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.
This paper presents a customized water-based drilling fluids design for drilling challengig sections through varying formations. The offset wells were reviewed to identify the issues while drilling the trajectory through troublesome reactive and depleted formations that showed wellbore stability issues, stuck pipe incidents, and induced severe losses. Additional problems experienced while drilling include shale dispersion, resulting in fine solids buildup in the drilling fluid, and the adherence of shale to the drill pipe and bit, reducing penetration rates. The customized drilling and completions fluids system was designed for different intervals. The system was developed with the following objectives in mind: improved hole stability through reactive formations; enhanced hole-cleaning efficiency at critical angles; minimized risk of stuck pipe across depleted formations with high porosity and permeability; minimized or non-induced losses to formation utilizing a unique wellbore strengthening technique; and improved rate of penetration to optimize drilling efficiency. This paper describes the customized high-performance water-based mud (HPWBM) design and performance. A comprehensive engineered approach addressed the challenges of drilling horizontal wells by using a high-performance aluminum complex and polyamine chemistry to improve wellbore stability. This approach for drilling fluid chemistry provides an alternative replacement for previously used nonaqueous drilling fluids. Three wells were drilled successfully, and the lessons learned on these wells were incorporated in drilling subsequent wells to continue improving drilling performance.
Formation damage is a by-product of drilling, completion and production process and is attributed to many factors. In open-hole (OH) and cased-hole (CH) wells, hydrocarbon flow may be impeded by various damaging mechanisms caused by drilling and completion fluids, in-situ emulsions, water block, organic deposition and oily debris left downhole. Mesophase fluids have been successfully developed to effectively resolve the persistent problem of near-wellbore damage. The physical-chemical properties of the mesophase systems include high oil solubilization, high diffusion coefficients through porous media and the reduction of interfacial tension between organic and aqueous phases to near zero, making them excellent candidates for removing formation damage. The chemistry of mesophase fluids makes the systems excellent choices for superior synthetic or oil-based mud (S/OBM) displacements in casing and for OBM filter cake cleanup in open-hole completion applications. Mesophase fluids are thermodynamically-stable, optically transparent solutions composed of two immiscible fluids. They differ from ordinary emulsions because they can be prepared with little or no mechanical energy input. They are typically composed of a non-polar or oil phase, an aqueous phase, surfactant(s) and an optional co-surfactant. Depending on how they are formulated, they can exist in a single-phase or in a three-phase system, in which the middle-phase microemulsion is in equilibrium with excess water and oil. The formulation characteristics, phase type, and ultimately, the cleaning efficiency of a microemulsion is dictated by the hydrophilic-lipophilic balance between the surfactant(s) and the physico-chemical environment. The microemulsions described in the study are single-phase where oil and water are co-solubilized by the surfactant(s) and co-surfactants. The water/oil interface has a zero or near-zero curvature, indicative of the bicontinuous phase geometry that produces very low interfacial tension and the rapid solubilization of oil upon contact. The formation of a mesophase does not ensure the fluid will solubilize oil effectively to leave surfaces water-wet. The mesophase behavior and cleaning efficiency can be altered by salinity, surfactant, co-surfactant, oil type, temperature and particulates. No two wells are identical and the physical and chemical conditions can vary greatly depending on the application. As a consequence, robust, optimized formulations are necessary and validation testing is required to determine the efficacy of a mesophase for a specific application, i.e., OBM displacement/cleanup and removal of formation damage in open-hole and cased-hole wells. This paper presents a technical overview of mesophase technology and field applications that demonstrate the efficiency of mesophase fluids for removing S/OBM debris and filter cakes, reducing near-wellbore damage and improving well productivity.
Lost circulation is a major contributor to non-productive time (NPT). Any efforts to better understand the factors that lead to it and subsequently identify a suitable cure will translate to tremendous savings of time and money for operators. Conventional materials such as calcium carbonate, nut shells, graphites and fibers are successful in curing many cases of seepage and partial lost circulation. However, there is a practical limit to the concentration of these materials used to combat the most severe losses due to the limitation of pumps and drilling assembly. In porous formations, high fluid loss squeeze pills have seen some success in reducing losses by forming a high compressive strength plug, but these pills do not have a good success rate in large fractures or vugular formations. Such challenges are better addressed by cross-linking pills, but even this solution does not always have a high success rate due to the low compressive strength of the formed plug. The new phase-transforming loss circulation material (PTLCM) was designed to be pumped easily and achieve thixotropic behaviour under downhole conditions, resisting losses in the thief zone prior to setting as a rigid plug with high compressive strength. A setting-control additive ensures the LCM does not prematurely set. The additive is used at a concentration calculated by considering the time required for pumping and the bottom hole temperature (BHT) in the thief zone. After the LCM sets, a high compressive strength solid plug is formed that can resist fluid loss to the formation. The LCM has a high acid solubility of ~95%, making this system a viable option for deploying in reservoir sections, depending on the client requirement and well conditions. This paper describes two recent successful applications deploying this novel technology. Case Study #1: While drilling in sandstone, the well experienced total losses, which presented an immediate challenge to maintain hydrostatic pressure. The operator responded by pumping several conventional pills loaded with a broad particle size range of fibers, granules and polymers. These pills were unsuccessful at healing the losses, so the operator opted to deploy the new technology LCM. The losses were cured successfully with a single application. Case study #2: Wells drilled in the Western Desert have traditionally experienced severe to total losses while drilling fractured dolomite. Frequently, such events have been difficult to cure by conventional means. The only solution has been multiple applications of cement plugs to heal the losses. This case study describes a well with dynamic losses of more than 150 bbl/hr that were healed by spotting one pill through the circulating sub across the thief zone. The losses were successfully cured, allowing the operator to continue drilling.
Customizing a fluid system for drilling into the pay zone or working over an existing well requires a thorough understanding of the reservoir. Damage mechanisms while drilling in the pay zone include fine solids migration, clay swelling, drill-in fluid (DIF) incompatibilities with reservoir fluids, and the use of reservoir damaging chemicals that can reduce the average formation permeability and lower production rates. A suitable drill-in fluid system must be chemically nonreactive with the rock minerals and reservoir fluids, and be less invasive to preserve the native state of the rock along with its natural wettability. The selection of the bridging particles type, size distribution, and concentration must be based on reservoir rock morphology and the calculated pore throat size distribution. An adequate selection rapidly establishes a tight, thin filter cake and an efficient bridging mechanism that prevents the invasion of filtrate and fine drilled solids deep into the formation, minimizing damage to the reservoir and the potential for differentially stuck pipe. This paper discusses the extensive laboratory analysis performed to design a DIF system based on the reservoir characteristics. This customized DIF was then successfully field tested with predefined key performance indicators (KPIs) to drill two wells, each with a production interval of approximately 2,000 ft, in the Kingdom of Saudi Arabia. Fluid properties, along with particle size distribution of bridging additives, were continuously monitored and precisely controlled through drilling fluids engineering. The optimized drilling practices and hydraulics analysis also enabled us to improve hole cleaning, prevent influx, and minimize hole instability.
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