A methodology for wellbore stability analysis of drilling into presalt formations: A case study from southern Iran

Drilling into presalt formations has been a long-standing issue due to the rapid changes in the diameter of the borehole during drilling operations either because of creep or wash-out dissolution. There have been many studies on characterization of salts, with many mathematical models being presented to estimate the pressure induced due to the squeezing salt sheets. However, the results of none of these models have been fully validated against real field data and some recommendations have been made based on numerical simulations. In this study, attempts were made to introduce a methodology based on damage mechanics for wellbore stability analysis of a wells drilled in the southern part of Iran. The results obtained indicated that the presence of a thick salt layer in the well has resulted in significant wellbore closure in the intervals above the reservoir section. It was also found that the salt exhibits viscoelastic behaviour during drilling due to the homogeneous temperature which has not reached the threshold limit of viscoplastic boundary. A complicated change in the stress regime was also observed which could be linked to the existence of the thick salt layer or presences of a fault crossing the well. Therefore, it is recommended to further validate this model in other wells using the methodology presented

Present-day stress orientation in the Molasse Basin

The present-day maximum horizontal stress orientation in the Molasse Basin is broadly perpendicular to the strike of the Alpine front, indicating that the stress pattern is probably controlled by gravitational potential energy of Alpine topography rather than by plate boundary forces. The present-day maximum horizontal stress orientations determined herein have important implications for the production of hydrocarbons and geothermal energy in the German Molasse Basin, in particular that hydraulically-induced fractures are likely to propagate N–S and that wells deviated to the north or south may have reduced wellbore instability problems

Selection of Optimal Well Trajectory Using Multi-Objective Genetic Algorithm and TOPSIS Method

This study presents a novel approach for optimizing well paths in extended reach drilling (ERD) wells. Different trajectories can be used for ERD wells, each with its pros and cons. Previous research overlooked certain objective functions in single-objective optimization and lacked an autonomous method for selecting the best solution from Pareto optimal solutions in multi-objective optimizations. Furthermore, they lacked comparing different profiles in well design. Risk assessment and operational factors, which greatly influence optimization and drilling success, were insufficiently considered. This study utilized the multi-objective genetic algorithm (MOGA) and the technique for order preference by similarity to an ideal solution (TOPSIS) method to select the optimal well path based on torque, wellbore length, risk (e.g., keyseat), and required tools. First, all possible trajectories were determined, and MOGA identified the optimal path with minimal torque and length. The fuzzy decision-making method automatically selected the best solution from the Pareto optimal solution set. The associated risks and required tools are evaluated for each trajectory. Finally, the TOPSIS method selected the optimal trajectory based on torque, length, risks, and required tools. The case study demonstrated that the undersection path was the most advantageous trajectory for ERD wells, with a 60% closeness to the ideal state. The multiple build trajectory achieved 57% closeness, while the build and hold and double build paths had lower closeness values (43 and 28%, respectively). Consequently, it can be inferred that in the context of ERD wells, it is preferable to carry out the deviation process at deeper depths

An approach for optimization of controllable drilling parameters for motorized bottom hole assembly in a specific formation

This study focuses on optimizing drilling parameters when using Positive Displacement Motors (PDMs). In drilling operations involving mud motors, weight-on-bit (WOB) alterations lead to variations in the system's parasitic pressure drop. Consequently, this affects the optimum flow rate and the hydraulic power of the bit. Also, if the flow rate changes, the bit's rotations per minute (RPM) also change. In other words, using PDMs creates a link between the hydraulic system and the drilling speed, such that changing drilling parameters such as the WOB causes changes in the hydraulic system's performance. Therefore, one possible way to optimize the drilling parameters is to consider the drilling rate and hydraulic system simultaneously using a multi-objective approach. This study used an integrated approach encompassing data mining and mathematical modeling, employing a multi-objective framework to identify optimal parameters. The approach was applied to Dariyan Formation drilling data. The data mining approach revealed a well-distributed data set covering optimal and suboptimal zones suitable for optimization. In data mining, the identification of optimal conditions included a WOB of 11500 lb, a rotation speed of 105.8 rev/min, and a flow rate of 843 gpm, leading to an ROP of 44.23 ft/h. In multi-objective optimization, the optimal parameters consisted of a WOB of 14480 lb, a rotation speed of 115 rev/min, and a flow rate of 920.8 gpm, resulting in an ROP of 40.49 ft/h. Comparing optimal results with the drilling data shows a substantial MSE reduction of over 35 %. The results show the good performance of this approach in detecting the optimal and non-optimal drilling variables

Characterizing the Potential for Injection-Induced Fault Reactivation Through Subsurface Structural Mapping and Stress Field Analysis, Wellington Field, Sumner County, Kansas

Kansas, like other parts of the central U.S., has experienced a recent increase in seismicity. Correlation of these events with brine disposal operations suggests pore fluid pressure increases are reactivating preexisting faults, but rigorous evaluation at injection sites is lacking. Here we determine the suitability of CO2 injection into the Cambrian‐Ordovician Arbuckle Group for long‐term storage and into a Mississippian reservoir for enhanced oil recovery in Wellington Field, Sumner County, Kansas. To determine the potential for injection‐induced earthquakes, we map subsurface faults and estimate in situ stresses, perform slip and dilation tendency analyses to identify well‐oriented faults relative to the estimated stress field, and determine the pressure changes required to induce slip at reservoir and basement depths. Three‐dimensional seismic reflection data reveal 12 near‐vertical faults, mostly striking NNE, consistent with nodal planes from moment tensor solutions from recent earthquakes in the region. Most of the faults cut both reservoirs and several clearly penetrate the Precambrian basement. Drilling‐induced fractures (N = 40) identified from image logs and inversion of earthquake moment tensor solutions (N = 65) indicate that the maximum horizontal stress is approximately EW. Slip tendency analysis indicates that faults striking <020° are stable under current reservoir conditions, whereas faults striking 020°–049° may be prone to reactivation with increasing pore fluid pressure. Although the proposed injection volume (40,000 t) is unlikely to reactive faults at reservoir depths, high‐rate injection operations could reach pressures beyond the critical threshold for slip within the basement, as demonstrated by the large number of injection‐induced earthquakes west of the study area

Technology Focus: Multilateral/ Extended-Reach Wells

Technology Focus The development of multilateral wells and long-reach wells has become important to maximizing recovery for many oil fields. These technologies are often applied in offshore environments, where large reservoir areas are drained from one or more platforms. In the late 1980s, long-reach wells started to use existing infrastructure better by drilling beyond the design limits at that time. Several major operators were extending their limits, and, in the late 1990s, BP’s Wytch Farm showed that a horizontal departure exceeding 10 km was feasible. This had a significant effect on the industry because offshore platforms now could be designed for up to 10-km reach as opposed to the early 1980s, where 3-km reach was common. A field could now be developed with one platform instead of three, resulting in enormous savings. Multilateral-well technology also matured during the past 2 decades. There were many drivers for this development. One of the most important was the desire to increase production in tight reservoirs. Another advantage is directional control. Well stimulation with fracturing has the drawback that the fracture direction is controlled by the in-situ stresses in the rock. Multilateral branches, on the other hand, can be drilled in any direction. There is a considerable technology development around these technologies. Those that help clear the challenges such as those related to wellbore stability, wellbore friction, equipment limitations, and operational aspects can be considered mature technologies today. The main benefit from directional drilling is the maximizing of reservoir recovery. From this perspective, multilateral/extended-reach wells may be considered one of the most important means of improved oil recovery. JPT Recommended additional reading at OnePetro: www.onepetro.org. SPE/IADC 163525 Setting Free the Bear: The Challenges and Lessons of the Ursa A-10 Deepwater ERD Well by John Gradishar, Shell, et al. SPE/IADC 163487 Case History of a Challenging Thin-Oil-Column Extended- Reach-Drilling Development at Sakhalin by Vishwas P. Gupta, ExxonMobil, et al. SPE 170831 Going Long—Overcoming Challenges in Completing 3600-m Laterals by R. Liston, Step Energy Services, et al.</jats:p

Technology Focus: Multilateral/Extended-Reach Wells (May 2017)

Technology Focus In a previous issue of JPT, I read an interesting comment. A petroleum engineering department had visitors. One of them was asked to draw a well on the chalkboard, and she instinctively drew a horizontal well. She obviously considered horizontal wells as common. This illustrates that, during the last decade, wells such as horizontal wells, long-reach wells, and multilateral wells came to be considered mature technologies. Another aspect is that the technical level has increased significantly during this development. Currently, in well engineering, there are also many activities designed to stretch limits, improve processes, and make solutions more competitive economically. The main objective of multilateral and extended-reach wells is improved field recovery. Multilateral wells expose more reservoir and improve reservoir drainage, whereas long-reach wells often increase drainage from existing platforms. Up to 80% of long horizontal wells may have inflow-control tools. The most common is the inflow-control-device orifice to control the water/oil contact, but more-advanced autonomous systems are being developed with more-precise control functions. A related group of tools includes water-stop mechanisms. Water production is a considerable challenge for the oil industry, from production, cost, and disposal perspectives. At present, there exist many useful completion technologies for inflow control and for workovers and stimulation purposes. New and improved functionalities open up for more-detailed reservoir analyses that ultimately will result in higher field recovery. The featured papers all show improved solutions for constructing multilateral and long-reach wells. They show the dynamics of a continuous striving for improvements. These well types are very important tools in the search to maximize recovery from petroleum fields.  Recommended additional reading at OnePetro: www.onepetro.org. SPE 180445 Increasing Performance of Multilateral Wells Using Oil Fingerprinting by M.D. Jensen, ConocoPhillips, et al. SPE 183422 Korchagina P-108: Breaking ERD Records Offshore North Caspian Sea—A Case Study by Vasily Zvyagin, Lukoil, et al. SPE 184608 Reducing Well Costs and Extending Field Life With Intelligently Controlled Trilateral and Quadrilateral TAML Level-5 Multilaterals by Mark Glaser, Halliburton, et al.</jats:p

A New Fracture Model That Includes Load History, Temperature, and Poisson's Effects

Abstract The fracture equation used in the oil industry is derived from the Kirsch equation for the hoop stress. Because of its simplicity, it is almost exclusively used for the prediction of fracture initiation pressures. However, it is not useful for analysis of load history. An analytic study was undertaken to model load history leading to the fracturing of the borehole. To use the model, initial conditions must be established, given by the virgin in-situ stress state and the pore pressure, followed by the load history and the temperature history. Imposing a volumetric strain balance, a new fracturing equation is developed. Because the borehole is loaded in the radial direction, causing tension in the tangential direction, a Poisson's effect arises. In addition, the general solution includes effects of temperature history. Example cases will show the improvement with the new model. The first case compares the new load-history fracture model with the Kirsch solution. The Poisson's scaling factor in the new solution leads to a higher fracture pressure than the conventional solution. This may explain some of the discrepancy between models and field data. The second case investigates the thermal effects by comparing the fracture pressure for the drilling phase with a hot-production phase and a cold-water-injection phase. It is believed that by including the pressure and temperature load history, a better assessment of the fracture strength is obtained, leading to better predictions.</jats:p