English Edition (6 MB pdf) - Saudi Aramco

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Wellbore cleanup trips had been made in the early MSS deployments for Saudi Aramco. The likelihood that foreign objects in the wellbore were causing the deployment issues of the MSSs in Saudi Aramco wells was considered low. Ledges Wellbores are typically drilled with a drill bit then reamed with a watermelon-type mill. Drill bits can “deflect” when encountering harder formations or after making connections. This deflection can result in “steps” in the wellbore, which are easy for the bit and watermelon mill to negotiate, but difficult for the much stiffer liner pipe and tools, Figs. 3 and 4. A completion assembly is normally much stiffer than a drilling assembly, and typically contains tools with a larger outside diameter (OD). Ledges are also more common where the well is drilled in the minimum in-situ stress direction crossing several fracture planes or faults. Ledges can occur in areas where the fracture planes are crossed resulting in minor break outs of the formation face. In the case of the early wells drilled for the MSSs in Saudi Aramco, the wells were drilled in the maximum in-situ stress (i.e., parallel to the fracture plane). This ledge phenomenon was recognized when MSSs were first deployed and was addressed early in the history of running these systems. A gauge/reamer assembly was designed to simulate the larger OD and stiffer components of the MSS, Figs. 5a and 5b. The OD of the gauge/reamer is larger than the OD of the liner components but smaller than the inside diameter (ID) of the wellbore. The gauge/reamer bottom-hole assembly (BHA) is designed to be very stiff and before running the MSS, sliding this BHA into the wellbore is first attempted. If tight spots are encountered, then the drillpipe is rotated and reciprocated until the BHA is able to slide easily through the section. The intention is not to make the hole large, only to enable passage of the MSS liner. The gauge/reamer assembly was run on the initial MSS deployment for Saudi Aramco. No significant tight spots were encountered during this gauge/reamer trip. The likelihood that the incomplete deployment of the MSS was caused by ledges was considered low. Nevertheless, to ensure the wellbores in subsequent Saudi Aramco wells are free of ledges, doglegs or any other type of obstruction, the reamer BHA was made up with two reamers separated by a drill collar or joint of heavy weight drillpipe, Figs. 5a and 5b. By making this reamer assembly as stiff as possible, any potential problem areas are identified and resolved before the liner is deployed. Dogleg Severity (DLS) Saudi Aramco has used geosteering to move the wellbore towards “sweet” spots (i.e., those containing gas) identified by the “look ahead” logging while drilling (LWD) technology. If this technology is applied too often while drilling a well, and if the moves are too abrupt, the resulting wellbore can have multiple undulations. The deployment of any kind of liner into such tortuous wellbores can be very problematic. The first MSS deployed for a Saudi Aramco deep gas was into a well that had been geosteered. The DLS of this well was not very high, but this was considered as a most likely cause for the liner not reaching total depth (TD). To increase the potential for successful deployment, all subsequent MSS candidate wells for Saudi Aramco were drilled with rotary steering. The DLS of the rotary steered wells has been negligible. The second deployment of an MSS for Saudi Aramco deep gas occurred in August 2007. All the precautions to avoid mechanical sticking were implemented for this well. The open hole section for this well was originally intended to be approximately 4,000 ft, but upon completion of drilling the logs, it showed no hydrocarbons in the lower half of the well. The MSS was successfully deployed for the upper half of the well and the production results were once again noteworthy. While attempting to deploy an MSS into a third deep gas well in 2008, the assembly became stuck with approximately half of the liner into the open hole. There was much discussion about where the assembly was stuck and the cause. Pipe stretch calculations were conducted and it was determined that the stuck point was near the toe of the assembly. Comparison with drilling records for that well revealed that the drilling assembly had been stuck on at least three occasions at almost the same point while drilling the well. Examination of log data revealed that the toe of the MSS was across a low-pressure zone. It was an ideal set of conditions for differential sticking. DIFFERENTIAL STICKING Figs. 5a and 5b. Gauge/reamer tool used to locate and smooth out ledges in the wellbore. According to the Schlumberger Oil Field Glossary 8 , the definition of differential sticking is: A condition whereby the drilling or completion assembly cannot be moved (rotated or 36 SUMMER 2010 SAUDI ARAMCO JOURNAL OF TECHNOLOGY
eciprocated) along the axis of the wellbore, Fig. 6. For example, the completion string can get stuck in filter cake that was previously deposited on a permeable zone. Differential sticking typically occurs when high contact forces caused by low reservoir pressures, high wellbore pressures, or both, are exerted over a sufficiently large area of the downhole assembly. The pipe is held in the cake by a difference in pressures between the hydrostatic pressure of the mud and the pore pressure in the permeable zone. A relatively low-differential pressure (delta p) applied over a large working area can be just as effective in sticking the pipe as can a high-differential pressure applied over a small area. The force required to pull the pipe free can exceed the strength of the pipe. Mitigation of Differential Sticking with Centralizers With the knowledge that differential sticking was the most likely cause of deployment issues for the MSS, the task was to determine how to overcome these challenges. The most readily available tool to combat differential sticking is centralization of the pipe so that it stands off the wellbore. Although it is widely recognized that centralized pipe is much less prone to differential sticking, many operations personnel strongly oppose the use of centralizers because of the increased risk of mechanical sticking. They cite occasions where they have attempted to run centralized liners, but could not get them to the bottom. In these cases, they pulled the liners back to surface, removed the centralizers, and then were able to force the liner to TD. It was immediately realized that the ledge phenomenon that had been identified early in the deployment of MSS was possibly the same issue that had caused the problems with deployment of centralized liners. If so, the gauge/reamer tool that had been successfully used to address the mechanical sticking issues for early MSS could also solve the problem with mechanical sticking when using centralizers. It was also noted that the centralizers had not been run in both previous cases where the MSSs had become stuck. Therefore, the lack of centralization was considered to be the most significant factor contributing to the MSS becoming stuck. Other Steps Taken to Reduce Sticking Potential Several other steps were taken to improve the chances for successful deployment of MSS assemblies. First, it was noted that on the wells where the MSSs had become stuck, that the 9 5 ⁄8” casing had been set above the lower-pressure zones, Fig. 7. The MSSs had to be conveyed through these zones before reaching the target depth. To mitigate this issue, candidate wells were selected where the open hole would not go through zones with widely ranging formation pressures, thereby minimizing the potential for differential sticking, Fig. 8. Second, the mud weights in some previous MSS wells had been excessively high, up to 2,000 psi overbalanced compared to the pore pressures in the lower pressurized zones, resulting in differential sticking conditions. Because of the variation in formation pressures, when the mud weight was increased to provide adequate hydrostatic pressure for the high-pressure zone, Fig. 7 – Zone 4), the low-pressure zones, Fig. 7 – Zones 1 and 2, were over pressured, creating conditions for differential sticking. The mud quality itself is also influential in the probability for differential sticking. A thick, solids laden mud cake is more likely to cause sticking issues than a thin Fig. 7. Differential sticking of completion string due to open hole going through low-pressure zones. Fig. 6. Differential sticking as viewed in a cross-section of the wellbore 8 . Fig. 8. Candidate wellbores where the open hole does not go through low-pressure zones. SAUDI ARAMCO JOURNAL OF TECHNOLOGY SUMMER 2010 37
Page 3 and 4: Summer 2010 THE SAUDI ARAMCO JOURNA
Page 5 and 6: 24” CSG at 365 ft EPC 178,00#, X4
Page 7 and 8: Stage Depth (ft) Direction Fluid Vo
Page 9 and 10: The injectivity test, which can be
Page 11 and 12: REFERENCES 1. Moore, N.B.A., Kruege
Page 13 and 14: Next Generation Technologies for Un
Page 15 and 16: to 60 ft/hour with the hydraulic or
Page 17 and 18: improving drilling performance. The
Page 19 and 20: Robotics for Horizontal Image Acqui
Page 21 and 22: mud cap to TD at 10,100 ft. Open ho
Page 23 and 24: unning the operations by convention
Page 25 and 26: Stimulating Khuff Gas Wells with Sm
Page 27 and 28: Fig. 2. ACTive fiber optics. DESCRI
Page 29 and 30: • Treatment acid: 26% HCl acid (1
Page 31 and 32: 25 20 15 10 5 0 Well 1 Well 2 Produ
Page 33 and 34: Fig. A3. Post flush temperature res
Page 35 and 36: Wassim Kharrat has been working wit
Page 37: SAUDI ARAMCO EXPERIENCE WITH INCOMP
Page 41 and 42: then either continue running the as
Page 43 and 44: Application of Hydrajetting Technol
Page 45 and 46: Amount of Proppant (lb) 135,600 lb
Page 47 and 48: Development and Optimization of 12
Page 49 and 50: Vertical Section View 10,000 Well A
Page 51 and 52: Fig. 8. Powered rotary steerable sy
Page 53 and 54: needed a fit-for-purpose bit design
Page 55 and 56: laboratory and previous field tests
Page 57 and 58: performances in the 12” direction
Page 59 and 60: Jaywant Verma is a Drilling Enginee
Page 61 and 62: favorable economics of drilling sma
Page 63 and 64: orehole fluids. This tool can be co
Page 65 and 66: Fig. 6. Plot of a sidetracked (Well
Page 67 and 68: BIOGRAPHIES Izuchukwu “Izu” Ari
Page 70: GUIDELINES FOR SUBMITTING AN ARTICL

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