Understanding of fluid movement in and near the wellbore is a crucial factor for effective reservoir management including successful remedial actions and field development planning. One of the key objectives in well surveys is to detect and locate sources of fluid flows behind multiple pipe barriers. The conventional Production Logging Tool (PLT) is run to detect fluid flow and identify the type of fluid under downhole conditions, but is limited to measurements only inside the wellbore. Similarly, other diagnostic techniques, such as cement bond logging, give insight only into the cement integrity and also have limited capabilities to detect cross flows behind casing.Recent developments in temperature and noise logging tools and advanced interpretation techniques have provided higher resolution and sensitivity, enabling the detection of previously undetectable leaks and fluid flow behind casing [1].In the present case, a water zone has been identified in a producing formation with High Precision Temperature (HPT) logging and Spectral Noise Logging (SNL) followed by advanced numerical temperature modelling using the TermoSim software application. SNL identifies flowing zones and differentiates between rock-matrix and fracture flows, and TermoSim then numerically models heat exchange between the wellbore fluid and the surrounding rocks and reservoirs. The resulting model quantifies fluid production from each reservoir unit. Conventional production logging (PLT) locates fluid entry points in the wellbore. The integrated HPT-SNL and PLT logging suite can trace the entire water path from the reservoir into the wellbore. This paper describes water source identification by an HPT-SNL-PLT logging suite deployed in several production wells of a Kuwait oil field. In some of the wells in this field, it has been found that water encroached into the perforations from a watered reservoir below through a channel behind the casing. In other wells, it has been found that cold water breakthrough occurred laterally from nearby water injectors. The exact identification of water sources is a crucial step in any further well remedial work to reduce or eliminate them from oil producing wells. [2]

TX 75083-3836, U.S.A., fax +1-972-952-9435. AbstractThe candidate selection criteria, job design, and improved implementation techniques are important parameters for success in remedial acidization jobs in mature fields.Effective acid diversion across heterogeneous carbonate reservoirs has always been challenging and is even more difficult when stimulating high-water-cut wells. For these types of wells, it is crucial to stimulate the oil-saturated layers rather than the watered-out layers. Bullheading conventional stimulation treatments tend to result in the aqueous-based stimulation fluid being injected into the high-water-saturated zones and away from the high-oil-saturated zones. This often results in a dramatic increase in water productivity and a minimal gain in incremental oil.Recently, several of Dubai Petroleum's offshore oil wells have been treated using 15% hydrochloric acid (HCl) and a viscoelastic-surfactant (VES)-based diverter, resulting in a significant uplift in oil production and a decrease in water cut. The VES diverter permits the oil-saturated zones to be stimulated while minimizing the stimulation impact of the water zones, despite large permeability contrasts. This VES fluid is able to maintain its viscosity when in contact with water and it breaks when in contact with oil. The increase in production with decreasing water cut showed the success of this stimulation diversion technique.This paper describes the candidate selection criteria, design, and implementation of successful carbonate matrix stimulation for high-water-cut wells in mature, water-flooded offshore fields.

Well surveillance is a key component of production optimization cycle of the gas lifted assets. Even though monitoring of the surface well parameters can give some clues on the downhole gas lift system performance of oil wells, Flowing (pressure and temperature) Gradient Surveys (FGS) in most cases is still required to check the health of the downhole gas lift system and troubleshoot the downhole inefficiencies of well gas lift operations. The FGS has certain level of risk as it involves running electronic memory gauges on wireline in the well at flowing conditions. An emerging technology using CO 2 tracer was implemented as a pilot project in eleven gas lifted wells offshore fields Dubai. The results show that this method is very effective for the quick and reliable determination of lift gas entry points in the well. The method can detect the operating lift depth, detect multiple points of injection and even detect tubing leaks.It is true that the downhole pressure and temperature data cannot be obtained from tracer surveys. Nevertheless, the technology can be used as an alternate tool to FGS for the following advantages:1. Minimum equipment hook-up and no need to shut-in or choke the well, means no production loss.2. Less equipment required for the survey, reduces logistics issues especially in offshore locations.3. No wireline tools introduced into the wellbore, eliminate well intervention risk 4. Suitable for wells where a FGS is not possible due to well slugging, significantly deviated or with downhole obstruction. 5. Possible to run tracer survey on 3-4 wells on a day if the wells are located at the same platform. This paper will describe the objectives of the pilot project, the well candidate selection criteria, details of the execution of the survey and interpretation of the results. Practical suggestions for getting the best results from such surveys will also be provided.

Servicing oil and gas wells requires their integrity assessment both during operation and before abandonment. One of the main objectives in well integrity analysis is the location of metal losses in tubing and/or casing caused by corrosion, erosion or other types of pipe damage. The first three metal barriers (normally tubing, production casing and intermediate casing) are of the most interest to the industry. Dual string completions is an additional complication to through-tubing assessment of the second and third barriers.Magnetic Imaging Defectoscope (MID) is an electromagnetic scanning tool that recor ds magnetisation decays induced by high-power electromagnetic pulses. Metal pipe barriers contribute to magnetisation decays at different times depending on their diameters, which makes it possible to differentiate each of them and determine their individual thicknesses. Thickness determination requires the numerical finite-element modelling of each recorded magnetisation decay and iterative fitting of the properties and thickness of every metal barrier to the actual tool readings. A data array can store hundreds of thousands decays, and the data processing optimisation loop therefore requires parallel computing with multi-core processors to process data within a reasonable time frame. The MID hardware and interpretation algorithm have been tested on multiple laboratory stands simulating various downhole multi-barrier completions from 2-7/8Љ up to 13 3/8Љ pipes with artificial defects of various shapes and sizes ranging from 7 mm to 140 mm. This paper presents laboratory results and three selected field cases demonstrating the application of Magnetic Imaging Defectoscopy (MID) in single-string and dual-string completions for thickness evaluation of three barriers independently by a memory through-tubing survey.• Well W-01 with metal losses found at the same depth in the second and third barriers, i.e. 9 5/8Љ and 13 3/8Љ casings • Well W-02 with metal loss found in the second barrier, i.e. 9 5/8Љ casing, in an interval containing two strings. This corrosion has been confirmed by a repeated MID survey after pulling out the completion • Well W-03 with through-hole metal loss found in the second and third barriers, i.e. large-diameter 9 5/8Љ and 13 3/8Љ casings, through a 7Љ liner. This through-hole corrosion has been confirmed independently by High-Precision Temperature Logging and Spectral Noise LoggingThe above metal losses have been located by through-tubing memory surveys in offshore wells that were to be abandoned. The results of the MID surveys were then used to design environmentally safe abandonment procedures.

Majority of the oil and gas fields in the UAE are mature multi-layered carbonates reservoirs, which determines complex vertical heterogeneity and challenging development of those reservoirs. Conventional methodology to measure sublayer pressure is to utilizing different wireline formation testers for any new well or worked over well before commissioning for production. Once well is completed and put on production; usually the average reservoir pressure is measured at the depth of perforation using conventional pressure build up (PBU) or bottomhole closed-in pressure (BHCIP) methods. Using conventional approach it is always difficult to understand which layers are more depleted than others, as only average reservoir pressure is recorded in the wellbore. In case of the heterogeneous multi-layer reservoirs, pressure measured conventionally in the wellbore will be at most of the times, inadequate for sublayer pressure estimation. This paper will describe new methodology of formation pressure evaluation, as well as real case study done in one of the developed offshore carbonate field in the UAE. This method allows measuring each sublayer pressure for producing wells without interruption of the production and properly defining any differential pressure between sublayers. This will help when applying any gas shut-off or water shut-off techniques and prolong the life of producing wells, as well as to help future development of the field. The determined reservoir pressure for each layer has been compared with recent formation pressure tester measurements obtained for this well. The pressure measurement is in the range of 20 psi tolerance. Identification of sublayer reservoir pressure for each producing interval is vital for highly heterogeneous multi-layered reservoirs. This technique is important for gas and water production management when one or several sublayers become depleted. Appropriate action for gas/water shut-off technique can be applied in the right time which will help to manage reservoir efficiently, as well as reducing the cost for conventional pressure measurements and eliminating the loss of production due to shut in time for pressure stabilization during conventional BHCIP or PBU.