvolume in the slurry, this means that the disposalcapacity of this well is at least 155,000 bbl[23,849 m3] of slurry. Since the injection zonewas a permeable sandstone formation fromwhich fluid could readily leak off, the impact offluid volume on disposal capacity was ignored.

Analysis of the operational data also helpsvalidate modeling results and provides earlywarning of potential downhole problems. On awell in the Sakhalin area, a dedicated CRI wellwas drilled, and 51⁄2-in. injection tubing wasinstalled. The injection zone was a low-permeability shale formation with interbeddedsandstone layers, both above and below theperforated interval. Hydraulic fracturing simula -tions demonstrated that fractures created fromslurry injection would grow upward from theshale formation and into multiple zones.

As operations began, step-rate pump-in andfalloff tests were performed. Analysis of slurryproperties and injection-pressure data showedthe signature of fracture-height growth duringthe injections (right). More detailed analyses onthe pressure-decline data after slurry injectionsalso showed fracture-height recession overmultiple zones during the shut-in periods.Pressure and pressure-derivative plots versus aspecialized time function, often referred to asthe G-function, indicated the signatures offracture-height recession over multiple zones.12

These results were consistent with preinjectionfracture-modeling results.

Integration of the geologic evaluation,numerical modeling and pressure signatureyielded a full picture of fracture developmentdownhole. Analysis of the pressure data in thiscase allowed engineers to avoid rapid injection-pressure increases and the potential for loss ofinjectivity by adjusting the injection-rate andslurry-viscosity specifications as part of theongoing quality-control process.

Pressure Monitoring During CRI OperationsPressure monitoring forms the foundation forunderstanding how an injection well isperforming. Pressure trends over time provide akey indictor of operations performance. If thepressure rises slowly over time, this mightsuggest a normal filling of the injection zone.However, a rapid pressure rise suggests near-wellbore plugging that requires immediateattention. Conversely, a rapid drop in pressuremight indicate a leak in the system, either at thesurface or downhole. Finally, pressure data are a

key input parameter for hydraulic fracturemodels, which are used both for initial systemdesign and model validation throughout the lifeof the injection operation.

Early in a project, rock properties are notalways clearly understood, and the exact litho -logical sequence is not always known, soengineers make assumptions for a wide variety ofmodel-input parameters. This initial feasibility

study determines the range and potential storagecapacity of a hydraulically induced subsurfacefracture complex, the lateral and vertical growthof the fractures, and the anticipated pressurechanges during CRI operations (bottom). Thesesimulations provide guidance for injection-welldesign, the number of injection wells required,the pressure regime for the tubing design, andsurface-equipment specifications.

> Monitoring injection cycles. CRI engineers monitor injection-cycle pressuredata to identify trends such as fracture-height growth. The slight increase infracture initiation pressure (red) may indicate fracture-height growth,although further analysis is required for confirmation.

0

800

400

1,200

1,600

600

200

1,000

1,400

Surfa

ce in

ject

ion

pres

sure

, psi

05/12/0411:02

05/12/0415:50

05/12/0420:38

05/13/041:26

Date/time

05/13/046:14

05/13/0411:02

> Typical injection pressure and pressure falloff signatures during a single injection episode in CRIoperations. Shown here is a typical injection-pressure recording over an entire injection cycle thatincludes a pumping or injection period and a shut-in period. After pumping stops, the fracture willclose and pressure will decline, eventually reaching that of the formation. Variances or abnormalitiesin these curves help engineers identify problems in the injection system.

520

500

480

460

440

420

400

380

360

340

320

Surfa

ce p

ress

ure,

psi

Time, h

Last pumping pressure

Fracture closure

Instantaneous shut-in pressure

Injection period Shut-in period

Fractureclosure Formation transient response

1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5

Formation pressure

Formation pressure

Once the injection well has been drilled andlogged, the rock properties and lithologysequence are input into the model, improving itsaccuracy. Then, after the first injectionsequence, injection pressures at specificpumping rates, slurry densities and viscosity dataprovide further information for model validationand adjustment. This cycle of monitoring, modelupdate and validation is repeated at intervalsduring the slurry-injection project, so the modelis continually refined, and the projected rangesfor slurry-injection capacity, fracture growth andpressure development are narrowed.

Technicians at the wellsite closely monitorinjection-pressure data to ensure that thepressure response is developing as predicted.Deviations from the modeled pressure trendsduring the injection phases can provide earlywarning signs of unexpected fracture develop -ment and extension, or other problems.13 M-ISWACO has developed a CRI monitoring anddiagnostic system for real-time CRI quality

control and assurance. The portable systemmonitors real-time slurry rheology, density,pumping rate and injection pressures.

Engineers use the monitoring system data toensure that operational parameters are withinthe ranges specified and simulated in the prewellplanning phase. During injection operations, amonitoring and diagnostic software packageensures that the injection well is performing asexpected and alerts CRI operators to anydeveloping risks (above). A cuttings-transportsimulator is also available to forecast slurrystability and help maintain injec tivity. If the real-time monitoring system signals potential risks,M-I SWACO CRI assurance engineers at thewellsite then use FracCADE fracturing designand evaluation software or other diagnostic toolsto provide a more detailed pressure analysis.

In the North Sea, one operator used CRItechniques to inject cuttings below the 133⁄8-in.casing shoe of the main wellbore. The injection

formation was located in a geologically complexenvironment close to a major fault. This location significantly increased the risk levelassociated with CRI operations and disposalfracture containment.

To minimize these risks, a group of M-ISWACO geomechanics experts specializing ininjection monitoring and pressure-trend analysisidentified subsurface risks and geologicalhazards during injection operations and fracture-geometry evolution. The team monitored andevaluated all injection parameters on a dailybasis and performed in-depth analysis ofinjection pressure.

Pressure analysis during one injectionsequence resulted in abnormal postshut-in-pressure decline, represented by a straight-line pressure-decline pattern. This unusualpattern had not been observed during earlierinjections. Analysis of the event showed nosignificant variations in injection parameters orslurry rheology.

The main objectives of pressure-declineanalysis are to identify the reasons for unusualpressure patterns, to predict the impact onfracture behavior and the CRI system, and toevaluate any associated risks. Data from otherCRI projects had demonstrated that a straight-line pressure-decline pattern may have severalcauses, one being the development of abnormalrestrictions at the injection point.

The engineering team analyzed pressurederivatives with respect to nondimensional G-function data after a specific shut-in time todetect changes that occurred during the pressure-decline process. Analysis of the derivativesindicated linear behavior during the pressuredecline. Based on the initial information fromthe straight-line pressure-decline interpretationand indirect factors such as behavior of pressurederivatives, the most likely cause of this unusualpressure-decline behavior was a restriction inthe injection point.

To confirm the diagnosis, a cement bond log(CBL) was run to verify the condition and level ofcement at the injection point and to determinewhether a restriction had developed at thatinjection point. CBL data confirmed that thelevel of cement in the 95⁄8-in. annular section washigher than designed and had bridged part of theopenhole section, introducing a restriction at theinjection point.

From the pressure-analysis results and areview of the CBL data, engineers were able todefine the problem and implement mitigationprocedures to minimize the restriction impact

64 Oilfield Review

> Monitoring the injection process. A system of sensors and intelligent software combined with aquick-look screen help MI-SWACO’s engineers monitor and control the CRI process. Minimal userinput is required, and all data are available on one screen. Quick diagnostic evaluations help detectpotential problems and reduce risks.

Winter 2006/2007 65

and the risks to further injection operations.Changing the volume of the displacement stageand reduced residence time for cuttings in thestatic well annulus allowed operations tocontinue despite the annular restriction. Morethan 46,000 bbl [7,300 m3] of injection slurrywere safely injected into the CRI well.

In another North Sea case, an operator wasusing annular injection processes between the133⁄8-in. and 95⁄8-in. casings in a production well todispose of oil-base cuttings generated by primarydrilling operations. After five months of normalinjection procedures, a pressure spike of 600 psi[4,137 kPa] was noted during annular injection.Sudden injection-pressure increases may berelated to a number of factors, including wellobstruction or well plugging, fracture plugging,particle settlement and operational errors suchas closed valves. Some problems are relativelyeasy to identify through adequate analysis ofpressure signatures, but others are more elusive.

Onsite engineers and technicians checkedthe well for potential leaks and confirmed theintegrity of the CRI system. During evaluation,routine CRI operations continued with theknowledge that the injection pressures werespiking higher than normal. While carefullymonitoring the annular pressures duringinjection, technicians noted that annularpressure spikes seemed to coincide with highlevels of production caused by artificial lift.

Since there were no other practicalalternatives for cuttings management, it wascritical to understand the reasons for theconsistent increase in surface pressure duringthe postshut-in period after CRI injection and itsrelationship to production activity. Following acareful and extensive evaluation, engineers foundthat the CRI pressure spikes were related tofracture-gradient increase resulting from thermalexpansion of the formation during production.

Analysis of CRI pressure behavior showedthat a considerable pressure difference occurredwhen the well was flowing and when it was static.Engineers discovered that the 600-psi variationobserved between the two situations coincidedwith a theoretical fracture-gradient increaseassociated with a 23°C [41°F] change in rocktemperature. The effect of the rise in tempera -ture resulting from production operations wasgreatest near the wellbore, increasing formationstress by about 600 psi. The CRI injectionpressure had to overcome this effect to open thefracture, causing a sudden increase in theinjection pressure.

Daily monitoring of injection parameters andregular in-depth pressure analysis can signifi -cantly reduce risk and increase the level ofinjection quality assurance. Monitoring also helpsto ensure environmentally safe and seamless CRIoperations in spite of the significant uncertain -ties of data availability and quality. Regular in-depth pressure analysis allows engineers tomonitor the progression of injection fractures,validate and update geomechanical models andextend the life of the injection well.

Reducing Oil WasteThe amount of waste-oil mud pumped downinjection wells along with cuttings is consid -erable. Although OBMs generally have a muchlonger life than water-base muds, their life is notindefinite. During the course of drilling, solids-removal equipment extracts cuttings and finesolids from muds as they return to the surface.

However, even with highly efficient equipment,not all of the solids can be removed. The smallamount left in the mud is continuously subjectedto the grinding action of pumps and othermechanical equipment. Over time, the particlesbecome smaller and smaller, eventually reachingsizes less than one micron and exponentiallyincreasing their surface area (above).

As the ultrafine solids content in the mudincreases, the fluid’s performance and generalstability decreases; eventually the mud isconsidered “worn out” and is disposed of. Sincemuch of the economic value of an oil mud lies inthe oil itself, generations of drillers and servicecompanies have searched for methods to recoverbase oil from these worn-out muds.

> Increasing surface area. The mechanical action of drilling and circulating deteriorates cuttings. Ifnot removed from the circulating system, with time they become smaller, similar to a cube beingdivided, and increase in surface area (top). Drilling performance and cost suffer as more chemicalsand fresh volume are required to manage this increased surface area. Eventually, cuttings mayreduce in size (bottom) to a point that makes removal from the drilling fluids difficult, if not impossible.

13. Fragachán F, Ovalle A and Shokanov T: “ PressureMonitoring: Key for Waste Management InjectionAssurance,” paper SPE 103999, presented at the FirstInternational Oil Conference and Exhibition in Mexico,Cancun, August 31–September 2, 2006.

The M-I SWACO RECLAIM technology is achemically enhanced solids-removal process,capable of eliminating the majority of the finesolids from nonaqueous fluids. The fine solids, orlow-gravity solids (LGS), that accumulate in amud system during the drilling process hinderefficient drilling in several ways: pipe-stickingpotential is increased, rotary-torque levels mayrise, the penetration rate may decrease, and themud may experience other problems related toits increased viscosity.

Solids-control equipment typically removesLGS particles greater than 5 to 7 microns, whilesmaller particles remain in the mud system. Asthe concentration of these fine solids continuesto build, the only conventional recourse is todilute the mud system to reduce the LGSconcentration or to build new mud. Dilution and building of more mud increase waste,disposal volumes and the overall cost of thedrilling project.

The RECLAIM system is designed to removethe bulk of fine colloidal particles and may alsobe used to increase the oil-to-water ratio (OWR)of the drilling fluid. The technology comprisesflocculants, surfactants and a RECLAIM unit skidcontaining all the components required toeffectively flocculate fine solids in a nonaqueousfluid (below).

Flocculation of oil-wet solids in suspension isnot a trivial task. Surfactants developed by M-ISWACO and their research partners weaken themud’s emulsion so that proprietary flocculatingpolymers can agglomerate the fine solids. Onceflocculated, the LGS can be removed withconventional centrifuge techniques. The polymeralso promotes the demulsification of the brinedroplets in the mud. Therefore, a secondaryeffect of this process is that water is removedalong with the solids, concentrating the base-oiland increasing the OWR.

RECLAIM technology may be used on activedrilling projects to improve solids-controlequipment efficiency, in postwell mud recondi -tioning of inventory and for the recovery of baseoil from worn-out mud systems. In the process,fluids from the active drilling operations orstorage location are transferred to the RECLAIMunit feed pump (next page). Before the fluidreaches the pump, a surfactant is injected intothe fluid at predetermined concentrations. Thesurfactant reduces the emulsion stability of themud allowing the flocculating polymer to adhereto the fine solids.

As the fluid is transferred to the centrifuge,flocculating polymer is added to the fluid streamby an injection pump. The fluid is then routedthrough a mixing system for blending. Afterwards,high-speed centrifuges separate LGS and waterfrom the base fluid. Reclaimed fluid is returned tothe active system or tanks for storage. The waste

66 Oilfield Review

> A self-contained system for reclaiming fluid. The RECLAIM skid-mounted treatment unit contains all the equipment necessary to facilitate the RECLAIMprocess including polymer and surfactant tanks, water and oil tanks, pumps, mixers, control systems, and feed and return lines.

Winter 2006/2007 67

stream is discarded from the centrifuge fordisposal. This waste material contains not onlythe flocculated solids but also a portion of thewater phase. If required, the bulk of the waterphase can be removed by adjusting the polymer-treatment level. Excess polymer is also removed,ensuring the generation of a virtually solids-free,reusable, nondegraded base-fluid.

In one case, while drilling in the foothills ofthe Rocky Mountains northwest of Calgary, anoperator was left with 1,258 bbl [200 m3] of 1.20-sg [10-lbm/galUS] low-toxicity mineral oil-base mud after drilling each well, most of whichwas stored for reuse on the next drilling project.14

As mentioned previously, as oil-muds wear outthrough reuse, performance parameters suffer,particularly the rate of penetration. In this case,the operator needed to improve rate ofpenetration (ROP) to reduce well costs. One wayof improving ROP is to drill with a low-density mudof 0.95 sg [7.91 lbm/galUS] or less. However, thedensity of the oil-base fluid in use could not bereduced from 1.20 to 0.95 sg by conventionalmeans and would have to be disposed of,increasing the cost of both the drilling fluid anddisposal. RECLAIM technology was used onlocation to reduce the existing mud density from1.20 to 0.95 sg, eliminating the need to replaceand dispose of 1,258 bbl of mud per well.

In another case, mud returned from the fieldto an M-I SWACO mud plant in the Middle Eastcontained 16 to 20% LGS, had an OWR rangingfrom 70:30 to 80:20, and an average density of1.20 sg. The operator’s specification for mud tobe returned to the field was a 90:10 OWR with adensity of less than 1.08 sg [9.0 lbm/galUS].

At the mud plant, engineers had anotherproblem. Standard treatment to bring the usedmud back into condition required high levels ofdilution with diesel, which would take asignificant amount of time and stress the limitsof plant capacity. The dilution process would alsoproduce large volumes of waste fluids that wouldrequire disposal.

Using RECLAIM technology, engineersachieved an OWR of 90:10 with no significantchange in the volume of fluid being treated. Thetechnology allowed the dilution volume to besignificantly reduced from 160 to 30%, which inturn reduced mud-treatment costs. OWRs up to98:2 were achieved with increased doses offlocculent, and recovered fluid was used fordilution in place of new diesel.

RECLAIM technology effectively eliminatedthe high dilution required to recondition mudreturns from the rig, and significantly reduceddisposal costs for excess fluids. Costs to bring thetreated-mud properties back to specificationwere a fraction of those likely to be incurredduring dilution or when building new mud.

Managing Waste and ResourcesUnearthing terrestrial resources is an age-oldprocess. Regardless of the method used, thegenerated wastes must be properly managed.Through generations of drillers, the E&P industryhas sought the perfect solution for drilling-wastedisposal. While current solutions to the problemare not perfect, they are far better than thoseavailable just a few decades ago.

Up-to-date practices, including fracturingunderground formations, help recover hard-to-access reserves and, at the same time, provide asuitable resting place for millions of tons ofdrilling waste. By returning rock and debrisexcavated from the Earth back to their origin,operators have taken a significant step towardenvironmental stewardship. Similarly, methodssuch as RECLAIM technology are improving theutilization of available resources, and reducingwaste products and the costs of recoveringhydrocarbon reserves.

CRI and RECLAIM technologies are among ahost of other methods either in use or underdevelopment that promise to facilitate move menttoward minimizing environmental impact whileimproving reserve recovery. In the years to come,the continued development and deploy ment ofclean and green technologies will help the oil andgas industry extract the Earth’s resources withminimal environmental impact. —DW

> Processing fluids to be reclaimed. Typically, drilling fluid is moved from the active system or from storage to the processing unit. Additive stations andmixers process the fluid and prepare it for solids separation by a high-speed centrifuge. From a single feed stream, the system returns three phases; baseoil to be returned to the active system or to storage, a waste solids stream, and the oil-mud’s water phase.

Mud fromstorage or active

mud system

RECLAIMunit

feed pump

Discardedsolids and

waste water

Mixingsystem

FlocculatingpolymerSurfactant

1

2 4 5 6

3 7

M-I SWACOcentrifuge

Reclaimed fluid to active mud

system or storage

14. Fluid density is often given as specific gravity, or sg,representing density in grams per cubic centimeter.