Advanced levels of depletion cause unexpected reduced pore pressures and thus reduced reservoir fracture gradients, presenting considerable drilling challenges in the Burgan Field in Kuwait. This can lead to matrix damage due to mud losses and result in borehole collapse due to the relative increase of effective stress concentration in the vicinity of the borehole. The area of the study showed high levels of non-productive time (NPT) as well as increased costs due to the drilling of unplanned sidetracks in highly deviated wells. LWD Penta-combo measurements including azimuthal sonic and formation pressure have been utilized to model fracture gradient and borehole collapse gradient in real-time, and proved effective at reducing risks and rig time by allowing proactive management of these challenges. Borehole collapse in offset wells was analyzed to predict and simulate the wellbore stability of a planned well via a pre-drill geomechanics model prior to drilling the well. The well was planned with a high deviation of 56° and oil based mud. The salinity of the water phase was recognized as an essential factor in assessing wellbore stability risk with respect to shale-dependent time failure. The integration of real-time LWD sonic and density data with formation pressure testing data in the geomechanics model for the first time in the 12 ¼-in. section showed excellent correlation and confirmed different levels of depletion in the reservoir. Uncertainty in the modeled fracture gradient was significantly reduced and effectively eliminated with the inclusion of real-time formation pore pressure testing data. This successful combination of modeled pore-pressure curves from the real-time LWD sonic data with the real-time formation pressure test data acquired while drilling in the same run is a first in Kuwait. A total of 15 pressure points were sampled in real time while drilling, allowing for proactive mud window optimization and borehole stability geomechanical analysis. This real-time wellbore stability technique based on advanced LWD azimuthal acoustic technology in conjunction with real-time formation pressure testing while drilling has been developed with a unique process and workflow allowing the operator to drill the well with no significant wellbore stability issues and with the optimized shape of the borehole for a safe casing run. In addition, NPT was reduced to 0 hours and overall days per well were reduced significantly.
Before a well is drilled, the forces and stresses acting within a formation are in equilibrium. However, as the wellbore is drilled and a cylindrical volume of rock is removed, the stresses originally exerted on that volume must instead be transferred to the surrounding formation. The cylinder of rock is essentially replaced by a cylinder of drilling fluid, with its hydraulic pressure substituting for the mechanical support of the rock being removed. The hydrostatic pressure from the drilling fluid is uniform in all directions, and it cannot replicate any directional shear stresses that exist within the formation. Formation stresses redistribute around the borehole wall, and if they exceed the rock strength, the borehole will start to deform. If the borehole wall itself begins to fail, the resulting problems could include stuck pipe, borehole wall breakout, swelling shales, and unintentional hydraulic fracturing. The ability to predict and implement corrective action prior to any borehole problem occurring greatly reduces operational risk and ultimately increases operational efficiency. This is accomplished through the development of a geomechanical model which combines local geological and geomechanical field knowledge with comprehensive drilling and evaluation data from offset wells. The geomechanical model provides the ability to predict and simulate wellbore stability of a planned well. Fields exhibiting considerable lateral heterogeneity and depositional variation can be challenging, but prediction and planning become more accurate as additional wells are drilled. The well discussed in this paper was drilled with a bottomhole assembly (BHA) which included an azimuthal acoustic tool that enabled real-time wellbore stability analysis and equivalent circulating density (ECD) measurements to maintain an accurate mud-weight window. Real-time monitoring allowed predicted model responses to be confirmed, and/or the model to be updated. The well was drilled to its final depth with no adverse borehole events, resulting in a quality borehole and a casing run with zero nonproductive time (NPT).
Wireline (WL) measurement emerged a long time before the logging while drilling (LWD) technology which created generations of petrophysicists with different school of thoughts. With the dramatic increase in the adoption rate of the advanced LWD technologies, highlighting the logging environment effects and revisiting our understanding of the formation responses logged under different borehole conditions are more critical than ever. Hundreds of LWD datasets from various environments have been reviewed to identify its effects on data quality and responses from bottom-hole-assembly (BHA) design, driving mechanism, tool eccentricity, well angle, mud properties, differential invasion, borehole condition, formation fluid properties, and drilling fluids interactions. Some of these effects co-occur on many occasions, complicating the log response. Examples and demonstrations of our understanding and interpretation of these phenomena are discussed in the study. Looking to the reservoir in the relatively fresh state, a few minutes after drilling with an understanding of the logging environment provides a unique opportunity to obtain precise formation evaluation and insight into reservoir behavior when combined with different time laps acquisitions. This work is a continuation and addition to (Parmanand et al., 2018) which was extended to include more environmental factors in different oil fields and reservoirs with more advanced LWD technologies. This work summarizes the long cumulative experience of interpreting LWD measurements, shares the main observations related to LWD responses and serves as a ready reference to identify measurement artifacts from actual formation responses. It is helpful as a reference guidebook for log analysts, geologists, geo-steering engineers, and others.
Downhole reservoir fluids sampling in tight formations has been a continuous challenge due to various reasons. The paper presents a technique of successfully collecting downhole fluid samples for first time in ultra-low permeability reservoir having a history of deep invasion. This became possible by initiating micro-scale fractures followed by pumping out for sampling. Using this technique, downhole formation fluid samples were collected, clean-up time was optimized, in addition to acquiring in-situ stress information during the process. A preliminary assessment was performed using open hole formation evaluation logs and pore pressure measurements to identify the most suitable zones for stress measurement and fluid sampling. Single packer sleeve fracture initiation tests were performed to break down the high stress dense layers. In the reservoir rock, the stress measurement involving initiation of a micro-scale fracture was followed by pumping out formation fluid from the fractured zones to collect clean formation fluid samples. The formation breakdown and fracture closure pressure were measured successfully to calibrate minimum and maximum lateral tectonic strains which were valuable inputs for designing the hydraulic fracturing treatment. In the offset wells, fluid sampling attempts from this zone of interest have proven unsuccessful after multiple attempts involving pumping out over 300 liters because of the high depth of invasion leading to a thick flushed zone around the wellbore. The process of initiating micro-scale fractures followed by pumping out provided a high permeability flow channel for efficient fluid sampling. The near wellbore fractures resulted in pumping at higher rates and reaching the higher oil saturated zones of this deeply invaded formation. Hence, formation fluid samples were successfully collected in spite of the low permeability and high invasion typically encountered in this reservoir. Unlike the unsuccessful sampling attempts in the offset wells, this technique of initiating micro-scale fractures in the reservoir rock followed by pumping out helped in collecting formation fluid samples. This technique can be used to collect reservoir fluid samples from micro-Darcy formations and unconventional reservoirs by improving the flow through the induced fractures and thereby reducing the uncertainty that may persist in failing to collect samples from such zones.
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