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.
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.
Drilling long laterals within Shuaiba limestone reservoir without exit to Nahr-Umar shale in the challenging field "B" that is characterized by geological uncertainty can have major risks. The low to very low resistivity environment reservoirs are common in Oman especially while placing wells nearby OWC; on a reservoir spot window of 1-2m TVD only. The main objective is to place the well less than 1m TVD below the reservoir top, this was achieved by utilizing Multilayer Bed Boundary Detection and Rotary Steerable System. Integrating propagation resistivity curves response with the directional resistivity curves response from Bed Boundary detection tool have been used as a guide for an optimal well placement in low resistivity reservoir, along with Rotary Steerable System are one of the best strategies which have been used to place the wells within the right spot. For tight geosteering window with an aggressive formation tendency pushing the azimuth left or right and continues inclination instability associated with the existence of an interbedded layers of hard streaks within the reservoir, a faster and more competent Rotary Steerable System tool and Bit selection is required, as proven it provides better stability results for achieving well placement objectives and respond in fast manner to geosteer in real time. The objective of this paper is to describe the geosteering logging while drilling (LWD) technology and technique and Rotary Steerable system (RSS).
Ultralow-resistivity reservoirs, common in Oman, are frequently encountered when drilling wells at the flank of an infill field with nearby oil/water contacts (OWC) in a reservoir sweet spot window of 1 to 2- m true stratigraphycal thickness (TST). An integrated solution developed to better position the wells in this type of reservoir has resulted in successful cases on net-to-gross (NTG), which exceeded expectations in terms of wells production and well deliveries. Integrating resistivity propagation curves response with directional resistivity curves (distance- to- boundary curves) response allows for optimizing well placement and assists in determining the best approach of well objective during drilling. Once drilling the lateral section began, a careful evaluation of the distance-to-boundary service tool inversion and directional measurements were performed in addition to conventional resistivity curves evaluation. This procedure ensured accurate placement of the well; thereby, avoiding water contact. Drilling optimization in long lateral sections has been carried out by optimizing bottom hole assembly (BHA) design, bit selection, and drilling parameters, taking geo-mechanics and geological uncertainty factors into consideration.
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