SPE 93379

Successful Use of Horizontal Well Technology in Mitigating Water Production and

Increasing Oil Recovery in the South Umm Gudair Field, PNZ, Kuwait
D. Barge, SPE, and T. Tran, Saudi Arabian Texaco; O. Al-Shaarawy and M. Jha, SPE, Kuwait Oil Co.; B. Hagtvedt,
Total; M. Al-Haimer, Kuwait Oil Co.; and M. Al-Harbi, Saudi Arabian Texaco

Copyright 2005, Society of Petroleum Engineers Inc.

production. Fig. 2 provides the production history for the
This paper was prepared for presentation at the 14th SPE Middle East Oil & Gas Show and SUG field.
Conference held in Bahrain International Exhibition Centre, Bahrain, 12–15 March 2005.

This paper was selected for presentation by an SPE Program Committee following review of
information contained in a proposal submitted by the author(s). Contents of the paper, as
Several campaigns were performed to mitigate increasing
presented, have not been reviewed by the Society of Petroleum Engineers and are subject to water cuts and increase oil recovery. In 1994 and 1995,
correction by the author(s). The material, as presented, does not necessarily reflect any
position of the Society of Petroleum Engineers, its officers, or members. Papers presented at remedial work on 13 high water cut wells was performed.1
SPE meetings are subject to publication review by Editorial Committees of the Society of
Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper
This work was limited to mechanical isolation techniques. An
for commercial purposes without the written consent of the Society of Petroleum Engineers is additional, 11 wells were worked over using these techniques
prohibited. Permission to reproduce in print is restricted to a proposal of not more than 300
words; illustrations may not be copied. The proposal must contain conspicuous between 1996 and 2002. Efforts made to control high water
acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O.
Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.
production and increase oil recovery using mechanical
plugback techniques initially looked promising. However,
Abstract decreases in water cut were often short-lived as water
The producing history of the South Umm Gudair Field (SUG) encroachment in individual wells continued. Table 1
is characterized by increasing water cuts and increasing summarizes the results observed from the mechanical water
decline rates. Several different conventional techniques were shut-off work.
applied to mitigate the effects of water encroachment.
Results from applying these techniques were mixed. While Successful application of polymers in water shut-off
some earlier applications looked promising, later applications treatments in the East Umm Gudair field located north of SUG
were often marginal. As a result, horizontal sidetracking was was reported by Kuwait Oil Company.2 As a result, in 1998,
introduced in the SUG field. A total of 15 horizontal the first chemical treatment to control water encroachment was
sidetracks were performed from 1999 to 2004, resulting in performed in the SUG field. By the end of 2002 a total of 12
both increases in oil production and reduction in water cut. wells had been treated chemically to control water production.
This paper presents the results of sidetracking 15 wells in the Table 2 details a summary of the chemical water-shutoff
SUG field to mitigate water encroachment and increase oil treatments. Treatment life averaged approximately 14 months.
recovery. A few wells were retreated with lower-than-expected results as
optimal gel placement was difficult to control and treatment
Introduction radius was insufficient to impede the encroaching water.
The SUG field, discovered in 1966, produces from the Lower
Cretaceous-aged Ratawi Oolite formation and consists of a Since results to mitigate increasing water production and
large, anticlinal Oolitic reservoir with a combination dropping oil rates by mechanical and chemical methods were
edgewater and bottomwater drive. The reservoir is a southern mixed, other methods were investigated. Study of WOC
extension of the northern Umm Gudair field located in the development and production characteristics suggested water
northwestern corner of the Partitioned Neutral Zone (PNZ) encroachment resulted from a combination of edgewater drive
between Saudi Arabia and Kuwait. The structure map of the and bottomwater coning. The application of horizontal wells
field with well locations is presented in Fig. 1. to alleviate coning problems and contact reservoir areas of
bypassed oil is well documented.3-8 As a result, sidetracking
The SUG field was subjected to three main development high-water-cut vertical producers was implemented. Prior to
phases. Phase 1 consists of 17 wells drilled between 1966 and the first horizontal sidetrack in 1999, average field water cut
1968. An additional 12 wells were part of Phase 2 and were was 33%, with individual well water cuts ranging from 8% to
drilled during the period 1993 to 1995. Phase 3 covers the 95%.
current time period and includes 34 wells drilled from 1998 to
2004. In each phase, the WOC rose irregularly across the This paper presents the results of sidetracking 15 wells in
field. Production data show water production has increased the SUG field to mitigate water encroachment and increase oil
over time in a number of wells with resulting drops in oil recovery. Production diagnostic plots, including WOR and
2 SPE 93379

WOR′ derivative plots, were used to identify production field.

mechanisms.9-10 The success of the sidetrack program relied
on an understanding of the current field WOC profile and a Open-hole logs of recently drilled wells and thermal
review of production data. After sidetracking, oil production decay time (TDT) logs on older wells facilitated developing
from these wells increased by approximately 4 times their pre- the current WOC model. Numerous wells had multiple TDT
sidetrack rates. Water cut dramatically decreased from a well logs run previously. Historically, TDT logs were run to
average of 72% to 6%. determine saturation profiles and aid in selecting and planning
plugbacks and workovers.1 Calculated water saturations were
Reservoir and Fluid Properties compared over time for a given well to model WOC
The main productive interval in the SUG field is the early- movement. Fig. 5 illustrates the changing WOC for SUG-A
Cretaceous Middle Minagish limestone series of over time. SUG-A had three saturation profiles established
predominately carbonateous rocks. The Minagish is between 1966 and 1985. As shown in the figure, rising WOC
informally called the Ratawi Oolite in the SUG field. is observed over time for the well. The rising WOC is
Minagish carbonate deposition was strongly influenced by interpreted as development of a water cone.
changes in relative sea level. The shallow water grainstone,
packstones, and rudist buildups which form the best reservoir The current WOC model map was constructed using a
intervals at SUG were deposited in cycles. Recognition of combination of available open- and cased-hole logs. In
these cycles enables regional correlation of time-equivalent addition, data from perforated, squeezed, and isolated intervals
strata and is essential for prediction of potential reservoir were incorporated in the interpretation. This map, displayed
facies away from existing well control. The presence of in Fig. 6, shows the presence of a highly disturbed WOC
similar reservoir intervals of equivalent age in surrounding model for the Ratawi Oolite reservoir. The disturbance in the
fields shows that the Ratawi Oolite platform carbonate system WOC model is attributed to water-coning effects in
was of regional extent, covering most of southern Kuwait. combination with edgewater fingering. Edgewater fingering
appears to dominate in the eastern side of the reservoir, while
The average depth of the Ratawi Oolite reservoir in the coning effects are predominately seen in the central and
SUG field is – 8,200 ft SS, with an original WOC of -8,430 ft western parts of the reservoir. The east-west structure cross-
SS. The reservoir consists of a 450 to 550-ft thick interval of section, Fig. 4, shows the current disturbed WOC model.
porous oolitic limestone and an oil column in the reservoir Local coning is observed in Wells SUG-C, SUG-B, and SUG-
ranging from 200 to 300 ft thick. The average porosity of the A. The shallow WOC observed in SUG-D, SUG-E, and SUG-
oolite pay is 23%. Permeability ranges between 50 and 350 F wells is believed to be the result of the active edgewater and
md, with an average of 245 md. The oolite pay is subdivided lateral invasion rather than local coning. In contrast, the area
in multiple layers to account for varying permeability flow around SUG-G well has experienced very little if any water
units and a number of low kv/kh vertical flow baffles. The invasion
term baffle describes thin low permeability layers with varying
capacity to affect vertical fluid movement.11 Some levels are Production Diagnostic Plots
identified as possible barriers, but their lateral extension and Evaluation of production diagnostic plots including water cut
sealing capacity are not fully mapped. The primary recovery is and Water Oil Ratio (WOR) plots were conducted. WOR and
enhanced by strong edgewater and bottomwater drive. WOR time-derivative plots (WOR′) for identification of water
coning, channeling and near well-bore problems is
The fluid quality in the SUG Ratawi Oolite reservoir documented.9-10 Candidates for horizontal sidetrack exhibited
varies laterally with depth; however, average oil gravity is an average water cut of approximately 70% and a flattening of
24.5oAPI with a formation volume factor of 1.213 res water cut versus time, suggesting that a reservoir layer has
bbl/STB. The solution GOR is 250 scf/STB and oil viscosity watered out. Fig. 7 shows a typical response of water cut
measures 3.64 cp at a bubblepoint pressure of 883 psia and versus time seen in the screening process. Log-log plots of
reservoir temperature of 175oF. Formation-water salinity is WOR and WOR′ versus time were also constructed for each
260,000 ppm. The reservoir pressure has declined from an candidate. WOR and WOR′ plots identify the dominant
initial 4,030 psi to approximately 2,200 psi. produced-water mechanism. 9-10 These plots were used to
differentiate between coning and channeling. Coning,
Water/Oil Contact (WOC) Model channeling, and coning/channeling systems were observed.
Producing water cuts in SUG have increased over time. To Figs. 8 through 10 display examples of each.
gain understanding of water movement in the field, we used
available open- and cased-hole saturation profiles to develop a Horizontal Sidetrack Program
WOC model and log-analysis data from wells drilled between As increasing water production is curtailed in the early life of
1966 and 1968 to map the original OWC. Using a water- a well by plugbacks, opportunities for additional water shutoff
saturation cut off of 80% to model the WOC, we saw no in response to a rising WOC are limited. Isolating the lowest
appreciable difference in depth for the WOC across the field zone might reduce water production, but productivity is also
other than a gentle dipping towards the flank of the reservoir. affected. The WOC model and production diagnostic plots for
Therefore, the original WOC was interpreted as a uniform line the SUG field indicated coning and or viscous fingering to be
corresponding to a depth of -8430 ft SS. Fig. 3 and Fig. 4 a significant factor in water production in the majority of
display the uniform, undisturbed original WOC of the SUG vertical wells. A horizontal sidetrack main advantage is to
SPE 93379 3

reduce near-wellbore drawdown to minimize vertical flow of Job Execution/Trajectory Design. The objective of a
water into the well bore. The reduction in drawdown reduces horizontal sidetrack is to overcome water encroachment
coning, cusping, and viscous-fingering effects. In sidetracking resulting from water coning and lateral water movement. Both
a vertical well some distance from the current wellbore, phenomena negatively affect the producing life of the well and
increased recovery of oil is possible in poorly or unswept ultimate recovery. In planning sidetrack trajectories for
areas. candidate wells, the following factors were considered:
• Target zones of unswept oil to maximize recovery.
Sector Model. We used a commercial black oil simulator to
construct a simple “sector” simulation model to evaluate the • Reduce coning effects by proper planning of
benefits of a horizontal sidetrack. The model included, horizontal direction.
sidetrack candidate SUG-A and the four direct offset wells • Minimize interference effects from direct offsets.
SUG-B, SUG-H, SUG-I, and SUG-J as shown in Fig. 1. We • Maintain adequate spacing from existing completions
imported the structure map, shown in Fig. 1, directly into the affected by water encroachment.
reservoir simulator and described the structure using a 37 rows
by 26 columns grid system. We represented the producing The kickoff point and build section were limited to the
formation by 20 simulation layers populated with available 400 to 500 ft thick Ratawi Limestone interval directly above
petrophysical data. the targeted Ratawi Oolite reservoir. The upper problematic
Ratawi Shale section was avoided to minimize hole problems.
After initializing the model, we made refinements Build rate averaged from 10 to 20 0/100 ft. The heel of the
through the history match process adjusting properties of the horizontal section was typically landed approximately 500 ft
model until predicted water cut and reservoir-pressure away from the original vertical wellbore. The lateral target is
behavior agreed with historical well values. We achieved a in the M 3b and M 4 Ratawi Oolite reservoir,
satisfactory history match by developing vertical
transmissibility multiples on specific layers, based on down Procedure. The first four horizontal sidetracks were
hole pressure data, and applying two relative-permeability data completed openhole from the kickoff point to total depth.
sets as well as capillary pressure data. Three of the four wells experienced sudden production losses
within six months of initial completion. Re-entry into these
A prediction case was run with the following constraints: wells revealed that a problematic laminated shale section at
• Maximum withdrawal rate was limited to 6,000 the base of the Ratawi Limestone had collapsed. Two of the
BFPD. failed wells were successfully reentered and a 5 in. liner was
• Maximum water cut per well was 95%. run to cover the problem area. Repair of the third well was
unsuccessful and the well was abandoned. Running 5 in.
• Minimum production per well was 50 BOPD.
liners across the Ratawi Limestone build section was adopted
as a field standard to eliminate sloughing and caving problems
Simulation results compared total production from the
and to maintain wellbore integrity. Fig. 11 displays the
vertical well and horizontal well case. Results indicated
current horizontal sidetrack completion used in the SUG field.
incremental oil production of 1,069 BOPD and an increase of
As a result, the basic sidetrack procedure followed in the field
3.5 million bbl of recovered oil with the horizontal sidetrack.
evolved to the following:
Sensitivity cases to optimize the horizontal well design were
attempted; however, the relatively coarse gridding of the 1. Move rig on location. Kill well. Nipple down
model was insufficient to model the near-well-bore area. wellhead. Nipple up BOP.
2. Pull production equipment. Run bit and casing
Candidate Selection. The WOC model and production scraper to clean out wellbore.
diagnostic plots formed the basis for screening candidates. 3. Run Gyro survey to tie-in Directional Drilling plan.
We identified possible sidetrack targets first by screening all 4. Run in hole with a cement retainer. Set cement
wells in the field for high water cuts. Next, we compared retainer above existing Ratawi Oolite perforations.
production diagnostic plots with the current WOC model to Cement squeeze all open perforations.
see if the high water cuts suggested water-coning effects or 5. Set Whipstock assembly. Mill a 60 to 80 ft casing
lateral water movement. We also considered the performance section.
of offset producers and the current WOC model, searching for 6. Sidetrack hole through milled window with
indications that the well should produce with lower water cuts measurement while drilling tool (MWD) and gamma-
that the observed value. ray (GR) in drill string following directional plan.
7. Drill 6-1/8 in. hole to liner setting depth.
Low oil rate producers and adequate well spacing are also 8. Run 5 in. Hydril liner with 7 in. liner hanger. Hang
important. Wells with low rates as a result of low productivity and cement liner in place.
indexes or limited drawdown can be substantially improved by 9. Run in hole with a 4-1/8 in. bit on 3-1/2 in. and 2 7/8
horizontal sidetrack. Adequate well spacing is necessary to in. drill pipe equipped with a 3-1/8 in. mud motor,
minimize interference effects between wells, resulting in MWD and GR.
improved recovery. In addition, the location of future infill 10. Drill according to the horizontal well path plan.
wells was taken into consideration in evaluating well spacing.
4 SPE 93379

11. Trip out of hole with drilling assembly. Acidize was based on maintaining producing bottom hole pressures
horizontal interval with coiled tubing to remove near from 1300 to 1400 psi. This resulted in producing
wellbore damage. approximately 75% more total fluid at 35% greater producing
12. Trip out of hole. Run pump and place well on bottomhole pressure.
production.
Table 3 shows test results for each horizontal sidetrack
This procedure was followed with little deviation for the performed. Prior to horizontal sidetrack production averaged
majority of the horizontal sidetracks. The average horizontal 732 BOPD per well. Initial tests performed after horizontal
length drilled was approximately 1600 ft. sidetrack averaged 3,980 BOPD. Fig. 14 shows normalized
production for the horizontal sidetrack program for a period of
New Sidetrack Strategy. Beginning in 2004, a new 12 months before and 12 months after implementing the
strategy was applied in selecting and drilling horizontal horizontal sidetrack program on the first 12 wells. Production
sidetracks in the SUG field. The new strategy targeted the low was normalized on time, as the sidetracks were performed
permeability, heterogeneous M 3b layer on top of the Ratawi over a three-year period. As shown in the figure, production
Oolite reservoir. The reservoir quality of the top layer is often increased by 290%. Water production significantly decreased
poor with finer grain size and average permeabilities ranging from 73% to 9% and appeared to had stabilized at about 28%.
between 50 to 150 md. This interval is characterized by a This represents an initial decrease of 18,700 BWPD and a
fining upward signature on the Gamma Ray and Bulk Density stabilized decrease of 10,000 BWPD. Total incremental oil
open-hole log curves. Reservoir surveillance data indicates produced through December 2002 from the first 12 sidetrack
this heterogeneous layer is poorly swept in comparison to the wells is 15.6 million barrels of an estimated 31.3 million
lower more homogeneous high permeability layers M 4 – M barrels ultimate incremental.
12. Fig. 12 shows the example of the lateral target M 3b.
Conclusions
The lateral length of the new side track well is designed
1. Horizontal sidetrack technology was successfully applied
to target approximately 1200 ft of the M 3b. The M 3b in the SUG field on 16 high water cut wells. Total initial
reservoir net pay ranges from 20 ft to 25 ft with bottomwater oil production from the fifteen wells increased by 444 %
below. As a result, lateral placement is restricted to a 6 ft
and water cut decreased from 73% to 9%.
window in the upper M 3b reservoir. In order to stay within
the targeted window, a geosteering model is built for the
2. Production diagnostic plots were effectively used with a
planned trajectory with predicted resistivity and Gamma Ray
high degree of confidence to differentiate water
profiles, polarization horn, anisotropy, and bed boundary
production mechanisms such as coning and channeling.
effects.
3. Previous mechanical and chemical water shut-off
A critical success factor for horizontal drilling in the low
techniques have limited opportunities as water/oil contact
permeability target is a proper drilling fluid system that
(WOC) continues to rise.
minimizes damage to the lateral. A water base mud consisting
of a xanthan clarified dispersable (XCD) polymer, starch and
4. A highly irregular WOC profile is interpreted for the SUG
calcium carbonate is used. Calcium carbonate, a key
field. A combination of edge water and vertical water
component, is used as a bridging agent to plug the pore throat
movement as well as the heterogeneity of the Ratawi
quickly to minimize spurt loss, build an effective filter cake,
Oolite reservoir contribute to this irregularity.
and prevent mud invasion into the formation.
5. The strategy of targeting the thin low permeable M 3b oil
During landing and drilling of the lateral section, the
reservoir by horizontal sidetracking is proven to be
geosteering and communication activities were monitored by
successful in SUG field.
the Asset Management Team (AMT) and well-site personnel
in real-time. Allowing real time decisions to be made to the
adjustment of the lateral trajectory due to geological changes
References
ensured optimal lateral placement. Fig. 13 is an example of 1. Johnson, R.S. et al: “Proven Technology Yields High Impact
geosteering modeling and real-time data acquisition from one Results – A Case History of Water Shut-Off in the PNZ’s South
of the sidetracked wells. Umm Gudair Field,” paper SPE 36210 presented at the 1996
Abu Dhabi International Petroleum Exhibition and Conference,
Results Abu Dhabi, 13-16 November.
Electric submersible pumps are used to produce all SUG 2. Chawfa, M.L., Al-Otaibi, A., and Waheed, A.: “Case Histories
wells. Vertical producers are typically designed to operate at Of Successful Water Shutoff Techniques Utilised in Enhancing
producing bottomhole pressures between 850 and 900 psi. Oil Output From Minagish Oolite Reservoir Of East Umm
Gudair, (West Kuwait),” paper SPE 49464 presented at the 1998
The ability to produce more fluid at lower drawdowns,
Abu Dhabi International Petroleum Exhibition and Conference,
impeding water coning and encroachment, is a main advantage Abu Dhabi, 11-14 October.
of horizontal sidetrack. Simple productivity estimates were 3. Hongyin, Z. and Peimao, Z.: “Improved Oil Recovery of Edge
made for each horizontal sidetrack drilled.12 Down-hole and Bottom Water Reservoir by Drilling Horizontal Sidetracks,”
electric submersible pump design for each horizontal sidetrack paper SPE 64511 presented at the 2000 SPE Asia Pacific Oil and
SPE 93379 5

Gas Conference and Exhibition, Brisbane, Australia, 16-18 Table 1—Summary of Results from Mechanical
October. Water Shut-off Workovers
4. Chen, Y. et al.: “The Practice of Recovering By-passed Oil by Metric BOPD BWPD Water Cut,
Horizontal Wells in Guan 2 Reservoir, Linpan Oil Field,” paper %
SPE 54281 presented at the 1999 SPE Asia Pacific Oil and Gas Average production before 2,100 2,366 79
Conference and Exhibition, Jakarta, Indonesia, 20-22 April. work-over
5. Taylor, R.W. and Russell, R.: “Case Histories: Drilling and Average initial production 3,700 635 18
Completing Multilateral and Horizontal Wells in the Middle after work-over
East,” paper SPE 39243 presented at the 1997 SPE/IADC Average production 6 months 3,070 1,038 28
Middle East Drilling Technology Conference, Bahrain, 23-25 after work-over
November. Average treatment life, 26
6. Peng, C.P. and Yeh, N.: “Reservoir Engineering Aspects of months
Horizontal Wells – Application to Oil Reservoirs with Gas or Number of wells treated 24
Water Coning Problems,” paper SPE 29958 presented at the
1995 International Meeting on Petroleum Engineering, Bejing,
PR China, 14-17 November. Table 2—Summary of Results From Chemical Water
7. Kabir, C.S., Ma, E.D.C., Dashti, Q., and Al-Shammari, O.: Shut-Off Treatments
“Understanding Coning Performance in a High-Anisotropy Metric BOPD BWPD Water Cut,
Reservoir: The Burgan Reservoir Case Study,” paper SPE 62993 %
presented at the 2000 SPE Annual Technical Conference and Average production before 1,563 2,502 60
Exhibition, Dallas, 1-4 October. work-over
8. Wu, G., Reynolds, K., and Markitell, B.: “A Field Study of Average initial production after 3,870 527 11
Horizontal Well Design in Reducing Water Coning,” paper SPE work-over
30016 presented at the 1995 International Meeting on Petroleum Average production 6 months 2,833 1,752 35
Engineering, Bejing, PR China, 14-17 November. after work-over
9. Chan, K.S.: “Water Control Diagnostic Plots,” paper SPE 30775 Average treatment life, months 14
presented at the 1995 SPE Annual Technical Conference and Number of wells treated 12
Exhibition, Dallas, 22-25 October.
10. Yortsos, Y.C. et al.: “Analysis and Interpretation of Water/Oil
Ratio in Waterfloods,” SPEJ (December 1999) 413-424. Table 3—Summary of Horizontal Sidetrack Results
11. Tillman, R.W. and Pittman, E.D.: “Barriers to Flow in Tidal Performed Between 1999 and 2004.
Sandstone Reservoirs, Sun Ranch Field, Wyoming,” paper SPE Before Sidetrack After Sidetrack
27966 presented at the 1994 University of Tulsa Centennial
Water Water
Petroleum Engineering Symposium, Tulsa, 29-31 August. SUG Oil Rate Cut Oil Rate Cut Oil Gain
12. Joshi, S. and Schuh, F.: “Horizontal Well Technology,” Well BOPD % BOPD % BOPD
University of Tulsa Continuing Education (March 1989) 28-29.
K 1,121 73.7 6,590 0.8 5,469
F 1,177 72.7 6,259 1.3 5,082
L 1,210 72.0 6,283 1.3 5,073
M 562 77.0 4,915 0.8 4,353
J 262 82.4 4,047 4.0 3,785
N 428 82.0 3,916 32.5 3,488
P 975 70.0 4,277 1.0 3,302
H 1,776 60.0 5,055 4.0 3,279
A 626 60.0 2,964 4.0 2,338
Q 608 48.9 2,653 13.0 2,045
R 1,261 64.3 2,022 47.0 761
S 147 93 910 40 763
T 756 73 3,618 9 2,862
U 0 0 5,278 2 5,278
V 0 0 930 4 930
Average 732 73 3,980 9 3,248
6 SPE 93379

Fig. 1—SUG structure map and highlighted sector model area.

South Umm Gudair

Production Profile
1,000,000 100
Production, BOPD 90
Water Cut, Percent
80
Oil Production, BOPD

Phase
Phase
Water Cut, Percent

III 70
Phase II
60
I
100,000 50

40

30

20

10
10,000 0
Jan-66

Jan-68

Jan-70

Jan-72

Jan-74

Jan-76

Jan-78

Jan-80

Jan-82

Jan-84

Jan-86

Jan-88

Jan-90

Jan-92

Jan-94

Jan-96

Jan-98

Jan-00

Jan-02

Time, Date

Fig. 2—SUG field production profile showing major phases of

field development and historic increase in water cut.

Fig. 3—Contour map representing the original water/oil contact in

the SUG field.
SPE 93379 7

Fig. 4—East-West structure cross section showing the original

uniform water/oil contact (WOC1) and the current highly irregular
water/oil contact (WOC2).

Fig. 6—Contour map showing the current highly disturbed

water/oil contact in the SUG field (1999).

SUG-K Pre-Sidetrack Production History

10,000 200
180

160
Production Rate, BPD

140
1,000

Water Cut, %
120

BOPD BWPD Water Cut 100

80
100
60

40
20
10 0
Jun-95 Jun-96 Jun-97 Jun-98 Jun-99 Jun-00 Jun-01
Date, months

Fig. 7—Flattening of water-cut versus time response observed in

horizontal sidetrack screening process suggesting the presence
of a watered-out layer.

Fig. 5—Comparison of TDT logs run at various times in well SUG-

A depicts rising WOC attributed to coning.
8 SPE 93379

SUG-P
WOR Diagnostics
10

WOR WOR'
1

0.1

0.01

0.001

0.0001
10 100 1,000 10,000
Cumulative Production Time, Days

Fig. 8—The gentle upward trend of WOR and flat to downward

trend of WOR′ observed in the WOR and WOR′ plot of SUG-P
9
production history is indicative of coning.

SUG-H
WOR Diagnostics
10
WOR WOR'
1

0.1

0.01
Fig. 11—Current horizontal completion configuration showing 5”
0.001 liner coverage of reactive shale above target Ratawi Oolite
reservoir.
0.0001
10 100 1,000 10,000
Cumulative Production Time, Days

Fig. 9—The sharp upward trend of WOR and WOR′ observed in

the WOR and WOR′ plot of SUG-H production history is indicative
9
of channeling.

SUG-F
WOR Diagnostics
10
WOR WOR'
1 Casing set
@ above
M3a
0.1

0.01
Un-swept oil

0.001

0.0001
10 100 1,000 10,000
Cumulative Production Time, Days

Fig. 10—The slow upward trend followed by a sharp increase of

WOR and the initial downward trend ensued by an upward rise in
WOR′ observed in the WOR and WOR′ plot of SUG-F production Fig. 12—Example of a trajectory design for a new horizontal
history suggest a combination of early coning followed by late sidetrack well to target remaining oil in the low permeability M 3b
9
time channeling. layer.
Fig. 13—Example of a geosteering model and actual LWD data
collected in realtime.

40,000

Oil Rate
35,000
Water Rate
30,000
Production Rate, BPD

25,000

20,000
After Sidetrack
15,000

10,000

Before Sidetrack
5,000

0
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26

Normalized Time, months

100

Water Cut
80
Water Cut, Percentage

60

After Sidetrack
40

20
Before Sidetrack

0
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26

Normalized Time, Months

Fig. 14—Horizontal sidetracking 12 South Umm Gudair wells had

a big effect on field production, increasing oil production by 290%
and decreasing water production by 88%. Water cut in the 12
wells decreased from 70% to 9% and stabilized at 28%.