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.

The Mauddud Formation in the Greater Burgan field is a thin carbonate reservoir with very low permeability but with moderate to good porosity and variable fracture density. The formation could be divided into three distinctive layers, based on the structural and digenetic complexities. Production in Mauddud wells show rapid decline due to tight rock matrix (low permeability). This decline is associated with an increase in Gas-Oil Ratio (GOR) as reservoir pressure falls below the bubble point pressure near the wellbore. Horizontal wells were drilled in an attempt to develop the Mauddud Formation targeting sweet zone. Most of the wells were located in a relative structural high on the up-thrown blocks of the North and Eastern flank of the Greater Burgan field that had the highest likelihood of intersecting fractures. They are mostly adjoining the major faults. There are now around 40 wells drilled in Mauddud including horizontal and multilaterals, most of which became non-producers due to above reasons. A study has been carried out to evaluate opportunities to revive these wells through available and new technologies in the industry. A detailed geological study incorporating all the available data was carried out initially. Wells were screened for stimulation by using various proven new technologies. Acid Frac, Stage Frac, near well bore SurgiFrac and Matrix Acid techniques have been applied with varying results. Advanced placement technique like distributed temperature profiling was used in some of the jobs. This paper presents the details of the application of the above mentioned technologies, to the candidate wells and discusses the results. The success of some of these technologies opened up new opportunities for a new beginning to revive the closed wells completed in Mauddud Formation.

Kuwait Oil Company operates several brown fields that produce more than 2M bbl\day. With reservoir being depleted and drop in reservoir pressure 60% of the KOC field dependent on utilizing artificial lift methods to produce their wells. This shifted the main workover activities to be ESP installations and changeouts. An ESP changeout takes in-between 30-45 days of operations, where wells will be shutdown waiting on workover rig. KOC pioneered a novel workover solution to quickly restore production and minimize deferred oil in their brown fields. The technique utilizes High tension Wireline units to deploy a slim type ESP set inside production tubing with 8 hours only without the need of a work over rig. The rigless wireline ESP deployed pump system will play a pivotal role in how KOC will perform Workover operations in the future. Wells are placed back online with capacity of producing up to 1000 bbl\day. A detailed candidate selection is required pre every job to review the well barriers and confirm the capability of the pump to perform the operation. Proactive well management and surveillance require digital solutions with data seamless flow from downhole to the hands of engineers, edge computing enable operators to proactively manage their assets, detect and manage potential issues, and ultimately improve well performance. Additionally, this approach reduces the dependency of domain experts to frequently analyze data enabling the capability to act in real time. Once the Workover becomes available, the pump is retrieved, and the well is ready for workover eliminating any deferred production from the time ESP fails till workover is available. This paper will discuss the first deployment of this pump in Kuwait, which marks the longest deployment of such technologies globally. The first of deploying the pump is to perform well simulation to ensure the pump will be capable of lifting the well. This is followed by a tubing integrity check to ensure that the well integrity is in a good condition and no fluid re-circulation is expected during production. The operations require setting a special packer inside the tubing to create a seat for the pump and the full Wireline stack pressure control equipment is rigged up on the wellhead and the pump is connected to the TEC cable mounted on the wireline unit drum. The complete deployment of the pump on Wireline unit takes between 8-10 hrs and the whole operation is done in less than 24 hours. The first deployment of the new pump managed to restore a production of 1000 bbl of liquid in dead well that is waiting for workover to install an ESP. For the period of 30 days, the pump operated flawlessly and pumped 30,000 bbl of liquid to surface. A portable GOR conducted and observed that the WC of the well was around 60%. Kuwait Oil Company saved around 18,000 of deferred production while waiting for rig to be available. The results allowed KOC to optimize the utilization of the assigned rig by performing other workover operations while the well was kept on producing. The first installation paved the road for a long-term deployment of these pumps in Kuwait fields. In addition, the whole workover operations strategy will be revisited by having such a rigless capability.

The Passive Inflow Control Device enhances the well productivity and recovery by removing Heel to Toe effect in a homogeneous reservoir and allowing production optimization along the entire horizontal section in case of heterogeneous reservoir. But these ICDs have their own limitations in controlling the high water producing zones in horizontal wells. The introduction of Sliding Sleeve Technology in horizontal wells has added a greater value to ICDs by further controlling water production from undesired zones. The new Advanced Inflow Control Device with sliding sleeve approach is built upon the usefulness of sliding sleeve technology in horizontal wells. This rigless technology can be used to maximize oil production from horizontal wells, save huge rig workover cost and extend the economic life. This paper describes a case study in Greater Burgan Field showing the challenges encountered while drilling the horizontal well and benefits associated with the integration of the passive Inflow Control Devices (ICD) with Sliding Sleeves in complex horizontal wells. After the well was put on production, Production Logging Tool (PLT) was run to identify the high water producing compartments and accordingly plan was made to close these ICDs by mechanically shifting the sliding sleeves. Pre and post DTS survey clearly confirmed the successful closure of high water producing ICDs. Several flow tests were done before and after shifting the sliding sleeves to monitor the reduction in water cut. A complete case study is presented to permit the readers to know the benefits of using sliding sleeves along with ICDs in horizontal wells and thus improve the hydrocarbon recovery. Leveraged knowledge from this pilot has provided an insight into the capabilities of sliding sleeve type of ICDs.

With the continuous production from Kuwait oil reservoirs, a clear decline in reservoir pressure is observed. Subsequently, the demand for artificial lift is increasing to sustain production. Maintenance of those wells requires frequent interventions and continuous presence of workover rigs, which affects overall cost of production. Change of the electrical submersible pump (ESP) deployment method represents one of the cost reduction initiatives undertaken by the operator to reduce well intervention time and improve asset utilization. To minimize deferred production generated by the ESP replacement operation, a novel rigless approach leveraging coiled tubing (CT) was introduced in southeast and west Kuwait. It reduces operating costs and eliminates disruptions to operations by enabling rigless retrieval and redeployment of a standard ESP assembly. To evaluate the efficiency of using CT as rigless ESP retrieval and conveyance method, two candidate wells were selected to recover and redeploy a 108-ft-long ESP system. The intervention methodology relied on CT equipped with optical line and real-time downhole telemetry, a high-pressure rotary jetting tool, and a specific ESP deployment assembly. The retrieval and redeployment of the ESP was executed in a single rigless intervention, averaging less than 72 hours of operational time per well. This represents five times improvement over the standard practice using a workover rig. The intervention was executed in several stages, according to the well intervention program, and included tubing drift and cleanout runs, retrieval, inspection, and redress of the ESP assembly, followed by its successful redeployment. The high-pressure rotary jetting tool was used to condition the wellbore tubulars across the fishing area, while downhole real-time data enabled by the 1 3/4-in. CT equipped with optical telemetry were instrumental to eliminate uncertainties associated with changing downhole conditions. The casing collar locator allowed live depth control and ensured accurate positioning of the ESP. Its careful retrieval and redeployment were monitored thanks to the downhole axial force readings, which allowed controlling the weight applied on the fishing assembly. Internal and external downhole pressure data, along with downhole temperature, helped in controlling actuation and use of the high-pressure rotary jetting nozzle under nominal conditions for maximum efficiency. This enhanced rigless ESP replacement technique, made possible by the joint use of CT and real-time downhole measurements, was confirmed as a robust workover method for retrieval and redeployment of rigless ESPs in southeast and west Kuwait. The experience gained in the first two wells brings a new level of confidence to Kuwait operators about this technique, which certainly can be expanded to other fields in the Middle East and elsewhere.