The highly pressurized intervals coupled with high permeability makes the drilling of the 6-1/8” horizontal hole section particularly challenging in the water injector wells, as mud losses are frequently encountered with differential sticking events. The objective of the workover operations in the objective field is to sidetrack the power water injector from the existing well's motherbore, converting the well in to a dual lateral, which will maintain the reservoir pressure and enhance oil recovery from the oil bearing formation. This variance in formation pressure distribution makes drilling with high mud density systems a challenge, and increases the risk of encountering losses and differential sticking. To overcome the challenges mentioned, the application of MPD technology with the Constant Bottom-Hole Pressure (CBHP) method during the drilling of the 6-1/8” hole section enables utilizing a mud system that is statically below the formation pressure, while keeping the Equivalent Circulating Density (ECD) slightly over the formation pressure and constant at static and dynamic conditions. This objective is achieved by applying surface back pressure using an Automated MPD control choke manifold. As the drilling continued in the lateral, dynamic formation pressure evaluation was performed to assess the changing formation pressure, and to adjust the drilling parameters. This paper will summarize the results of the MPD campaign, compares conventional drilling methods, and highlights the lessons learned from the application of the MPD (CBHP variant), to enhance drilling efficiency, and to mitigate drilling hazards such as losses and differential sticking. The analysis will further enhance the drilling practices of the Power Water Injector wells.
Saudi Arabia wells, onshore and offshore, often require workovers as a result of the corrosive environment to which the downhole equipment is subjected. When the workover jobs required a single hole to be punched in "soft" tubing using traditional methods, high failure rates and inherent delays in mobilizing explosives often severely compromised job economics. This paper presents several case histories in which a new slickline-deployed electro-mechanical tubing punch was used for the first time worldwide. Although the workover requirements in each well were different, and the jobs were conducted in both onshore and offshore environments, all required a single hole to be drilled. The case histories will discuss the advantages provided to the operator through use of the new electro-mechanical tubing punch. These included:100% perforating reliabilityReduced rig time by eliminating mobilization of explosives and other equipment, if failures occurred.Reduced costs, since electro-mechanical perforating is more cost effective than electric-line "soft-shot" methodsApplicability to deployment on slickline, E-line, or coiled tubingSimplicity in use of the electro-mechanical perforatorEnhanced personnel and environmental safety from:Elimination of explosivesUse of alkaline or lithium batteriesUse of mono-conductor lineUse of CTU pressure-switch adapter The new method was 100% successful and resolved the problems experienced with all previously used conventional mechanical perforating methods. Although run in highly corrosive downhole conditions, the perforating tool had 100% success in perforating the "soft" tubing. A thorough follow-up inspection of the tool showed that it had sustained no damage of any kind. An in-depth discussion concerning the electro-mechanical perforator design, its application in Saudi Aramco wells, its operational advantages, and its significant impact on safety and economics will be presented. Introduction Improved well completion methods in Saudi Aramco have enabled safe, efficient, and economical production from oil and gas wells. However, as the fields matured, the wells often required workovers due to several factors, which included:CorrosionReduced productionNeed for conversion to water injector wellsSidetracksIntegrity of the well headIncreased safety concerns. Once a well completion had been designated as a candidate for a workover, the first step for Aramco was to determine a safe, economical procedure to successfully perform the workover.
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 Petroleu m Engineers, its officers, or members. Papers presented at the SPE meetings are subject to publication review by Editorial Comm ittee 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 prohi bited. 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,
The number of old wells completed with uphole packers showed a dramatic increase in casing leaks. The leaks were dumping aquifer fluid directly to the reservoir and vice versa. Many wells experienced this kind of problem. The conventional practice to isolate these kinds of leaks was to run and cement a scab off liner. This resulted in running smaller production strings andconsequently resulted in a dramatically reduction in the production rate and choking wells with high pressure it also limits future remedial workovers of developed future leaks. Saudi Aramco launched a campaign to recover and salvage wells that had been affected by severe casing leaks and hot spot corroded sections. The solid expandable liner was introduced in two sizes of casing. Introduction and usage of this new technical application will have a maximum ID after setting the solid expandable to run the maximum tubing size, to achieve the highest production rate. This paper will describe the successful application of this technology and its comparative advantages, including reduced cost and salvaging wells without the need to sidetrack as had been done before. The paper also includes some review of recently applied casing repair results in several wells. Introduction The number of old wells completed with uphole 7" packers showed a dramatic increase in casing leaks over the years. The leaks were dumping aquifer water directly to the reservoir. The cause of casing leaks is well known to be a combination of very poor to nonexistent primary cement bond around 9–5/8" casing due to severe lost circulation in aquifer during drilling and cementing phase, and very corrosive aquifer water that entered the well bore and corroded through both 9–5/8" and 7" casing, which resulted in an increased water production and a drop in pressure and temperature as demonstrated by SBHP/T surveys (refer to Figure 1 for an illustration of the well selected for the case history). The conventional practice to isolate these kinds of casing leaks was to run and cement a scab off 4–1/2" liner inside 7" production casing or liner. This resulted in running smaller production strings and consequently resulted in a dramatical reduction in the production rate and choking wells with high pressure it also limits future remedial workovers of developed future leaks. Previous case histories In early July 2003 well A with 4–1/2" scab off liner were selected to workover due to severe corrosive aquifer water that again corroded the scab off liner. A 3–1/2" x 4–1/2" expandable casing patch was deployed to seal off the leak and allowed the well put back on production. The expandable casing patch contained solid expandable launcher and hanger joint each with 10 elastomer seals, and spaced out with regular un-expanded 3–1/2" 9.3# N-80 tubing. In early August 2003 well B with 4–1/2" scab off liner were selected for workover due to severe corrosive aquifer water that again corroded the scrab off liner. Another expandable casing patch was utilized to isolate the leak. The top and bottom seal element of the casing patch were designed to be expanded by hydraulically forcing a swedge into the casing overlap to achieve a metal-to-metal seal with pin element that has a slip-like setting mechanism. Because of the very tight clearance between the casing patch and existing 4–1/2" liner, first two attempts to run the patch into the well failed. Two 3–7/8" milling & clean-out runs and a dummy run were performed before finally getting the patch into the well and set across the planned interval.
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