Kuwait Oil Company (KOC) has recently drilled the first multilateral well in a North Kuwait field to improve oil production in productive layers subjected to water coning problems by increasing reservoir exposure using Level 4 multilateral technology. The multilateral well targeted the same sand in different directions with two laterals. Both of the laterals were drilled using rotary steerable drilling systems to reduce drilling time. The drilling process used a full suite of logging while drilling (LWD) tools, including azimuthal deep resistivity technologies, to ensure the well path is precisely geosteered within the reservoir boundaries and density/porosity tools in real-time, combined with specialized modeling software to position the well in the best possible reservoir.Level 4 multilateral technology was selected after performing an extensive geological assessment and studying the challenges of exploiting oil in the target sand reservoir. The 12 1/4-in. main section was cased and cemented with 9 5/8-in. casing to the landing point; the 8 1/2-in. lateral-I was drilled and completed with 5 1/2-in. inflow control devices (ICDs). The sidetrack was performed by cutting a window from a specialized latch coupling in the 9 5/8-in. casing; the 8 1/2-in. section was drilled to the landing point, and the 7-in. liner was run and fully cemented. The 6 1/8-in. lateral-II was drilled and completed with 4 1/2-in. ICDs.The fully cemented and cased junction or bifurcation should help achieve greater well integrity and prevent fluid migration from the adjacent area, while the specialized latch coupling should help ensure easy access to either of the laterals, as required. The ICD technology and swellable packers were selected to delay water breakthrough from an active aquifer.This publication describes the application of multilateral and geosteering technologies, and analyzes the advantages and disadvantages of the first multilateral well drilled in North Kuwait that began with a campaign of higher order (Level 4) multilateral. The well is considered to be a pilot well to identify the feasibility of using multilateral technology as a production model to help enhance oil recovery and reduce drilling costs in the field by replacing the cost of drilling new wells.

Continuous improvement initiatives prompted the deployment of a new way to drill smart wells combining the most recent technologies. The solution consists of a complete closed loop workflow utilizing an intelligent rotary steerable system (RSS) with high-frequency downhole measurements and processing capacity, an in-bit parameter sensing device, and a novel high-speed telemetry system guided by an autonomous drilling platform. Primarily focused on reducing human intervention and improving performance, the leading Key Performance Indicators (KPI) selected to benchmark the performance were drilling time, represented by Rate of Penetration (ROP), and flat time represented by casing running time. All while providing operational consistency and reducing Health Safety and Environment (HSE) risks. The autonomous drilling platform orchestrates the rhythm in which the RSS executes commands to stay on the planned well path. Another workflow links between well placement software and the autonomous drilling platform in case a change in well trajectory is required for well placement purposes. The new pilot workflow triggered a critical well process for the planning and design phase. A comprehensive pre-well modeling exercise was required as it was the first run in the country for most of the featured technologies. The in-depth exercise resulted in a scenario-based decision tree to ensure seamless workflow execution. Three primary functions were planned for automation with varying machine control levels, and limitations posed by the drilling rig. Those functions covered directional steering and trajectory control, vibration mitigation, and hydraulic management. The first section delivered a field record with a 30% faster ROP than the best offset achieving a 7deg /100feet dogleg seamlessly while adapting to formation behavior changes to meet well plan objectives. The section also achieved the fastest casing run time among similar profile wells, breaking the second KPI record. The automation platform provided steering control during the entire section, landing the well perfectly in the target reservoir, making the section best in class in the area. Meanwhile, the hydraulics management function provided a smooth hole profile that helped tripping and casing running time. The vibration modes recorded using in-bit sensors helped analyze and build with a more effective drilling roadmap for modeling/executing future wells with even higher accuracy. With the above performance, it is worth noting that the record section was delivered using one of the historically slowest rigs in North Kuwait. The paper focuses on the details of the automated drilling suite and the internal and external workflows developed with the operator to enable the deployment of such a system and help introduce a more innovative way to drill, resulting in breaking all the records achieved with conventional methods from the first trial. It also discusses the viability of applying such methodology to other projects of varying complexity.

The Great Burgan reservoir is the largest sandstone oilfield in the world, it has been developed and produced since the 1930s. Historically developed through deviated wells, a new project of horizontal wells was initiated recently to produce from the UB3 reservoir unit. A pilot hole is usually required to identify the presence of productive sublayers and the depth of the oil-water contact (OWC), which must be avoided in the horizontal section. Elimination of the pilot hole would help to minimize the time and cost of development (Al Khalifa et al. 2020). The azimuthal ultra-deep resistivity mapping service (UDR) has proven its capability to eliminate the need for pilot holes by mapping reservoir boundaries and OWC on the fly, earlier than with traditional methods. This facilitates real-time geosteering to land the well in a single drilling run in the productive zone. Additionally, it helps to reduce non-productive time by making it easier to stop drilling and set casing above a target layer and to help optimize future well planning in field development. A feasibility study performed on offset wells showed promising potential from application of this method in the UB3. Real-time UDR geomapping detected multiple thin sand lenses on top of UB3 but showed that they were not of commercial capacity. The decision was made to continue drilling deeper for a larger sand layer. The UDR detected a massive sand below the smaller lenses and the well was landed in it. Early mapping also helped to optimize the landing with the desired inclination and dog-leg severity. The OWC was detected ~35 ft TVD below the landing point. Without UDR it would have been impossible to detect the OWC and very challenging to perform an accurate landing. The target could have been missed by landing either too shallow or too deep or with the wrong inclination. Following the landing of the well the lateral section was drilled through upper and lower lobes of the massive sand with a total cut of 1649 ft MD. This comprised 450 ft MD of upper lobe, 350 ft MD of transition interval, and 637 ft MD of lower lobe inside BU3, with an average porosity of 30 p.u. and a water saturation of less than 10%. Formation pressure tests measured mobility of up to ~3.4 D/cp. This case study demonstrates that utilization of the ultra-deep resistivity mapping service enabled a new approach to drilling lateral wells in the Burgan field development, improving reservoir insight and reducing well drilling time and cost.

The Mauddud reservoir in the Raudhatain and Sabiriyah fields of north Kuwait includes production layers that were historically exploited using vertical wells. As lower layers begun producing water, horizontal producers from upper layers were planned. A recent simulation study was performed for electrical submersible pumps (ESPs) in the reservoir. ESPs must be placed vertically and as near to the target layer as possible for maximum sweep effect, and as a result, greater build rates in the build section of the well were required to enter the reservoir laterally at the optimal depth. With a requirement for these wells to be drilled with a rotary steerable system, a high build rate (HBR) rotary steerable system (RSS) is required.An upgraded true point-the-bit (PTB) RSS was run for the first time with a polycrystalline diamond compact (PDC) bit in a matched system. A logging-while-drilling (LWD) suite was used while drilling the build section and steer into the target reservoir. The RSS was modified to increase the effective bend angle at the bit and optimize the fulcrum point geometry for high dogleg capability. Bottomhole assembly (BHA) modeling was performed to optimize the stabilization while simultaneously managing stresses in the BHA. Bit designs were optimized with an integrated bit-BHA model to provide sufficient lateral aggressiveness and good hole quality. Extensive planning and BHA optimization exercises were performed to address the challenge.The initial field tests were performed in Kuwait, and the planned trajectory was initially designed with a ϩ/-10 deg/100 ft build rate. The proposed system was successfully run and exceeded requirements; While drilling the build section, the real-time LWD correlation showed the target formation coming in 19 ft shallower than was initially estimated, requiring a higher than planned dogleg to land the well in the target zone. The RSS deflection was increased to increase the dogleg output, based on the updated target location. The upgraded RSS responded immediately and the system was able to deliver in excess of 12 deg/100 ft build rate, producing a smooth curve at high rate of penetration (ROP) and with low vibration -achieving the target TVD required. A high build rate capability using the PTB system was proven while sustaining the PTB advantages, including superior hole quality, enhanced directional control, and reduced drilling time.This new development provides a unique capability to the industry in a true PTB RSS system with high dogleg capability. Good hole quality and steerability of a PTB RSS can now be achieved simultaneously in high dogleg applications. Good hole quality combined with precision in wellbore control improves drilling performance and completion installation in high dogleg applications. This capability enhances the project economics and enables increased production potential.

Formation testing while drilling (FTWD) proved to be of great value to the asset team at Kuwait Oil Company (KOC) while recently drilling a deep, deviated well to target the Zubair sands. The deviated 8-1/2-in. hole section of the well had been planned to cut through more than 1,100 ft of true vertical thickness containing multiple reservoir units with varying pressures, lithologies, and formation characteristics, which posed a great risk for drilling operations and required the use of relatively high-density mud to maintain wellbore stability. The presence of highly depleted reservoir zones in this mature reservoir resulted in a challenging pressure overbalance in excess of 4,800 psi. Attempts to measure formation pressure in previous vertical offset wells in the same depleted zone in the same field/environment using wireline formation testers yielded either unsuccessful or erroneous results, indicating a tight formation, which conflicted with previous production and coring data available that suggested high-permeability sands were present. The high overbalance was suspected to be the primary cause of formation damage and blockage resulting from solids content in the drilling fluid and longer exposure time. KOC has historically opted for taking pressure points in wipe mode rather than dynamically while drilling in open holes containing unstable Zubair shales. Moreover, a large number of planned pressure points with the drilling assembly cutting across various sand zones posed several challenges. The asset team had plans to exploit such depleted zones through future horizontal drilling; however, an up-to-date pressure measurement was required to assess feasibility. This paper discusses the planning, design, and execution of this well. It also focuses on the use of the FTWD solution alongside other logging-while-drilling (LWD) and rotary steerable assemblies to overcome the drilling challenges and successfully follow the planned data-acquisition program to optimize the completion and production strategy and discusses how the solution affected the decision making for future wells.