SPE-115491-MS

SPE 115491 Powered Rotary Steerable Systems Offer a Step Change in Drilling Performance Hussain E. Al-Yami, Abdallah A. Kubaisi and Khalid Nawaz, SPE, Saudi Aramco; Amir Awan, Jaywant Verma and Sukesh Ganda, SPE, Schlumberger

Copyright 2008, Society of Petroleum Engineers This paper was prepared for presentation at the 2008 SPE Asia Pacific Oil & Gas Conference and Exhibition held in Perth, Austra lia, 20–22 October 2008. 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 does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. 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 SPE copyright.

Abstract Drilling horizontal gas wells at an average TVD of 12,500 ft in Saudi Arabia has always been very challenging owing to harsh drilling conditions. These wells are drilled in southern Ghawar field. Subject formations include bands of Lower and Middle Triassic and Upper Permian, composed of dolomite, shale, silt stone, and anhydrite formations. The main challenges in drilling these formations are slower penetration rates and difficulty in sliding with conventional motors in both the build and lateral sections. This paper describes a step change in drilling performance using powered rotary steerable systems (PRSS) technology that led to record directional runs through difficult Khuff sections. With the PRSS assembly, the company was able to drill both vertical and curve sections in one run, maximize ROP, and increase footage per bit run while meeting directional requirements. PRSS successfully kicked off from vertical and improved ROP up to 192% compared to conventional motor ROP in deep gas drilling. Significant improvements in ROP resulted in saving multiple bit trips in 12-in., 8 3/8-in., and 5 7/8-in. hole sections.

Introduction: Figure 1 shows the stratigraphic view of Ghawar field in Saudi Arabia. The late Permian Khuff A, B, and C stacked carbonate reservoirs are the main gas-producing zones at depths of 10,000 to 12,000 ft. Formations encountered are well recognized for providing a harsh and hard drilling environment. Steerable motor drilling is a relatively inefficient process, with associated problems in the area ranging from trajectory control in unstable formations to slow penetration rates, pipe sticking, and slide drilling. Conventional steerable motor drilling requires sliding of the bottomhole assembly to steer the well  path; therefore, drilling becomes slower and potentially more problematic. Rate of penetration (ROP) is impacted as a result of wellbore friction, plus BHA and drillstring components tend to hang up. Also, while drilling the Khuff wells, high mud weights are required to balance the formation pressures. Drilling formations with different reservoir pressure increases the tendency of the drillstring to stick to the permeable formations, hence giving rise to differential sticking, which in turn gives rise to sliding difficulties.

Conventional Conventional Well Profile and Casing Design Two different types of casing designs are used while drilling these deep gas wells, namely “K1” and “K2”. Figure 2 shows the comparison of the casing designs. In the conventional K2 well profile, 13 3/8-in. casing is set from surface to 30 ft into Base Jilh dolomite. A typical well  profile calls for vertical vertical drilling of about 800 to 1,000 ft with with a performance motor motor and an aggressive polycrystalline polycrystalline diamond compact (PDC) bit. The bit is then pulled out of hole and the build section is drilled with a steerable motor bottom hole assembly at a planned 4° to 4.5° dogleg severity. The 9 5/8-in. casing is planned and set at about 70° inclination into Khuff C carbonate. On average, 3 bit trips are required to drill the 12-in. build section. After setting 9 5/8-in. casing, personnel use a rotary assembly to clean out cement and drill the shoe track. 8 3/8-in. single or dual laterals are drilled in the Khuff-C reservoir,

2

SPE 115491

In a K1 design, 9 5/8-in. casing is set 30 ft into Base Jilh dolomite formation. The build section is drilled in 8 3/8-in. hole size to Khuff-C carbonate with a 7-in. liner run. 5 7/8-in. single or dual laterals are drilled in the Khuff-C reservoir layers. K2 is preferred over K1 casing design because the possibility exists of setting additional casing string in case high pressure is encountered in the Jilh formation while drilling the 12-in. hole section. Figure 3 shows plan and vertical section view of typical directional profile.

Principles of Operation Rotary steerable systems have entered the local spotlight recently owing to their potential for revolutionizing the way directional wells are drilled. Rotary steerable systems can be categorized by their mode of operation. There are two steering concepts for these systems: point-the-bit and push-the-bit. Push-the-Bit Rotary Steerable System

At a short distance behind the bit (approximately 1 ft) three actuators (called “pads”) are positioned around the circumference of the biasing unit (BU) for the purpose of applying lateral force to the formation. The outward stroke of these  pads is limited by mechanical stops (“kickers”) so that the deviation of the centerline of the BHA is controlled to a set limit. For example, if the hole must be drilled in a build direction, the pads are activated to push on the low side of the hole; for a drop condition, the pads would push against the high side of the hole, etc. This rotary steerable system exploits the raw power of the mud to drive the pads out. At the heart of this actuation system is a simple rotary valve, which opens and closes the supply of mud to the pad actuators in symphony with the drillstring rotation. Once set, the position of the push-point is maintained no matter how the drillstring rotates. This is achieved by a control system called the control unit (CU) that sits above the BU in a collar (see Figure 4).

Point-the-Bit Rotary Steerable Systems

Figure 5 shows a point-the-bit rotary steerable system. These systems operate by placing a relative bit offset “bend” in the system, much like a standard motor assembly. This bend is held geostationary with respect to the formation. To understand the point-the-bit principle, one can make comparisons to conventional drilling systems that use motors or turbines. A bent housing and stabilizer on the bearing section allows the motor to drill in either an oriented (sliding) or a rotary mode. In the rotary mode, both the bit and the drillstring rotate. The rotation of the drillstring negates the effect of the bent housing, and the bit drills an over-gauge straight path parallel to the axis of the drillstring above the bent housing. In the sliding mode, only the bit rotates. The motor changes the well course in the direction of the bent housing, and the drillstring slides down the hole  behind the bit. In the point-the-bit system, the bent housing is contained within the collar of the tool. This bent housing is controlled by means of an electric motor that rotates counter to the direction of and at the same velocity as the drillstring. This control allows the bent housing to remain geo-stationary (nonrotating), while the collar is rotating. PRSS

A PRSS is a high-performance rotary steerable system (RSS) that has a fully integrated high-torque power section that converts mud hydraulic power to mechanical energy (Figure 6). This energy, combined with rotation provided by the rig’s topdrive, significantly increases downhole power at the bit. The additional torque capacity allows using aggressive PDC bits for directional application and higher weight on the bit, resulting in increased ROP and more cost-effective drilling. This system has the ability to drill faster and farther. The integrated power section rotates the bit and allows drillstring rotation to be slowed. Stick/slip and other damaging vibration modes common to conventional rotary drilling are reduced. All available energy is used to drill the hole optimally. Casing wear and drillstring fatigue is reduced owing to slower drillstring rotation, minimizing the chance of drillstring or casing failure. All external parts rotate at drillstring speed, reducing drag. The rotation also helps clean and condition the hole, lowering the risk of differential or mechanical sticking. For deep gas operations in Saudi, both point-the-bit and push-the-bit systems were utilized in conjunction with downhole  power sections, i.e., PRSS.

PRSS Field Results The PRSS were successfully utilized in various hole sections including build sections (12 in., 8 3/8 in.) and lateral hole sections (8 3/8 in., 5 7/8 in.) in the southern Ghawar field of Saudi Arabia.

SPE 115491

3

The well profiles were similar to those of steerable motor applications; however, the well plans were customized based on thorough analysis of formation tendencies and dogleg response. The one-trip approach to drilling the curve section allowed moving the kickoff point shallower, thereby reducing dogleg and tortuosity Figure 7 shows a comparison of MWD continuous inclination versus stationary survey for a well drilled by conventional motor BHA and a PRSS BHA. It is clear that PRSS helped in reducing microdoglegs. Case 1: PRSS in Build Sections

Objectives in the 12-in. build section were to drill both vertical and curve sections in one run, maximize ROP, and increase footage per bit run while meeting directional requirements. The main challenge in drilling the 12-in. section was to kick off from vertical in the right direction and then to follow the well path to land the well in Khuff-C Carbonate. To date, thirteen 12-in. curve sections have been successfully drilled in deep gas with five casing-shoe-to-casing-shoe runs. In every 9-in. PRSS job, we successfully kicked off from vertical an d landed the well in the desired formation. Average ROP achieved with the 9-in. PRSS is 23.2 ft/hr. This ROP is 115% higher than conventional motor ROP. Smooth borehole drilled by the system eliminated the need for a reaming trip before running casing, thereby saving an additional trip. Performance improvement owing to the 9-in. PRSS has resulted in saving 77.6 days. Figure 8 shows comparison of ROP using a motor and a 9-in. PRSS. The profile discussed earlier was for a typical Khuff-C well; however, there were three wells targeting deeper sand stone formations called Unayzah. In these wells, a 12-in. section is drilled to the Khuff formation. The rest of the build section, from Khuff to the top of Unayzah, is drilled in an 8 3/8-in. hole section. The average ROP seen in drilling the 8 3/8-in. curve section is 11.1 ft/hr. With the implementation of PRSS, average ROP of 23.3 ft/hr was achieved while drilling the same formations, which is more than 110% improvement over motor average ROP. Figure 9 shows a comparison of ROP between a motor and a 6.75-in. PRSS. Drilling a 12-in. curve section with a conventional motor resulted in 5 stuck pipe incidents out of 45 sections drilled in last 3 years. Continuous rotation of all external parts of PRSS helped in successfully drilling 13 curve sections so far without any stuck pipe incidents. Case 2: PRSS in Lateral Sections

Drilling 8 3/8-in. and 5 7/8-in. horizontals in the range of about 5,500 ft and at a TVD of about 12,000 ft has been very challenging due to length of the lateral, high TVD, high mud weight, differential sticking, and geological uncertainties. The Khuff-C reservoir is composed of 12 layers named C-1 to C-12. These layers have different reservoir pressure. Typically inclination is built from 70° to about 88° before the well is landed into the target Khuff-C layer. Invariably, well control situations are encountered owing to drilling through a layer with higher reservoir pressure. For well control reasons, the highest formation-pressure layer dictates the mud weight required to drill the rest of the lateral. This leads to drilling with higher overbalance across low-pressure layers, hence sliding problems and stuck pipe incidents. There is high uncertainty in the thickness and dip of the reservoir layers, and placing a lateral in the selective Khuff-C layer is geologically challenging. Uncertainty increases whenever the well is drilled on the flank. These wells involved extensive geosteering, causing a tortuous well path that leads to sliding problems and higher torques. Figure 10 shows actual torque and tripping loads for an 8 3/8-in. horizontal section drilled by conventional motor BHA. Extensive geosteering coupled with tortuosity caused by slide/rotary drilling led to higher friction factors. The friction factors in casing and open hole were 0.38 and 0.49 respectively when a conventional motor was used. Further, the well was planned to be drilled to 19,300 ft measured depth but it had to be called early TD at 17,224 ft owing to rotary torque reaching the top limit of 26,000 lb. The well was drilled from 12,496 ft to 17,224 ft with an average ROP of 16.2 ft/hr. The RSS was introduced earlier with an objective of overcoming sliding  problems and drilling a smoother wellbore. Wells were successfully drilled to planned target depth using RSS when it was not possible to drill ahead using conventional motor technology owing to inability to slide. However, there was no significant improvement in penetration rate. Running RSS alone led to high stick/slip (Figure 11) requiring adjustment in surface  parameters affecting drilling performance. The 6.75-in. and 4.75-in. PRSS were introduced in 8 3/8-in. and 5 7/8-in. sections respectively with the objective of improving ROP, drilling smoother borehole, and improving log quality. Figure 12 shows a comparison of a textured image of the borehole drilled with PRSS and a conventional motor. The image on the left is the section drilled with the PRSS and the image on the right is of the section drilled with the motor. It can clearly be concluded that the section of the hole drilled with the mud motor is enlarged and has a high degree of rugosity, whereas PRSS drilled a smoother borehole. Additionally, smoother boreholes helped improve the quality of petrophysical and geological logging information. Figure 13 shows a comparison of the density image data with conventional motor and PRSS. The image on the left is the image gathered while drilling with a motor and the image on the right is the one gathered from the data while drilling with PRSS. There is a clear demarcation between the two. Density image quality is better with a PRSS run and is truly representative of changes in lithology and formation dip. Quadrant densities with the motor run were affected by borehole rugosity. From PRSS, these were true representations of formation heterogeneity around the borehole and were successfully used for formation evaluation and well placement/geosteering. The smoother borehole drilled with PRSS also helped in reducing torque and drag. Figure 14

4

SPE 115491

shows torque-and-drag graphs for an 8 3/8-in. horizontal section drilled by the 6.75-in. PRSS. The friction factor in the cased hole and openhole sections were reduced to 0.2 and 0.30 respectively. This helped in successfully drilling the lateral to 19,110 ft measured depth with an average ROP of 33.6 ft/hr. Higher rotary speeds at the bit and slower drillstring RPM helped in reducing the vibrations in the drillstring, hence improving the penetration rate. As a result, we have been able to deliver ROP improvement of 74% in 8 3/8-in. laterals (Figure 15) and likewise ROP improvement of 192% (Figure 16) over average motor ROP in the 5 7/8-in. section.

Conclusions: Application of a PRSS saved 77.6, 101.5, and 14.8 days in 12-in., 8 3/8-in., and 5 7/8-in. sections respectively. The integrated  power section played a key role in improving penetration rate and mitigating stick/slip so that all available energy was used for drilling optimally. In addition to tangible time savings, it offered benefits such as reduced tortuosity, better hole cleaning, and improved LWD log quality. Elimination of sliding enabled the use of relatively aggressive PDC bits, which were otherwise being used for performance vertical drilling only. There had been situations when wells had to be called early TD owing to high torque and the inability of the conventional BHA to slide. Application of PRSS led to successfully drilling the well to planned target depth without any problems. As mentioned earlier, the system was used successfully in different fields in 12-in., 8 3/8-in. and 5 7/8-in. hole sections. Utilization of a PRSS in deep gas drilling helped save 194 rig days. Figure 17 shows rig day savings in different hole sections. The system discussed in this paper has set new standards in the industry and has brought a step change in drilling  performance in deep gas drilling in Saudi Arabia.

References G. C. Downton and D Carrington, “Rotary Steerable Drilling System for 6-in Hole.” – SPE-79922 Stuart Schaaf, Demos Pafitis, Eric Guichemerre, “Application of a Point the Bit Rotary Steerable System in Directional Drilling Prototype.” – SPE-62519

SPE 115491

5

Figure 1: Stratigraphy

Figure 2: Casing Design K2 vs K1

6

SPE 115491

Vertical Section View

Plan View

Figure 3: Plan and Vertical Section View of K2 Design (Dual Lateral)

SPE 115491

7

Figure 4: Push-the-Bit Rotary Steerable System

Figure 5: Point-the-Bit Rotary Steerable System

Figure 6: Powered Rotary Steerable System

8

SPE 115491

Figure 7: MWD Stationary Inclination versus Continuous Inclination in Well Drilled with Conventional Motor and Powered Rotary Steerable System

SPE 115491

9

Figure 8: Performance Improvement in 12-in. Build Section

Figure 9: Performance Improvement in 8 3/8-in. Build Section

10

SPE 115491

Figure-10: Torque and Tripping Loads for 8 3/8-in. Horizontal Section Drilled by Conventional Motor BHA. Friction Factor in Casing 0.38, Open Hole 0.49

Pick up, Slack off & Rotating weight in 8 3/8" Section drilled by Motor

HookLoad (kl-bs) 200

220

240

260

280

300

320

340

360

380

400

420

440

460

480

500

520

540 12300

9 5/8" Casing shoe at 11510. ft MD  Theo. PU W eight CSG 0.25, OPH 0.35 FF  Theo. PU W eight CSG 0.30, OPH 0.40 FF  Theo. PU W eight CSG 0.35, OPH 0.45 FF  Theo. PU W eight CSG 0.40, OPH 0.50 FF  Theo. PU W eight CSG 0.45, OPH 0.55 FF Theo. SO Weight CSG 0.25, OPH 0.35 FF Theo. SO Weight CSG 0.30, OPH 0.40 FF  Theo. SO Weight CSG 0.35, OPH 0.45 FF  Theo. SO Weight CSG 0.40, OPH 0.50 FF  Theo. SO Weight CSG 0.45, OPH 0.55 FF  Theo. Rot Weight

12800

13300

13800

 Actual ROT Weight  Actual PU

14300

 Actual SO Weight

14800 8 3/8" Section Block Weight = 45 (1000 Ibf) Mud Weight = 11.1pcf 15300

15800

16300

16800

17300

   )    t    f    (    h    t   p   e    D    d   e   r   u   s   a   e    M

SPE 115491

11

Figure-11: Powered Rotary Steerable System Helped in Reducing Stick/Slip

12

SPE 115491

Section Drilled with Motor

Section Drilled with PRSS

Nominal Bit size

Figure-12: MWD Stationary Inclination versus Continuous Inclination in Well Drilled with Conventional Motor and Powered Rotary Steerable System

SPE 115491

13

Drilled with Motor

Drilled with PRSS

2D Image

2D Image Quadrant Density

Average Density

Quadrant Density

Average Density

Figure 13: Density Image Data with Conventional Motor and 6.75-in. Powered Rotary Steerable System

14

SPE 115491

Figure 14: Torque and Tripping Loads for 8 3/8-in. Horizontal Section Drilled by 6.75-in. Powered Rotary Steerable System. Friction Factor in Casing 0.20, Open Hole 0.30

Pick up, Slack off & Rotating weight in 8 3/8" Section drilled by PRSS

HookLoad (klbs) 210

230

250

270

290

310

330

350

370

390

410 14600

9 5/8" Casing shoe at 14000. ft MD

 Theo. PU Weight CSG 0.15, OPH 0.20 FF  Theo. PU Weight CSG 0.20, OPH 0.25 FF  Theo. PU Weight CSG 0.20, OPH 0.3 FF  Theo. PU Weight CSG 0.25, OPH 0.35 FF  Theo. PU Weight CSG 0.30, OPH 0.40 FF Theo. SO Weight CSG 0.15, OPH 0.20 FF Theo. SO Weight CSG 0.20, OPH 0.25 FF  Theo. SO Weight CSG 0.20, OPH 0.30 FF  Theo. SO Weight CSG 0.25, OPH 0.35 FF  Theo. SO Weight CSG 0.30, OPH 0.4 FF

15100

15600

16100

 Theo. Rot Weight

16600  Actual ROT Weight  Actual PU  Actual SO Weight

17100

8 3/8" Section Block Weight = 45 klbs Mud Weight = 11.1 pcf  17600

18100

18600

19100

   )    t    f    (

   h    t   p   e    D    d   e   r   u   s   a   e    M

SPE 115491

15

Figure 15: Performance Improvement in 8 3/8” Lateral Section

Figure 16: Performance Improvement in 5 7/8-in. Lateral Section

16

SPE 115491

Figure 17: Rig Day Saving Due to Powered Rotary Steerable System Utilization