Horizontal

T

he average horizontal well is more

expensive and technically difficult to drill

than the average vertical well. Yet, around

the world, horizontal wells are being spudded in

ever increasing numbers. Almost 80% of the wells

being drilled in Oman, Qatar and Abu Dhabi are

horizontal. Why should this be?

In simple terms, horizontal wells allow us to do

things more efficiently than vertical wells. It would be

short-sighted to ignore a technique which offers

improved drainage in typical reservoirs and

penetrates more of the discrete compartments in

complex reservoirs, while helping to reduce gas and

water coning.

In this article, Roy Nurmi brings together the

experience of staff in the Middle East headquarters’

interpretation, development and marketing team.

Fikri Kuchuk (petroleum engineer), Bruce Cassell

(geophysicist), Jean-Louis Chardac (log analyst) and

Philippe Maguet (manager) examine new

developments in horizontal well characterization for

reservoirs of the Middle East region, spanning Egypt

to India.

The article includes important published

contributions to the Geo’94 Conference from A. F.

Jubralla and P. Cosgrove (Qatar General Petroleum

Corporation, Doha, Qatar), and S.J. Whyte

(Petroleum Development Oman, Muscat, Sultanate

of Oman).

8 Middle East Well Evaluation Review

Throughout the Middle East, hori-

zontal wells are being used for

field developments which, in the

past, would have relied on vertical wells.

While the basic geology of many Middle

East fields is well known, details of reser-

voir structure, faulting, facies and pore

system heterogeneity are not usually so

well-defined.

The recent increase in horizontal

drilling has helped reservoir engineers

and geoscientists to understand the lat-

eral variations, permeability barriers and

compartments which occur between

existing vertical wells. Using horizontal

wells we can locate leached zones, find

unconformities and probe pinchouts and

other sites with by-passed oil potential.

Horizontal wells are usually drilled to

enhance oil production. In some situa-

tions the improvement may be dramatic

- enabling development of a reservoir

which 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 be

assessed carefully.

There are many kinds of reservoir

where the potential benefits of horizontal

drilling are obvious.

• Thin reservoirs: a vertical well drilled

into a thin reservoir will have a very small

contact surface (effectively limited by

reservoir thickness) with the oil-producing

horizon. A horizontal well in the same

reservoir layer can have a contact surface

running 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 very

large ones. If the well trajectory has been

planned carefully these large vertical

fractures can be used to improve pro-

ductivity, even when the overall fracture

density 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 underlines

the importance of having a good reservoir

model before drilling begins or being able

to assess the well accurately during or

after 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 to

reduce the amount of water or gas con-

ing in any given reservoir (figure 1.1).

This means that the total volume of oil

recovered 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-related

fractures mentioned above). However,

with advance planning, these can be

dealt with using selective completion

techniques.

Horizontal wells remove oil from a

reservoir over a long producing zone at

relatively slow rates. In contrast, vertical

wells take oil very quickly through much

shorter lengths of borehole. The flow

geometry associated with horizontal

wells tends to reduce the influence of

heterogeneity along the long drain - so

increasing total production.

• Thin layered reservoirs: oil recovery

from water flooding can be improved

dramatically by injecting and producing

from horizontal wells, rather than using

vertical wells in a traditional water flood

(figure 1.2).

• Heterogeneous reservoirs: horizontal

heterogeneity in reservoirs presents a

problem for vertical wells - they can only

access those reservoir compartments

which lie immediately below the drilling

rig. Horizontal wells can be used to

search for isolated and by-passed oil and

gas accumulations within a field.

From a logging viewpoint the benefits

of horizontal wells in a heterogeneous

reservoir are just as clear. Horizontal

wells pass through the lateral hetero-

geneity, revealing much more about the

internal reservoir structure than a verti-

cal well could. This means that in a com-

plex depositional environment (such as

a channel sandstone) the well can find

more of the oil- and gas-bearing zones or

compartments (figure 1.3) and so

increase total production (figure 1.4).

Vertical well

Horizontal well

Cross section Mukhaizna Field, Oman

Gas

Oil

Channel sand

Fig. 1.3: HITTING THE

TARGETS: In channel

sandstone reservoirs

comprising a number of

discrete oil and gas

accumulations a vertical

well may only find one

target, while a horizontal

or deviated well could

find several oil and gas

zones. A similar

application was used by

QGPC for a

heterogeneous 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 wells

drilled 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 HorizontalDrilling in Petroleum Development Oman Exploration1990-1993. AAPG International Conference, The Hague,The Netherlands.

M. Kharusi (1991) Evaluating the Opportunities forHorizontal Wells in Oman. 2nd Archie Conference,Houston, Texas, USA. pp. 35-46.

10 Middle East Well Evaluation Review

A technique for the ’90s

Before 1990, horizontal drilling was not a

popular technique. The oil industry only

drilled horizontal wells in difficult situa-

tions as a ‘last resort’. The global total for

1989 was just over 200 horizontal wells.

In 1990, that total leapt to almost 1200

wells, with nearly 1000 of these drilled in

the USA (figure 1.5).

In the USA, interest in horizontal

drilling techniques has been concen-

trated in Texas, specifically on the

Austin Chalk. Activity in this formation

soared from just 10 horizontal wells in

1989 to more than 200 in 1990. The pro-

duction results have more than justified

some of the intense activity in this

region. Success led some people to spec-

ulate that by the end of the century 50%

of all new wells being drilled in the USA

would be horizontal. Although this pre-

diction seems unlikely to be fulfilled,

there is no doubt that horizontal wells

will form a major part of oilfield strategy

in the USA and other mature oil

provinces around the world as operators

strive to produce oil and gas from low-

permeability zones which have been

missed by vertical wells.

The spectacular successes in the

Austin Chalk Formation transformed hor-

izontal drilling into a mainstream tech-

nique. Around the world, operators

applied the lessons learned in Texas to

boost production in their own reservoirs.

Inevitably, this led to some failures

where the horizontal drilling approach

was inappropriate, but it also brought

some outstanding achievements.

One of the leaders in horizontal

drilling is the Canadian oil industry. The

heavy, low - mobility oil which makes up

a large proportion of total Canadian

reserves was the initial reason for this

interest in horizontal wells.

Gas and water are much more

mobile than the thick, viscous oils

found in Canada’s oil sands. As a result,

vertical wells soon experience exces-

sive water and/or gas production

through coning effects. Using horizontal

wells, oil can be produced at low pres-

sures (without reducing production

rates) to keep gas and water away from

production wells for as long as possible.

The maintenance of production rates is

possible because the horizontal drain-

hole covers much more of the reservoir

than a vertical equivalent.

A study based on the first 500 hori-

zontal wells drilled in Canada predicted

that in 1993 alone horizontal drilling

would increase crude oil recovery by

2 billion barrels. Almost 20% of the 11,408

wells 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 in

order of decreasing oil rate production for

horizontal wells. This example is from

Canada’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 proportion

of these outside North America.

Another Canadian development has

been the use of re-entry wells to recover

significant quantities of oil left behind by

earlier 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)

410

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. FongRecent Adances in Horizontal Well Applications. 1994Canadian SPE / CIM / CANMET International Conference -‘Advancements in Redeveloping Mature Miscible FloodReservoirs with Horizontal Wells in Adverse ExploitationConditions.’

11Number 16, 1995.

In the Prudhoe Bay Field, Alaska,

USA, British Petroleum has drilled more

than 50 side-track wells from damaged

or low-yield wells. These coiled-tubing

workovers were a great success. It was

discovered that some of the faults were

water conduits. Review of the seismic

profiles for the field showed that

approximately 90% of the horizontal

wells penetrated faults which were visi-

ble on the latest 3D seismic. It was con-

cluded that between 10% and 20% of the

faults were conductive.

Why choose horizontal?

Horizontal wells cost more than vertical

wells - so what do they offer in return? In

problematic wells, for example, where

there is a thin oil column or a risk of

early water or gas production, vertical

wells 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 better

results than its vertical counterpart.

Higher oil rates, coupled with greatly

reduced gas-oil ratios, have made hori-

zontal wells the first choice for many

reservoirs. In some countries, such as

Qatar, Abu Dhabi and Oman, horizontal

drilling 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 is

a common feature of fields which have

been developed using vertical wells (fig-

ure 1.7). Even the flexibility of extended

reach wells - so important in offshore

operations where additional platforms

would be prohibitively expensive - can-

not match horizontal well performance.

Drilling horizontal wells is expensive

but, within any field, costs follow a

clear downward trend with time. In

Oman’s Nimr Field the ratio of drilling

costs between vertical and horizontal

wells decreased dramatically (figure

1.8) in the course of field development.

This decrease reflects the driller’s

greater familiarity with well conditions

and the consequent improved advance

planning.

2

1.8

1.6

1.4

1.2

1

134

156

157

158

169

170172

175

177

180

Time

Cos

t rat

io (

horiz

onta

l/ver

tical

)

Nimr Field, Oman

Fig. 1.8: GOING DOWN: The cost of horizontal wells usually decreases rapidly through time. In this

example, 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 a

third more expensive than a comparable vertical well. Modified from M. Kharusi, PDO, 1991 Archie

Conference, 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 wells

have by-passed.

Whip stock

Dry hole

Deviated well

Horizontal well

Undrained oil Attic oil

Sand pinchout

12 Middle East Well Evaluation Review

New horizons in Oman

The potential of horizontal wells has

been recognized throughout the Middle

East, but it is Oman that has seen the

most radical changes in field develop-

ment. In 1986, Petroleum Development

Oman (PDO) drilled three short radius

wells in a chalky Shuaiba limestone oil

reservoir. 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 was

suspended.

The rapid improvements in horizontal

drilling techniques over the following

four years persuaded the company to try

again and, in 1990, PDO embarked on a

more ambitious trial of eight medium-

radius wells in a number of reservoirs.

The results of this second phase were so

impressive 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 drilled

more than 200 horizontal wells in more

than 20 fields and seven different reser-

voir horizons. These include carbonates

and various sandstone facies (marine,

fluvial, aeolian and periglacial) with thin

and thick oil columns, heavy and light

oils and high and low water cuts. Large

numbers of reservoir heterogeneities

have been encountered, resulting in pro-

ductivities which were mediocre in one

well and spectacular in another only

200 m away.

PDO’s initial effort was centred on

improving the viability of marginal reser-

voirs. However, using horizontal wells to

replace vertical wells in the low perme-

ability zones of good reservoirs, has

proved very successful.

In the Natih Field, productivity

depends on the number and orientation

of fractures intersected by a well. A good

well - one which penetrates many open

fractures - will produce approximately

600 m3/day, but wells which intersect

few fractures may reach only 85 m3/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 faults

with throws as small as 3m. By overlaying

the fracture orientation data from core and

FMI* (Fullbore Formation MicroImager)

on a seismic dip map (figure 1.9a) a link

can be established between fractures and

faults. A revised well-targeting strategy

based on this information has allowed the

placement of wells near small faults and

flexures 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 borehole

imagery to reveal

fractures. Gross

production per well in

Natih Field (b) was found

to correlate closely with

proximity to faults defined

by 3D seismic. These

examples are taken from

the GEO/94 volume

article, Fractures and 3D

Seismic - the Natih Field

of North Oman, presented

by S. Whyte of Petroleum

Development Oman.

The close association between fractur-

ing and faulting was also observed in FMI

images from horizontal wells in Idd El

Shargi Field, offshore Qatar (figure 1.10).

Borehole imagery was combined with the

poor 3D seismic to ensure optimal field

development using horizontal wells. The

increased production from the first and

second horizontal wells drilled in this field

was 10 times greater than production from

the earlier vertical wells.

Apart from the economic benefits

which a well-planned horizontal drilling

campaign can provide, there are other

factors to be considered. Horizontal

drilling reveals a great deal about a

reservoir, information which is simply

not available from vertical wells.

Detailed logging of a horizontal well

allows us to measure and model the lat-

eral variations of permeability and

porosity which influence reservoir

development (figure 1.11).

As more information is gathered, the

full complexity of many reservoirs has

become apparent. By improving our pic-

ture of the reservoir we can recognize and

avoid potential problems or deal with

them before production is affected.

800

0

400N

034

N08

6

N10

5N

017L

N00

5

N07

9

N05

3

N02

9

N06

4

NW

006

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

Shuaiba A

0

5000

1000m

2000m

Shuaiba D

Kharaib reservoir

Depth (m)

0

13Number 16, 1995.

Fig. 1.10: Unexpected

faulting made it

difficult for two

horizontal wells to

remain within the

target (Kharaib

reservoir layer) in

Qatar’s Idd El Shargi

Field. FMS images

from both wells

revealed that the

fractures were closely

related to the faults.

Exact dip and strike

values for the faults

were also obtained

using the FMS. The

use of borehole

imagery indicated

which faults were

open and were

responsible for the

loss of drilling fluids

in the second well.

This figure is modified

from the GEO 94

paper presented by

P. Cosgrove and A.F.

Jubralla of QGPC.

Since 1989 more than 50 horizontal

wells (46 producers and a handful of

injectors) have been drilled in several

Offshore Abu Dhabi reservoirs - Zakuk,

Umm Shaif, Um Al Dalkh and Satah.

Successful efforts to reduce the time and

cost of operations while increasing pro-

ductivity have recently been described

at the ADIPEC meeting in Abu Dhabi.

Major advances were possible, thanks to

the steerable drilling techniques which

were introduced in 1991. These have

provided smooth well profiles, and mini-

mized fishing and side-tracking. ZADCO

reported that almost three weeks of

drilling time could be saved on dual

completion horizontal wells when com-

parisons were made with the standard

dual-completed deviated wells being

drilled three years ago.

ADNOC has used a horizontal drilling

in the development of the Jarn Yaphour

Field which is situated close to the sub-

urbs of Abu Dhabi. Horizontal drilling

was seen as the best way to minimize

environmental impact and guarantee the

highest safety levels for the city.

Side-tracking in SaudiArabia

The reservoir characteristics of many

Middle East oil and gas accumulations

suggest that horizontal infill drilling

could bring about major improvements

in semi-depleted reservoirs in fields

which may have been producing for 40

years or more.

One such reservoir is the Ratawi

reservoir of Wafra Field in the Saudi

Arabia-Kuwait Neutral Zone. A review of

selected well performance and reservoir

data showed that drilling moderate to

long horizontal wells in the more perme-

able layers would improve recovery effi-

ciency and field productivity.

A study indicated that over a five-

year period a 2000 ft horizontal well,

completed in the upper layers of the

reservoir, would produce almost seven

times more oil than a vertical well in the

same location.

P. Cosgrove and A.F. Jubralla The Development of a TightChalky Limestone Guided by 3D Seismic and the FMS inthe Idd El Shargi Field, Offshore Qatar. GEO 94Conference, Bahrain.

Wellbore

Fault with textural change

Fracture

Bedding change

Fault without drag

Bedding

D U

Top of hole

Bottom of hole

Top of hole

D U

Fig. 1.11: THINK

HORIZONTAL:

Borehole imaging tools

were designed for

vertical wells and

analysts have become

accustomed to

interpreting vertical

well images. When run

in a horizontal well the

geometry of faults,

fractures and bedding

features are very

different.

When the length of the horizontal sec-

tion is extended to 3000 ft, the five-year

cumulative oil production increases by

15%. More importantly, the cumulative

water production for the well is only one

quarter of that estimated for the 2000 ft

example.

H. Menouar (King Fahd University of Petroleum andMinerals) and W.S. Huang (Texaco E&P Technology)Horizontal Well Design in Wafra Field, Ratawi OoliteReservoir. 1993 SPE Middle East Oil Show.

Fig. 1.12: The ratio of horizontal

to vertical permeability, and

the variations in that ratio

throughout the reservoir are

crucial to the choice between

horizontal and vertical wells.

Where there are many low-

permeability barriers which

impede vertical (but not

horizontal) oil and gas

movement, vertical wells may

be more efficient than

their horizontal

counterparts.

14 Middle East Well Evaluation Review

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 wells

always 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 isotropic

reservoirs horizontal wells out-perform

Extended reach

Extended reach8

11

1 1

22

3

5

67

0

Distance (m)

0

1000

2000

3000

4000

5000

Dep

th (

m)

800 1600 2400 3200 4000 4800 5600 6400 7200

Legend

ONGC, India1

PDO, Oman2

AOC, Saudi Arabia3

Shell, Turkey

4

OXY, Oman

5

ADCO, Abu Dhabi

6

ZADCO, Abu Dhabi7

ELF, Oman

8

UNOCAL, USA

9

Mærsk Oil, Qatar

10

Statoil, North Sea

11

11

Cliff's Oil and Gas, USA12

1

10

12

9

234

1

1

13

14

Mærsk in Oman

British Petroleum in UK

Record makers andbreakers

Drillers claim world records more regu-

larly than sportsmen and women. The

long reach wells of 1990 are dwarfed by

wells drilled in 1994 (figure 1.13).

A well drilled recently by the

Norwegian State Oil Company, Statoil, in

their offshore Statfjord Field, had a hori-

zontal displacement of 7288 m with a true

vertical depth (tvd) of 2788 m, giving a

total length of 8758 m.

In Louisiana, USA, a very deep hori-

zontal well has been drilled by Cliff’s Oil

and Gas. The well, Martin A-1, has a true

vertical depth of 4675 m and a total dis-

placement of 5212 m.

One of the longest short-radius hori-

zontal wells was drilled by PDO in

Oman, while the longest medium-radius

well, Mærsk Oil Qatar’s Al Shaheen No.2,

reached 3899 m.

The greatest horizontal/vertical depth

ratio is found in a well drilled by UNO-

CAL in June 1992. This well, drilled off-

shore California, USA, has a 1489 m

horizontal displacement and a tvd of just

293 m. This means a length :depth ratio

of 5:1.

As drilling distances and depths grow

larger, the importance of accurate and

reliable directional methods becomes

ever more important.

their vertical counterparts for two main

reasons;

• borehole inclination; and

• the longer contact length between

borehole and reservoir.

In cases where vertical permeability

is significantly lower than horizontal per-

meability (figure 1.12), production can be

reduced to the point where vertical wells

are better. For a fixed length well, hori-

zontal wells are less effective than verti-

cal wells only where kv/kh (vertical

permeability/horizontal permeability) is

less 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 8715 m. 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 fthorizontal: 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 horizontal

wells can be a problem (figure 1.14).

The tool length is effectively controlled

by the radius of curvature in the well:

long tool strings cannot be pushed

round tight bends. Short radius wells

cost 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 a

relatively low curvature and a final hori-

zontal section which runs along the top

of a reservoir (figure 1.15). It makes use

of conventional directional drilling and

completion techniques.

•Medium radius laterals: the medium

radius lateral was developed to allow

conventional directional drilling, logging

techniques and completion hardware in

horizontal lateral drainage wells. Build

rates of 8°- 20°/100 ft are used to drill

from a vertical bore into a conventional-

ly sized lateral. Control over build rate is

achieved by varying motor size and

borehole size.

•Short radius laterals: the entry sections

from 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 open

hole 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 radius

of curvature for each

type determines the

logging and

completion techniques

which can be applied

in each case.

Fig. 1.14: ROUND THE

BEND: Short radius

wells cannot be

logged. The tool

strings are too long to

negotiate the tight

wellbore curve.

Build rateMWDDirection controlDrilling methodCompletion

Longradius

1˚- 6˚/100ftYesYesDirectionalOpen hole

Mediumradius

8˚- 20˚/100ftYesYes

Shortradius

1.5˚- 3˚/ftNoDifficult

16 Middle East Well Evaluation Review

Follow the pilot

Some pilot holes are vertical but others

are inclined holes which are drilled

through the zones of interest before

beginning the horizontal portion of a

well. A pilot hole is usually situated

close to an existing development well

when there is uncertainty in the struc-

tural dip across the field. Good dip data

is essential for horizontal wells: a minor

measurement error, such as 0.5°, will

result in a vertical displacement of 44 ft

over a horizontal distance of 5000 ft.

Images recorded in a pilot well provide

the most thorough dip determination

available because the geologist can

select the dip directly, even in cases

where wavy or discontinuous bedding

would reduce the quality of data from a

dipmeter 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 the

planned horizontal well trajectory (fig-

ure 1.16b) to complete half the build and

move the control point closer to the

drainhole.

In reservoirs where the structure or

stratigraphy remain uncertain, pilotless

horizontal wells are now being drilled

with 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 new

systems such as MWD (Measurements

While Drilling), LWD (Logging While

Drilling) and geosteering techniques. In

areas where the geology is relatively sim-

ple and well-known, horizontal wells can

now be drilled without a pilot. In com-

plex fields, however, we rely on pilot

holes to identify the tops of formation

precisely.

Steering clear

Directional drilling (or geometrical steer-

ing) aims to keep the well on a pre-

planned trajectory, while ‘geosteering’ is

the use of geological information to guide

a well to its target, especially when the

geology turns out to be different from

that expected. Sophisticated measure-

ments, now available during drilling

(from MWD and LWD methods), make

this geosteering task considerably easier.

The latest techniques can identify

changes in resistivity and allow direc-

tional adjustments to be made before the

drill bit strays deep into overlying shales

or an underlying water layer.

Geosteering methods can keep a well

in a very thin reservoir zone and can

react quickly to abrupt lateral changes

such as those encountered when a bore-

hole crosses a fault plane.

Reservoir top

Reservoir top

Reservoir top

Horizontal well

Horizontal well

Vertical pilot well

Oil water contact

Deviated pilot well (45˚)

Oil water contact

Oil water contact

No pilot well

LWD and MWD with geosteering replacing a pilot

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

Fig. 1.16: PILOTS FOR PREDICTION: A pilot well allows the driller to predict what will be

encountered 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 to

reservoir variations rather than following a planned geometric trajectory.

(a)

(b)

(c)

Keeping the well on course is obvi-

ously very important, but there are other

reasons for using LWD and MWD tech-

niques. They permit:

• accurate selection of 1st and 2nd build

points and, especially, the target entry

point (horizontal section or reservoir

section);

• 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 petroleum

industry's first fully instrumented, steer-

able, positive displacement motor

(PDM). It provides long to medium

radius directional drilling capability plus

azimuthal resistivity and azimuthal

gamma ray to aid steering, motor RPM

and inclination measurements at the bit.

Mother well (madar chan)

Bedrock Alluvial fan Longitudinal section

Groundwater table before ghanat was dug

Groundwater table while 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 the

motor housing, which reduces bit-to-

measurement lag to a few feet. Data is

transmitted to the PowerPulse MWD tool

by electromagnetic telemetry with no

wiring through motor sections or drill-

string components.

Guiding a drillstring directionally

through the earth's crust has been a less

than perfect science. Reaching the target

quickly and safely depends on careful

planning, the expertise of the directional

driller, and the performance of the hard-

ware and navigation instrumentation.

The directional driller formulates a

drilling 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 to

unforeseen changes in bed and fluid

boundaries between offset wells.

Until now, the directional driller has

had to manipulate the drillstring based

on MWD measurements made from less-

than-ideal positions, as far as 100 ft from

the bit. When geological changes are

noted, 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 changes

all this. The system puts the sensors

where they belong - at the bit - and turns

the drillstring into a reliable source of

real-time drilling and petrophysical infor-

mation that leads to dramatically

improved drilling performance and pro-

ductivity.

As horizontal drilling becomes stan-

dard practice in oil provinces around the

world, the technique which allows

driller and geologist to ‘see’ the rocks

during drilling will probably become

more popular. This method is likely to

reduce the number of pilot wells drilled

in the future.

Fig. 1.17: WATER PRODUCTION: The history of horizontal wells can be traced to the Middle East. In

the 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.

HORIZONTALHISTORYHorizontal wells are not a new idea. The

earliest horizontal wells were drilled

more than 2000 years ago (figure 1.17).

The first written records concern the use

of horizontal groundwater wells in the

central plateau of Iran. According to the

Greek historian Polybius, they were

used to increase water production.

Many thousands of such wells, and

the air shafts that allow access for servic-

ing, are still being used in central Iran.

These horizontal, tunnel-like wells are

known as ghanats (or qanats) in Farsi,

kharis in Turkish and foggara (or phalaj)

in Arabic.

Similar wells were used in Egypt’s

Western Desert more than 2500 years

ago to increase the water flow from frac-

tured Nubian sandstone. The use of hori-

zontal tunnel-wells as water producers

soon spread across the globe to places

as far apart as India and Spain.

As the technique spread through

Europe, a better understanding of the

process emerged. In south-eastern

England, for example, long (up to 7500 ft)

horizontal tunnels were constructed in

the low permeability chalk. The higher

flow rates associated with the presence

of fractures proved to the early horizon-

tal drillers that placing their wells perpen-

dicular to the main fracture orientation

increased the number of fractures

encountered and boosted production.

The application of horizontal wells in

oilfield 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 the

Commonwealth of Independent States

(CIS), horizontal drilling dates back to

the 1950s.

Reaching the parts other wellscannot reach

The horizontal approach in oilfield tech-

nology has generally been reserved for

problematic 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 technique

has been applied to solve a particular

problem until new, cheaper or more effi-

cient alternatives have been developed.

So why, after all this time and the

technical development of vertical meth-

ods, is there still so much interest in hor-

izontal drilling? The answer is simple:

horizontal wells can succeed in places

where vertical wells would fail.

17

18 Middle East Well Evaluation Review

FAULTS,FRACTALS ANDFLUIDSFractures and faults can behave as barri-

ers or baffles to reservoir flow, but very

little research has been published on

these effects. Generally we should expect

to encounter more open fractures and

permeable faults in a horizontal well than

previously mapped for the reservoir -

unless the well is drilled specifically to

avoid these features. Good reservoir

characterization is critical for optimal

well placement (figure 1.18), for design of

appropriate well tests and for selecting

the correct completion methods.

Multidisciplinary studies and new

technologies in 3D seismic surveys and

3D borehole imagery have been com-

bined to reveal faulting which would not

have been detected by standard devel-

opment methods. However, in carbonate

reservoirs many faults are invisible to

dipmeter and seismic techniques.

Deformation occurs by brittle failure,

rather than plastic deformation so there

is no characteristic ‘drag zone’.

In some reservoirs it may be possible

to use fractal methods or other statistical

analysis of fracture distribution (figure

1.19). This method may help to explain

the size distribution of sub-seismic faults

encountered in horizontal wells.

Reservoir faults have been identified

as water sources in many of the massive

carbonate sequences in and around the

Gulf and in some sandstone reservoirs

from Syria to Yemen. As the volume of

borehole imagery data from horizontal

wells continues to grow, it becomes

apparent that shear faulting plays a

major role in water production for many

fields. How can we identify these faults

and deal with them before they affect

production?

Typical shear faults dip at high angles

and are very rarely intersected by verti-

cal wells. In addition, their movement is

predominantly strike-slip (lateral) which

makes them invisible on 2D seismic sec-

tions. Moreover, their brittle deformation

and the absence of drag zones along the

fault plane make them equally invisible

to dipmeters.

Careful examination of electrical

images can reveal shear faulting.

Apertures which are larger than those of

associated fractures and differences in

bedding or textural characteristics on

either side of these high-angle, conduc-

tive features (faults) are subtle yet defi-

nite clues to their presence (figure 1.11).

East

OWC

drainhole

North

Further evidence of shear faulting can

be gathered by looking at horizontal

slices, or slices parallel to the formation

boundaries, in high-quality 3D seismics.

Seismic and electrical imaging tech-

niques should be combined to assess

the large-scale distribution of shear

faults, while well testing can be relied on

to determine their effect on fluid flow.

Fault identification methods used in

vertical wells (e.g. missing sections to

indicate normal faults or repeated sec-

1

0.01 0.1 1 10 100

10

100

Cum

ulat

ive

num

ber

of fr

actu

res

Fracture spacing, ft

1000

10,000 Fig. 1.19: Fractures

often display a fractal,

or power law,

distribution. In simple

terms, this means that

there are relatively

few large faults and a

huge number of small

faults. Bill Belfield

and Jerry Sovich of

ARCO recently

revealed a fractal, or

power, relationship

for fracture spacing

from horizontal well

data. Modified from

W. Belfield and J.

Sovich (ARCO). This

study is based on

analysis of more than

13,000 fractures

defined by electrical

imagery in six

horizontal wellbores.

tions for reverse faults) are not generally

applicable in horizontal boreholes.

Extensional faults can be recognized by

the fact that the dip of the deformation or

drag along these faults is in the same

direction as the fault plane, but dipping in

the opposite direction to the fault plane.

For listric growth faults and reverse faults,

the deformation along the down-thrown

block dips in a direction opposite to the

fault plane.

W. Belfield and J Sovich, Fracture Statistics fromHorizontal Wellbores. Canadian SPE/CIM/CANMETInternational Conference on Recent Advances inHorizontal Well Applications.

Fig. 1.18: DRAINING

AGAIN: This South

American example,

from Lake Maracaibo

in Venezuela,

illustrates the

flexibility of the

horizontal well

technique. Having

identified the location

and orientation of the

major fault, the

operator chose to

position the horizontal

drainhole along the

crest of this plunging

anticline to maximize

oil recovery. Similar

techniques are being

used by GUPCO in the

fault-block reservoirs

which occur in Egypt’s

Gulf of Suez.

19Number 16, 1995.

Logging along the horizon

The long period when horizontal wells

were considered a ‘last resort’ is under-

lined by the under-development of log-

ging systems and interpretation for

horizontal wells. The methods which are

available have lagged behind the

advanced interpretative techniques

developed for vertical wells, but this sit-

uation is changing. Established research

and development programmes are cur-

rently yielding new approaches to log

analysis in horizontal wells.

Acoustic measurements inhorizontal wells

Seismic and sonic techniques can be

applied in horizontal wells, although pro-

cessing and interpretation of the data

can be more complicated than in vertical

wells.

Vertical Seismic Profiles (VSPs) and

Walkaways work by measuring the dif-

ference between downgoing and

reflected wavefields. In horizontal wells,

where the receivers are arranged hori-

zontally, there is no moveout difference

between the two wavefields. This prob-

lem is easily overcome by comparing

the responses of geophones (velocity

sensitive devices which record direc-

tional information) and hydrophones

(pressure-sensitive devices which pro-

duce an identical pressure response for

both downgoing and reflected fields). By

subtracting one seismogram from the

other we can eliminate the effect of the

downgoing wavefield, allowing geophysi-

cists to image reflectors below the seis-

mic receivers.

Sonic measurements inhorizontal wells

Sonic waveform acquisition using the

Dipole Shear Sonic Imager, for example,

can be applied to estimation of mechani-

cal properties (e.g. compressional and

shear 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, one

based on Stoneley slowness and the

other on amplitude attenuation. Depths

of investigation using these techniques

range from 0.5 to 5.0 ft, depending on the

formation’s shear velocity and transmit-

ter frequency. However, in a horizontal

well the shear wave may be affected by

layers lying near the borehole. In this

situation the shear wave can no longer

be 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 particular

example the wellbore trajectory pene-

trated the shale layer on two occasions.

In both cases the shear measurement

appears to read the limestone slowness

and is, therefore, unsuitable for perme-

ability determination. Track four of fig-

ure 1.20 shows an abnormally high fluid

mobility predicted in the shale. The

energy-based approach involves only

energy loss due to actual fluid move-

ment between the borehole and the for-

mation, so the technique works even as

the 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 the

well 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 /∆telast

Stoneley anelasticattenuation

Affected bylimestone ∆tsh

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

Per

mea

bilit

yP

erm

eabi

lity

to another. The result is displayed in

track five, where the Stoneley anelastic

attenuation curve shows zero fluid

mobility wherever the borehole is com-

pletely surrounded by shale. The rela-

tively high fluid mobility seen in various

places coincides with fracture systems

which are also evident in the waveforms

and confirmed by Stoneley fracture

detection as well as by FMI images.

Fractures can only be detected by

Stoneley 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 suited

to 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

20 Middle East Well Evaluation Review

How big is thismeasurement problem?

Formation logging tools were developed

for vertical holes where they make lat-

eral measurements on the surrounding

formations. During the development pro-

cess it was assumed that the tool would

encounter similar sediments on either

side of the wellbore.

These tools provide information on

horizontal wells, but the data they

record can be distorted and must be

interpreted with care.

When the zone influencing the tool's

reading is not uniform, the data reflects

the mixed properties from the various

layers (figure 1.21). Devices which con-

tact the borehole wall may give appar-

ently irreconcilable readings over large

distances, while those tools which have

been designed to compensate for bore-

hole or invasion effects may be distorted

beyond recognition.

There is, however, some good news:

tools such as the FMI* (Fullbore

Formation MicroImager) and the

Formation MicroScanner* (FMS) were

easily adapted to the new conditions,

and have proved particularly useful for

defining barriers and heterogeneities in

horizontal wells.

As horizontal drilling becomes

increasingly 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 new

Resistivity-at-the-Bit measurement which

is available using the IDEAL GeoSteering

system (figure 1.22). At present, most

interpretation is carried out on data

which has been collected using tradi-

tional logging techniques. The emphasis

now is on changing interpretation tech-

niques - not tool configuration.

Horizontal thinking - turnyour ideas around

The main adjustment involves the ana-

lysts themselves. Accustomed to work-

ing in a vertical frame of reference, the

log analyst must overcome months or

years of practice interpreting vertical

logs 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 opportunities

can be visualized.

An

adri

ll

Driller’sscreen

Safetyscreen

Client’spresentation

Depth andother surface

sensors

Detailed wellplan from

drilling planningcenter

Remotecommunications

Fig. 1.22: ONE FOR ALL: The

IDEAL system offers a flexible

downhole data gathering system

linked to a display which presents

the information in a clear format.

The data is sent direct to the

wellsite team and can be

transmitted to a client's office,

allowing the client to monitor

progress in real-time.

Fig. 1.21: Problems encountered in

obtaining logging measurements in

horizontal wells where the

formations are not symmetrical

around the wellbore.

(a) (b)

(c) (d)

21Number 16, 1995.

Given the rapid variations which are

possible in rock sequences, there is no

reason to suppose that at any given posi-

tion the sediments immediately above a

horizontal hole are identical or even sim-

ilar to those immediately below it. This

has posed a problem for log analysts. In

fact 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 the

simplest geological sequences. However,

if we can select data from one or two

sensors at a time, we can characterize

the beds which lie above, below and

around the tool.

The IDEAL solution?

Recent developments such as the new

IDEAL system have revolutionized hori-

zontal drilling. IDEAL can transmit vital

drilling and geological data from the bit

to the surface in real time. This transfer

is accomplished in two stages. The tools

at the bit communicate, via a wireless

telemetry link, with a high data rate

MWD tool located further back along the

string. This device then pulses data

through the mud column to the surface.

Well #3 Geosteered using GeoSteering tool

Well #1 Geometrically steered using surveys

Missed target

Missed again!Well #2 Geologically steered using CDR tool

0

1

-1

0

200

100

Horizontal section MD,m

∆ T

VD

,m

Reservoir target

Non - reservoir

Fig. 1.23: A responsive

approach to horizontal

drilling is now possible

using 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 on

target from start to

finish.

This arrangement means that the MWD

tool can be placed anywhere in the

string and still make measurements at

the bit.

The data transmission rate, recording

frequency and the information which is

transmitted in real time can be selected

to meet the requirements of each particu-

lar job.

The resistivity and gamma ray mea-

surements which the system makes are

azimuthal, 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 a

reservoir or drop into the water layer

below.

This geosteering technique is a signifi-

cant improvement on the geometrical

steering methods which had become

standard practice (figure 1.23). In geo-

metric steering a plan is drawn and the

well drilled according to agreed spatial

coordinates. Then, after drilling, the well

is logged to determine whether it is in

pay or not.

In geological steering, measurements

from Logging While Drilling tools, typi-

cally 50-90ft behind the bit, are used to

check if the hole is in the target zone.

The geosteering technique uses mea-

surements taken at the bit. This allows

geologists 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 increase

in hydrocarbon production and reduced

water cut.

Taking the test

Wells are tested to gather information

about a reservoir from downhole pres-

sure and/or flowrate measurements. In

vertical wells, the process is familiar and

relatively straightforward. For horizontal

wells, the situation is a little more com-

plex: extra parameters have to be derived

from the pressure transient test data.

Horizontal wells pose two special prob-

lems for the reservoir engineer. The most

obvious is the large wellbore storage

effect associated with horizontal sections

which may be thousands of feet in length.

Wellbore storage effects are pressure

effects caused by the volume of fluids in

the wellbore before the test begins. This

potential problem can be overcome by

downhole shut-in or downhole flow mea-

surements and logarithmic convolution.

22 Middle East Well Evaluation Review

The second problem is the more com-

plex nature of the transient. Once the

wellbore storage has stabilized in a hori-

zontal well, four types of flow regimes

may develop (three of which are radial).

First flow regime -(first radial flow period)

When a horizontal well first starts to

flow, an elliptic-cylindrical flow regime

develops as the pressure disturbance

propagates through the near-well rock in

anisotropic systems. In most reservoirs,

except those in which the anisotropy

ratio kh/kv is large, this flow regime even-

tually changes to pseudo-radial (figure

1.24a) and this radial flow pattern contin-

ues until the effect of the nearest bound-

ary is felt at the wellbore. The behaviour

of this first regime is similar to the early-

time behaviour of partially penetrating

vertical wells.

It is possible to obtain the geometric

mean permeability and damage skin

from the first flow regime provided the

wellbore pressure is not affected by well-

bore storage and/or boundaries. The

vertical permeability can be computed

from the time of onset of the pressure or

pressure-derivative from this flow regime

(in oilfield units).

Second flow regime -(second radial flow period)

Once the pressure disturbance reaches a

no-flow boundary (either above or

below the well) a second flow regime

takes over. Hemi-radial flow develops as

shown in figure 1.24b. This type of flow

regime occurs when the well is not

equidistant from the top and bottom no-

flow boundaries. Occasionally, a well

may be located so close to a boundary

that the first flow regime does not have

time to develop. The slope of the second

flow regime, which is twice that of the

first, can also be used to obtain the geo-

metric mean permeability and damage

skin.

Third flow regime -(intermediate time-linear flow)

If the length of the horizontal well is

much greater than the formation thick-

ness, a linear flow regime may develop

for a short period after the effects of the

top and bottom no-flow boundaries have

been felt. The well length can be

obtained from this flow regime.

Fourth flow regime -(third radial flow)

As the pressure disturbance continues to

propagate into the reservoir, the influ-

ence of the length of the well on the

overall flow regime diminishes to the

point where the well can be assumed to

be a single drainage point. A third period

of radial flow pattern then starts in all

reservoirs except those which have a

gas cap, or aquifer, near reservoir

boundaries. The semilog straight line

slopes (figure 1.24c) of this period can be

used to determine the horizontal perme-

ability and geometric skin if the reservoir

thickness is known.

Fig. 1.24: A NEW REGIME:

When a horizontal well

starts to flow, an elliptic-

cylindrical flow regime

develops. This eventually

changes to a pseudo-radial

flow pattern (a) and this

continues until the effect of

the nearest boundary is felt

at the wellbore. Once the

pressure disturbance

reaches a no-flow boundary

hemi-cylindrical flow

develops (b). As the

pressure disturbance

continues to propagate into

the reservoir, the influence

of the length of the well on

the overall flow regime

diminishes to the point

where the well can be

assumed to be a single

drainage point. A third

period of radial flow pattern

then starts (c).

The upsurge in horizontal drilling

activity has made the use of transient

well testing common practice in deter-

mining the productivity of horizontal

wells. In the past, horizontal wells were

analyzed using the techniques which

had been developed for vertical wells.

Over the last 10 years, however, new

solutions have been presented for hori-

zontal wells. We now have interpretation

techniques for estimating horizontal and

vertical permeabilities, skin and reser-

voir pressure.

Testing hardware has also undergone

a rapid change to meet the horizontal

challenge and coiled tubing technology

has been developed to allow the use of

production logging tools.

10

1

0.1

10-4 10210010-2

Time

Der

ivat

ive

Hemi-radialFirst-radial

Third-radial

(a)

(b)

(c)

23Number 16, 1995.

Fig. 1.26: This example, showing the contrast between horizontal and vertical permeability within

individual 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 routine

basis. 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 sedimentary

processes which produced the rock

sequence. Geological characterization of

layered reservoirs and their evaluation

has become much easier in recent years,

thanks to the availability of 3D seismic

surveys and high-resolution wireline

logs.

Transient behaviour in layered reser-

voirs is important because the layering

influences productivity in horizontal

wells. Single-layer models are frequently

used to interpret data from layered reser-

voirs, but this produces results which

are clearly less than perfect. Research

into multi-layer models has not been

rapid but recent results have been

encouraging.

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°) a

vertical well is usually perpendicular to

the depositional environment and flow

can be considered to be radially sym-

metrical around the wellbore.

In horizontal wells, however, (figure

1.25b) the vertical variations of formation

properties and irregular shale distribu-

tion mean that the system must be con-

sidered heterogeneous in relation to a

horizontal 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 by

faults, fractures and other discontinu-

ities, are more difficult to characterize in

a horizontal well.

Layer variations

The subtle, and not so subtle, variations

which occur within the layers of a multi-

layer reservoir must be considered for

modelling. Engineers who take average

permeability values for each layer and

plug these into a single-layer model can

only expect poor estimates of actual

reservoir behaviour.

A recent study focused on a nine-

layer system comprising horizontal lay-

ers of different thickness, with high and

low permeabilities distributed randomly

through the layers (figure 1.26).

20

10

5

15

20

5

10

5

15

0 20 40 60 80 100

Permeablity, md

Laye

r th

ickn

ess,

ft

Horizontal permeability (kh)

Vertical permeability (kv)

Average vertical and horizontal permeabilities Skin Reservoir pressure - P Wellbore geometry - Lw Simple discontinuity?

• Vertical variation of the formation properties and shale distribution make the system heterogeneous 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 and horizontal 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

24 Middle East Well Evaluation Review

Fig. 1.28: PRESSURE

GAUGED: The drop in

pressure towards the

fault reflects

production from the

vertical well which is

depleting this reservoir

compartment. Once the

horizontal well crosses

the fault, however, it

encounters original

reservoir pressures and

production increases

dramatically.

In this study, single-layer and multi-

layer approaches to modelling were

applied to the data and the results are

presented in figure 1.27. For the single-

layer models, the thickness-weighted

average horizontal permeability and

either the harmonic average of vertical

permeabilities or the harmonic average

of khkv, are used to compute system

behaviour. 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 boundaries

are detected.

After a transition period, all of the

curves flatten, indicating that infinite act-

ing radial flow conditions have been

reached. The behaviour of the nine-layer

reservoir 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 as

an equivalent single-layer system.

Pressure in profile

A pressure profile along a horizontal

well can reveal a lot of new information

about a reservoir and can open up new

hydrocarbon accumulations which have

been by-passed in the early stages of

field development. Figure 1.28 shows an

example where production from the

original 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 barriers

to 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 usually

completed in open hole or with slotted

liner. However, as the technology

becomes more widespread and drain-

holes grow longer, there will be a

greater need for more sophisticated

completion techniques.

Mechanical limitations mean that

medium and short radius horizontal

wells are normally completed barefoot

(figure 1.29a). This type of completion

can cause major problems. The long pro-

ducing length of horizontal wells means

that they are likely to cross zones of con-

trasting vertical permeability, a situation

which inevitably leads to premature

water or gas production. Barefoot and

slotted liner completions offer no

prospect of repair: once the well has

started to produce water the situation

can only get worse.

Only long-radius horizontal wells can

be completed with cemented/perforated

liners. However, as a result of gravity

segregation during cementing, mud dis-

placement is often incomplete. This can

make it difficult to achieve a consistently

high quality of cementation.

A popular completion method in long-

radius wells is a slotted liner set in a bare

hole which may have a sand pack (figure

1.29b). However, in the long term, when

well repair is necessary, this technique is

no better than barefoot completion.

Time, hr

Der

ivat

ives

, psi

100

10

10-1

100

101

102

103

nine-layer ‹kv› harmonic average ‹kh kv› harmonic average

nine-layer system

single

-laye

r sys

tem

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

√ kh k

v

(Harmonic average of thickness weighted average of horizontal permeabilities)

single-layer system

Fig. 1.27: MULTIPLE CHOICE: A comparison of the single-layer and multi-layer approaches. For the

two 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 is

clearly very different from either of the two equivalent single-layer models, although the curves

converge after 100 hours.

25Number 16, 1995.

The introduction of slotted liners with

inflatable packers mounted externally

(figure 1.29c) offers the ideal answer for

the selective completion of wells with

potential water producing zones, such as

major faults or heavily fractured intervals.

The external packer arrangement allows

each 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 call

for greater flexibility and improved

methods for selective completion. The

selective completion approach will, in

turn, increase the amount of perforation

carried out in a well. Oriented perforat-

ing techniques have proved very useful

in many horizontal wells. A method

which allows charges to be fired

upwards, perforating the well on the side

away from the water layer, or firing

down and perforating away from a gas

layer, are two obvious applications.

Other aspects of completion currently

under investigation include looking at

gravel fluid properties during mud dis-

placement (as completion fluid is

inserted into the well), and stability

problems (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 be

applied in 1995 (figure 1.30), correctly

predicted that the near monopoly for

traditional wireline techniques which

existed then would be replaced by fast-

growing shares for LWD (Logging While

Drilling) and coiled tubing methods.

The main reason for this shift was the

anticipated increase in horizontal

drilling.

However, some of the predictions

about horizontal drilling made in the

mid-1980s were over-enthusiastic. While

these forecasts now seem unlikely to be

fulfilled (vertical techniques have not

been completely abandoned) there is no

doubt 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 horizontal

completion which Zakum Development

Company (Zadco) are using to produce

from three separate reservoir zones in

the Upper Zakum Field, UAE.

If the evolutionary process continues

and horizontal wells claim a larger share

of drilling expenditure in the world's

major oilfields, further changes in

drilling, logging and completion practices

are 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. A

large proportion are

open hole or barefoot,

(i.e. without cement or

liner). Open hole

(barefoot) completions

are relatively

inexpensive, but, when

there is a water entry

problem along faults,

the well must be

selectively completed.

This involves

cementing behind

inflatable packers - a

relatively expensive

process. It is better,

therefore, to avoid

water-producing faults

if possible.

38%38%

21%3%

Wired coiltubing

(open hole)

(casedhole)

Nolog

LoggingWhile

Drilling(MWD / LWD)

Conventional wire line

Fig. 1.30: This 1991

forecast predicted a

greater role for LWD

and coiled tubing

logging methods as

more horizontal wells

were drilled. These

methods have evolved

rapidly over recent

years and provide a

reliable alternative to

traditional wireline

techniques in fields

where horizontal

drilling predominates.