SPE Members Abstract Extended-life polymer gel plugs have met rigorous requirements as a sealant for restoring a barrier in the tubing annulus when tubing-annulus leakage has occurred. These requirements include urgency to restore annulus integrity dynamic placement in unbalanced well conditions, and ease of removal without milling the tubing. Very attractive economic benefits have resulted. Introduction Casing deformation resulting from reservoir compaction has caused 45 well workovers, starting in 1981, in three of the Greater Ekofisk Area fields. The Ekofisk, Eldfisk, and West Ekofisk fields are located in the southern portion of the Norwegian sector of the North Sea (Fig. 1). Compaction of up to 30 ft has deformed casing both in the chalk reservoirs and in the overburden formations. Deformation in the overburden leads to tubing damage and leakage causing the well to be plugged and scheduled for a sidetrack workover when a rig is available. This paper describes experiences with extended life polymer gel (ELPG) plugs to seal leaking tubing annuli, thus allowing the wells to continue to produce until workover is practical. Gel characteristics determined by laboratory testing are presented, the placement techniques in wells are described, and field experience is given with regard to plug life and removal for well workovers. The present well failure rate of five to eight wells per year along with the shut-in time of 6 months or more before a rig is available has significant economic consequences. The demanding requirements for an annulus sealing method include urgency to restore the annulus barrier, dynamic placement in unbalanced well conditions, effective sealing of the annular area, and obtaining a plug which can be easily removed without milling. Gel plugs have proven to be a reliable and cost effective sealing system for this application. CASING DEFORMATION Casing deformation caused by reservoir compaction (Fig. 2) is the dominant mechanism for well failure at Greater Ekofisk. As the originally overpressured, high-porosity chalk formations are being depleted, reservoir compaction results. P. 201^
Using fiber-optic coiled tubing (CT) to perform distributive temperature sensing (DTS) and distributed acoustic sensing (DAS) logging to identify multiple points of leak detection is discussed using a case study. The case study provides an in-depth review of the operation performed on a land-based horizontal well where a single well intervention run successfully logged the entire wellbore, resulting in the identification of multiple depths where casing had failed during an initial hydraulic fracture stimulation attempt. Additionally, a brief review of fiber-optic logging techniques and equipment is described.
Offshore drilling operations that encounter shallow gas formations must consider the potential annular gas flow that may occur following primary cementing. Many specialized cements and procedures have been developed to combat gas migration, but the complexities of gas migration control still challenge operators worldwide. In offshore shallow environments, additional complications can arise with the presence of weak formations and cold temperatures. In such conditions, lightweight lead cements are employed to avoid fracturing the wellbore. Although lead cements are often viewed simply as "filler" materials, shallow gas control slurries must far exceed that role as they become the mechanism to help isolate the movement of gas up the annulus. Presented in this paper is a review of the properties of gas control cementing systems specifically related to lightweight lead slurries. The importance of fluid loss control, rapid gelation, and compressive strength at the time of drillout is stressed. Silica fume cement and newer cementing additives such as colloidal silica and small particle cement are highlighted as means of helping prevent shallow gas migration. Several offshore cementing operations are documented which confirm the success of applying the prescribed designs and methods.
A case study is presented on increasing operational efficiencies using fiber optic-equipped coiled tubing to perform distributed temperature sensing (DTS) and distributed acoustic sensing (DAS) in conjunction with millout operations. In unconventionals with plug-and-perf or sliding-sleeve completions, hydraulic workover or coiled tubing is deployed to millout and clean the wellbore to total depth (TD) before the well can be put on production. Traditionally, the millout and cleanout process is a standalone operation. In the event a diagnostic service is performed on the well, a workover rig, coiled tubing unit, or wireline would be deployed in a second intervention after the initial millout is performed. This method presents a challenge to operators who want to bring wells online in a timely and economical manner. By combining the millout and diagnostic cababilities into a single operation, operational efficiencies were significantly increased for the operator. Operators were able to minimize exposure to in-well operations and reduce the number of interventions necessary to bring a single well online. This resulted in a reduction of well shut-in time and faster data turnaround time on diagnostic evaluation. Simultaneous milling and diagnostic services were completed on 31 wells throughout 2018. Plug/Sleeve/Sand millouts were performed to well TD with a fiber-optic capable coil-tubing unit. Then the same work string was used to gather diagnostic data on the entire completion interval during the same run. These diagnostic data were collected and provided to the operator in an effort to better understand the completion design and hydraulic fracture placement. The operational efficiency gained by deploying diagnostic services in conjunction with the millout services lowered the operator's operation costs by USD 100,000 and operations time by 36 hr on average.
The objective of this paper is to clearly outline the basic principles and techniques required to successfully perform well intervention in wells with low-pressure formations, thief zones, and/or depleted reservoirs—specifically, horizontal or highly deviated wells. The paper aims to review the considerations and provide an example of reliable execution in its most basic form, including simplified calculations designed to be used in conjunction with advanced modeling software available in the industry. Coiled-tubing intervention in lateral wells with fluid-loss potential is inherently high risk. The risk of poor solid suspension or loss of fluid circulation results from the inability to avoid fluid loss and causes costly job failures, lost workstrings or equipment, or reduced well production. For land-based operations in the United States, coiled tubing has been reliably and successfully deployed in depleted and low-reservoir-pressure wells that were unable to support a hydrocarbon or water column to surface. These jobs include sand cleanouts, re-fracture preparation cleanouts, and underbalance millouts in extended laterals. Commingled nitrogen and water-based systems were used to reduce hydrostatic pressures exerted on the reservoir and, thereby, allowed for successful continued circulation. The fluid system was adapted to each well intervention to consider formation type, reservoir fluid composition, job requirements, BHA requirements and limitations, chemical compatibility, cutting suspension potential, and foam integrity. When combined with real-time monitoring of, and response to, well conditions, the occurrence of job failure was greatly reduced.
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