Horizontal wells with extended reach drilled in Ghawar field awarded significant improvements, maximizing hydrocarbon production and attained ultimate recoveries. Over the life of those wells, intervention work is necessary to maintain hydrocarbon production by conducting remedial action, such as acid stimulation or water shut off. Necessary data for decision making can be obtained through running surveillance tools, which has proved to be a challenge, considering that these sensors will have to be deployed to total depth (TD). Many well intervention methods have been developed over time to overcome these challenges, such as coiled tubing (CT) and several types of wireline tractors. Wireline tractor technology has evolved to reduce time, cost and improve data quality and increase wellbore coverage. The use of a wireline tractor imposes fewer personnel on the job, much less equipment and less lifting of heavy loads resulting in a smaller footprint impacting the environment. In addition, the fast rig up of the wireline tractor and the running in hole (RIH) and pulling out of hole (POOH) speeds the highly deviated section, and cuts down on operating time. This paper will demonstrate horizontal logging experience gained from trial testing a new deployment solution for the production logging tool (PLT). A new generation of wireline tractors was utilized successfully to deploy the PLT for the first time in the Saudi Arabian field and showed exceptional performance. The tractor proved its capability to overcome different challenging wellbore conditions, such as rugosity, washouts, and high dogleg severity (DLS). Moreover, the tractor was able to efficiently pass through very short sections with large changes in the inclination and azimuth, This paper also covers the whole cycle of candidate selection, job design, execution challenges, post job evaluation, lessons learned and experience gained to optimize similar future jobs.

Maintaining oil production while both water cut and reservoir pressure are changing with time is a challenging task especially for fields equipped with artificial lift systems such as Electrical Submersible Pump (ESP). ESPs have a defined recommended operating range (ROR) that can reduce the flexibility of the system therefore a variable speed drive (VSD) unit is being used to extend the ROR. A surface choke is also another option to adjust the flow rates and control the ESP to operate within its recommended range. However, inefficient use of both options can be detrimental on the life cycle of the production system. High VSD Frequency will increase the motor speed which leads to increased power consumption. Low choke setting causes high hydraulic losses across the choke that can lead to wastes of energy. In oil fields equipped with ESPs, power consumption as well as ESP run life play a significant role in specifying the operation cost and economical life of the field. Therefore, it's essential to optimize the operation conditions of the ESP to optimize the operation conditions of the ESP through minimizing power consumption while maintaining a production rate that fall within the pumps ROR. Utilizing a technique that can quickly provide the best choke and frequency setting is a key to achieving more optimized operation in a dynamic field. This paper will discuss an in-house developed application that can calculate the minimum ESP motor operating frequency and the optimum choke setting point required to maintain the production rate at the minimum power consumption and lower motor speed. With the availability of real-time data from the surface and down-hole equipment, the optimization process was automated by collecting data and modeling surface equipment and ESP. this application is being used to optimize an entire field and the pilot test showed very promising results. A substantial 2000 KVA, which is equivalent to 1600 KWh, was saved by adjusting only 57 wells.

High water production may cause adverse effects on reservoir performance, which can result in production losses. To mitigate this situation it is crucial to utilize water management to reduce water production, optimize oil production, increase the well life and revive dead wells. One feasible option to isolate the water producing zone is a rigless water shut off (WSO) using mechanical isolation. This kind of operation is more challenging for horizontal wells with open hole completion. This paper will demonstrate the impact of a successful WSO on overall performance of a horizontal open hole producer with 4,600 ft of reservoir contact. The well produced with 58.5% water cut and the production log showed that most of the water was coming from the toe of the horizontal section. This paper highlights a mechanical rigless WSO method used to isolate a water contribution zone using a fiber optic telemetry enabled coiled tubing (CT) conveyed inflatable packer capped with cement. Fiber Optic Coil Tubing (FOCT) provides real- time downhole temperature, pressure (inside and outside the CT) and casing collar locator (CCL) measurements used to achieve accurate packer setting depth, confirm packer setting and ensure the suitability of the cement recipe. The complete cycle of candidate selection is addressed.

Electric Submersible Pumps (ESPs) is very popular artificial lift systems to boost oil production now days. Home ofmany ESP installations, with high frequency of change outs per year and with the harsh production environment, a development of ESP technologies to reduce change-out time and improve run life is keep ongoing. These technologies address business challenges timely in a proactive approach. Currently deployed ESPs require a time-consuming rig installation on jointed tubing. With several factors such as: an average run life of three years for ESPs, a rig-based change-out time of up to two weeks offshore, and an uncertainty of when a rig can be scheduled; the need for a more rapid rigless solution is critical for future operations. Majority of the ESP installation are completed as part of tubing completion and deployed by drilling rig which requires high spending to recover the well during ESP replacement. Several types of technologies to deploy ESP rig-lessly were introduced into industry to optimize the retrieval and deployment cost during ESP replacement. Limited success story was recorded and open more thought to overcome the challenges. The first worldwide new reliable cable rigless deployed electrical submersible pumping (ESP) system was successfully installed and put on production. What makes this system unique concept and the first worldwide of its kind are two main components. The first component is the innovative cable hanger design that insures total cable isolation while providing a non-restricted flow through the tubes that are built into the body of the spool. The second component is the specially designed and manufactured CT from selected material that has high resistance to H2S and CO2 and it was made exactly fit the ESP cable providing full protection from corrosive wellbore fluid. This design aimed to boost production of oil wells with lower ESPs installation and replacement cost. The new system eliminates the need for and expensive rig to replace the ESP and accelerate production restoration. This system will be a great addition especially for offshore environments where not only the rig intervention costs are expensive, but also limited rig availability can delay ESP replacement. This paper will share the concept, design, field implementation planning and technical challenges, lesson learnt during preparation and installation of this first of kind system.

In many fields, high water production can cause adverse effects on the reservoir performance, which can result in production losses. To mitigate this situation, it is crucial to utilize water management to reduce water production, optimize oil production, increase the well life and revive dead wells. One of the options is utilizing a workover rig to isolate the water entry zone by running swellable or inflatable packers. This option is costly and time consuming, taking into consideration the time required to prepare the location for the rig, stripping out and returning back flowline and cleaning wells prior returning to production. To overcome this challenge, it was essential to look for an alternative solution that requires less time and cost. One of those solutions is isolating the water producing zone by rigless water shut-off (WSO), using mechanical isolation. This kind of operation is more challenging for extended reach horizontal wells. This paper highlights the mechanical rigless WSO method used to mechanically isolate a water contribution zone by utilizing fiber optic enabled coiled tubing (FOECT) telemetry and setting an inflatable packer combined with a capped with cement. This successful WSO treatment positively impacted the overall performance of a dead horizontal oil producer with 4,000 ft of reservoir contact. The WSO resulted in decreasing the water cut from 68% to 0%, and revived the dead well with 10 thousand barrels per day (MBOD) oil gain. Real-time downhole temperature, pressure (inside and outside the coil tubing) and casing collar locator (CCL) measurements, obtained by FOECT was utilized to get accurate packer setting depth, confirm packer setting and ensure the suitability of cement recipe slurry design. The whole cycle of candidate selection, job design, execution challenges, post job evaluation, lessons learned and the experience gained to optimize the similar future jobs are covered in this paper.