SPE 126097

Drilling and Completing Horizontal Wells in Unconsolidated Sandstone Reservoir in Saudi Arabia; A Rock Mechanics View Rabaa Ali S, Abass, H.H, and Talal S Mousa/ Saudi Aramco

Copyright 2009, Society of Petroleum Engineers

This paper was prepared for presentation at the 2009 SPE Saudi Arabia Section Technical Symposium and Exhibition held in AlKhobar, Saudi Arabia, 09–11 May 2009. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to 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 the SPE meetings are subject to publication review by Editorial Committee of Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and whom the paper was presented. Write Liberian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract Drilling horizontal wells is a common practice for Saudi ARAMCO in most of its oil and gas reservoirs of Saudi Arabian clastic and carbonate fields. A comprehensive study of rock mechanical properties with detailed analysis of the in-situ stress field was conducted to evaluate well stability during drilling and completion across a friable eolian oil-bearing sandstone reservoir. This paper discusses the application and implementation of the study to successfully drill and complete development horizontal wells in a challenging sandstone reservoir.

All horizontal wells were completed with different type of sand screens including Premium and Expandable Sand Screen (ESS). It is vital to obtain a near-gauge hole during drilling for a maximum stability of the screen during the life of a well. It is therefore important to prevent excessive compressive shear failure at the wellbore wall and avoid instability problems during drilling and completion. Therefore, an optimum confining pressure to the wellbore surface needs has been derived. The recommended mud type and weight windows derived from the study have been employed while drilling producers but not with injectors. The correlation between the mud weights and the in-situ stress magnitude will be discussed.

Well stability during drilling and long term screen integrity is dependant on the well azimuth relative to the in-situ stress field. The azimuth of the maximum horizontal stress, SHmax, was determined to generally line up in the E-W direction. The wellbore stability problems experienced in this direction as well as those drilled normal to it (i.e., N-S), will be addressed.

In regards to stability of very weak and friable formation intervals (such as those encountered in the, dunes and sand sheet facies), the operational practices are focused on creating gauged hole with least erosion effect as a critical measure to deploy the ESS; thus, ensuring successful completion and sustained production. The effect of mud on rock strength was evaluated during the foregoing study; therefore, results from using oil-base mud will be discussed and compared to results from the wells drilled with water-based mud.

Introduction A comprehensive study of rock mechanical properties with detailed analyses of the in-situ stress field was conducted to evaluate well stability during drilling and completion across a friable eolian oil-bearing sandstone reservoir1. This paper discusses the application and implementation of the study to successfully drill and complete development horizontal wells in a challenging sandstone reservoir. To develop the field to its target production, Saudi Aramco drilled a number of horizontal wells, single and multilaterals to ensure maximum reservoir contact. The study recommended to drill horizontal wells in the E-W direction (parallel to SHmax) to acquire stable wellbore during drilling and completion at optimum mud weight. Drilling in the N-S direction is less stable that requires excessive mud weight. It was recommended to use oil based mud (OBM) to ensure wellbore stability across shale formations as well as the unconsolidated sandstone intervals encountered throughout the reservoir. The time-dependant failure and the effect of osmotic pressure generated from the difference between mud and shale water

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activities should be considered in any wellbore stability study that involves shaly formations2. Most horizontal oil producers are drilled with OBM and oriented E-W while horizontal water injectors are drilled with water based mud (WBM) and oriented N-S. Results indicated that both producers and injectors drilled at different drilling orientations and mud types have encountered similar wellbore instability problems but not sever ones. Since the sand is friable with high sanding tendency, all wells were completed with sand control completions such as compliant expandable sand screen (ESS) and standalone premium screens. The compliant expansion technique is reported to provide an internal support for the wellbore3.

Rock Mechanical Properties Because mechanical integrity of the wellbore for the chosen completion strategy is of critical importance, the previous study focused on characterizing the mechanical properties to ensure stable and gauged hole during drilling and completion. A summary of the reservoir mechanical characteristics is given below:

Pore Pressure: The pore pressure data in the reservoir of interest follow a hydrostatic trend of 0.433 psi/ft expressed with respect to the drill floor. We used this gradient as the current pore pressure in the reservoir formation for wellbore stability analysis. In Situ Stress Orientation: The breakout and tensile fracture orientations observed from the logs of vertical wells revealed a relatively consistent stress orientation of SHmax averaging E-W as shown in Figure 1.

Figure 1. Base map of the the reservoir showing the direction of the maximum principal stress (SHmax).1

Overburden: The vertical in situ stress was derived from bulk density wireline log data that was acquired from the surface down to the reservoir levels. Integration of these density data with respect to depth revealed an overburden gradient of 1.09 psi/ft at the level of the reservoir.

Minimum Principal Stress: One injectivity test was conducted in the reservoir which yielded a gradient of 0.7 psi/ft for Shmin. Maximum Principal Stress: The results of the stress analyses suggest a strike-slip faulting stress state (SHmax > Sv > Shmin) with average SHmax magnitudes equal to 1.2 psi/ft. This stress-regime is consistent with others found in Saudi-Arabia4 and the region.

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Elastic 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 prediction during production:

1. Young’s modulus and Poisson’s ratio 2. Uniaxial compressive strength (UCS) 3. Cohesive strength (c) 4. Internal friction angle 5. Hollow cylinder strength (HCS)

The lab testing results are summarized in Table 1 in terms of uniaxial compressive strength:

Table 1: Strength of the main facies Facies type UCS range (psi)

Dunes 2,000 – 7,400 Sandsheet 3,900 – 6,600 Paleosoil 2,300 – 4,530Playa 12,420 Fluvial Not tested

Strength Correlations: To develop continuous rock strength profiles in the reservoir section, we utilized wireline logs data. Unconfined compressive strength (UCS) was derived using a published relationship based on density and sonic logs5. The log-calculated UCS from the original Hemlock equation was then calibrated using the UCS values from the laboratory measurements conducted in the same well from which the wireline log data were available. The resulting calibrated strength algorithm is then given as:

3043002.0)( −•= MpsiUCS where 2)( pvRHOBpsiM •= The available lab UCS data mainly belongs to the weaker intervals near the top and the middle part of the reservoir formation and show a satisfactory match with the log-predicted strength. There are also very weak intervals predicted in the reservoir with UCS values close to 500 psi. This is consistent with some of the unconsolidated core section observed in the laboratory and from which no samples could be retrieved. For the wellbore stability analysis – in particular when considering well integrity during expandable sand screen deployment – we consider the weakest portions of the reservoir (i.e., conservative approach). As we will discuss below, UCS values were selected for analysis ranged from as weak as 500 psi to 2,600 psi. If well integrity can be maintained for these weak sections, the remainder of the well with stronger rock should also be stable. Drilling Practices and Field Observations This project has been initiated to improve our development and completion strategy for sand control based on the strength characterization of the reservoir. All wells are drilled horizontally and designed as a big-hole design for producers for effective well bore radius and flexible accessibility and slim-hole design for injectors as shown in Figure 2.

Most horizontal producers were drilled through 8 1/2” hole with OBM in the E-W direction (parallel to SHmax) to acquire stable wellbore during drilling and completion as recommended by the geomechanical study. Conversely all horizontal injectors were drilled across 6 1/8” hole with WBM in the N-S direction (Normal to SHmax) which was not recommended by the study. The average mud weight used for drilling the reservoir was 67 lb/ft3 (8.9 lb/gal). Wellbore instability problems (tight spots, caving, and hole collapse) have been encountered in most of development wells drilled in this field including horizontal producers and injectors, and vertical evaluation wells.

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Figure 2: Wellbore schematic for producers and injectors.

The following observations are drawn from the drilling experiences of all development wells drilled in the field:

1) The instability problems seem to be independent of wellbore azimuth which requires close examination of the stress field and the critical mud weight required.

2) The instability problems are related to shale formations and playa (silt) sandstone formations as in Figure 3. Since all injectors were drilled with water-based mud and all producers were drilled with oil-based mud, the chemical and mechanical related wellbore instability problems should be separately evaluated.

3) The instability problems happen at different wellbore deviations which may necessitate using different mud weights as the deviation angle is built up from vertical to the horizontal direction.

4) Many of the wellbore instability problems were reported upon resuming drilling following tripping in or out operations.

Figure 3: shale formation and Playa large cuttings at the shakers indicating hole collapse and severe wellbore instability problems. Observation 1: We start with the following analysis6. The numerical analysis conducted to date assumes the well is drilled parallel to the maximum horizontal stress (σH). This direction is assumed to be a “‘safe direction” for initiation of a wellbore breakout. To evaluate this recommendation, let’s recall some theoretical background. Mud weight should be calculated to prevent the initiation of tensile and shear failures. The mud weight is limited by two boundaries: 1) The upper boundary which is the pressure that causes tensile failure and mud loss, and 2) The lower boundary which is the pressure required to prevent shear failure. A wellbore breakout occurs within the wellbore area that experiences the most compressive circumferential stress. If we consider two cases where θ = 0 (σH,max) and θ = 90 (σH,min), we have

Big-hole design Producer

Slim-hole design Injector

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σ σ σθ,= = ′ − ′ − +0 3 H,min H,max w rp p

σ σ σθ,= = ′ − ′ − +90 3 H,max H,min w rp p

To initiate a tensile failure, as is the case in hydraulic fracturing, σθ=0 should become a negative value of the tensile strength (σθ = 0 = -T). The breakdown pressure, pbd required for initiating a fracture can be readily calculated:

pbd = ′ − ′ + +3 T pH,min H,max rσ σ , or in terms of total stresses,

pbd = − + −3 T pH,min H,max rσ σ

Let’s consider the compressive failure equations to compare wellbore stability in the directions of σHmax and σhmin. Figure 4 shows the wellbore stability results for these directions. For a wellbore parallel to σH (E-W) the breakout is likely to occur on the sides of the wellbore and less likely to happen top-bottom. A well drilled parallel to the σhmin, (N-S), breakout is likely to occur on the top and bottom of the wellbore and less likely on the sides. If we consider the value of stress concentration and the severeness of breakout then a wellbore parallel to σHmax (E-W) will be exposed to a deviatoric stress of 0.39, while a wellbore drilled in the direction of σHmin the deviatoric stress will be 0.11. It is therefore; we will have a failure in both directions; however the breakout is more severe for the well drilled in the direction of σHmax.

// σHmax (E-W) // σhmin (N-S)

2.57 psi/ft 2.07 psi/ft

1.01 psi/ft 2.51 psi/ft

1.09 psi/ft 1.09 psi/ft

0.7 psi/ft 1.2 psi/ft

Dev. Stress = 0.39 Dev. Stress = 0.11

Figure 4: Theoretical evaluation of stress concentration around a horizontal well drilled in the two principal directions; σHmax (E-W) and σhmin (N-S). Now, we used Pbore-3D developed at the University of Oklahoma7 to verify this result then compare the results with field observation. The poroelastic model of the PBORE-3D model was selected with the Modified Lade failure criterion to determine the mud weight window required to prevent failure in two principal directions; SHmax and Shmin.(Figures 5 & 6). Observing the failed zones around the wellbore in the principal stress directions indicate the same results discussed earlier. For a wellbore parallel to σH (E-W) the critical region occurs on the sides of the wellbore while it is on top and bottom for a well drilled parallel to the σhmin, (N-S).

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Figure 5: The critical regions of a horizontal well drilled in the direction of σHmax (E-W)

Figure 6: The critical regions of a horizontal well drilled in the direction of σHmin (N-S) Observation 2: It is important to differentiate between the mechanical and chemical effects on wellbore instability problems. The bottom hole pressure provides support to the wellbore wall when a mud cake is developed. Mud

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cake development is a function of formation permeability where it builds enough mud cake when formation permeability is high and no mud cake is developed across tight formation such as shale. Although the filtrate is minimal to build a mud cake when drilling shale and siltstone, it is enough to raise the pore pressure locally that tensile failure may occur. On the other hand a mud cake is quickly developed in higher permeability formation, which helps in providing the designed overbalanced pressure to support the wall of a wellbore. Therefore, it is anticipated to have more wellbore instability problems during drilling tight formation as compared to permeable formation. This has been observed in this field as the zone sitting above the reservoir is generally combination of silt and shale of extremely low permeability and most of wellbore stability problems occur across this zone until it is cased. Shale presents particular challenges to drilling worldwide because it contains rich clay content, which has large surface area and complicated water molecule or ionic communication between the shale and drilling fluid that change the mechanical properties. Swelling pressure may increase or decrease in the shale depending on the mud chemistry. Increasing the swelling pressure is detrimental to maintaining borehole integrity.

Flow of drilling fluids due to pressure gradient between drilling fluid and shale pore water is controlled by Darcy’s law and is usually from wellbore to shale formation assuming an overbalanced drilling operation. Raising mud weight of a drilling fluid that has a water phase may increase the mechanical stability due to increasing confinement pressure, but it can also contribute to shale hydration. Oil-based drilling fluids has an advantage over water-based drilling fluids in this type of flow because of the threshold capillary pressure. The radial stress is higher in OBM as compared to the WBM because of the pressure dissipation of the later as it is miscible with the shale pore water.

Observation 3: Now let’s go back to Pbore-3D and analyse wellbore stability for same horizontal well but in all azimuths. Figure 7 shows the wellbore stability results for all directions in terms of mud weight required to maintain well stability. For a wellbore parallel to σHmax (E-W) the mud weight is 11.3 Ib/gal (84.5 lb/ft3); while it is 13 Ib/gal (97 lb/ft3) for a well parallel to σhmin (N-S). The least mud weight of 10.5 Ib/gal (78 lb/ft3) was observed for a well drilled NE-SW or NW-SE. It should be noted that although one direction is better that another, all directions may experience wellbore instability problems because of the strike-slip stress field and having weak zones of a UCS in the range of 100-1000 psi, throughout the reservoir. Tolerable breakout angle is usually used when investigating a wellbore instability problem. Figure 7 is determined assuming a breakout angle of 30 o and Figure 8 is for acceptable breakout angle of 45o.

Figure 7: Pbore-3D results for the give well al all azimuths and deviations with 30o tolerable breakout angle. Considering the failure mode of the shale, one can decide on whether to allow any breakout or not when designing the mud weight window. With higher acceptable breakout, almost all azimuths require similar mud weight indicating

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that there is no much difference in drilling the horizontal wells in any specific direction. We notice a clear difference as the deviation angle is built. Figure 9 is made for no break out which shows that the mud weight required for stable hole is higher for a vertical well and as you build up the deviation angle less mud weight is needed. This indicates that drilling through the shale zones we should consider higher mud weight and as the deviation angle is increased to the maximum value, the mud weight can be reduced to drill the horizontal section.

Figure 8. Pbore-3D results for the give well al all azimuths and deviations with 45o tolerable breakout angle.

Figure 9. Critical mud weight varying hole information from Pbore-3D results.

Observation 4: We discuss the following circulation and time-dependant effects to understand why tight hole may occur upon resuming drilling following a downtime as a result of some operational issues.

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Static vs. Dynamic Circulation: The difference between dynamic mud density and static mud density has been realized in many wellbore instability problems and the concept of Equivalent Mud Density (ECD) was used to explain the problems encountered after stopping drilling the well for any operational reason. When the pumps are shut down and the mud weight is reduced from Equivalent Mud Density to static mud density, the rock faces lower confinement and the stress concentration may trigger rock failure. Diffusion flow: This is the flow of solutes from high concentration to low concentration based on Fick’s law8. This flow is effective in high permeability shale as the large size solutes are able to flow through the porous structure of the formation. Therefore in fractured or permeable shale the diffusion causes solutes to flow from drilling fluid to shale formation or vice versa of the species depending on their concentrations within the drilling fluid and shale water. This flow can cause shale stability problems. For example calcium ions from CaCl2-brine drilling fluid invading shale changing the clay structure because of cation exchange reactions. Shale hydration causes strength reduction thus triggers wellbore instability problems. The transfer of water and ions from and into shale formation is the main reason for the chemical effect of wellbore instability during drilling. Shale tends to hydrate when it is in contact with water and that changes the physical and mechanical properties which make it vulnerable to failure.

Osmotic Flow: It is a driving force affecting the transfer of solutes and associated water between two media of different concentrations in the presence of a semi-permeable membrane because of the very small pores that can block solutes but allow water molecules to flow. This is because the water molecules are much smaller than the solutes. The driving force is determined by the water activity difference between drilling mud and shale pore fluid at in-situ conditions. The flow will continue to be from high water activity (low salt concentration) to low water activity (high salt concentration).

Completion Implementation The completion design is based on rock mechanical characteristics of the field’s sandstone reservoir to achieve wellbore stability, productivity improvement and sand control. The well stability during drilling and production is essential to ensure the stability of the well completion especially the ESS completion during the life of a well. The chemical effect of drilling and completion fluids on sand strength and sanding tendency has been quantified. Understanding minimum required mud weights is an important issue when dealing with weak and/or poorly consolidated formations to be completed with ESS. It is vital to obtain a near-gauge hole during drilling for a maximum stability of ESS during the life of a well. It is therefore important to prevent excessive compressive shear failure at the wellbore wall and avoid instability problems during drilling and completion. Therefore, abiding by the mud weight recommendation during drilling is part of the successful ESS completion in terms of ESS deployment and long term stability. A concern for sustained integrity during reservoir production was raised as the ESS will be deployed in a horizontal well going through a sequence of facies with alternating formation strengths (i.e., strong to weak and vice versa). Figure 10 shows as an example an interface between dune and playa facies. This interface is likely characterized by an extreme strength contrast. Interfaces of this type need to be carefully considered in the completion design as they may provide weak spots in the completion due to the risk for shear failure and accompanied damage of the ESS. Therefore, in the engineering analysis of the ESS integrity, one has to assume a conservative approach in the sense that the weakest material does have very low or essentially no cohesion.

Figure 10. A sharp interface appears between Sand Dune and Playa facies.

The completion used in the field utilizes a hybrid smart ready completion utilizing either a combination of ESS, blank pipe, and expandable blank pipe with swellable packers (Figure 11) or a combination of premium sand screens, blank pipe, and mechanical packers. This novel completion provides the ability to screen off weak

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sandstone sections in the case of ESS while isolating the siltstone and other fine grained sections with blank pipe and packers to provide effective sand control and avoid screen collapse and/or plugging caused by migrating fines in the annulus areas. The completion also offers the possibility for insertion of future intelligent well completion equipment utilizing the 7” blank pipe section to set packers in.

Figure 11: ERCTM completion- a combination of ESS, blank pipe, and expandable blank pipe with swellable packers Conclusions

1. Based on drilling experience, the generated geomechanical model is verified and calibrated such that it robustly and accurately predicts compressive and tensile failure around given wellbores. This model is based on measurements of in-situ reservoir conditions and consistent with observations of wellbore failures derived from electrical image logs. This model was then utilized as a basis for wellbore stability predictions.

2. The UCS variation in the reservoir and the severity of the strike-slip faulting condition (σHmax > σV > σhmin), or (1.2 > 1.09 > 0.7), made all direction prone to wellbore stability problems. The least stability problems should be related to well direction of NE-SW or NW-SE.

3. The laboratory analysis revealed that clay particles are part of the cementation material and therefore special drill-in-fluid recipe was designed to overcome its instability problem.

4. The analysis indicated that wellbore instability problems are more sever when drilling deviated wells than horizontal wells. Therefore, it is anticipated that the mud weight during building up well angle should be higher than drilling the horizontal section.

5. Time-dependant failure is related to two issues; the reduced ECD after a short drilling break, and the time-dependant diffusion which aggravates the shale instability problems.

6. Most of the wellbore instability problems encountered while drilling injection wells are related to shale instability problems due to using water based mud when drilling these wells.

Acknowledgements The authors wish to thank Saudi Aramco for permission to publish this paper. Special appreciation goes to the Southern Reservoir Management and EXPEC ARC for their support.

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