A major exploration and production (E&P) company is acquiring a significant number of multiphase production logs a year for reservoir management. It is anticipated that this number will increase, when these deviated and horizontal wells start to produce water. It is more challenging when these wells become dead due to downhole communication between an aquifer and the objective reservoir resulting in excessive downhole water dumping. The strategy, therefore, is to run advanced production logging tools (APLT) integrated with the pulsed neutron logging tool (PNLT) to provide velocity along with holdup maps across the diameter of the borehole from an array of sensors and water velocities inside the wellbore or the annulus, respectively. The combination between APLT and PNLT data provides accurate detection and quantification of water zonal contributions. The aim of the three case examples presented in this paper is to facilitate detecting the leak point and assembling the inflow profiles. The first example is an open hole completion. The logging data showed 1000 bbl of down-flow movements in the tubing-casing annulus (TCA) starting from the shallow aquifer. The second well was completed with an inflow control device (ICD). Water dumping was observed from the leak over the blank pipe down to the screen interval, which is also supported by temperature deflection. The third example is a cased-hole perforated completion. An integrated logging approach yielded reliable results in detecting the water entry interval, and the water entry was identified from the perforated section flowing upward to the casing leak. This detected crossflow in the mentioned examples at shut-in conditions was the reason that the wells were dead. The established integrated logging solution and field examples showed evidence that a leaking interval was suspected to be responsible for high water cut, reducing well performance and killing the wells. The source of water production identified provides the justification for a workover to isolate the water entries, secure the objective reservoir, and revitalize the dead well.

Accumulation of hard scale in the production tubing will not only affect the well accessibility it will also lead to a dramatic decline in production rate and locking the allocated production. Maintaining wells accessibility to wellbore for well intervention operations in order to run logs, water shut-off jobs, well securement operation,…etc. is part of well integrity and performance assurance program. The traditional operation approaches in other areas and reservoirs include isolating the active reservoir prior to operations are not suitable for all cases especially when formation damage is expected to take place. The implementation of underbalance mechanical de-scaling operations using coiled tubing; will lead to restore wells to production faster, regain well productivity and avoids the formation isolation stage. The candidate oil producer; located in Southern Area of Ghawar Field; had accumulations of hard Iron Sulfide scale inside the tubing at different depths. Acid de-scaling operation using bullheading technique utilizing 20% HCL went vain to restore well accessibility and productivity. Hence, the underbalanced coiled tubing de-scaling operation was successfully executed for the first time ever in an oil well in Saudi Arabia. The operation consisted of two CT runs executed in underbalanced conditions, where the first CT run was with milling tool and second CT run was with jetting tool. It is worth to mention that the well is equipped with two different tubing sizes (6,500′ of 4 ½″ & 300′ of 3 ½″ TBG). This variation on the tubing size resulted in operation optimization as will be illustrated on the paper. This paper will illustrate the operation in terms of planning, risk assessment, execution, results and well performance prior and after restoring well accessibility and productivity. Moreover, the paper will highlight the optimization done during the field operation execution after obtaining extra information from the first run using milling tool. This operation has resulted in cost saving of more than $1 MM, 30% production gain and restoration of the well full accessibility.

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Electric submersible pumps (ESPs) are considered to be a very cost effective artificial lift method by industry standards, particularly in water supply wells (WSWs). In four WSWs, ESP performance had experienced a number of premature failures, which resulted in short average run lives of less than 1 ½ years, high operating costs, and unsustainable water supply required for injection pressure support and field development. To ensure that future ESP application in these wells is successful and improve run life, a multidisciplinary team was formed and conducted a comprehensive review to identify the causes of previous ESP failures and recommend methods to improve current practices based on all gathered engineering data; including, dismantle results of pulled ESP units, well and reservoir data, completion strategy, ESP equipment design, commissioning, and data monitoring. The analysis indicated that the failures were primarily the results of corrosion and solids, and lack of close monitoring of ESP performance review, which prevented rectification of the problems in a timely manner. Secondary problems were also identified, such as tight wellhead clearance that damaged wellhead penetrators during installation, failure of tubing internal coating, and insufficient wellbore cleanout before making up ESPs during workovers, etc. This engineering approach has successfully helped to increase confidence in, and reliability of, ESP operations, optimization, sustained field production levels, and reduced capital and operating costs due to improved pump run life. This paper reviews the performance of ESP systems in WSWs and the challenges faced during the past 4 years of operation. Also, it covers installations, commissioning, dismantle inspection failure analysis (DIFA) results, operation philosophy, optimization methodology, average ESP run life, and ESP technical improvements.

Although early corrosion detection may allow preventive maintenance to reduce the risk of environmental damage and surface incidents (explosion, fire, leakage, and related consequences), many of the wells producing today were completed decades ago, when corrosion control and monitoring were not a primary concern. Even with today's technological advances, corrosion cannot be completely prevented, but it can be controlled and minimized through proper planning, monitoring, and maintenance. Middle Eastern operators have experienced varying degrees of casing completion failures in recent years due to common highly corrosive, water-bearing zones across shallow depths. The electromagnetic (EM) pipe inspection tool provides critical monitoring for evaluating casing integrity by locating, identifying, and quantifying damage and corrosion. Failure to address potential corrosion attack can impact well profitability as operators must respond by implementing extensive and potentially expensive restoration methods. Not only does mitigation increase operating expenses, it may force operators to shut-in well production for unplanned periods of time. The immediate aim of the examples presented in this paper is to understand the levels of corrosive damage that are present in the wells; that have serious repercussions on the flow efficiency of completions. This assessment of well integrity investigations is used to identify any extensive corrosion in the outer casing before it penetrates through the inner casings. The provided field examples were logged rigless to establish the condition of multiple pipes. Corrosion intervals were suspected of being responsible for reducing well performance and killing the wells. Casing metal loss (ML) evaluations assisted in identifying which wells need workover attention to avoid excessive loss in production, environmental pollution, repair costs, or accidents.