Drilling high pressure wells in the Khursaniyah field, Saudi Arabia, has become a challenge due to the high pressure flow from Base Jilh Dolomite formations coupled with loss circulation across the depleted Upper Jilh formations in the 8 3/8" section. The variations in formation pressure across these layers have led to issues like well flowing, losses, and stuck pipe causing considerable nonproductive time. This paper analyzes the historical problems encountered in the offset wells to identify the critical fluids related issues during drilling of this section: Thermal and pressure stability of fluids additives.Downhole pressure management.Differential sticking or induced losses.Low contamination tolerance to formation fluids influx.Barite sagging.Rheology and free-water management. This paper also discusses laboratory customization of optimized high-density fluid formulations and field handling guidelines to drill this critical 8 3/8" section and minimize fluid associated risks. The fluid was modeled to have as low a rheology and gelation profile as possible while suspending weight material by understanding the pressure envelope, bore-hole strength, torque, and drag constraints in combination with the fluid rheology and density relationship under the influence of anticipated drilling practices. The field application on this customized formulation with engineering observance was successful to drill this critical section and the case study for such well is presented in the paper.

Introduction Managed Pressure Drilling (MPD) has become a well-recognized and common technique used to drill across hole sections with a small margin between the pore and fracture pressures of the exposed formations. In many applications worldwide, conventional drilling is not viable in extreme narrow drilling window sections, where well control incidents are numerous and lost circulation is severe. Rather than tirelessly trying to tweak mud weight (MW) to handle these troubles while drilling conventionally, the use of surface backpressure (SBP) along with lower density drilling fluids allow for maintaining the bottom-hole pressure (BHP) within the drilling window. The MPD surface choke, equipped with hydraulics modelling software, exerts SBP automatically to maintain a stable BHP while drilling and thus results in an integrated drilling operation with minimal risk and proactive approach (Medley et al. 2008). This paper highlights the drilling operation of an onshore HPHT gas field where an over-pressured zone is encountered, requiring extreme mud gradients. Wells in the field required varying mud densities from as low as 147 pcf and up to 157 pcf. This high density mud along with the narrow drilling window increase the risk of lost circulation and stuck pipe when drilling conventionally. MPD was utilized successfully in several wells, providing improvement in the time required to drill and reduced drilling complications. It enabled drilling with lower MW and enhanced control of BHP, thereby avoiding losses resulting from the high equivalent circulating density. Specific procedures were developed for MPD drilling across this high pressure zone. Manganese tetroxide mud was used to enhance the rheological properties of the drilling fluid. The resulting mud has proven to have significantly lower viscosity and less tendency to settling compared to barite mud systems. The combination of manganese tetroxide mud and MPD drilling proved to be an excellent option to drill through tight mud windows with ultra-high mud weight systems.

Generally, long-radius wells are kicked off in the base of the Jilh (BJD) formation in the Ghawar field, Saudi Arabia. The well profiles require 3° to 4°/100 ft dogleg severity (DLS). The two problematic formations encountered while drilling these curve sections are the BJD and the Sudair formation. Overpressure exists in the BJD, and drilling in this unstable formation often leads to kicks. The Sudair formation, which is plastic shale, has a tendency to microball the bit, leading to slower penetration rates. Higher inclination through Sudair formation generally means more contact and hence longer duration of slower rate of penetration (ROP). Responding to domestic demand for natural gas growth, Saudi Aramco started to focus on reducing unit cost and maximizing reservoir production. After a feasibility analysis, drilling medium-radius curve wells with steerable motors was put forth as a solution; this would mean drilling vertically through problematic formations and target entry (TE) could be reached in 800 to 900 ft of vertical section which would result in increase in reservoir exposure and therefore production. Drilling a medium-curvature well with a conventional motor assembly required a minimum of five runs. Drilling with a steerable motor and rock bit combination resulted in extra bit trips, wiper trips to clean the hole, and multiple reaming trips before running the liner. In all, drilling efficiency was poor because of slow penetration rates and multiple bit trips. After some modifications, a high build rate rotary steerable system (HRSS) was introduced in a well in a challenging deep gas environment. Deployment of the new technology allowed the kickoff point to be pushed deeper, reducing risk and cost. The section was drilled in a single run, saving 6.5 days and improving penetration rate 84% over conventional mud motor bottomhole assembly (BHA). The introduction of new technology, while significant, was not the only factor contributing to the step change in drilling performance; the success was realized by a thorough understanding of local drilling conditions, which informed bit, BHA, and well design decisions and led to superior execution.

The field of interest involves penetrating a predominantly dolomite and dolomitic limestone formation associated with highly pressurized saltwater equivalent to as high as 157 pcf (21 ppg). The most over-pressurized zones are encountered across the ±1,000 ft. base layer of this formation where the majority of flow incidents occurs. This is further exacerbated by the extremely narrow mud window of 0.5-1.0 pcf (0.07-0.14 ppg) between the pore pressure and fracture pressure. Such conditions may lead to risky operations that include well control, high mud weight (MW) design complications, differential sticking, drillstring design limitations, liner equipment failure, poor cement job, etc. Fully automated managed pressure drilling (MPD) systems are utilized to drill the 12 in. hole section and walk the tight window across this rock. This approach allows for applying surface back-pressure (SBP) and accurately holding constant bottomhole pressure (BHP) while keeping constant MW throughout the drilling operation. This operation also witnessed the application and utilization of fully automated MPD systems as means to run and cement a 9-5/8 in. liner across this troublesome zone. Conventionally running liners in excessively high kill MW of ±155 pcf (20.72 ppg) while dealing with tight margins is particularly challenging as it yields total losses due to the surge effect. Conventional cement jobs also mandate filling the hole with high kill MW before the cementing operation, inducing losses and resulting in poor well integrity, leaking liner packer, wet casing shoe, etc. Utilizing MPD systems to run and cement the 9-5/8 in. liner allowed for multistage hole displacement, filling the hole with a lighter MW, and maintaining constant BHP throughout the entire operation regardless of any surface tool failure (pump cavitation, leaking cement head, and surface lines, etc.). This paper details the planning and design phase along with the operational sequence of running and cementing the 9-5/8 in. liner with fully automated MPD systems. A case study will be highlighted to establish lessons learned and best practices.

During the development phase of a gas field, the abnormal pressure in a dolomitic limestone formation demanded an extremely high mud weight to control the well. The casing design of this case-study field has entailed the installation of a 7″ × 9-5/8″ liner hanger in combination with a liner top packer followed by a tieback to surface. Due to this hole section being directly above the pay zone, it is crucial that the liner installation and the wellbore integrity are not compromised for the subsequent well completion. The downhole pressure conditions require a drilling mud weight up to 157 pcf (~ 21 ppg), where solids content could reach as high as 49% using conventional weighing materials. For a liner deployment, this means that the high concentration of solids can cause plugging in the setting ports of conventional hydraulic liner hanger and running tool system. Additionally, the thin balance between ECDs and the formation fracture pressures in this field generated events of severe fluid loss during the liner deployment or while cementing. A liner not fully supported by cement — due to severe fluid loss during cementation — can experience ballooning, and be unable to withstand piston forces acting against the liner top packer during well completion operations. These forces can, in some cases, exceed the ratings of the liner top packer's hold-down slips, therefore allowing the packing element of the liner top packer to not set properly. For these reasons, an optimized deployment strategy was planned and implemented to address these challenges. It included improvements to the hydraulic liner hanger and running tool system, calculations to simulate an optimal running speed of the liner, enhanced procedures for liner deployment and cementation, including revised setting procedures for the liner hanger slips, and modifications to drill pipe wiper plug design. The objective of this paper is to detail the benefits of implementation, detailed pre-job planning, improvements for optimal drilling mud properties and modifications to the liner hanger system, and procedures that resulted in successful deployments of liners in this field. In addition, a case study will be shared as a way to institute lessons learned and best practices.