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An important measure for increasing oil and gas recovery is infill drilling. For mature fields, drilling and completion of new wells can be challenging due to a limited (or non-existent) operational window. The operational window is defined by an upper and a lower bound. The lower bound is usually based either on the pore pressure or the borehole stability limit, whichever is higher. The upper bound is an estimate of the maximum hydraulic pressure the wellbore wall can be exposed to without experiencing fluid loss (called Fracture Gradient, FG). Losses can occur in all types of reservoirs, but depleted reservoirs are more prone to losses because of reduced pore pressure and the decreasing in-situ stress. With reducing stress, the fracture propagation pressure decreases, and it becomes easier to open and drive a hydraulic fracture. A mitigating factor is to reduce mud weight, but this is not always possible in cases of differential depletion where there can be a complex distribution of pore pressure and fracturing pressure along the well. In many such cases, a FG much larger than the fracture propagation pressures in the low-pressure zones is required so that a mud weight can be selected that will balance the high-pressure zones. Such strategies then rely on the extra "strength" provided by the wellbore and specialized particles. Lost-circulation issues lead to non-productive rig time and direct costs associated with lost volumes of mud. If not managed correctly, they may also lead to loss of well/technical sidetrack and, in the worst case, serious well control incidents. Understanding the mechanisms in play is crucial for curing losses, since lost circulation materials used to treat losses caused by induced fractures are not necessarily effective against losses in naturally fractured rocks because of differences in fracture aperture and connectivity. Numerical modelling and analysis of lost-circulation mechanisms are presented in this article. Losses at so-called weak points are addressed and analysis of field data is discussed. Different potential influences on the FG are considered. Effects of varying rock properties and reservoir depletion, and different borehole geometries are modelled and discussed. Shale/sand interfaces are modelled as potential weak-zones and the resulting shear stresses across such interfaces are analyzed during drill-out. We find that such interfaces can be potential weak-zones and that boreholes with non-circular shape are more likely to experience tensile fracturing and mud losses. This highlights the challenges when estimating FG for heavily depleted reservoirs and it confirms the understanding that poor drilling practice which can create weak-points can directly reduce the FG (in addition to unfavorable ECD conditions in well).
An important measure for increasing oil and gas recovery is infill drilling. For mature fields, drilling and completion of new wells can be challenging due to a limited (or non-existent) operational window. The operational window is defined by an upper and a lower bound. The lower bound is usually based either on the pore pressure or the borehole stability limit, whichever is higher. The upper bound is an estimate of the maximum hydraulic pressure the wellbore wall can be exposed to without experiencing fluid loss (called Fracture Gradient, FG). Losses can occur in all types of reservoirs, but depleted reservoirs are more prone to losses because of reduced pore pressure and the decreasing in-situ stress. With reducing stress, the fracture propagation pressure decreases, and it becomes easier to open and drive a hydraulic fracture. A mitigating factor is to reduce mud weight, but this is not always possible in cases of differential depletion where there can be a complex distribution of pore pressure and fracturing pressure along the well. In many such cases, a FG much larger than the fracture propagation pressures in the low-pressure zones is required so that a mud weight can be selected that will balance the high-pressure zones. Such strategies then rely on the extra "strength" provided by the wellbore and specialized particles. Lost-circulation issues lead to non-productive rig time and direct costs associated with lost volumes of mud. If not managed correctly, they may also lead to loss of well/technical sidetrack and, in the worst case, serious well control incidents. Understanding the mechanisms in play is crucial for curing losses, since lost circulation materials used to treat losses caused by induced fractures are not necessarily effective against losses in naturally fractured rocks because of differences in fracture aperture and connectivity. Numerical modelling and analysis of lost-circulation mechanisms are presented in this article. Losses at so-called weak points are addressed and analysis of field data is discussed. Different potential influences on the FG are considered. Effects of varying rock properties and reservoir depletion, and different borehole geometries are modelled and discussed. Shale/sand interfaces are modelled as potential weak-zones and the resulting shear stresses across such interfaces are analyzed during drill-out. We find that such interfaces can be potential weak-zones and that boreholes with non-circular shape are more likely to experience tensile fracturing and mud losses. This highlights the challenges when estimating FG for heavily depleted reservoirs and it confirms the understanding that poor drilling practice which can create weak-points can directly reduce the FG (in addition to unfavorable ECD conditions in well).
Summary Mud losses are frequently observed when drilling in depleted formations. This is because of the decrease in the minimum in-situ stress during depletion. As a result of this decrease, the lost-circulation pressure—or fracture gradient (FG)—decreases, and the operational mud-weight window shrinks. Losses in such formations are often observed when drilling through sand/shale sequences. Preventing and curing losses requires a sound understanding of loss mechanisms. In this study, we investigate several mechanisms that might be responsible for the elevated risk of mud losses in differentially depleted sand/shale sequences. Numerical models of synthetic cases representative of lost-circulation scenarios in a high-pressure/high-temperature (HP/HT) field in the North Sea, under normal faulting conditions, are set up using the finite-element method. The simulations reveal that shear displacement at the horizontal sand/shale interfaces is unlikely to cause losses. On the other hand, shear displacement and losses might be induced at high-angle sand/shale interfaces, such as those found near faults. In addition, faults introduce an extra complexity to the stress distribution and stress-path coefficients. Stress anisotropy near faults might increase during depletion, making both lost-circulation issues and borehole-stability problems worse. The zone most prone to lost circulation in a faulted formation is located in depleted sand adjacent to the fault. The loss mechanism here is because of drilling-induced fractures (DIFs). In addition, depletion itself might induce fractures in shale adjacent to the depleted sand and located across the fault from it. Such fractures might then serve as escape paths for the drilling fluid during infill drilling. The loss mechanism here is caused by pre-existing, depletion-induced fractures. These findings are in agreement with field observations. A noncircular (elliptic or irregular) borehole cross section is found to reduce the fracture-initiation pressure (FIP). An irregular borehole cross section is, thus, another possible mechanism behind irregular loss patterns observed in depleted fields. The results from the study are important for establishing best practices when drilling in depleted formations.
Minimizing formation damage is vital for maximizing productivity when an openhole (slotted liner) completion strategy is used, and it is particularly challenging in high temperature wells with bottomhole static temperature approaching 190°C (374°F). A barite-weighted fluid system for such high temperature wells was identified as unsuitable due to lack of ability to remediate via acid treatment. This paper discusses how a customized barite-free non-aqueous drill-in fluid system was used to successfully achieve productivity objectives for three such wells. Based on reservoir and well data provided, a 1.15 to 1.20 sg (9.60 to 10.0 lbm/gal) barite-free, non-aqueous drill-in fluid system was designed using a high density calcium chloride/calcium bromide brine as the internal phase to compensate for the absence of barite as a weighting agent. An engineered acid-soluble bridging package was included to protect the reservoir from excess filtrate invasion and allow for potential remediation by acid treatment at a later stage. The fluid system was subjected to formation response testing, and the results obtained proved satisfactory, confirming the fluid system was suited for drilling the reservoir. A similar solids-free system using higher density brine as the internal phase, was also formulated. This was spotted in the open hole once drilling was completed to help eliminate any potential for solids settling before running the slotted liner. Three wells were successfully drilled and completed. The barite-free system remained stable, allowed for trouble-free fluids-handling and drilling operations, and performed as expected. To aid in minimizing fluid invasion into the reservoir, onsite particle size distribution (PSD) measurements were performed in order to optimize bridging material additions while drilling and enhance efficiency in managing the solids control system. Because of the extremely high bottomhole temperature, a mud cooler was installed to help control the flowline temperature below 60°C (140°F); this helped maintain fluid stability and preserve functionality of downhole tools in this hostile environment. The solids-free system was successfully spotted in the open hole after drilling the section before well completion. This eliminated any settling potential and reduced flowback of solids during production. The recorded productivity of these wells met expectations.
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