Leak in well bore tubulars & packers leads to communication between tubing/casing or Short/Long strings thus causing enormous production losses in Oil & Gas industry. Moreover, it can cause cross flow between different reservoirs. Sometimes leak may lead to charging of shallow formations thus posing a big threat to well integrity. The detection of the source of communication presents a big challenge to the industry. Knowing the precise location of a leak helps in designing an effective remedial action thus reducing downtime and repair costs. When a fluid leaks, it moves from the high-pressure side through the leak point to the low-pressure side, where it expands rapidly and produces a turbulent flow creating noise and temperature changes. Conventional noise and temperature tools are not capable of detecting the leak point with high confidence. However, the new generation Noise and Temperature logging tools have been able to locate such leaks precisely. This paper presents successful use of Spectral Noise Logging in combination with High Precision Temperature logging (HPT-SNL) in a dual-completion oil well in Kuwait Oil Company for identifying communication between the long and the short tubing strings. The acoustic tool contains a new-generation, high-sensitivity hydrophone – a piezo crystal element that records noise in a wide frequency range (0.1 – 60 kHz). Temperature tool utilizes a super-sensitive platinum sensor with a response time of less than one second. Leak was detected at the bottom blast joint of the long string that was causing water entry into the short string thus killing the well. The technology can be used in critical oil and gas wells to identify tubing and casing leaks and address well integrity issues. It can also be used in water injection wells to identify the zones of water intake.

This pspar was selected for presantati~by an SPE Prcgram Committee following review of mform.stien contained in an abatract submitted by the author(s). Contents of the paper, as presented, have not bean reviewed by the Sodety @f Petroleum Engineers and are subject to wmaction by the auther(s). The material, as presented, dees not necessarily reflect any p.$cion ef the s.cciefy @f Pelrdeum Enginsara, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the %ciely of Petroleum Engineers. EWtrordc reproductico, dtstrtbutlon, or storage of any part of this papar for ccfnmerdal purpaaes Wthcut the v.titten cement of the Sceiety of Petroleum Engineers is pr&lbitsd. Permlaalen to reproduce in pffnt Is restricted to an abstract of not more than 300 words: illustrabcms may nOt be copied,The abstract must contain conspicuous acknowledgment of Mere and by whom the papar was presented. Write Librarian, SPE, P.0, eos 833836, FSichardsen, TX 7S383-3836, U.S.A., fax 01-972-952-9435. AbstractTraditionally, formations with permeabilities greater than 103 md are not considered as candidates for hydraulic fracturing sdrmdation.This perception is based on the idea that the increased effective wellbore radius is not needed in high permeability formations.This paper proposes that, if properly designed and pefiormed, hydraulic fracturing benefits extend beyond the increased effective wellbore radius. These benefits include; emmding the wellbore beyond the drilling damaged zone eliminating the need for further stimulation, increased productivity in wells limited by drawdown, and increased productivity with a higher flowing bottom-hole pressure which hinders water encroachment in edge watex drive systems.This work is based on field data and computer simulations from the Gulf of Mexico area. These high permeability wells were hydraulically fi-actured and gravel packed using the FracPac system. Fracture design and operational implementation strategy, including post completion flow rate and period, will be presented in this paper.Moreover, NODALTM analysis, well test, and production data will be presented.Well test and production data have shown that hydraulic fractures associated with the sand control system, have significantly impacted wells' performance and achieved the desired objectives.

Well integrity is one of the critical concern during the life cycle of wells and impose an enormous challenge to the oil & gas industry. External and/or Internal corrosion of tubing & casing is one of the main reasons of leaks in the wells causing fluid movement from one annulus to other annulus. Complete understanding of the source of pressure communication between different annuli is of prime importance for designing an effective remedial action. Most leaks can worsen with time and therefore, locating and repairing a leak in its early stages is essential otherwise it may sometimes lead to abandonment of the well. Knowing the precise location of a leak prior to executing repair jobs will lead to better planning thus reducing downtime and repair costs. The problem becomes more complicated when the leak diagnosis has to be done using conventional logging techniques without pulling out the tubing string.Presence of competent barriers is a fundamental imperative of well integrity. Imperfect barriers introduce risks that need assessment and management. Few wells go through their operating life cycle without undergoing material degradation and component failures resulting in imperfect barriers. Therefore, use of contingent barriers is necessary to minimize the likelihood of such failures and the resultant impact. This paper describes different types of through tubing logging techniques used by Kuwait Oil Company for identifying tubing-casing leak in an oil well and discusses the interpretation of the results. The paper also discusses the probable reasons for occurrence of the leak, remedial actions taken to arrest the leak and future completion philosophy to avoid such failures in the new wells.

Extended wellbore storage can be mistakenly interpreted as a reservoir response in gas well testing with surface shut-in. This interpretation usually results in false values for permeability, skin and reservoir size and shape. This paper investigates gas cooling effects on pressure transient testing with surface shut-in in gas wells. This study was prompted by the observation, that in gas wells, many of the buildup tests obtained with surface shut-in exhibited complex reservoir model behavior with relatively low skin. These models, such as narrow channels or multiple nearby boundaries, often did not agree with the actual reservoir system thus resulting in incorrect estimations of well and reservoir parameters. This in turn may result in missed opportunities to enhance well productivity and to develop the field further. The results presented in this paper are based on well test simulation and field data from five wells in three different fields offshore Louisiana. This work demonstrates the effect of gas cooling. in combination with gas compression. on the pressure derivative curve. Knowledge of the expected pressure derivative shape. and duration, will improve the design of buildup tests that will allow enough time for the actual reservoir response to be observed. This will result in a reliable reservoir model and correct estimation of permeability and skin factor. Introduction To minimize cost and operational risk, many well tests are performed with a surface shut-in with a bottom-hole pressure measurement, rather than bottom-hole shut-in and pressure measurement. However, a surface shut-in includes many factors that can effect the bottom-hole pressure value. The combined effect of these factors is usually referred to as the wellbore storage effect and period. A surface shut-in allows fluid flow from the tested formation into the wellbore for a long period of time, depending on the permeability and thickness of the formation, and the wellbore volume. Moreover, the multiphase composition of wellbore fluids results in an upward movement of the gas phase relative to the liquid phase. These changes in fluid pressure and temperature, may also result in liquid drop out or evaporation (phase changes). These factors will result in significant changes in the wellbore fluids' compressibility, density, and composition. Lee presented procedures to design well tests including after-flow conditions. He used Agarwal, Al-Hussainy, Ramey type curve empirical fit which predict the end of wellbore storage duration. In terms of equivalent shut-in times, Ate, the duration of after-flow is given by the following equation: Hegeman, Hallford, and Joseph presented a model for analyzing increasing or decreasing wellbore storage. Their model is based on modification and extension of Fair's approach. Fair modified Van Everdingen and Hurst equation by adding a term to account for the pressure change caused by phase redistribution: The changing storage pressure function has the following properties: (2a) (2b) (2c) P. 77^

Well integrity was and continues to be a significant priority for many operating companies around the world. A compromise in well integrity may have direct impacts on production sustainability well life and the environment. Well integrity became an important topic in the last decade after a number of the well blow-outs and oil spills around the world. The new electromagnetic time domain tool (EM) which is presented uses transient or Pulsed Eddy Current (PEC) measurements to perform quantitative evaluation of downhole corrosion in four concentric tubulars individually and to inspect a fifth tubular qualitatively. Case studies are presented that compare results of this instrument with industry-standard single-string evaluation tools such as multi-finger calipers. The novel electromagnetic tool which uses transient or PEC technology comprises three sensors which achieve high-resolution of the inner barrier and high radial depth of investigation for up to five barriers. Each sensor induces coaxial rings of eddy currents in multiple concentric tubulars and measures a time-varying response from the outward-diffusing eddy currents. The full transient responses from multiple sensors are then interpreted to obtain individual tubular thickness profiles. Case studies are presented where electrochemical external corrosion has penetrated inward and has affected the inner most barrier by having through holes which are also verified with another high resolution Multifinger caliper tool. Individual thickness measurement is valuable for proactive well integrity management because electrochemical external corrosion which is the primary corrosion mechanism in these wells causes the outermost casing to fail first and then continues to penetrate inwards. Therefore the new electromagnetic instrument enables early diagnosis of the outer tubulars to identify potential weak zones in the completion string while logging through tubing and eliminating the cost of pulling completions for this purpose. The paper covers the basics of corrosion logging tools and the benefits and drawbacks of running various tools and the advantages of combining several together. Also how the tubing completion like packer setting depths can affect the production casing integrity as well as workover operation impact. New case studies with multi-finger calipers support these conclusions.