evaluation libre

ABSTRACT

Drilling horizontal wells is a common practice for Saudi

Aramco in most of its oil and gas reservoirs in Saudi Arabian

clastic and carbonate fields. The field at hand, with its two

reservoirs, is no exception in regards to these field develop -

ment plans. While previously all wells in this field were cased

and perforated, during the planning stage for increasing

production, the question was raised whether an open hole

horizontal well completion is feasible over the life of the field

(i.e., when taking near-wellbore drawdown and far field

production-induced reservoir depletion into consideration).

The direct benefit would be that an open hole completion

greatly reduces the development costs for the 300+ production

wells planned for the field.

A rock mechanics study was undertaken to provide a

comprehensive understanding of the wellbore stability of open

hole horizontal wells throughout their life span, from drilling

through production during field development. Two objectives

identified for the study were: 1) assessment of wellbore

stability and critical drawdown rates during production to

avoid well collapse, and 2) the optimal well deviation,

azimuth and required mud weight during drilling to minimize

wellbore instability problems. To increase the accuracy of the

results and greatly reduce uncertainty, cores from both

reservoirs were retrieved to provide representative samples of

the formations of interest. A testing program was undertaken

to determine the static and dynamic mechanical properties,

compressive rock strength, rock failure characteristics and

thick wall cylinder strength. The effect of water on rock

strength was tested as well, to evaluate if water encroachment

poses additional risk to the mechanical integrity of the

formation. In addition, the required geomechanical model – in

particular in-situ stress field, magnitude and direction – was

determined from several data sources: stress-induced wellbore

failure analyses (from oriented caliper and wellbore image log

analyses), microfrac testing, direct pore pressure measure -

ments, wireline log data, and analysis of the general regional

stress information for the area surrounding the field.

The study showed that an open hole completion is feasible

for most well azimuths in both reservoirs. Although, it was

determined that the tar-bearing intervals of both reservoirs are

not competent enough to be completed open hole due to the

risk of wellbore collapse. The recommendation was therefore

to avoid the tar-bearing intervals and to consider casing those

zones as applicable. The rock strength showed minimal effect

as a result of exposure to water; therefore, water flooding will

not be a concern from a wellbore integrity point of view. A

field-specific compressive rock strength-wireline sonic log

correlation was developed and calibrated with results from the

lab tests. The flank wells tolerate more drawdown pressure

than crest wells, due to higher rock strength in the flank.

Additionally, it is recommended that the wells be drilled in the

direction of minimum principal horizontal stress (σhmin), to

maximize borehole stability and minimize required mud

weights during drilling and completion. The results from this

extensive study were incorporated into Saudi Aramco’s

reservoir management decision tree.

INTRODUCTION

Wellbore instability problems are being experienced during the

drilling of horizontal wells in highly stressed formations, such

as shale, unconsolidated sandstone and weak carbonates. The

instability problems can range from a simple washout to total

collapse of the hole, and these problems are related to the

mechanical properties (strength and deformation under stress),

the drilling fluids properties, the in-situ stress field, and time-

dependent deformation. Open hole completion may be

possible in weak carbonate if the in-situ stress field is not

critical in terms of magnitude and mode (normal, strike-slip or

inverse). For example, a rock mechanics study on a shallow

carbonate formation in Saudi Arabia has revealed unconfined

compressive strengths less than 2,000 pounds per square inch

(psi); however, the results of wellbore caliper monitoring as a

function of production time showed no changes in wellbore

size, and therefore all horizontal wells were completed open

hole1.

Over the past years, drilling extended-reach wells with long

open hole intervals has increased markedly in the industry,

and Saudi Aramco has taken a lead role in these activities. For

the difficult drilling campaigns associated with drilling these

long-reach wells, oil-based mud (OBM) systems have been the

industry choice for difficult drilling. Their application has

been typically justified on the basis of borehole stability, fluid

loss, filter cake quality, lubricity and temperature stability.

44 FALL 2009 SAUDI ARAMCO JOURNAL OF TECHNOLOGY

Evaluation of Wellbore Stability duringDrilling and Production of Open HoleHorizontal Wells in a Carbonate Field

Authors: Dr. Hazim H. Abass, Mickey Warlick, Cesar H. Pardo, Mirajuddin R. Khan, Dr. Ashraf M. Al-Tahini, Dr. Dhafer A. Al-Shehri,

Dr. Hameed H. Al-Badairy, Yousef M. Al-Shobaili, Dr. Thomas Finkbeiner and Satya Perumalla

Water-based muds (WBM) are attractive replacements from a

direct cost point of view. Past efforts to develop improved

WBM for shale drilling have been hampered by a limited

understanding of the drilling fluid/shale interaction

phenomenon. This limited understanding has resulted in

drilling fluids designed with non-optimum properties to

prevent the onset of borehole instability.

The structure of the oil field analyzed in this study is a

conventional northwest trending asymmetric anticline. To

develop the field to its target production, Saudi Aramco’s

reservoir management team planned to drill a number of

horizontal wells to ensure maximum reservoir contact (MRC).

Because the mechanical integrity of the wellbore for an open

hole completion strategy is of critical importance, Saudi

Aramco decided to have a geomechanics evaluation conducted

to understand if and how well integrity can be maximized

through utilization of the right mud weights and well

directions, so that stable conditions during drilling and

production would be guaranteed. The objective was to evaluate

the feasibility of open hole completion; therefore, the wellbore

stability throughout the life span of the well was the focus of

the study. Additionally, it is important to optimize the mud

weights during drilling to minimize wellbore instabilities, and to

recommend optimal well orientations and maximum values for

drawdown and depletion to allow for a stable well throughout

the production phase. Therefore, the objective of the study was

to combine the knowledge of reservoir and material properties

with a detailed analysis of the present-day in-situ stress field to

assess under what conditions, during drilling and production,

mechanical rock failure may occur at the wellbore wall and

become so severe that it would no longer be manageable.

RESERVOIR CHARACTERIZATION FOR WELLBORE

INTEGRITY ANALYSIS

Creating a circular hole and introducing drilling and

completion fluids to an otherwise stable formation is the

reason for a series of phenomena that can result in wellbore

instability, casing collapse, perforation failure and sand/solids

production. The circular hole causes a stress concentration

that extends to a few wellbore diameters away from the hole.

This stress concentration, which differs from the far-field

stresses, could exceed the formation strength, resulting in

failure. The circular hole also creates a free surface that

removes the natural confinement, which can, depending on

the mechanical properties of the formation, reduce formation

strength and trigger inelastic and time-dependent failure.

Therefore, a circular hole causes several important effects

around a wellbore: 1) creation of a stress concentration field,

2) removal of the confinement condition, and 3) inelastic and

time-dependent displacement caused by creating a free surface.

Additionally, when a wellbore is actively loaded (pressure in

the wellbore is less than the reservoir pressure) or passively

loaded (pressure in the wellbore is higher than the reservoir

pressure), another stress effect could cause wellbore failure.

Wellbore failure that triggers solids production may be

compressive, tensile, cohesive or a combination of all three.

The compressive failure occurs during drilling where the rock

cannot withstand the concentration of hoop stress around the

hole. In addition, when cementation materials deteriorate due

to mud filtrate exposure, the problem can be exacerbated. The

calculation of mud weight to prevent compressive failure will

be presented in this article. Typically, the failed zone is

oriented in a specific direction relative to the in-situ stress

field; therefore, the well orientation can be selected to

maximize wellbore stability during drilling and production.

A geomechanics study was initiated to predict wellbore

stability during drilling, completion and production. The basis

for making successful and accurate predictions lies in the

understanding of a sound geomechanical model. The

constituents of the geomechanical model are three principal

stresses (vertical stress, maximum principal horizontal stress,

and minimum principal horizontal stress), pore pressure and

mechanical rock properties. When the horizontal stresses are

not equal (a frequent condition in the Earth’s crust), a stress

anisotropy is created, and wellbore instability can be

pronounced as wells are direction and deviation sensitive.

Pore pressure is another important parameter in the

geomechanical model as most failure criteria depend on

effective stress. When all these parameters are known, a

geomechanical model can be created and subsequently utilized

for evaluation of wellbore stability. In this study, data from 11

wells were used to determine the in-situ stress field (magnitude

and direction), and the reservoir pressure. The analyzed data

include in-situ pore pressure tests, wireline logs (including

electrical FMI/FMS image logs) and laboratory results from

rock mechanical tests (triaxial compression as well as thick

wall cylinder tests). The approach for predicting wellbore

stability is then based on a comprehensive understanding of

the present-day geomechanical model of the field, verified and

calibrated against drilling experiences (i.e., indication of

mechanical well instability in wells previously drilled in the

field and target formations). The latter information is acquired

and compiled from drilling and completion reports. Problems

encountered during drilling are classified into different

categories, such as tight hole, pack off, washing, reaming and

more. Based on drilling experience for a specific mud weight

in a given well trajectory, the generated geomechanical model

is verified and calibrated to mechanical failure in the wellbore

(stress induced borehole breakouts, hole washouts, etc.) in

such a way that it robustly and accurately predicts

compressive and tensile failure around given wellbores.

PORE PRESSURE

Pore pressure within the Earth’s crust plays a vital role in

managing wellbore stability during drilling and production,

governing stress magnitudes (e.g., the fracture gradient,

among others). The overall effect of pore pressure changes is

influenced by the rock behavior, including pore and bulk

SAUDI ARAMCO JOURNAL OF TECHNOLOGY FALL 2009 45


respect to depth taken from many wells revealed an over -

burden gradient of 1.04 psi/ft at the level of the reservoirs.

MINIMUM HORIZONTAL PRINCIPAL STRESS

Only very limited information on the minimum principal

stress (σhmin) was available, since no leakoff tests (LOT) or

extended leakoff tests (XLOT) were conducted in the

reservoirs. One injectivity test was performed in Reservoir B

at 8,265 ft, and we utilized the maximum pressure reached

from this test as a proxy for the least (or minimum) horizontal

principal stress, with an equivalent gradient of 0.75 psi/ft.

MAXIMUM HORIZONTAL PRINCIPAL STRESS

Similarly to the in-situ stress orientation, interpreted borehole

breakouts from the FMI log were utilized to constrain the

magnitude of the maximum principal horizontal stress (i.e.,

σHmax). The analyzed breakout width and orientation, as well

as σhmin from the injectivity test and the UCS, were utilized to

estimate the magnitude of σHmax. The analysis resulted in an

average value of 0.97 psi/ft as a lower bound and 1.07 psi/ft

as an upper bound in the field. Therefore, the present-day in-

situ stress field can be characterized as a transitional normal

to strike-slip faulting system, such that σHmax ≥ σv > σhmin.

ROCK MECHANICAL PROPERTIES

For a successful drilling and completion strategy in poorly

consolidated formations, it is vital to determine the

mechanical properties of the formation. The following

properties are needed to provide recommendations on

wellbore azimuth, mud weight window during drilling,

completion design, and wellbore stability prediction during

production: 1) Static and Dynamic Young’s modulus (E)

and Poisson’s ratio (v), 2) UCS, 3) Cohesive strength (c), 4)

Internal friction angle (ø), and 5) Hollow cylinder strength

(HCS). An experimental testing program was initiated to

derive some of the parameters listed above. Samples of

compressibility often discussed under stress path response of

reservoir. As pore pressure changes with time during the life

cycle of a field due to production and injection processes,

stress magnitudes (including the fracture gradient) change

accordingly. These production/injection induced stress changes

may influence the stability of a wellbore as well as cause

compaction and subsidence on the field scale in some cases.

The pore pressure in the formations of interest, as derived

from direct measurements in offset wells, at present is

approximately hydrostatic with no significant overpressure

detected. In Reservoir A, current pore pressure is 3,980 psi,

and will be depleted appreciably to 3,000 psi, in 2024 and to

2,000 psi in 2035. In Reservoir B, current pore pressure is

3,832 psi, and it will be depleted to 3,200 psi in 2024 and to

2,500 psi in 2035. The corresponding gradients from these

values were used as the current and future pore pressure

conditions in the two reservoirs for wellbore stability analyses

during drilling and production.

IN-SITU STRESS ORIENTATION

An available electrical image log (i.e., FMI) for this study from

one well was rigorously calibrated, verified and dynamically

normalized to provide optimal image quality. The purpose of

the wellbore image analysis was to identify and characterize

stress-induced wellbore failure, such as stress-induced

borehole breakouts and drilling-induced tensile fractures.

Wellbore breakouts are enlargements of the wellbore wall,

with 180° spacing caused by localized shear failure where the

circumferential hoop stress is most compressive and exceeds

the uniaxial compressive strength (UCS) of the rock. In

vertical wells, breakouts always form in the direction of the

least principal horizontal stress (σhmin)2, 3. In deviated wells,

however, the position of breakouts is a function of the

wellbore trajectory and the stresses acting on the well4.

Therefore, when wellbore failures can be detected, their

occurrence and characteristics (i.e., azimuthal width) can be

used to constrain in-situ stress magnitudes, effective rock

strength and stress orientations.

Drilling-induced tensile wall fractures occur where the

circumferential hoop stress may become tensile and exceed the

tensile strength of the rock. They also form symmetrically in

the borehole wall 90° from the orientation of the breakouts

(i.e., in vertical wells in the direction of the maximum principal

horizontal stress, σHmax)5. Statistical analysis of a wellbore

failure indicated a mean value for the orientation of the σHmax

as N25°E with a marginal error of 10º. This estimated azimuth

for σHmax strikes obliquely to major fault trends found in the

field, and it is consistent with the regional stress trend.

OVERBURDEN

The vertical in-situ stress (σv) was derived from bulk density

wireline log data that were acquired from the surface down to

the reservoir levels. Integration of the density data withFig. 1. Stress-strain curves from a single stage triaxial test.

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

-0.01 -0.005 0 0.005 0.01 0.015

Strain

Str

ess

(Psi

)


Fig. 2. Mohr circles and Coulomb failure line (left) from the samples tested in single stage mode (right) - the resulting rock mechanical parameters are shown in box on top left.

Table 1. A summary of rock-mechanical testing results

Bulk Confining Young's Poisson Peak Friction Shear

Sample Depth Density Porosity Pressure Modulus Ratio Strength UCS Angle Cohesion Angle

# (ft) (gm/cc) % PSI (PSI) (PSI) (PSI) (Degrees) (PSI) (Degrees)

S-02 8,153.3 2.64 2.0 747.9 6.705E+06 0.386 25,466 22,736.8 41.7 5,101.6 65.8

S-03 8,153.7 2.65 1.5 1,456.7 7.596E+06 0.333 31,424.5

S-04 8,153.8 2.67 0.8 2,944.2 7.133E+06 0.346 36,887.8

LA-07 8,212.4 2.08 15.4 717.9 6.287E+05 0.358 1,861 237.2 22.8 78.9 56.4

LA-08 8,213.2 2.12 15.0 1,459 8.776E+05 0.265 3,537.1

LA-09 8,213.4 2.10 14.2 2,917.9 9.003E+05 0.324 3,571.2

S-06 8,335.9 2.35 11.2 722.6 1.333E+06 0.098 4,041.4 2,462.2 21.8 832.8 55.9

S-07 8,336.2 2.31 11.3 1,463 1.308E+06 0.065 5,659.7

S-08 8,336.4 2.25 12.5 2,905.9 8.516E+05 0.235 5,085.8

S-10 8,369.7 2.48 6.5 735.4 4.152E+06 0.201 10,461 9,038.2 25.9 2,827 58

S-11 8,370.1 2.50 5.9 1,458.5 4.970E+06 0.258 13,448.4

S-12 8,370.3 2.44 7.7 2,912.9 4.753E+06 0.243 16,254.9

MO-36 8,734.2 1.97 24.3 2,906.3 2.079E+06 0.205 5,509.4 458.8 21.9 155 56

MO-26 8,734.7 2.02 15.9 733.1 1.312E+06 0.201 2,028.3

MO-27 8,734.9 2.10 15.3 1,455.9 1.798E+06 0.223 3,721.6

RM-3D 8,735.2 2.00 16.7 729.4 1.011E+06 0.174 2,125.8 830.3 11.3 340.3 50.7

MA-28 8,735.7 2.13 14.5 2,905.6 1.500E+05 0.132 5,111

MO-32 8,736.9 2.06 16.7 153.4 4.968E+05 0.500 975.

MA-23 8,739.8 2.21 8.4 154.4 7.994E+05 0.366 1,251.3 1,803.9 18.7 646.5 54.4

RM-4D 8,742.9 2.40 5.6 2,904.3 2.656E+06 0.472 6,690.7

RM-2D 8,743.4 2.37 1.4 1,455.2 2.041E+06 0.312 5,445.6

MO-46 8,765.2 2.37 0.1 726 3.127E+06 0.323 7,587.3 15,319.8 42.7 3,357.8 66.3

MO-47 8,765.4 2.35 0.1 1,465.1 2.470E+06 0.246 7,789.2

MO-48 8,765.8 2.42 0.1 2,909.4 3.276E+06 0.245 12,664.8

MO-49 8,807.1 2.93 0.3 724.7 6.807E+06 0.217 19,258.2 15,298 42.7 3,346.1 66.4

MO-50 8,807.2 2.93 0.5 1,454.5 7.105E+06 0.238 22,638

MO-51 8,807.4 2.91 0.8 2,905.4 9.855E+06 0.075 30,523.5


microscope (ESEM) and energy dispersive X-ray (EDX) tests,

to understand the nature of these samples. The results

revealed that high-sulfur tar was mainly found between the

oolites, and no tar was found in the micropores of CaCO3

within the oolites, Fig. 4. The tar seems to be like

cementation materials to the oolitic groups; thereby reducing

the mechanical strength of the formation. Therefore, the tar-

bearing zones are not competent enough to be completed

open hole due to the risk of wellbore collapse. The

recommendation is to avoid as much as possible the tar-

bearing intervals or consider casing those zones as applicable.

ROCK-STRENGTH MODEL

It is important to characterize an entire formation in terms

of its compressive rock strength to evaluate wellbore stability

during drilling, completion and production. Figure 5 shows

lab result correlations between the UCS and porosity, or the

UCS and the inverse of compressional velocity. Since core

plugs are generally obtained from a limited portion of the

reservoir only, it is imperative to establish empirical

correlations between rock properties (as determined in the

laboratory) and log data to obtain tools for formation

strength characterization along the entire reservoir in a given

wellbore. Sonic log data and the UCS lab results were

utilized to obtain a transform for rock strength, which

provides a continuous rock strength profile of the reservoir

section, Fig. 6. The following transforms were the basic

relations for the functions appearing in Fig. 6:

UCS = 366,842 e(-0.0624∆t) (Reservoir A)

UCS = 20.244 (∆t)2 – 3302 (∆t) +135,741 (Reservoir B)

The units for UCS are in psi and ∆t (compressional sonic

interval transit time) is in µsec/ft. Although the strength model

is derived based on one well, it can be applied to other areas

1½” diameter by 3” length were plugged horizontally from

a full core (4” diameter) and tested in a single and

multistage fashion. Confining pressures for these tests were

selected to simulate the stress and pressure conditions in

the vicinity of the wellbore (i.e., 5 MPa, 10 MPa and 15

MPa). The multistage procedure implies that an earlier

loading cycle is unloaded when the rock sample

approaches failure at a given confining pressure and the

same sample is reloaded under the subsequent higher

confining pressure.

Triaxial Compression Tests

Weak samples were tested in a single stage, conducted on

three plugs, Fig. 1. The triaxial testing results were modeled

by Mohr-Coulomb failure criterion. This criterion postulates

that failure occurs when shear stress at a given plane reaches a

critical value related to the formation frictional resistance, and

is given by:

(1)

Equation 1 shows three components: cohesion (c), effective

normal stress (σn) and friction (tan ø). Shear failure breaks the

rock along shear planes. Equation 1 may be described in

terms of the principal stresses as follows:

(2)

The factors UCS and φ are coefficients for the linearization

and should be determined experimentally. The failure envelope

is determined from many Mohr circles. The envelope of these

circles represents the basis of this failure criterion, Fig. 2. A

summary of the rock mechanical testing results of core

samples taken from both reservoirs are shown in Table 1.

THICK WALL CYLINDER (TWC) TESTING

Thick wall cylinder tests were performed on core samples of

1½” diameter with a 0.5” diameter hole drilled exactly in the

center. The axial and confining stresses are simul taneously

increased during the test (i.e., the sample is loaded

hydrostatically). The axial stress, confining pressure, axial

strain and radial strain are monitored during the test. Loading

continues until complete sample failure occurs or the

maximum loading stress (governed by the loading frame) is

reached. The thick-walled cylinder test provides a simulated

condition of the near wellbore formation being stressed as the

near wellbore reservoir pressure is decreased. The resulting

elastic/plastic deformations around the wellbore as a function

of the effective-stress increase can be modeled to determine

the critical reservoir pressure at which wellbore failure is

initiated. Figure 3 shows selective thick wall cylinder tests.

The lowest failure stress of about 4,000 psi was observed

in tar-bearing samples, as shown in the top right graph of

Fig. 3, which depicts a collapse of the inner hole. Therefore,

two tests were performed: environmental scanning electron Fig. 3. Four thick wall cylinder tests performed on selective samples.

0

5,000

10,000

15,000

20,000

0 0.001 0.002

Strain

Co

nfi

nin

g P

ress

ure

, p

si

0

1,000

2,000

3,000

4,000

5,000

0 0.001 0.002 0.003 0.004 0.005

Strain

Co

nfi

nin

g P

ressu

re, p

si

Axial Strain

Radial Strain

Axial Strain

Radial Strain

0

5,000

10,000

15,000

20,000

25,000

0 0.002 0.004 0.006

Strain

Co

nfi

nin

g P

ress

ure

, p

si

0

5,000

10,000

15,000

20,000

0 0.001 0.002 0.003

Strain

Co

nfi

nin

g P

ressu

re, p

si

Axial Strain

Radial Strain

within the reservoir. Therefore, the sonic log is a tool that can

be used as a proxy for rock strength at any location. The log-

based strength correlations can be statistically evaluated to

find average wells as minimum/maximum values and

distribution functions of rock strength. Based on the

developed correlations, it was found that Reservoir B appears

relatively weaker than Reservoir A. Furthermore, there is a

trend of increasing rock strength from the crest to the flanks.

Reservoir B exhibits narrow P10 (10th percentile) and P50

(50th percentile) ranges 2,000 psi to 3,000 psi and 2,500 psi to

4,950 psi, respectively, while the same range for Reservoir A is

2,500 psi to 4,500 psi and 3,750 psi to 7,700 psi. Figure 7

shows the UCS distribution functions across Reservoirs A and

B as derived using sonic log velocities and lab strength data.

Great variability depicting rather strong (UCS >10,000 psi) as

well as rather weak (UCS < 2,000 psi) intervals are apparent.

Also, Reservoir A appears generally stronger than Reservoir B.

WELLBORE STABILITY DURING DRILLING

(UNDEPLETED AS WELL AS DEPLETED CONDITIONS)

The geomechanical model previously developed and discussed

was utilized as a basis to predict minimum required mud

weights during drilling and completion of the reservoir


Fig. 4. Tar-bearing sample showing the dark phase, which is tar between the oolites.

Fig. 5. Lab-data correlations of UCS as a function of porosity (top), and 1/Vp

(bottom).

Rock Strength Correlation - UCS-Porosity

0

4,000

8,000

12,000

16,000

Porosity

UC

S, p

si

0

40

0% 4% 8% 12% 16%

50 60 70 80

3,000

6,000

9,000

12,000

15,000

Inverse Compression Velocity, micro-sec/ft

UC

S,

psi

Fig. 6. Continuous UCS profiles for Reservoir A (left) and Reservoir B (right).


with a high tendency for failure, while cool colors show a low

failure tendency. These diagrams are constructed at an average

depth for Reservoir A. Figure 8 also shows an example of this

diagram assuming average rock strength, UCS = 8,000 psi, for

the initial Reservoir A pressure of 3,980 psi and at a depleted

condition of 3,000 psi. Generally, highly deviated and

horizontal wells oriented along σHmax (i.e., N25°E) require

higher mud weights than those drilled normal to σhmin (i.e.,

N115°E). In addition, wells deviated up to 30° can be drilled

in any direction with more or less the same mud weight (i.e.,

less sensitive to well azimuth). The directions of horizontal

wells with special focus are shown by the white circles: N25°E,

N55°E, N70°E, N85°E and N115°E. The color scale in the

diagrams was set so that it spans the same range of mud

weights to better compare the changes in mud weights as a

result of production. We also indicate the direction of σHmax.

WELLBORE STABILITY DURING PRODUCTION

If the reservoir pressure is reduced in response to depletion,

the effective stress within the rock formation increases

according to the effective stress concept. A Mohr-Coulomb

material with strain hardening model was developed to be

used in the finite element modeling. Triaxial tests that

exhibited shear failure without compaction, characterized by

an increase then a decrease in volumetric strain, were selected

to establish the material model which describes the entire

loading part of a sample in the elastic and plastic domain until

the peak stress at failure.

This material model was then used to simulate the thick

wall cylinder tests to construct a generic material model that

describes the weakest parts of the reservoir. The empirical

formation under present-day pore pressure conditions. We

conducted the wellbore stability analysis also for depleted

pressure conditions assuming a depletion development

scenario. The plan predicts a decrease of Reservoir A’s pore-

pressure from an average current value of ~3,980 psi to

3,000 psi in 2024 (∆P = 980 psi) in response to production

(as discussed above).

As reservoir pressure declines due to production, the total

horizontal stresses decline as well. Commonly, the stress path

(i.e., change of stress with change of pore pressure) in a given

reservoir can be established with repeated extended leakoff or

minifrac tests. Since these data were not available, we

calculated the stress changes by assuming poroelastic reservoir

behavior. This poroelastic model is two-dimensional and

assumes a relatively flat, extensive (i.e., length >> width)

reservoir with constant overburden stress. For the horizontal

principal stress changes, we consider coupling between pore

pressure and total stress depending upon the value of Poisson’s

ratio as well as Biot’s coefficient. This results in ∆S/∆P = 0.67

for Poisson’s ratio of 0.25 and Biot’s coefficient of 1.0.

MINIMUM MUD WEIGHT PREDICTIONS

For the stability analysis, we constructed lower hemisphere

stereographic projections, Fig. 8, that enables the prediction of

minimum required mud weights for wells of arbitrary

deviation and orientation to maintain well integrity at a

specific depth. The colors indicate failure tendency in terms of

required mud weights to restrict wellbore failure to a critical

breakout width (i.e., 90° for vertical wells and 30° for the

horizontal wells; for intermediate hole inclinations, it is linearly

interpolated). Warm colors indicate orientations and deviations

Fig. 7. UCS distribution functions across Reservoir A (left) and Reservoir B (right).

relationship between Young’s Modulus and UCS was obtained

from the results of lab tests and incorporated in the finite

element model to evaluate rock plastic strains under different

pressure drawdown scenarios. A critical total plastic strain

was considered as a criterion to evaluate wellbore integrity

under a given depletion mode. A critical total plastic strain

was determined and calibrated with the thick wall cylinder

tests. The failure criterion derived indicated that failure

initiation occurs at a plastic strain of 15 millistrain, and

complete hole failure (i.e., collapse) results when the plastic

strain is 20 millistrain. The P10 rock strength value was

selected in the finite element simulation, which is 4,500 psi for

Reservoir A and 2,000 psi (Crest well) to 3,000 psi (Flank

wells) for Reservoir B. The simulations were conducted

utilizing present-day pore pressure values as well as those

predicted for 2024 and in 2035. We ran simulations for well

azimuths parallel to σHmax, and σhmin, as well as intermediate

azimuths between σHmax and σhmin directions of N85°E,

N70°E and N55°E. Furthermore, we investigated three

different pore-pressure levels of Reservoir A: 3,980 psi

(present day), 3,000 psi and 2,000 psi.

In general, we found that the most favorable well

orientation under any drawdown and depletion condition is

N115°E, which is parallel to σhmin and the least favorable well

orientation under any drawdown and depletion condition is

N25°E, which is parallel to σHmax.

For horizontal wells parallel N115°E (in direction of σhmin),

we find:

• At present-day reservoir pressures, horizontal wells

parallel to N115°E (in direction σhmin) are predicted to

have solids-free production and a stable borehole even

at 2,500 psi drawdown.

• When reservoir pressure reaches 3,000 psi, horizontal

wells parallel to N115°E (in direction of σhmin) will

produce solids free if drawdown is limited to 900 psi;

borehole collapse, however, is not expected unless the

drawdown exceeds 2,500 psi.


wells parallel to N115°E (in direction of σhmin) are

predicted to produce some solids at any drawdown;

borehole collapse, however, is not expected unless the

drawdown exceeds 800 psi.

For horizontal wells with azimuth N70°E - N250°E, we find:

• At present-day reservoir pressures, horizontal wells parallel

to N70°E are predicted to produce solids free if drawdown

is limited to 1,875 psi; borehole collapse, however, is not

expected unless drawdown exceeds 2,500 psi.


wells parallel to N70°E are predicted to produce some

solids at any drawdown; borehole collapse, however, is

not expected unless drawdown exceeds 1,850 psi.


Fig. 8. Lower hemispheric projection showing required mud weights to prevent excessive wellbore failure and collapse for wellbores of arbitrary deviation and orientation

drilled into Reservoir A with an assumed rock strength of UCS = 8,000 psi at an initial condition of reservoir pressure = 3,980 psi (left), and at a depleted condition of

reservoir pressure = 3,000 psi.


• At present-day reservoir pressures, horizontal wells

parallel to N25°E (in direction of σHmax) are predicted

to produce solids free if the drawdown is limited to 900

psi; borehole collapse, however, is not expected unless

the drawdown exceeds 2,500 psi.


wells parallel to N25°E azimuth (in direction of σHmax)

are predicted to produce some solids at any drawdown;

wellbore collapse, however, is not expected unless the

drawdown exceeds 900 psi.


wells with N25°E (parallel to σHmax) azimuth are

predicted to collapse at any drawdown.

Figure 9 shows the results as highlighted above in terms of

plastic strain vs. drawdown for the different pore pressure

conditions and well azimuths.

CONCLUSIONS

1. The geomechanical model for the Reservoir A field is a

transition between normal and strike-slip faulting

systems (σHmax ≥ σv > σhmin), with vertical stress of ~150

pcf - 151 pcf, minimum horizontal stress (σhmin)

estimated to be ~106 pcf, maximum horizontal stress

estimated to be ~145 pcf - 155 pcf and hydrostatic pore

pressure level (64.4 pcf) at reservoir level. A rock

strength correlation between UCS and sonic velocity has

been established.

2. The mud weight required to prevent breakout generation

and maintain wellbore stability during drilling was

determined, as it is important to obtain a gauged hole

during drilling for a maximum wellbore stability during

production. Minimum mud weights required to drill a

horizontal well in Reservoir A at initial reservoir pressure

are 64 pcf - 65 pcf for a well parallel to σhmin direction

and 68 pcf - 70 pcf for a well parallel to σHmax direction.

These mud weights will proportionally reduce when the

reservoir is depleted to 3,000 psi. The minimum mud

weights required to drill a horizontal well in depleted

conditions are 56 pcf - 57 pcf for a well parallel to σhmin

direction and 61 pcf - 62 pcf for a well parallel to σHmax

direction.

3. The tar-bearing zones are not competent enough to be

completed open hole due to the risk of wellbore collapse.

The recommendation is to avoid as much as possible any

tar-bearing intervals or consider casing those zones as

applicable.

4. Open hole completion is possible in non-tar zones

and the most favorable well azimuth is N115°E,

which is the direction of σhmin. A horizontal well

drilled at this direction will be stable even at 2,500

psi drawdown at present-day pore pressure conditions

in Reservoir A.


wells with N70°E azimuth are predicted to collapse at

any drawdown.

Following are results for horizontal wells with azimuth

N25°E - N205°E (in direction of σHmax), the least favorable

well orientation under any drawdown and depletion:

Fig. 9. Plastic strain vs. drawdown for five different well azimuths considered in

this project (shown with different colors). The orange and red horizontal lines,

respectively, represent the critical plastic strain values for which solid production

initiates and becomes severe (i.e., hole is predicted to collapse). (a) Present-day pore

pressure of 3,980 psi, (b) Reservoir pressure of 3,000 psi, (c) Reservoir pressure of

2,000 psi.

ACKNOWLEDGMENTS

The authors wish to thank Saudi Aramco management for

their support and permission to present the information

contained in this article.

REFERENCES

1. Salamy, S.P., Faddagh, H.A., Ajmi, A.M., Lauten, W.T. and

Mubarak, H.K.: “Methodology Implemented in Assessing

and Monitoring Hole Stability Concerns in Open Hole

Horizontal Wellbores in Carbonate Reservoirs,” SPE paper

56508, presented at the SPE Annual Technical Conference

and Exhibition, Houston, Texas, October 3-6, 1999.

2. Zoback, M.D., Moos, D., Mastin, L. and Anderson, R.N.:

“Wellbore Breakouts and In-Situ Stress,” J. Geophys. Res.,

Vol. 90, 1985, pp. 5,523-5,530.

3. Moos, D. and Zoback, M.D.: “Utilization of Observations

of Wellbore Failure to Constrain the Orientation and

Magnitude of Crustal Stresses: Application to Continental,

Deep Sea Drilling Project and Ocean Drilling Program

Boreholes,” J. Geophys. Res., Vol. 95, 1990, pp. 9,305-

9,325.

4. Peska, P. and Zoback, M.D.: “Compressive and Tensile

Failure of Inclined Wellbores and Determination of In-Situ

Stress and Rock Strength,” J. Geophys. Res., Vol. 100, No.

7, 1995, pp. 12,791-12,811.

5. Ahmed, M.S., Finkbeiner, T. and Kannan, A.: “Using

Geomechanics to Optimize Field Development Strategy of

Deep Gas Reservoirs in Saudi Arabia,” SPE paper 110965,

presented at the SPE Saudi Arabia Technical Symposium,

Dhahran, Saudi Arabia, 2007.


BIOGRAPHIES

Dr. Hazim H. Abass is a Petroleum

Engineering Consultant at the

Exploration and Petroleum

Engineering Center - Advanced

Research Center (EXPEC ARC) of

Saudi Aramco. His research area of

interest is applied rock mechanics in

petroleum engineering, especially in hydraulic fracturing,

wellbore stability, sand production, perforation and stress

dependent reservoirs.

Before joining Saudi Aramco in 2001, he worked for 2

years at the North Petroleum Company in Iraq, 1 year at the

Colorado School of Mines, 9 years at the Halliburton

R&DC in Duncan, OK and 5 years as Halliburton’s

representative to the PDVSA R&DC in Los Teques,

Venezuela. Hazim holds nine U.S. patents, has authored

more than 35 technical papers and contributed to three

industrial books. He is a member and the Technical Editor

of the Society of Petroleum Engineer’s (SPE) Production &

Facilities and is a member of the International Society for

Rock Mechanics (ISRM). Hazim received the 2008 SPE

Middle East Regional Award of Production and Completion.

In 1977, Hazim received a B.S. degree in Petroleum

Engineering from the University of Baghdad, Baghdad, Iraq.

He received his M.S. and Ph.D. degrees in 1987 in Petroleum

Engineering from the Colorado School of Mines, Golden, CO.

Mickey Warlick is a Petroleum

Engineering Specialist with the Manifa

Reservoir Management Division and has

been with Saudi Aramco for 7 years. In

1981, he received his B.S. in Petroleum

Engineering from the New Mexico

Institute of Mining and Technology at

Socorro, NM. Mickey joined Chevron USA Inc., and began

work as a Reservoir Engineer in the Permian Basin located in

west Texas and eastern New Mexico. There, he worked on

diverse reservoirs ranging from shallow 2,000 ft oil reservoirs

to 30,000 ft deep gas reservoirs. Mickey gained experience in

working on primary, secondary and even CO2 tertiary

processes. He then moved to the Over Thrust area of

Wyoming where he gained firsthand experience in dealing

with 20% H2S gas reservoirs that required utmost safety in

drilling and workover operations. Later Mickey moved on to

La Habra, CA where he worked in Chevron’s international

operations developing and deploying new field technologies.

Just before his move to Saudi Arabia, Mickey transferred

to Houston, TX where he worked as a Reservoir Simulation

Engineer in Chevron’s International Reservoir Simulation

department. While in Houston, he earned his M.S. degree in

Petroleum Engineering from the University of Houston,

Houston, TX in 2001. Mickey joined Saudi Aramco in 2002,

working as a Reservoir Engineer in the Zuluf field. When

Saudi Aramco decided to bring the Manifa field on as one of

its major increments, he was transferred there and is

currently Team Leader for the Manifa reservoir of the Manifa

field development.


Cesar H. Pardo has 22 years of

experience with E&P companies. He

joined Saudi Aramco in 2006 and

worked for 1 year for the Gas

Reservoir Management Department

(GRMD) as a Senior Reservoir

Engineer. In April 2007 Cesar was

moved to the Manifa Reservoir Management Division

(MRMD) where he currently works as a Petroleum

Engineer Specialist. In 1987 he began working at Ecopetrol

(the Colombian state company) where he worked for 4

years in drilling, workover and production technology

engineering.

In 1990 Cesar joined Shell Colombia (Hocol) as a

Workover Engineer. In 1992 he was promoted to a

Production Technology Engineer and successfully designed

and implemented a fracturing campaign for 30 producer

wells and an ESP and gas lift campaign for over 70 wells.

In 1996 Cesar was promoted to a Reservoir Engineer,

working in Classical Reservoir Engineering and Numerical

Reservoir Simulation with Eclipse, and he performed an

OFM study, identifying new infill drilling and workover

opportunities. In 2002 he was promoted to a Senior

Reservoir Engineer and given the additional responsibility

as a Team Leader (Asset Manager Deputy), he prepared

and coordinated the Field Development Plan (FDP) for a

heavy oil field. In 2004 Cesar was promoted to Reservoir

Engineering Network Leader for the whole company in

Colombia, he coordinated and prepared the new Hocol

books for forecast and reserves, coordinated calculation

procedures and coordinated the annual reserves review and

auditing for 2 years.

Cesar received his B.S. degree in Petroleum Engineering

from the Universidad de America, Bogotá, Colombia.

Mirajuddin R. Khan is a Geologist

working in the Exploration and

Petroleum Engineering Center -

Advanced Research Center (EXPEC

ARC). Since joining Saudi Aramco in

1991, he has been serving as the Senior

Rock Mechanics Laboratory

Experimentalist.

Mirajuddin received his B.S. degree in 1984 and his M.S.

degree in 1985, both in Petroleum Geology from the

University of Karachi, Karachi, Pakistan. His interests are

rock mechanics’ applications in petroleum engineering.

Mirajuddin is a member of the Society of Petroleum

Engineers (SPE) and has published several technical papers.

Before joining Saudi Aramco, Mirajuddin worked as

Teaching Assistant for 1 year and then received a Research

Scholarship to work as a Research Scholar for 2 years at

the University of Karachi.

His awards include the 2004 Recognition Award of the

Engineering & Operations Services of Saudi Aramco.

Dr. Ashraf M. Al-Tahini is a Senior

Petroleum Engineer at the Exploration

and Petroleum Engineering Center -

Advanced Research Center (EXPEC

ARC) of Saudi Aramco. His areas of

interest include geomechanics and rock

physics, as he is currently involved in

leading several vital projects in the area of fracturing and

sand control.

In 1996, Ashraf received his B.S. degree in Chemical

Engineering from King Fahd University of Petroleum and

Minerals (KFUPM), Dhahran, Saudi Arabia. He received

his M.S. degree in 2003 and his Ph.D. degree in 2007, both

in Petroleum and Geological Engineering, from the

University of Oklahoma, Norman, OK.

During the 12 years of his career and education, he has

presented and published many technical papers. Ashraf has

also received many awards, including the Society of

Petroleum Engineers (SPE) paper mention award in 2008

for the Reservoir Geology and Geophysics Session, the

second place award for the SPE’s U.S. Rocky Mountain

Mid Continent Ph.D. paper contest in 2004 and the

University of Oklahoma Rock Mechanics Award for 2003

and 2006. In 2001, he received the best paper and

presentation award during the Saudi Aramco Technical

Exchange Conference in Dhahran.

Ashraf was the Chairman of the 2009 SPE Saudi Arabia

Section Technical Symposium and Exhibition and currently

he is the Chairperson of the SPE Saudi Arabia Section. He

is a member of SPE, the Society of Exploration and

Geophysics and the American Rock Mechanics Association.

Dr. Dhafer A. Al-Shehri is currently

the Manifa Subsurface Team Leader

with Northern Area Reservoir

Management. Since joining Saudi

Aramco in 1996, he has worked as an

Engineer, an Engineering Supervisor,

and General Supervisor for Drilling &

Workover Engineering, Reservoir Management and

Production Engineering. Dhafer also acted as the Chief

Technologist, Drilling Technology Team, Exploration and

Petroleum Engineering Center - Advanced Research Center

(EXPEC ARC).

Dhafer holds B.S. and M.S. degrees from King Fahd

University of Petroleum and Minerals (KFUPM), Dhahran,

Saudi Arabia, and a Ph.D. from Texas A&M University,

College Station, TX, all in Petroleum Engineering.

Prior to joining the company, he was a Petroleum

Engineering professor at KFUPM. As an active member of

the Society of Petroleum Engineers (SPE), he has authored

many technical papers on various topics and chaired the

local 1998 SPE Technical Symposium.


Dr. Hameed H. Al-Badairy is a Senior

Laboratory Scientist at the Research &

Development Center (R&DC) of Saudi

Aramco. He received his Ph.D. degree

in Materials Science and Engineering

from Liverpool University, Liverpool,

UK. Hameed has over 15 years of

academic and industrial experience in the fields of materials

science and electron microscopy. Prior to joining Saudi

Aramco he worked for 13 years as a Senior Research

Associate at the Department of Materials Science and

Engineering, Liverpool University.

Hameed has published more than 60 technical papers

and is a member of the National Association of Corrosion

Engineering (NACE), Institute of Materials, Minerals and

Mining (IOM3), North West & Liverpool Engineering

Society and the Technical Committee of the 13th Middle

East Corrosion Conference and Exhibition (13MECC). He

has presented his work at over 30 national and

international conferences and has been an invited keynote

speaker in four international conferences.

Yousef M. Al-Shobaili is currently the

Northern Onshore Fields Group

Leader at the Reservoir

Characterization Department. He

joined Saudi Aramco in 1994 after

receiving his B.S. degree in Petroleum

Geology and Sedimentology from King

AbdulAziz University, Jiddah, Saudi Arabia. During his

career he has worked in several disciplines of the

Exploration and Petroleum Engineering organizations.

Yousef’s experience covers several reservoir aspects,

including reservoir evaluation and assessment, reservoir

management and engineering assessment, petrophysical

integration, reserves estimation and assessment, identifying

new hydrocarbon from old fields, drilling operations and

well planning, reservoir description and geomechanics and

wellbore stability, log analysis and interpretation, and core

description and integration. He has also trained several

summer students, geologists, geophysicists and reservoir

engineers, and he developed an in-house log interpretation

and petroleum geology training course.

Yousef has authored and co-authored 18 technical

papers in reservoir evaluation, reservoir description,

geosteering, rock mechanics, reservoir management and

dynamics, and log/core petrophysics. He is the founder and

the first president of the Saudi Petrophysical Society (SPS).

Yousef attended and passed an intensive six month

petrophysical and log evaluation Schlumberger program.

He was the first worldwide non-Schlumberger employee to

ever join this program.

Dr. Thomas Finkbeiner is the Regional

Technical Advisor (EAME) for

GeoMechanics International (GMI).

He began work there as a specialist in

reservoir geomechanics and a

consultant for the petroleum industry

in wellbore stability and in-situ stress.

In 2001, Thomas was assigned to the Middle East, India,

and Pakistan as Director to develop, coordinate and

manage GMI’s services to regional operators and clients. In

the summer of 2004, Thomas relocated to Dubai, U.A.E.

and opened GMI’s regional office to run all Europe, Africa

and Middle East operations.

In 1994, Thomas received his M.S. degree in Geophysics,

and in 1998, he received his Ph.D. degree, also in

Geophysics, both from Stanford University, Stanford, CA

under the supervision of Prof. Mark Zoback (a renowned

expert in geo- and rock mechanics).

He has over 10 years of industry experience in

geomechanics and related applications, such as wellbore

stability during drilling and production, fluid migration

and more.

Satya Perumalla is a Senior

Geomechanics Specialist, working with

GeoMechanics International (GMI)

since 2007, and has diverse experience

in making connections between

geomechanics and drilling problems.

He has over 12 years of experience

working in the oil and gas industry as a Consultant,

working at various levels, supporting well engineering and

sub-surface interests of various operators, i.e., Shell, BG

and Total, etc., in the Middle East, Africa and India.

Satya received his M.S. degree in Applied Geology from

the Indian Institute of Technology, Roorkee, India.

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