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.

Torsional vibration (also known as stick and slip) is a major contributor to equipment failures and severe damage when drilling the 6 1/8-in. lateral limestone Shuaiba reservoir section in PDO North Oil fields. This paper examines multiple factors that can affect the severity of stick and slip and measures their actual impact. These factors include bit/bottomhole assembly (BHA) design and formation/mud properties. The effect of a software plugin to an automated drilling system that was designed to mitigate the effects of stick and slip was also examined. Initially, drilling dynamics data available for the lateral Shuaiba reservoir were analyzed to evaluate the levels of torsional vibration. Several proposed design changes to reduce the torsional vibration were then modeled separately using finite element analysis (FEA) to predict their dynamic behavior. Trials were conducted, and the impact of independently changing each factor in the overall torsional vibration was assessed. Data were collected from over 40 horizontal wells drilled in the same reservoir. In each set of trials, identical drilling conditions were maintained while changing a single factor. The analyzed legacy set of well data showed high levels of torsional vibration (stick and slip) in the lateral section for different fields that share nearly the same reservoir characteristics and bit/BHA design. Using a similar formation profile, the FEA modeling results suggested that stiffening the drillstring and using heavier sets of PDC bits would greatly reduce the torsional vibrations while maintaining a good rate of penetration. When these changes were applied, actual data were analyzed to measure the improvement. Additionally, the analysis found that specific formation characteristics such as formation density highly contribute the severity of torsional vibration. Modeling also suggested that applying higher torque to the bit reduces its RPM fluctuations and allows for lower surface parameters. This, in return, reduces the amplitude of the torsional vibration. Over eight trials were analyzed, and significant reductions in both the measured torsional vibrations levels and equipment failures and damages were seen. Finally, the effect of utilizing a software plugin to an automated drilling system to mitigate stick and slip when drilling the 6.125-in. lateral limestone reservoir was examined. Like the other proposed solutions, the remaining factors were kept constant. The paper offers a rare case study specific to lateral limestones reservoirs, where interbedded layers are a common contributor to the severity of torsional vibrations. The results and conclusions are based on downhole high-resolution data to calibrate finite element models to provide fit-for-purpose solutions. The results eliminate much of the theoretical explanations about root causes of torsional vibrations in limestone reservoirs.

Petroleum Development Oman (PDO) “M” gas field provides an unique set of challenges while drilling the 12.25 in intermediate hole section which include severe lateral vibrations, stick & slip, impact damage, limited bit life and low penetration rates. As a result, 3 BHA's were historically needed to complete the section totaling 16 days on average. A collaborated effort between Schlumberger and PDO was initiated, with the ultimate goal to reduce the number of days to drill the section. To achieve this goal a Petro Technical Engineering Center (PTEC) process was established to develop a system engineered BHA solution. This process was introduced to the field over several wells and resulted in drilling the entire section in one run and reducing the drilling time from 16 days to 7 days. The well profile is a 12.25in vertical hole typically drilled from +/− 1000m to +/−3400m MD, through highly interbedded formations ranging from 5-30 kpsi UCS and varying levels of abrasiveness. In a hard rock environment a system engineered approach is valuable to reduce the number of design iterations required compared to a trial and error method, due to the significant amount of time a well takes to drill. To complete this, a three phased approach was executed. Phase 1 –To identify the most stable bit and BHA combination to use in the 1st trial test, a time domain integrated FEA model1 was used determine the best suited bit combination. From this analysis it was concluded that a 5 blade 16 mm bit driven by a motorized rotary steerable system would provide the most stable option to pursue in the trial test. Along with the modeling a detailed parameter roadmap was generated from the collaborative efforts of both PDO's and Schlumberger's drilling teams. The roadmap was coupled with a ROP optimization application2 which provided real-time RPM and WOB drilling parameter recommendations to maximize ROP within the operational envelope defined on a per formation basis. Phase 2 – Building on the lessons learnt from Phase 1, a time domain Integrated FEA Model2 was used to fine tune the BHA and recommeneded removing the motor from the system would provide a more stable BHA in this application as well a switching to a less aggressive cutting structure in a 6 Blade 16 mm design. The model was also used to optimize the BHA design so that it generated limited vibrations enabling an aggressive strategy to reduce cost by removing the MWD, surface system and personnel. Thanks to its capability to keep a precise vertical control in automatic mode without the need to over-regulate the drilling parameters. This was implemented and resulted in the first shoe to shoe run in the field. Phase 3 – A new bit technology incorporating a conical diamond element3 was strategically placed in the center of the baseline PDC bit. It was then modeled using the same time domain integrated FEA model used in Phase 2 and selected for a trial test. The drilling system was run again and resulted in another successful shoe to shoe run with a further increase in penetration rate of 14.4%, and more improvements on following wells. The engineered solutions supported by the team effort and simulations made significant improvement in subsequent wells and are ongoing.

In a heterogeneous and fractured carbonate hard rock with UCS more than 15K psi, drilling a highly deviated well is a challenging process that would require real time monitoring, using best in class MWD and LWD technology. A client in South Oman is in a development phase of drilling 1000m lateral wells to maximize the exposure for optimum oil production. The carbonate formation is characterized as heterogeneous vuggy dolomites with a network of regional fractures acting as the secondary source of porosity. The thin reservoir is isolated by thick layer or Anhydrites above and Shale formation below & managing geological uncertainties in real time is going to be the differentiator between success and failure. A combination of hybrid RSS to manage aggressive steering requirements along with distance to boundary imaging LWD tool to identify the bed boundaries & keep the well on course along with an azimuthal resistivity ultra-high imaging for reservoir characterization were deployed to overcome these challenges. The proposed solution was put into challenge on well X for drilling 5.87in lateral section and 1000 m lateral was successfully drilled. Hybrid RSS with aggressive bend setting helped in geo-steering the well and managed to achieve directional objectives to chase the geological uncertainties. After confirming the formation dip the well was steered 6to 7ft from the bottom conductive layer with the help of distance to boundary resistivity imaging tool. Real-Time High-Definitionazimuthalresistivity images helped in petrophysical interpretation and formation evaluation. Later, better density memory imaging data helped in evaluation of full borehole structural features and detailed fracture characterization. Hybrid rotary steerable systems along with best in class LWD tools provide purpose to fit solution to drill and geo-steered well in the optimum place. Success of this combination has eliminated the risk of exiting the reservoir leading to costly sidetrack scenario. At the same time, it has also helped the client to optimize production by geo-steering the well in the high porosity sweet spot and by Identifying regional fractures. Developing deep, hard and heterogeneous carbonate reservoirs is a complex and challenging affair and a conventional approach to overcome these challenges is not always producing the best results. A novel approach with the help of advanced rotary steerable and logging while drilling tools helped client in developing the field by minimizing the risks and maximizing the best reservoir exposure characterized, as the well are drilled.

No abstract