This case study is done on a mature oil field. In this field, a thin dolomitic layer is thought to be acting as a baffle of water injector in the field. As this thin layer is less than 50 cm thick and not consistently recognizable using some conventional logs, this is a trial of using a combination of advance distance to boundary detection and ultra-high-resolution imaging tool to steer the well above this thin layer. Based on core available data, it is a dolomitized Redstone with a strong hydrocarbon stain. The tight, relative dolomite is likely to act as a baffle to vertical fluid flow. To enhance the effect of planned water injection project, placement of horizontal well just above the dolomitic layer by a meter or a meter and a half was the target for a successfully injector well in this field. Challenges to the landing of such a well includes depth, thickness, and dip uncertainties. Additionally, there are the errors that are inherent to correlating between the reservoir scale and the seismic scale. Finally, it is difficult to discern boundaries in this low-resistivity environment characterized by very low resistivity contrast. Resistivity contrast, in particular, is of major importance as it plays the main role in determining the operability of common distance-to-boundary tools. Combination of distance to boundary detection capability and Ultra-High Resolution Imaging while drilling allowed to place wellbore precisely at certain distance from the dolomitic fluid barrier, avoid any unwanted exits and to evaluate this dolomitic layer properties by resistivity, density/neutron data known as triple-combo sideways with the above mentioned used technology for steering. The data provided were integrated with seismic surveys to refine the reservoir structure and geometry interpretation. The improved understanding made it possible to optimize recovery and production through optimum landing of the well and to map the overlying and underlying reservoir parameters. By selecting the right tool configurations in the bottom-hole assembly (BHA), formation tops were detected from a distance of up to 2m true vertical thickness (TVT) and in the same time parallel to the dolomitic layer in most of the well trajectory. Resistivity contrast was as low as 0.3 ohm.m versus the 0.9 ohm.m when detecting the dolomitic layer marker unit. On the other hand, in some areas of the well, crossing the dolomitic layer and a one bouncing to it was needed to build the confidence in this method and confirming the steering interpretation for the future upcoming wells in the same field.
As in most of the Sultanate of Oman fields, faulted Shuaiba fields contain formations that are extremely faulted and folded. These conditions are a result of the extensive and complex tectonic activities that broke the rock into many structurally deformed blocks. Several studies have been conducted to identify the best drilling and geosteering methods to use in the area. An additional challenge in faulted Shuaiba fields is the bounding of the target reservoir by two dense and sticky layers with similar gamma ray, resistivity, and density. With such reservoir character, differentiating between the top and bottom to make the correct geosteering decision is a real challenge when using conventional logging-while-drilling and standard drilling technologies. A deep-directional boundary mapping tool enabled determining the borehole position inside the steeply dipping carbonate reservoir. Based on the mapping tool's directional measurements, the trajectory was adjusted to avoid exiting the reservoir from the top or bottom, thus continuously keeping the borehole within the reservoir sweet spot. A hybrid rotary steerable system (RSS) tool enabled achieving high doglegs over a short distance in response to the steep and sudden formation dip changes. If a sidetrack was found to be necessary, the hybrid RSS provided the ability to perform an openhole sidetrack in the same string to as deep as 897 m from the 7-in. liner shoe. At the same time, well design, bottomhole assembly (BHA) design and drilling parameters and envelopes were optimized, allowing new historical field records to be achieved in such challenging drilling environment, specifically, the a faulted Shuaiba fields, and in nearby Qarn Alam cluster fields. Due to the difficulty in mapping the reservoir boundary in faulted Shuaiba fields, the operator's geological model was determined to be insufficient. With the high-resistivity contrast in faulted Shuaiba fields, the deep-directional boundary mapping tool enabled the geosteering engineer to detect the top and bottom of the reservoir to a distance up to 2.5-m true vertical depth (TVD). The ability to detect the top and bottom of the reservoir provided reasonable time to react to any sudden changes in the formation. Introducing the directional boundary mapping tool made it possible to update the geological model based on the data obtained from the tool. During the prejob modeling, the well placement team, drilling team, and the operator's reservoir management team jointly set the geosteering objectives and assessed the risk of sidetracking the well, selected the appropriate BHA, and determined if the well would be drilled in the flank zone area. Drilling in the flank zone area was important due to the highly faulted area and sudden formation dip changes. Due to having a better understanding of the true vertical depth (TVD) and azimuth of the faulted Shuaiba reservoirs and being able to update the structural model based on the results and boundary mapping after drilling each well, the number of required sidetracks decreased. The hybrid RSS tool enabled the well placement team to make the quick changes in the trajectory needed to avoid the reservoir top or bottom. When the sidetrack was needed, the sidetrack point could be at any position of the trajectory due to the hybrid RSS tool's capability.
As one of the worst oil & gas business downturns struck, the need for a revolutionary approach of drilling was needed. Optimization was the key word during that period, it was about time to look back at drilling fundamentals, review and learn from previous failures and lessons while establishing new foundation for a transformed yet successful process that ensured an all-time historical success. While many trials of drilling optimization initiatives were executed over the years, inconsistent drilling performance delivery and repetitive failures continued to raise a red flag each time for variety of reasons. Drilling optimization in action was then introduced with its’ comprehensive drilling optimization package, where all historical norms, failures, lessons, and designs were analyzed thoroughly. New objectives and revised designs were proposed accompanied with a whole new process that ensured success. From challenges achieving required performance levels and dog legs in the top sections with increased risks of axial and lateral vibrations, to the difficulties faced in the landing section drilling through unconsolidated and reactive shales in the north, and through fragile weak formations in the south to the difficulties transferring weight to the bit at deeper depths in the horizontal laterals drilling highly porous zones of sticky limestones. Drilling optimization in action project was successfully introduced and executed with a renovated set of drilling parameters envelopes, revised trajectory designs, re-engineered BHA designs, right choice of fit for purpose bits models, adequate technology utilization and effective real-time performance reporting and monitoring. While cost optimization was the trend during the downturn, there was no better option to achieve desired financial results for both operator and service provider than the inclusion of the drilling optimization in action initiative into every well drilling program, it was proven to be an ultimate win-win technical and business solution.
An operator and a service company parternered in successfully drilling the longest extended-reach drilling (ERD) wells in the Sultanate of Oman. The project consisted of four wells to be drilled in the G field. These wells will be the first aquifer pumpoff wells drilled in the field with a goal of lowering the reservoir water cut (oil/water contact) for all nearby oil producers, and to minimize water production and maximize oil production. The buildup section required drilling through the risky gas cap and zones having possible total fluid losses. The risk of stuck pipe and the likelihood of gas kick, as well drilling through fractures on the horizontal section and experiencing potential total fluid losses, made successfully drilling the wells to TD even more difficult and challenging. The buildup section was divided into two string designs based on a previously used single-string design. The drilling objectives were to reduce and separate the risks in the different sections and to drill the gas cap formation in the 12.25-in. shale section, plus landing the well with possible fluid losses while entering the reservoir with the 8.5-in. bottomhole assembly (BHA). This drilling plan eliminated known risks, using BHAs for drilling the 12.25-in. section with a push-the-bit system, and drilling the 8.5-in. section with a high-buildup rate rotary steerable system (RSS) for dogleg severity assurance. Drilling both sections was performed with a near-bit gamma ray adapter for geostopping. The 6-in. lateral section was the main challenge in the drilling operations due to the anticipated highly fractured reservoir with possible total fluid losses and high-equivalent circulating density management. Poor borehole cleaning was expected due to the high-critical transport rate, as well severe shock and vibrations. The BHA was designed to be able to drill to TD using the following techniques: A finite element analysis (FEA) model was developed to determine the most excellent drillpipe to be used in terms of shock and vibration and buckling moments. The model recommended 4-in. drillpipe to reduce the high-surface pressure expected at TD.The FEA model helped in selecting the best driving system (motorized BHA) because the simulations indicated that the BHA would have lower shock and vibration and be able to handle the expected high-surface torque. Due to the expected faults and possible sidetrack, the final BHA selection was a motorized high-buildup rate RSS.The real-time parameter management and plan helped in selecting the best drilling parameters to minimize real-time shocks and vibrations. Drilling the buildup section with the two-casing string design solved the risk reduction and allowed for landing the four wells successfully. For the lateral section, the BHA design met the expectation of completing the drilling operation on one run to TD. Both companies teamed to successfully drill the two longest ERD wells in the Sultanate of Oman. All of the wells are in the very extended-reach group by ERD definition. Well G-55 is the longest ERD ratio well drilled to date by the operator with a 4.01 ratio.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.