The temperature gradient in a giant gas field in the Middle East shows wide differences from one location to another. The drilling environment in slim single-lateral wells is challenging due to the substantial temperature anomalies resulting to multiple drilling tool failures where recorded downhole temperature exceeded 320 degF. This paper focuses on the first implementation of mud cooler with chiller packages in a gas drilling project and how it affected downhole temperature and well delivery performance. The process that led to the successful implementation of the technology can be summarized in four phases: the analysis of business drivers, preliminary temperature simulations and package design, and compatibility analysis, installation and operation. The identified business drivers included prevention of tool failures, optimization of drilling parameters, reduction of additional trips and the removal of the time-consuming staging procedure. To address these business needs importing HT tools did not seem to be the optimal solution as the temperature anomalies are not experienced in every well; the mud cooler and chiller offered the needed flexibility and cost-efficient solution. The mud cooler and chiller packages were implemented in a series of high-temperature gas wells and proved to be highly effective in rapidly decreasing the temperature of the mud at surface and substantially cooling down the downhole drilling tools. Maintaining a low downhole temperature throughout the section enabled the reservoir laterals to be drilled more efficiently, with less runs, and with no temperature-related tool failure. At surface, the mud temperature was lowered by more than 40 degF. Downhole temperature reduction measured by the drilling and measurement tools was up to 21 degF. Remarkable performance was achieved, such as the drilling of more than 3,000 ft of 5-7/8″ lateral in a single run while keeping the downhole temperature below 280 degF which was decisive in preserving the downhole tools. This project is a notable illustration of successful collaboration between different business units within the integrated service provider's organization to design and implement a fit-for-purpose solution to enhance tools’ reliability in high-temperature environments. The key elements which made the implementation successful in extending the runs and eliminating non-productive time for improved well delivery performance will be presented and described in length in the paper. Integration of the different technologies involved proved to be a key driver of innovation in the project and allowed for faster trials and deployment of new technologies and ways of working. Both the operator and the integrated services provider joined their efforts to achieve step changes in performance in high-temperature gas wells which can be successfully implemented elsewhere with all the main IOCs and NOCs.

In a deep gas drilling project, landing the 7" liner at the top of a thin carbonate layer is critical to ensure ease of drilling and maximize reservoir exposure. Real-time multi-layer bed boundary detection technology was utilized to enhance top of reservoir detection certainty. This approach reduces the hard caprock interval in the next section which potentially causes wellbore instability and downhole tools failure, allowing drilling long reservoir section with minimum BHA runs. Picking the top of caprock using conventional approach was challenging due to the lack of control points and the absence of distinct markers to distinguish the reservoir from the caprock. The variations in formation thickness and structural complexities also generated uncertainty in well correlations. Past experience was a series of downhole tool failures, resulting in multiple BHA runs to drill the reservoir section. Drilling caprock too deep could also accidentally expose the reservoir which would have catastrophic consequences such as total losses, well control situation, and sometimes missing the sweat zone completely. The initiative comprised the introduction of a multi-layer detection resistivity mapping tool to detect bed boundaries with resistivity contrasts in the 8-3/8" hole section. The objective was to set the 7" liner as deep as possible to minimize the footage in the caprock in the next 5-7/8" section. Combined with in-depth well placement study to determine best trajectory for landing strategy, it enabled to push liner point closer to top of reservoir. In subsequent implementations of this novel approach, the 8-3/8" section was deepened in average by 20 ft TVD into the caprock against the default 5 ft TVD previously followed. The drilling performance in the subsequent 5-7/8" section was significantly enhanced. Minimum shocks and vibrations were observed, and maximum drilling parameters could be applied at section start resulting in much higher penetration rates. The reservoir section was successfully drilled in two runs, doubling the average footage drilled as compared to previous similar runs. From a reservoir management viewpoint, the initiative contributed to increase the net-to-gross ratio across the pay-zone which improved the efficiency of the frac stages and eventually expanded the overall gas production. This accomplishment was only made possible by the collaborative approach between the integrated services provider and the other stakeholders and was first deployed in a deep gas integrated drilling project. The client gave very positive feedback and the gas drilling unit is now considering implementing similar strategy in other rigs. From these promising results, it is believed that this initiative can also be implemented elsewhere in the Middle East where accurate well placement across thin carbonate layers is critical for successfully drilling the reservoir section.

The aerated drilling fluid technique was introduced to a deep gas well drilling project as a solution to overcome the challenges posed by top fractured formations and highly water-sensitive shales. The top holes were originally drilled with a diesel oil-emulsion drilling fluid which was later changed to a high-bentonite content drilling fluid system. The aerated drilling fluid aimed at improving the overall drilling performance and addressing top hole geological complications. The main objectives behind the introduction of aerated drilling were the mitigation of mud losses in Wasia and Shu’aiba formations and improvement of the penetration rate across the lowermost abrasive Biyadh interval. The aerated drilling fluid technique was successively implemented in four wells in different areas of the field. The system was a mixture of air and polymer-based fluid pumped inside a closed circulation system with the use of a rotating circulating head. The system provided the necessary viscosity to entrap the air downhole while allowing it to easily break out at surface in the separation equipment. The technique proved to be an excellent solution for drilling through lost circulation zones across the Wasia and Shu’aiba fractured limestone formations. Equally important, this technique delivered much higher penetration rates while drilling across the Biyadh interval. An effective oil-emulsion system used to be run to lighten the fluid column to prevent losses but was replaced by a high-bentonite drilling fluid for environmental reasons. The latter system was believed to seal the formation fractures due to its high gelation characteristics, thereby preventing losses. Despite being effective at preventing losses, this drilling fluid returned poor performance while drilling compacted clay intervals toward the end of the section. As a result, the casing point had to be set shallower thus complicating achieving the objectives of the subsequent hole section. The results of implementation exceeded expectations both in terms of ROP improvement and control of downhole losses, reducing the section drilling times by more than two in comparison to the high-bentonite content drilling fluid and up to 35% over the oil-emulsion drilling fluid. This technique was also remarkable in reaching the designed casing point in all sections drilled. This paper will describe in length the performance of the trial jobs, present the lessons learned from the implementation of this innovative drilling fluid technique and highlight the best practices utilized to make it a cost-effective solution.

From a drilling operation's perspective, the wells drilled in the direction of maximum horizontal stress are ideal as they have less risk of wellbore instability. However, when these wells are hydraulically fractured, the fracture grows along the wellbore in the direction of well azimuth. To avoid overlapping of two adjacent induced fractures and thereby communication between stages, only two to three multistage treatments can be performed. To increase production and enhance recovery, operators now drill horizontal wells along the minimum horizontal stress direction to generate multiple transverse fractures during the stimulation stage. However, drilling along the minimum horizontal stress direction requires higher mud weights and advanced geomechanics studies to minimize wellbore instability due to prevailing in-situ stress conditions. This increased mud weight leads to higher differential pressures across the depleted reservoir layers, which when coupled with formation instability, creates greater challenges such as stuck pipe and formation breakdowns. During the completion phase, the stiff multistage fracturing string containing multiple packers makes it more difficult to run through a slim hole, resulting in multiple failures, stuck pipe events, and nonproductive time. While drilling horizontal and high-angle wells in a giant onshore gas field, production holes are drilled through many reservoir layers. A few are highly depleted and the rest are highly pressurized. A high degree of skill is required to design and manage drilling fluids and drilling practices so that the depleted layers seal efficiently, thus preventing the development of a thick filtercake and differential sticking incidents. This paper outlines a successful neoteric methodology adopted in these challenging wells in a deep gas drilling lump-sum turnkey project in the Middle East after a detailed analysis of offset data and failure incidents. The outstanding performance achieved by adaptation in operational procedures while using the existing setup in both drilling and completion phases, challenges while implementing the strategies, and comparison of results with previous drilling techniques will also be covered to help operators drill successfully in similar conditions.

In a deep gas drilling project, the 22-in section across shallow fractured carbonates is drilled using an unweighted clay-water system incorporating up to 50-lbm/bbl bentonite. The main challenges comprise lost circulation, tight hole, and low penetration rates due to high clay content and lack of inhibition, resulting in geological complications and affecting the well delivery time. To seal off the large fractures in the lower-cretaceous limestones, the new drilling fluid was engineered with high thixotropic characteristics presenting a flat, shear-thinning rheological profile with low plastic viscosity, high yield point and flat gel strengths. The selection of candidate wells was supported by offset wells analysis considering drilling performance, penetration rate and footage achieved, and the likelihood of encountering losses. Fine-tuning of the fluid rheology was performed to effectively account for the probability of losses on each well and a fit-for-purpose drilling fluid formulation was designed. This innovative technology combining mixed-metal oxide with premium bentonite was run in a series of wells as a substitute to the previously used system. Due to its superior viscosity at low shear rates the fluid successfully prevented losses by gelling up in the interstices of the highly fractured limestone intervals. In addition, the fluid delivered higher drilling performance across the abrasive sandstone-clay intercalations and the hard carbonates toward the bottom of the section. By maintaining full circulation all way through and therefore avoiding the expenses associated with blind drilling and pumping mud cap, the initiative resulted in considerably lowering the fluid cost in this section. Significant operation time savings were also achieved by drilling the section faster to the intended casing point in a minimum number of runs. Enhanced wellbore condition that allowed the drill string to trip out on elevators instead of back-reaming also contributed to saving rig time. The casing could be run to bottom and cemented trouble free in one stage with cement returns to surface thus precluding the cost of stage collar tool in most of the wells. This paper unveils the facets of this versatile water-base fluid that was introduced as a solution to prevent losses and address poor drilling performance.