Horizontal Highlights

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Horizontal

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8 Middle East Well Evaluation Review

Throughout the Middle East, hori-zontal wells are being used forfield developments which, in the

past, would have relied on vertical wells.While the basic geology of many MiddleEast fields is well known, details of reser-voir structure, faulting, facies and poresystem heterogeneity are not usually so

well-defined.The recent increase in horizontal

drilling has helped reservoir engineersand geoscientists to understand the lat-eral variations, permeability barriers andcompartments which occur betweenexisting vertical wells. Using horizontalwells we can locate leached zones, findunconformities and probe pinchouts andother sites with by-passed oil potential.

Horizontal wells are usually drilled toenhance oil production. In some situa-tions the improvement may be dramatic- enabling development of a reservoirwhich would otherwise have been con-

sidered marginal or uneconomic.However, in cases where the improve-ment is likely to be less spectacular, hori-zontal drilling costs and benefits must beassessed carefully.

There are many kinds of reservoirwhere the potential benefits of horizontaldrilling are obvious.• Thin reservoirs: a vertical well drilledinto a thin reservoir will have a very smallcontact surface (effectively limited byreservoir thickness) with the oil-producing horizon. A horizontal well in the samereservoir layer can have a contact surfacerunning the length of the reservoir.

• Reservoirs with natural vertical frac-tures: horizontal wells typically intersect thousands of small vertical fractures and,if the reservoir contains them, some verylarge ones. If the well trajectory has beenplanned carefully these large verticalfractures can be used to improve pro-ductivity, even when the overall fracturedensity is low. However, if a fault frac-ture system is misinterpreted the result may be early water or unwanted gas pro-duction. The damage which an inappropri-ate horizontal well can cause underlinesthe importance of having a good reservoirmodel before drilling begins or being ableto assess the well accurately during orafter drilling.

Fig. 1.1: DON’T ADD WATER: The horizontal well produces more oil than its vertical counterpart,drains more of the reservoir and delays water production.

Fig. 1.2: IN FULL FLOOD: The effectiveness of traditional waterflood methods, which rely on vertical injectors and producers, can be reduced by poor sweep efficiency and early water breakthrough (a).The alternative is injection and production through two horizontal wells. This has been shown to produce a more uniform and effective sweep (b).

Channel sands

Overbank sands

Vertical injectors Vertical producers

Channel sands

Overbank sands

Horizontal injectors Horizontal producers

(a)

(b)



9Number 16, 1995.

• Reservoirs where water (and gas) con-ing will develop: the flow geometry asso-ciated with a horizontal drain helps toreduce the amount of water or gas con-ing in any given reservoir (figure 1.1).This means that the total volume of oilrecovered before water or gas break-through can be increased. The only

potential obstacle to a significant increase in oil recovery rate is the pres-ence of zones with high vertical perme-ability (e.g. the faults and fault-relatedfractures mentioned above). However,with advance planning, these can bedealt with using selective completiontechniques.

Horizontal wells remove oil from areservoir over a long producing zone at relatively slow rates. In contrast, verticalwells take oil very quickly through muchshorter lengths of borehole. The flowgeometry associated with horizontalwells tends to reduce the influence of

heterogeneity along the long drain - soincreasing total production.• Thin layered reservoirs: oil recoveryfrom water flooding can be improveddramatically by injecting and producing from horizontal wells, rather than using vertical wells in a traditional water flood(figure 1.2).• Heterogeneous reservoirs: horizontalheterogeneity in reservoirs presents aproblem for vertical wells - they can onlyaccess those reservoir compartmentswhich lie immediately below the drilling rig. Horizontal wells can be used tosearch for isolated and by-passed oil and

gas accumulations within a field.From a logging viewpoint the benefits

of horizontal wells in a heterogeneousreservoir are just as clear. Horizontalwells pass through the lateral hetero-geneity, revealing much more about theinternal reservoir structure than a verti-cal well could. This means that in a com-plex depositional environment (such asa channel sandstone) the well can findmore of the oil- and gas-bearing zones orcompartments (figure 1.3) and soincrease total production (figure 1.4).

Vertical well

H o r i z o n t

a l w e l l

Cross section Mukhaizna Field, Oman

Gas

Oil

Channel sand

Fig. 1.3: HITTING THE TARGETS: In channel sandstone reservoirscomprising a number of discrete oil and gasaccumulations a vertical well may only find onetarget, while a horizontal

or deviated well could find several oil and gas zones. A similar application was used by QGPC for aheterogeneous Arab-C reservoir in Dukhan Field. From J. Bouvier and A. Heward of Petroleum Development Oman. Presented at the1993 AAPG International Conference,The Hague, The Netherlands.

Fig. 1.4: OVERCOMING VARIATION: Reef reservoirs are often heterogeneous and vertical wellsdrilled in them suffer from low and rapidly diminishing production. Direct comparison of horizontal and vertical well performance in distal backreef facies indicates that the horizontal well is producing three times as much oil as its vertical counterpart during the three months since completion. After

M. Kharusi, 1991 Archie Conference, Houston, Texas, USA.

00

200

400

600

800Oil production m3 /d

20 40 60 80 100

Days since completion

Al Huwaisah Field, Oman

Improvement in oil rate horizontal 'distal backreef' wells AH - 61 / 65 / 68

Average oil plate vertical 'distal backreef' wells AH - 53 / 54 / 62

J.D. Bouvier and A. Heward (1993) A Review of Horizontal Drilling in Petroleum Development Oman Exploration

1990-1993. AAPG International Conference, The Hague,The Netherlands.

M. Kharusi (1991) Evaluating the Opportunities for Horizontal Wells in Oman. 2nd Archie Conference,

Houston, Texas, USA. pp. 35-46.




A technique for the ’90s

Before 1990, horizontal drilling was not apopular technique. The oil industry onlydrilled horizontal wells in difficult situa-tions as a ‘last resort’. The global total for1989 was just over 200 horizontal wells.In 1990, that total leapt to almost 1200

wells, with nearly 1000 of these drilled inthe USA (figure 1.5).

In the USA, interest in horizontaldrilling techniques has been concen-trated in Texas, specifically on theAustin Chalk. Activity in this formationsoared from just 10 horizontal wells in1989 to more than 200 in 1990. The pro-duction results have more than justifiedsome of the intense activity in thisregion. Success led some people to spec-ulate that by the end of the century 50%of all new wells being drilled in the USAwould be horizontal. Although this pre-diction seems unlikely to be fulfilled,

there is no doubt that horizontal wellswill form a major part of oilfield strategyin the USA and other mature oilprovinces around the world as operatorsstrive to produce oil and gas from low-permeability zones which have beenmissed by vertical wells.

The spectacular successes in theAustin Chalk Formation transformed hor-izontal drilling into a mainstream tech-nique. Around the world, operatorsapplied the lessons learned in Texas toboost production in their own reservoirs.Inevitably, this led to some failureswhere the horizontal drilling approachwas inappropriate, but it also brought some outstanding achievements.

One of the leaders in horizontaldrilling is the Canadian oil industry. Theheavy, low- mobility oil which makes upa large proportion of total Canadianreserves was the initial reason for thisinterest in horizontal wells.

Gas and water are much moremobile than the thick, viscous oilsfound in Canada’s oil sands. As a result,vertical wells soon experience exces-sive water and/or gas productionthrough coning effects. Using horizontalwells, oil can be produced at low pres-sures (without reducing productionrates) to keep gas and water away fromproduction wells for as long as possible.The maintenance of production rates ispossible because the horizontal drain-hole covers much more of the reservoirthan a vertical equivalent.

A study based on the first 500 hori-zontal wells drilled in Canada predictedthat in 1993 alone horizontal drilling would increase crude oil recovery by2 billion barrels. Almost 20% of the 11,408wells drilled in 1993 were horizontal.

Comparison of oil rates Comparison of GORs

G2 (6th)

0 20 40 60 80 100 120 140 0 1000 2000 3000 4000

G1 (1st)

E (2nd)

D (8th)

01 (4th)

G3 (11th)

02 (9th)

A1 (5th)

03 (10th)

H (3rd)

A2 (7th)

Pool H-wells (order drilled)

Horizontal wells

Vertical wells

Horizontal wells

Vertical wells

Oil rate (m /d) GOR3

Fig. 1.6: BALANCE SHEET: Horizontal wells produce higher volumes of oil (a) and smaller amounts of gas (b) than equivalent vertical wells. This sequence of wells is arranged inorder of decreasing oil rate production for horizontal wells. This example is fromCanada’s Devonian Rainbow Reef Reservoir,where lateral entry allowed the operator to produce oil without a high proportion of gas. Modified from F.J. McIntyre, et al. (1994).

Fig. 1.5: THE BIG BREAK: After some outstanding successes in the USA during 1989, the number of horizontal wells drilled soared from an annual total of 257 worldwide to almost 1200 wells in 1990. Since then more than 1000 horizontal wells have been drilled every year, with a growing proportionof these outside North America.

Another Canadian development hasbeen the use of re-entry wells to recoversignificant quantities of oil left behind byearlier production phases. These re-entry wells tend to be smaller in diame-ter (a factor controlled by the existing casing) and drilled with coiled tubing.

(a) (b)

41

0

200

400

600

800

1000

1200

1400

1600

65145

1986 1987 1988 1989

257

1990

1190

Horizontal wells

1991

1250

1992

1020

1993

1400

1994

1570

1995

Outside North America

Canada

United States

Est.

F.J. McIntyre, B.E. Hunter, D. See, F.Y. Wang, D.K. Fong

Recent Adances in Horizontal Well Applications. 1994Canadian SPE / CIM / CANMET International Conference -

‘Advancements in Redeveloping Mature Miscible FloodReservoirs with Horizontal Wells in Adverse Exploitation

Conditions.’



11Number 16, 1995.

In the Prudhoe Bay Field, Alaska,USA, British Petroleum has drilled morethan 50 side-track wells from damagedor low-yield wells. These coiled-tubing workovers were a great success. It wasdiscovered that some of the faults werewater conduits. Review of the seismicprofiles for the field showed that

approximately 90% of the horizontalwells penetrated faults which were visi-ble on the latest 3D seismic. It was con-cluded that between 10% and 20% of thefaults were conductive.

Why choose horizontal?

Horizontal wells cost more than verticalwells - so what do they offer in return? Inproblematic wells, for example, wherethere is a thin oil column or a risk of early water or gas production, verticalwells are usually very inefficient. A com-parison of horizontal and vertical well

performance (figure 1.6) clearly illus-trates the potential benefits. Every hori-zontal well in this example gives betterresults than its vertical counterpart.Higher oil rates, coupled with greatlyreduced gas-oil ratios, have made hori-zontal wells the first choice for manyreservoirs. In some countries, such asQatar, Abu Dhabi and Oman, horizontaldrilling has become standard practice,with the vertical drilling alternative being examined on a well-by-well basis.

In cases where the increase in pro-duction rate is not likely to be dramatic,there may still be implications for the

long term development and total recov-ery rate for a given reservoir. Attic oil isa common feature of fields which havebeen developed using vertical wells (fig-ure 1.7). Even the flexibility of extendedreach wells - so important in offshoreoperations where additional platformswould be prohibitively expensive - can-not match horizontal well performance.

Drilling horizontal wells is expensivebut, within any field, costs follow aclear downward trend with time. InOman’s Nimr Field the ratio of drilling costs between vertical and horizontalwells decreased dramatically (figure

1.8) in the course of field development.This decrease reflects the driller’sgreater familiarity with well conditionsand the consequent improved advanceplanning.

2

1.8

1.6

1.4

1.2

1

134

156

157

158

169

170172

175

177

180

Time

C o s

t r a

t i o ( h o r i z o n

t a l / v e r t i c a

l )

Nimr Field, Oman

Fig. 1.8: GOING DOWN: The cost of horizontal wells usually decreases rapidly through time. In thisexample, from Nimr Field in Oman, horizontal wells initially cost almost twice as much as the same

length of vertical well. However, as the field developed the cost of horizontal drilling fell to only athird more expensive than a comparable vertical well. Modified from M. Kharusi, PDO, 1991 ArchieConference, Houston, Texas, USA.

Fig. 1.7: Attic oil is a common feature of many fields which have been developed using vertical and

deviated wells. Unless a vertical well intersects the highest point of a structural trap there will always be oil above it and, therefore, out of reach. A horizontal well can be placed precisely, passing through the top of the structure and so producing the oil which vertical and deviated wellshave by-passed.

Whipstock

Dryhole

Deviated well

Horizontal well

Undrained oil Attic oil

Sand pinchout




New horizons in Oman

The potential of horizontal wells hasbeen recognized throughout the MiddleEast, but it is Oman that has seen themost radical changes in field develop-ment. In 1986, Petroleum Development Oman (PDO) drilled three short radius

wells in a chalky Shuaiba limestone oilreservoir. This reservoir had a history of gas and/or water coning and low produc-tion rates. The results were not encour-aging and horizontal activity wassuspended.

The rapid improvements in horizontaldrilling techniques over the following four years persuaded the company to tryagain and, in 1990, PDO embarked on amore ambitious trial of eight medium-radius wells in a number of reservoirs.The results of this second phase were soimpressive that the trial was extended.Sustained success has led to almost con-

tinuous horizontal drilling activity, using up to four drilling rigs at any one time.By the end of 1994, PDO had drilledmore than 200 horizontal wells in morethan 20 fields and seven different reser-voir horizons. These include carbonatesand various sandstone facies (marine,fluvial, aeolian and periglacial) with thinand thick oil columns, heavy and light oils and high and low water cuts. Largenumbers of reservoir heterogeneitieshave been encountered, resulting in pro-ductivities which were mediocre in onewell and spectacular in another only200m away.

PDO’s initial effort was centred onimproving the viability of marginal reser-voirs. However, using horizontal wells toreplace vertical wells in the low perme-ability zones of good reservoirs, hasproved very successful.

In the Natih Field, productivitydepends on the number and orientation

of fractures intersected by a well. A goodwell - one which penetrates many openfractures - will produce approximately600m3 /day, but wells which intersect few fractures may reach only 85m3 /day.Unfortunately, fracture distribution is not uniform across the field and, conse-quently, a lot of effort has gone into pre-dicting fracture location and density.

Fractures are relatively small features,typically accounting for less than 0.1% of total rock volume and are, therefore, not visible on seismic. However, their pres-ence can sometimes be inferred indi-rectly. By manipulating high-quality

3D datasets on CHARISMA and SPIRIT it was possible to map flexures and faultswith throws as small as 3m. By overlaying the fracture orientation data from core andFMI* (Fullbore Formation MicroImager)on a seismic dip map (figure 1.9a) a linkcan be established between fractures andfaults. A revised well-targeting strategybased on this information has allowed theplacement of wells near small faults andflexures with an average improvement of 30% in gross productivity, indicating that the wells are intersecting more open frac-tures than before (figure 1.9b).

Fig. 1.9: (a) Natih Field 3D seismic revealing faults,coupled with boreholeimagery to reveal fractures. Gross production per well in Natih Field (b) was found to correlate closely with proximity to faults defined by 3D seismic. Theseexamples are taken fromthe GEO/94 volume

article, Fractures and 3DSeismic - the Natih Fieldof North Oman, presented by S. Whyte of Petroleum Development Oman.

The close association between fractur-ing and faulting was also observed in FMIimages from horizontal wells in Idd ElShargi Field, offshore Qatar (figure 1.10).Borehole imagery was combined with thepoor 3D seismic to ensure optimal fielddevelopment using horizontal wells. Theincreased production from the first and

second horizontal wells drilled in this fieldwas 10 times greater than production fromthe earlier vertical wells.

Apart from the economic benefitswhich a well-planned horizontal drilling campaign can provide, there are otherfactors to be considered. Horizontaldrilling reveals a great deal about areservoir, information which is simplynot available from vertical wells.Detailed logging of a horizontal wellallows us to measure and model the lat-eral variations of permeability andporosity which influence reservoirdevelopment (figure 1.11).

As more information is gathered, thefull complexity of many reservoirs hasbecome apparent. By improving our pic-ture of the reservoir we can recognize andavoid potential problems or deal withthem before production is affected.

800

0

400

N 0 3 4

N 0 8 6

N 1 0 5

N 0 1 7 L

N 0 0 5

N 0 7 9

N 0 5 3

N 0 2 9

N 0 6 4

N W 0 0 6

Gross production per well (m /d)3

Close to faults

Far from faults

(b)

(a)

Seismic attribute map - Natih C Dipwith fractures from FMS and core

September 1993





Fig. 1.12: The ratio of horizontal to vertical permeability, and the variations in that ratiothroughout the reservoir arecrucial to the choice between

horizontal and vertical wells.Where there are many low- permeability barriers whichimpede vertical (but not horizontal) oil and gasmovement, vertical wells may

be more efficient thantheir horizontal counterparts.


Horizontal - always best?

Amid the upsurge of horizontal drilling and the predictions of its future domi-nance around the world, we face a fun-damental question - are horizontal wellsalways better than vertical wells?

Numerical modelling carried out by

researchers at the University of Waterloo, Canada, investigated the gen-eral case. They found that in isotropicreservoirs horizontal wells out-perform

Extended reach

Extended reach8

11

1 1

22

3

5

67

0

Distance (m)

0

1000

2000

3000

4000

5000

D e p

t h ( m

)

800 1600 2400 3200 4000 4800 5600 6400 7200

Legend

ONGC, India1

PDO, Oman2

AOC, Saudi Arabia3

Shell, Turkey4

OXY, Oman5

ADCO, Abu Dhabi6

ZADCO, Abu Dhabi7

ELF, Oman8

UNOCAL, USA9

Mærsk Oil, Qatar10

Statoil, North Sea11

11

Cliff's Oil and Gas, USA12

1

10

12

9

2

34

1

1

13

14

Mærsk in Oman

British Petroleumin UK

Record makers and breakers

Drillers claim world records more regu-larly than sportsmen and women. Thelong reach wells of 1990 are dwarfed bywells drilled in 1994 (figure 1.13).

A well drilled recently by theNorwegian State Oil Company, Statoil, intheir offshore Statfjord Field, had a hori-zontal displacement of 7288m with a truevertical depth (tvd) of 2788m, giving atotal length of 8758m.

In Louisiana, USA, a very deep hori-zontal well has been drilled by Cliff’s Oiland Gas. The well, Martin A-1, has a truevertical depth of 4675m and a total dis-placement of 5212 m.

One of the longest short-radius hori-zontal wells was drilled by PDO inOman, while the longest medium-radiuswell, Mærsk Oil Qatar’s Al Shaheen No.2,

reached 3899 m.The greatest horizontal/vertical depthratio is found in a well drilled by UNO-CAL in June 1992. This well, drilled off-shore California, USA, has a 1489 mhorizontal displacement and a tvd of just 293 m. This means a length:depth ratioof 5:1.

As drilling distances and depths growlarger, the importance of accurate andreliable directional methods becomesever more important.

their vertical counterparts for two mainreasons;• borehole inclination; and• the longer contact length betweenborehole and reservoir.

In cases where vertical permeabilityis significantly lower than horizontal per-meability (figure 1.12), production can be

reduced to the point where vertical wellsare better. For a fixed length well, hori-zontal wells are less effective than verti-cal wells only where kv /k h (verticalpermeability/horizontal permeability) isless than 0.5.

Fig. 1.13: REACHING OUT: The average length of horizontal wells has increased steadily over recent years. The total depths achieved in the longest wells

of 1990 (blue) are now drilled routinely. The longest wells of 1994 (red) have already been overtaken as directional drilling technology matures. Long wells present many technical challenges, but offer substantial rewards to those who want to hit multiple reservoir targets and so increase oil production.The 8 km step out barrier was first broken by an extended reach well at Wytch Farm by British Petroleum with a total depth of 8715m. The definition of horizontal wells has become increasingly blurred but a recent well drilled by Mærsk in Qatar had a total length of 5001 m.



15Number 16, 1995.

REACH AND RADIUS

Rigid tool length (L)

Radius of curvature (R)

Diameter (D)

Long radius Medium radius Short radius

D = 8 in.

R = 1500 ft

L = 70ft

D = 6 in.

R = 200 ft

L = 20 ft

D = 6 in.

R = 15 ft

L = 5 ft

'Drain hole type' short radius horizontal wellExtended reach well

D > 8 1/2in.

3˚/100ft 3˚/100ft1.5˚/ft

up to600 ft

horizontal: up to 1500ft

horizontal: up to 3000ft

80˚ to 85˚

D > 8 1/2in. D > 8in. D > 6in.

Long radius horizontal well

Medium radius horizontal well

8-20˚/100ft

Getting long tool strings into horizontalwells can be a problem (figure 1.14).The tool length is effectively controlledby the radius of curvature in the well:long tool strings cannot be pushed

round tight bends. Short radius wellscost less to drill, but cannot be logged -so we have no explanation for their suc-cess or failure.

The options

•Long radius: the long radius well has arelatively low curvature and a final hori-zontal section which runs along the topof a reservoir (figure 1.15). It makes useof conventional directional drilling andcompletion techniques.•Medium radius laterals: the mediumradius lateral was developed to allow

conventional directional drilling, logging techniques and completion hardware inhorizontal lateral drainage wells. Buildrates of 8°-20°/100 ft are used to drillfrom a vertical bore into a conventional-ly sized lateral. Control over build rate isachieved by varying motor size andborehole size.•Short radius laterals: the entry sectionsfrom a vertical well to short radius later-al are drilled at build rates of 1.5°- 3°/ ft.They are normally drilled in competent (non-friable) formations with an openhole completion. The high curvature pre-vents logging using the MWD system and

directional control in the horizontal sec-tion is difficult.• Extended reach wells: these have long horizontal sections to ‘reach’ their target.

Fig. 1.15: REACHING THE RIGHT LEVEL: Horizontal and extended reach wells perform a variety of functions. The radiusof curvature for eachtype determines thelogging and completion techniqueswhich can be applied

in each case.

Fig. 1.14: ROUND THE BEND: Short radiuswells cannot belogged. The tool strings are too long tonegotiate the tight wellbore curve.

Build rateMWD

Direction controlDrilling methodCompletion

Longradius

1˚- 6˚/100ftYes

YesDirectionalOpen hole

Mediumradius

8˚- 20˚/100ftYes

Yes

Shortradius

1.5˚- 3˚/ftNo

Difficult




Follow the pilot

Some pilot holes are vertical but othersare inclined holes which are drilledthrough the zones of interest beforebeginning the horizontal portion of awell. A pilot hole is usually situatedclose to an existing development well

when there is uncertainty in the struc-tural dip across the field. Good dip datais essential for horizontal wells: a minormeasurement error, such as 0.5°, willresult in a vertical displacement of 44 ft over a horizontal distance of 5000 ft.Images recorded in a pilot well providethe most thorough dip determinationavailable because the geologist canselect the dip directly, even in caseswhere wavy or discontinuous bedding would reduce the quality of data from adipmeter survey.

Pilot wells were initially vertical bore-holes drilled to test the sequence (figure

1.16a). Inclined pilots are best drilled at angles up to 45° in the direction of theplanned horizontal well trajectory (fig-ure 1.16b) to complete half the build andmove the control point closer to thedrainhole.

In reservoirs where the structure orstratigraphy remain uncertain, pilotlesshorizontal wells are now being drilledwith geosteering methods (figure 1.16c)which rely on the flexibility of the tech-nology rather than detailed planning along a fixed trajectory.

This pilotless drilling relies on newsystems such as MWD (Measurements

While Drilling), LWD (Logging WhileDrilling) and geosteering techniques. Inareas where the geology is relatively sim-ple and well-known, horizontal wells cannow be drilled without a pilot. In com-plex fields, however, we rely on pilot holes to identify the tops of formationprecisely.

Steering clear

Directional drilling (or geometrical steer-ing) aims to keep the well on a pre-planned trajectory, while ‘geosteering’ isthe use of geological information to guidea well to its target, especially when thegeology turns out to be different fromthat expected. Sophisticated measure-ments, now available during drilling (from MWD and LWD methods), makethis geosteering task considerably easier.The latest techniques can identifychanges in resistivity and allow direc-tional adjustments to be made before thedrill bit strays deep into overlying shalesor an underlying water layer.

Geosteering methods can keep a wellin a very thin reservoir zone and canreact quickly to abrupt lateral changessuch as those encountered when a bore-hole crosses a fault plane.

Reservoir top

Reservoir top

Reservoir top

Horizontal well

Horizontal well

Verticalpilot well

Oil water contact

Deviatedpilot well(45˚)

Oil water contact

Oil water contact

No pilot well

LWD and MWD withgeosteering replacing a pilot

Resistivity measurements at the drill bitto avoid non-reservoir water and shale

Fig. 1.16: PILOTS FOR PREDICTION: A pilot well allows the driller to predict what will beencountered along the line of the horizontal well. Pilot wells have evolved from simple vertical wells (a) to deviated pilots (b) with angles of 45° in the direction of the planned directory. Pilotless horizontal wells (c) are being drilled thanks to geosteering techniques which react toreservoir variations rather than following a planned geometric trajectory.

(a)

(b)

(c)

Keeping the well on course is obvi-ously very important, but there are otherreasons for using LWD and MWD tech-niques. They permit:• accurate selection of 1st and 2nd buildpoints and, especially, the target entrypoint (horizontal section or reservoirsection);• recognition of changing reservoir qual-ities such as porosity or fluid content;• measurements of resistivity with mini-mum invasion;• revealing faults early enough to react to potential problems;

• detection of fluid boundaries;• earlier identification of casing and cor-ing points; and• replacement of pilot holes.

The GeoSteering tool is the petroleumindustry's first fully instrumented, steer-able, positive displacement motor(PDM). It provides long to mediumradius directional drilling capability plusazimuthal resistivity and azimuthalgamma ray to aid steering, motor RPMand inclination measurements at the bit.



Mother well(madar chan)

BedrockAlluvial fan Longitudinal section

Groundwater tablebefore ghanat was dug

Groundwater tablewhile ghanat functions

Shafts

(chah)

Transverse section

Outlet (chesme)Canal to fields

(jube)

Water0.4m 0.9m

Number 16, 1995.

The sensor package is located in themotor housing, which reduces bit-to-measurement lag to a few feet. Data istransmitted to the PowerPulse MWD toolby electromagnetic telemetry with nowiring through motor sections or drill-string components.

Guiding a drillstring directionally

through the earth's crust has been a lessthan perfect science. Reaching the target quickly and safely depends on carefulplanning, the expertise of the directionaldriller, and the performance of the hard-ware and navigation instrumentation.The directional driller formulates adrilling plan prior to spudding the well,but as the bit is guided towards the tar-get formation, the driller must be pre-pared to modify that plan in response tounforeseen changes in bed and fluidboundaries between offset wells.

Until now, the directional driller hashad to manipulate the drillstring based

on MWD measurements made from less-than-ideal positions, as far as 100 ft fromthe bit. When geological changes arenoted, the bit may already have pene-trated unwanted formations because of the time lag in information acquisition.Now the IDEAL* (Integrated Drilling Evaluation and Logging) system changesall this. The system puts the sensorswhere they belong - at the bit - and turnsthe drillstring into a reliable source of real-time drilling and petrophysical infor-mation that leads to dramaticallyimproved drilling performance and pro-ductivity.

As horizontal drilling becomes stan-dard practice in oil provinces around theworld, the technique which allowsdriller and geologist to ‘see’ the rocksduring drilling will probably becomemore popular. This method is likely toreduce the number of pilot wells drilledin the future.

Fig. 1.17: WATER PRODUCTION: The history of horizontal wells can be traced to the Middle East. Inthe central plateau of Iran horizontal groundwater wells were in use more than 2000 years ago. According to the Greek historian Polybius they were used to increase water production.

HORIZONTALHISTORY

Horizontal wells are not a new idea. Theearliest horizontal wells were drilledmore than 2000 years ago (figure 1.17).

The first written records concern the useof horizontal groundwater wells in thecentral plateau of Iran. According to theGreek historian Polybius, they wereused to increase water production.

Many thousands of such wells, andthe air shafts that allow access for servic-ing, are still being used in central Iran.These horizontal, tunnel-like wells areknown as ghanats (or qanats) in Farsi,kharis in Turkish and foggara (or phalaj)in Arabic.

Similar wells were used in Egypt’sWestern Desert more than 2500 yearsago to increase the water flow from frac-tured Nubian sandstone. The use of hori-zontal tunnel-wells as water producerssoon spread across the globe to placesas far apart as India and Spain.

As the technique spread throughEurope, a better understanding of theprocess emerged. In south-easternEngland, for example, long (up to 7500 ft)horizontal tunnels were constructed inthe low permeability chalk. The higherflow rates associated with the presenceof fractures proved to the early horizon-tal drillers that placing their wells perpen-

dicular to the main fracture orientationincreased the number of fracturesencountered and boosted production.

The application of horizontal wells inoilfield technology has a shorter, but equally intriguing history. By the mid-1930s, patents for hardware and special-ized techniques began to appear in the

USA, and by the 1950s many short hori-zontal drainage wells were being drilled.In the countries which comprise theCommonwealth of Independent States(CIS), horizontal drilling dates back tothe 1950s.

Reaching the parts other wells cannot reach

The horizontal approach in oilfield tech-nology has generally been reserved forproblematic fields or reservoirs. This‘last resort’ status for horizontal drilling meant that technical advances were

slow and applied only to local problems.Horizontal drilling has gone through

several ‘false starts’ where the techniquehas been applied to solve a particularproblem until new, cheaper or more effi-cient alternatives have been developed.

So why, after all this time and thetechnical development of vertical meth-ods, is there still so much interest in hor-izontal drilling? The answer is simple:horizontal wells can succeed in placeswhere vertical wells would fail.

17




FAULTS,FRACTALS AND FLUIDS Fractures and faults can behave as barri-

ers or baffles to reservoir flow, but verylittle research has been published onthese effects. Generally we should expect to encounter more open fractures andpermeable faults in a horizontal well thanpreviously mapped for the reservoir -unless the well is drilled specifically toavoid these features. Good reservoircharacterization is critical for optimalwell placement (figure 1.18), for design of appropriate well tests and for selecting the correct completion methods.

Multidisciplinary studies and newtechnologies in 3D seismic surveys and3D borehole imagery have been com-

bined to reveal faulting which would not have been detected by standard devel-opment methods. However, in carbonatereservoirs many faults are invisible todipmeter and seismic techniques.Deformation occurs by brittle failure,rather than plastic deformation so thereis no characteristic ‘drag zone’.

In some reservoirs it may be possibleto use fractal methods or other statisticalanalysis of fracture distribution (figure1.19). This method may help to explainthe size distribution of sub-seismic faultsencountered in horizontal wells.

Reservoir faults have been identified

as water sources in many of the massivecarbonate sequences in and around theGulf and in some sandstone reservoirsfrom Syria to Yemen. As the volume of borehole imagery data from horizontalwells continues to grow, it becomesapparent that shear faulting plays amajor role in water production for manyfields. How can we identify these faultsand deal with them before they affect production?

Typical shear faults dip at high anglesand are very rarely intersected by verti-cal wells. In addition, their movement ispredominantly strike-slip (lateral) which

makes them invisible on 2D seismic sec-tions. Moreover, their brittle deformationand the absence of drag zones along thefault plane make them equally invisibleto dipmeters.

Careful examination of electricalimages can reveal shear faulting.Apertures which are larger than those of associated fractures and differences inbedding or textural characteristics oneither side of these high-angle, conduc-tive features (faults) are subtle yet defi-nite clues to their presence (figure 1.11).

East

OWC

drainhole

N o r t h

Further evidence of shear faulting canbe gathered by looking at horizontalslices, or slices parallel to the formationboundaries, in high-quality 3D seismics.Seismic and electrical imaging tech-niques should be combined to assessthe large-scale distribution of shearfaults, while well testing can be relied onto determine their effect on fluid flow.

Fault identification methods used invertical wells (e.g. missing sections toindicate normal faults or repeated sec-

1

0.01 0.1 1 10 100

10

100

C u m

u l a t i v e n u m

b e r o

f f r a c

t u r e s

Fracture spacing, ft

1000

10,000 Fig. 1.19: Fracturesoften display a fractal,or power law,distribution. In simpleterms, this means that there are relatively few large faults and ahuge number of small faults. Bill Belfield and Jerry Sovich of ARCO recently revealed a fractal, or power, relationshipfor fracture spacing from horizontal well data. Modified from

W. Belfield and J. Sovich (ARCO). This study is based onanalysis of more than13,000 fracturesdefined by electrical imagery in six horizontal wellbores.

tions for reverse faults) are not generallyapplicable in horizontal boreholes.Extensional faults can be recognized bythe fact that the dip of the deformation ordrag along these faults is in the samedirection as the fault plane, but dipping inthe opposite direction to the fault plane.For listric growth faults and reverse faults,the deformation along the down-thrownblock dips in a direction opposite to thefault plane.

W. Belfield and J Sovich, Fracture Statistics from Horizontal Wellbores. Canadian SPE/CIM/CANMETInternational Conference on Recent Advances in

Horizontal Well Applications.

Fig. 1.18: DRAINING AGAIN: This South American example,from Lake Maracaiboin Venezuela,illustrates theflexibility of thehorizontal well technique. Having

identified the locationand orientation of themajor fault, theoperator chose to position the horizontal drainhole along thecrest of this plunging anticline to maximizeoil recovery. Similar techniques are being used by GUPCO in thefault-block reservoirswhich occur in Egypt’sGulf of Suez.



19Number 16, 1995.

Logging along the horizon

The long period when horizontal wellswere considered a ‘last resort’ is under-lined by the under-development of log-ging systems and interpretation forhorizontal wells. The methods which areavailable have lagged behind the

advanced interpretative techniquesdeveloped for vertical wells, but this sit-uation is changing. Established researchand development programmes are cur-rently yielding new approaches to log analysis in horizontal wells.

Acoustic measurements in horizontal wells

Seismic and sonic techniques can beapplied in horizontal wells, although pro-cessing and interpretation of the datacan be more complicated than in verticalwells.

Vertical Seismic Profiles (VSPs) andWalkaways work by measuring the dif-ference between downgoing andreflected wavefields. In horizontal wells,where the receivers are arranged hori-zontally, there is no moveout differencebetween the two wavefields. This prob-lem is easily overcome by comparing the responses of geophones (velocitysensitive devices which record direc-tional information) and hydrophones(pressure-sensitive devices which pro-duce an identical pressure response forboth downgoing and reflected fields). By

subtracting one seismogram from theother we can eliminate the effect of thedowngoing wavefield, allowing geophysi-cists to image reflectors below the seis-mic receivers.

Sonic measurements in horizontal wells

Sonic waveform acquisition using theDipole Shear Sonic Imager, for example,can be applied to estimation of mechani-cal properties (e.g. compressional andshear bulk moduli, rock strength and fail-ure conditions etc.), or to gather informa-

tion on fractures and permeability.The permeability measurements are

derived from Stoneley wave measure-ments. There are two techniques, onebased on Stoneley slowness and theother on amplitude attenuation. Depthsof investigation using these techniquesrange from 0.5 to 5.0 ft, depending on theformation’s shear velocity and transmit-ter frequency. However, in a horizontalwell the shear wave may be affected bylayers lying near the borehole. In thissituation the shear wave can no longerbe relied on to estimate Stoneley slow-ness and permeability predictions can

become highly dubious.

The effects are shown in figure 1.20,where a horizontal well showed abnor-mally high Stoneley slowness-derived

permeability wherever the overlying shale was penetrated. In this particularexample the wellbore trajectory pene-trated the shale layer on two occasions.In both cases the shear measurement appears to read the limestone slownessand is, therefore, unsuitable for perme-ability determination. Track four of fig-ure 1.20 shows an abnormally high fluidmobility predicted in the shale. Theenergy-based approach involves onlyenergy loss due to actual fluid move-ment between the borehole and the for-mation, so the technique works even asthe borehole crosses from one formation

Fig. 1.20: LOGGING ON THE LINE: Horizontal wells usually have to track along thin formations or shadow the oil-water contact within a reservoir. During drilling it can be difficult just keeping thewell on course. By monitoring the response from various logs the driller can ‘see’ where the drill string crosses the contact of the Nahr Umr Shale and Shuaiba Limestone in an offshore well.

Affected bylimestone

∆tStoneley

∆tshear

Gamma ray

Stoneley∆t

meas / ∆t

elast

Stoneleyanelasticattenuation

Affected by

limestone∆t

sh

Nahr Umr Shale

Shuaiba Limestone

450

250

100

80

60

40

20

0.9

3

2

1

0(x10-4)

1.0

1.1

1.2

140

180

220

350

µs/ft

µs/ft

P e r m e a

b i l i t y

P e r m e a

b i l i t y

to another. The result is displayed intrack five, where the Stoneley anelasticattenuation curve shows zero fluid

mobility wherever the borehole is com-pletely surrounded by shale. The rela-tively high fluid mobility seen in variousplaces coincides with fracture systemswhich are also evident in the waveformsand confirmed by Stoneley fracturedetection as well as by FMI images.Fractures can only be detected byStoneley reflection when they are sub-orthogonal to the borehole trajectory.However, since horizontal wells are usu-ally drilled orthogonal to the fracture ori-entation, this technique is ideally suitedto horizontal holes.



Laterolog,

gamma-ray,neutron,

sonic, etc...

Radial measurement

Induction,MWD, e.m.resistivity,

deep dielectric

Circumferential measurement

Microresistivity,dielectric on skid,

density-Pe,electrical microscanner

Sidewall measurement

Selective radial measurement

ARI, FMI


How big is this measurement problem?

Formation logging tools were developedfor vertical holes where they make lat-eral measurements on the surrounding formations. During the development pro-

cess it was assumed that the tool wouldencounter similar sediments on eitherside of the wellbore.

These tools provide information onhorizontal wells, but the data theyrecord can be distorted and must beinterpreted with care.

When the zone influencing the tool'sreading is not uniform, the data reflectsthe mixed properties from the variouslayers (figure 1.21). Devices which con-tact the borehole wall may give appar-ently irreconcilable readings over largedistances, while those tools which havebeen designed to compensate for bore-

hole or invasion effects may be distortedbeyond recognition.There is, however, some good news:

tools such as the FMI* (FullboreFormation MicroImager) and theFormation MicroScanner* (FMS) wereeasily adapted to the new conditions,and have proved particularly useful fordefining barriers and heterogeneities inhorizontal wells.

As horizontal drilling becomesincreasingly popular (for certain opera-tors in some regions it is already stan-dard drilling practice) it is certain that new logging tools and techniques will

emerge. An example of this is the newResistivity-at-the-Bit measurement whichis available using the IDEAL GeoSteering system (figure 1.22). At present, most interpretation is carried out on datawhich has been collected using tradi-tional logging techniques. The emphasisnow is on changing interpretation tech-niques - not tool configuration.

Horizontal thinking - turn your ideas around

The main adjustment involves the ana-lysts themselves. Accustomed to work-ing in a vertical frame of reference, thelog analyst must overcome months oryears of practice interpreting verticallogs to ‘think in the horizontal’.However, once the interpretive adjust-ments have been made, an astonishing variety of reservoir data becomes avail-able and a range of new opportunitiescan be visualized.

A n a d r i l l

Driller’sscreen

Safetyscreen

Client’spresentation

Depth and

other surface

sensors

Detailed well

plan from

drilling planning

center

Remotecommunications

Fig. 1.22: ONE FOR ALL: The IDEAL system offers a flexibledownhole data gathering systemlinked to a display which presentsthe information in a clear format.The data is sent direct to thewellsite team and can betransmitted to a client's office,

allowing the client to monitor progress in real-time.

Fig. 1.21: Problems encountered inobtaining logging measurements inhorizontal wells where theformations are not symmetrical around the wellbore.

(a) (b)

(c) (d)



21Number 16, 1995.

Given the rapid variations which arepossible in rock sequences, there is noreason to suppose that at any given posi-tion the sediments immediately above ahorizontal hole are identical or even sim-ilar to those immediately below it. Thishas posed a problem for log analysts. Infact it has literally turned the world of

logging on its side.For example, a tool which makes

eight measurements around the bore-hole will give mixed readings even in thesimplest geological sequences. However,if we can select data from one or twosensors at a time, we can characterizethe beds which lie above, below andaround the tool.

The IDEAL solution?

Recent developments such as the newIDEAL system have revolutionized hori-zontal drilling. IDEAL can transmit vital

drilling and geological data from the bit to the surface in real time. This transferis accomplished in two stages. The toolsat the bit communicate, via a wirelesstelemetry link, with a high data rateMWD tool located further back along thestring. This device then pulses datathrough the mud column to the surface.

Well #3 Geosteered usingGeoSteering tool

Well #1 Geometrically steeredusing surveys

Missed target

Missed again!Well #2 Geologically steeredusing CDR tool

0

1

-1

0

200

100

Horizontal section MD,m

∆ T

V D

, m

Reservoir target

Non - reservoir

Fig. 1.23: A responsiveapproach to horizontal drilling is now possibleusing the geosteering technique. While geometrically and geologically steered wells move in and out of the reservoir target

zone, the GeoSteering tool used on Well 3 keeps the well ontarget from start tofinish.

This arrangement means that the MWDtool can be placed anywhere in thestring and still make measurements at the bit.

The data transmission rate, recording frequency and the information which istransmitted in real time can be selectedto meet the requirements of each particu-

lar job.The resistivity and gamma ray mea-

surements which the system makes areazimuthal, and so can be used to ‘look’up or down into the surrounding rock.This means that the driller and the geolo-gist have advance warning when the bit is about to pass up through the roof of areservoir or drop into the water layerbelow.

This geosteering technique is a signifi-cant improvement on the geometricalsteering methods which had becomestandard practice (figure 1.23). In geo-metric steering a plan is drawn and the

well drilled according to agreed spatialcoordinates. Then, after drilling, the wellis logged to determine whether it is inpay or not.

In geological steering, measurementsfrom Logging While Drilling tools, typi-cally 50-90ft behind the bit, are used tocheck if the hole is in the target zone.

The geosteering technique uses mea-surements taken at the bit. This allowsgeologists and drillers to work together -keeping the drill bit where it should be.The usual result is a higher percentage of drainhole pay with associated increasein hydrocarbon production and reducedwater cut.

Taking the test

Wells are tested to gather informationabout a reservoir from downhole pres-sure and/or flowrate measurements. Invertical wells, the process is familiar andrelatively straightforward. For horizontalwells, the situation is a little more com-

plex: extra parameters have to be derivedfrom the pressure transient test data.

Horizontal wells pose two special prob-lems for the reservoir engineer. The most obvious is the large wellbore storageeffect associated with horizontal sectionswhich may be thousands of feet in length.Wellbore storage effects are pressureeffects caused by the volume of fluids inthe wellbore before the test begins. Thispotential problem can be overcome bydownhole shut-in or downhole flow mea-surements and logarithmic convolution.




The second problem is the more com-plex nature of the transient. Once thewellbore storage has stabilized in a hori-zontal well, four types of flow regimesmay develop (three of which are radial).

First flow regime - (first radial flow period)

When a horizontal well first starts toflow, an elliptic-cylindrical flow regime

develops as the pressure disturbancepropagates through the near-well rock inanisotropic systems. In most reservoirs,except those in which the anisotropyratio kh /kv is large, this flow regime even-tually changes to pseudo-radial (figure1.24a) and this radial flow pattern contin-ues until the effect of the nearest bound-ary is felt at the wellbore. The behaviourof this first regime is similar to the early-time behaviour of partially penetrating vertical wells.

It is possible to obtain the geometricmean permeability and damage skinfrom the first flow regime provided the

wellbore pressure is not affected by well-bore storage and/or boundaries. Thevertical permeability can be computedfrom the time of onset of the pressure orpressure-derivative from this flow regime(in oilfield units).

Second flow regime - (second radial flow period)

Once the pressure disturbance reaches ano-flow boundary (either above orbelow the well) a second flow regimetakes over. Hemi-radial flow develops asshown in figure 1.24b. This type of flowregime occurs when the well is not equidistant from the top and bottom no-

flow boundaries. Occasionally, a wellmay be located so close to a boundarythat the first flow regime does not havetime to develop. The slope of the secondflow regime, which is twice that of thefirst, can also be used to obtain the geo-metric mean permeability and damageskin.

Third flow regime - (intermediate time-linear flow)

If the length of the horizontal well ismuch greater than the formation thick-ness, a linear flow regime may developfor a short period after the effects of thetop and bottom no-flow boundaries havebeen felt. The well length can beobtained from this flow regime.

Fourth flow regime - (third radial flow)

As the pressure disturbance continues topropagate into the reservoir, the influ-ence of the length of the well on theoverall flow regime diminishes to thepoint where the well can be assumed tobe a single drainage point. A third periodof radial flow pattern then starts in allreservoirs except those which have agas cap, or aquifer, near reservoirboundaries. The semilog straight lineslopes (figure 1.24c) of this period can beused to determine the horizontal perme-ability and geometric skin if the reservoirthickness is known.

Fig. 1.24: A NEW REGIME:When a horizontal well starts to flow, an elliptic- cylindrical flow regimedevelops. This eventually changes to a pseudo-radial flow pattern (a) and thiscontinues until the effect of the nearest boundary is felt

at the wellbore. Once the pressure disturbancereaches a no-flow boundary hemi-cylindrical flowdevelops (b). As the pressure disturbancecontinues to propagate intothe reservoir, the influenceof the length of the well onthe overall flow regimediminishes to the point where the well can beassumed to be a singledrainage point. A third period of radial flow patternthen starts (c).

The upsurge in horizontal drilling activity has made the use of transient well testing common practice in deter-mining the productivity of horizontalwells. In the past, horizontal wells wereanalyzed using the techniques whichhad been developed for vertical wells.Over the last 10 years, however, newsolutions have been presented for hori-zontal wells. We now have interpretationtechniques for estimating horizontal and

vertical permeabilities, skin and reser-voir pressure.

Testing hardware has also undergonea rapid change to meet the horizontalchallenge and coiled tubing technologyhas been developed to allow the use of production logging tools.

10

1

0.1

10-4

102

100

10-2

Time

D e r i v a

t i v e

Hemi-radialFirst-radial

Third-radial

(a)

(b)

(c)



23Number 16, 1995.

Fig. 1.26: This example, showing the contrast between horizontal and vertical permeability withinindividual layers, underlines the problems which reservoir modellers must overcome in apparently simple reservoirs.

Fig. 1.25: In vertical wells (a) reservoir tests can be carried out and interpreted quickly on a routinebasis. Horizontal wells (b) encounter lateral heterogeneities which are difficult to predict and greatly complicate the testing process.

Layered reservoirs

Most oil and gas reservoirs are layered.This layering reflects the sedimentaryprocesses which produced the rocksequence. Geological characterization of layered reservoirs and their evaluationhas become much easier in recent years,

thanks to the availability of 3D seismicsurveys and high-resolution wirelinelogs.

Transient behaviour in layered reser-voirs is important because the layering influences productivity in horizontalwells. Single-layer models are frequentlyused to interpret data from layered reser-voirs, but this produces results whichare clearly less than perfect. Researchinto multi-layer models has not beenrapid but recent results have beenencouraging.

Conventional well tests (figure 1.25a)allow the modeller to characterize a

homogeneous reservoir. Since sedimen-tary rocks are generally deposited at rel-atively low angles (typically <30°) avertical well is usually perpendicular tothe depositional environment and flowcan be considered to be radially sym-metrical around the wellbore.

In horizontal wells, however, (figure1.25b) the vertical variations of formationproperties and irregular shale distribu-tion mean that the system must be con-sidered heterogeneous in relation to ahorizontal well. As in the case of a verti-cal well we can estimate average perme-abilities, skin and reservoir pressure if the contrast between the layer proper-ties is not high. However, other factors,particularly those which are affected byfaults, fractures and other discontinu-ities, are more difficult to characterize ina horizontal well.

Layer variations

The subtle, and not so subtle, variationswhich occur within the layers of a multi-layer reservoir must be considered formodelling. Engineers who take averagepermeability values for each layer andplug these into a single-layer model canonly expect poor estimates of actualreservoir behaviour.

A recent study focused on a nine-layer system comprising horizontal lay-ers of different thickness, with high andlow permeabilities distributed randomlythrough the layers (figure 1.26).

20

10

5

15

20

5

10

5

15

0 20 40 60 80 100

Permeablity, md

L a y e r

t h i c k n e s s ,

f t

Horizontal permeability (kh)

Vertical permeability (kv)

Average vertical andhorizontal permeabilities

Skin

Reservoir pressure - P

Wellbore geometry - Lw

Simple discontinuity?

• Vertical variation of the formation properties and shale distribution make the systemheterogeneous for horizontal well testing.

• For only single-layer systems (small contrast among layer properties).

P kh kv S zw Lw

Six-parameter model

hzw

Lw Lw

z

oy

- kh kv

- S

P

kr

S

Average vertical andhorizontal permeabilities

Skin

Reservoir pressure

Wellbore geometry fracture

Simple discontinuity faults

Three-parameter model

- kr

- S

- P

(a)

(b)



Pressure profile along a horizontal well

High

Low

Pressure


Fig. 1.28: PRESSURE GAUGED: The drop in pressure towards thefault reflects production from thevertical well which isdepleting this reservoir

compartment. Once thehorizontal well crossesthe fault, however, it encounters original reservoir pressures and production increasesdramatically.

In this study, single-layer and multi-layer approaches to modelling wereapplied to the data and the results arepresented in figure 1.27. For the single-layer models, the thickness-weightedaverage horizontal permeability andeither the harmonic average of verticalpermeabilities or the harmonic average

of khkv, are used to compute systembehaviour. The derivatives for each of the three cases clearly indicate the first radial flow regime before the effects of the top and bottom no-flow boundariesare detected.

After a transition period, all of thecurves flatten, indicating that infinite act-ing radial flow conditions have beenreached. The behaviour of the nine-layerreservoir model is clearly very different from either of the two equivalent single-layer models, although the curves con-verge after 100 hours.

This example demonstrates that

multi-layer systems cannot be treated asan equivalent single-layer system.

Pressure in profile

A pressure profile along a horizontalwell can reveal a lot of new informationabout a reservoir and can open up newhydrocarbon accumulations which havebeen by-passed in the early stages of field development. Figure 1.28 shows anexample where production from theoriginal vertical well has depleted reser-voir pressure in a single fault compart-ment. By continuing along the reservoir

zone, the horizontal well can cross seal-ing faults or other permeability barriersto locate and produce separate oil accu-mulations. Analysis of pressure along the length of the well informs us about reservoir connectivity.

Contemplating completion

At present, horizontal wells are usuallycompleted in open hole or with slottedliner. However, as the technologybecomes more widespread and drain-holes grow longer, there will be agreater need for more sophisticated

completion techniques.Mechanical limitations mean that

medium and short radius horizontalwells are normally completed barefoot (figure 1.29a). This type of completioncan cause major problems. The long pro-ducing length of horizontal wells meansthat they are likely to cross zones of con-trasting vertical permeability, a situationwhich inevitably leads to prematurewater or gas production. Barefoot andslotted liner completions offer no

prospect of repair: once the well hasstarted to produce water the situationcan only get worse.

Only long-radius horizontal wells canbe completed with cemented/perforatedliners. However, as a result of gravitysegregation during cementing, mud dis-placement is often incomplete. This can

make it difficult to achieve a consistentlyhigh quality of cementation.

A popular completion method in long-radius wells is a slotted liner set in a barehole which may have a sand pack (figure1.29b). However, in the long term, whenwell repair is necessary, this technique isno better than barefoot completion.

Time, hr

D e r i v a

t i v e s ,

p s

i

100

10

10-1

100

101

102

103

nine-layer

‹kv› harmonic average

‹kh kv› harmonic average

n i n e - l a

y e r s y

s t e m

s i n g l e

- l a y e r s

y s t e

m

(Harmonic average of vertical permeabilitiesthickness weighted average of horizontal permeabilities)

√kh k

v (Harmonic average of

thickness weighted averageof horizontal permeabilities)

single-layer system

Fig. 1.27: MULTIPLE CHOICE: A comparison of the single-layer and multi-layer approaches. For thetwo single-layer models, average horizontal permeability (taking bed thickness into account) and average vertical permeability were calculated. The behaviour of the nine-layer reservoir model isclearly very different from either of the two equivalent single-layer models, although the curvesconverge after 100 hours.



25Number 16, 1995.

The introduction of slotted liners withinflatable packers mounted externally(figure 1.29c) offers the ideal answer forthe selective completion of wells withpotential water producing zones, such asmajor faults or heavily fractured intervals.The external packer arrangement allowseach section of the horizontal well to be

shut off or flow-metered independently.

Turn and fire

The heterogeneity encountered along the length of a horizontal drain will callfor greater flexibility and improvedmethods for selective completion. Theselective completion approach will, inturn, increase the amount of perforationcarried out in a well. Oriented perforat-ing techniques have proved very usefulin many horizontal wells. A methodwhich allows charges to be firedupwards, perforating the well on the side

away from the water layer, or firing down and perforating away from a gaslayer, are two obvious applications.

Other aspects of completion currentlyunder investigation include looking at gravel fluid properties during mud dis-placement (as completion fluid isinserted into the well), and stabilityproblems (borehole stability, cleaning of perforations etc.) which are typical of horizontal wells.

The future

A 1991 forecast of the market share of

logging techniques which would beapplied in 1995 (figure 1.30), correctlypredicted that the near monopoly fortraditional wireline techniques whichexisted then would be replaced by fast-growing shares for LWD (Logging WhileDrilling) and coiled tubing methods.The main reason for this shift was theanticipated increase in horizontaldrilling.

However, some of the predictionsabout horizontal drilling made in themid-1980s were over-enthusiastic. Whilethese forecasts now seem unlikely to befulfilled (vertical techniques have not

been completely abandoned) there is nodoubt that horizontal wells can out-per-form vertical wells in a variety of set-tings.

Future articles will outline the innova-tive use of laterals in reservoir develop-ment. One example is the multilateral(four holes in one well) dual horizontalcompletion which Zakum Development Company (Zadco) are using to producefrom three separate reservoir zones inthe Upper Zakum Field, UAE.

If the evolutionary process continuesand horizontal wells claim a larger shareof drilling expenditure in the world'smajor oilfields, further changes indrilling, logging and completion practicesare sure to follow.

Open hole

Slotted liner - classical type

Slotted liner with external inflatable casing packers

Cemented and perforated liner

(a)

(b)

(c)

(d)

Fig. 1.29: There are several options for completion of horizontal wells. Alarge proportion areopen hole or barefoot,(i.e. without cement or liner). Open hole(barefoot) completions

are relatively inexpensive, but, whenthere is a water entry problem along faults,the well must be selectively completed.This involvescementing behind inflatable packers - arelatively expensive process. It is better,therefore, to avoid water-producing faultsif possible.

38%

38%

21%

3%

Wired coiltubing

(openhole)

(casedhole)

Nolog

LoggingWhile

Drilling(MWD / LWD)

Conventional wire line

Fig. 1.30: This 1991forecast predicted a greater role for LWDand coiled tubing logging methods asmore horizontal wellswere drilled. Thesemethods have evolved rapidly over recent years and provide areliable alternative totraditional wirelinetechniques in fieldswhere horizontal drilling predominates.

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