A workflow that combines optimization of the drill string and bottomhole assembly (BHA) design during well planning and then applies advanced surveillance tools to a well-trained drilling crew yields reduced vibrations, higher drilling rates, and less trouble cost. This methodology is based on the premise that an efficient drilling operation requires optimized tool designs, advanced diagnostics using real-time drilling parameters, and onsite training of efficient drilling practices and the proper use of rig control systems. The use of efficient modeling procedures to compare alternative drill string and BHA designs provides valuable insights into the string and tool selection process. A method to select the optimal stabilizer contact locations for the BHA tools helps to avoid lateral vibration dysfunctions, and a torsional vibration model can quickly evaluate the resistance of alternative string designs to harmful torsional stick-slip vibrations. Provided the proper hardware, a well-trained driller can be more effective with automated drilling performance evaluation tools that provide real-time drilling parameter recommendations based on optimizing Mechanical Specific Energy (MSE), torsional vibration stick-slip severity, and Rate of Penetration (ROP). BHA lateral vibrations modeling is field-proven and has been applied globally. One case study will show an application of the model to select a BHA design with specified rotary speed sweet spot. The torsional vibration model can be used in both a design process and in a real-time surveillance mode. In one case study, stick-slip vibrations were too severe to drill ahead with a tapered string design that was selected to lower the equivalent circulating density (ECD). The model helped identify the increase in stick-slip resistance obtained by substituting a portion of the smaller pipe with larger pipe. A real-time surveillance tool provides automated drilling performance analysis and makes recommendations to the driller on bit weight and rotary speed. The recommendations are based on the torsional vibration model results, operating in a surveillance mode, and the MSE and ROP. Rig control systems impact drilling dynamics and efficiency in ways that are not well understood by most drillers, and training on awareness and mitigation of these effects can avoid severe dysfunctions.

The objective for drilling development wells is to penetrate the target reservoir, maximize recovery, and ensure maximum production. Determining accurate true vertical depth (TVD) in real time is essential to achieving these objectives in thin reservoirs. Ideally, encountered different formation tops while drilling should match the reservoir structure model within a reasonable accuracy; however, during drilling operations, formation tops frequently become shallower or deeper without any logical reasons. This article presents the causes of this uncertainty and provides a solution to the drilling operations problem in real time. The majority of the drilling bottomhole assemblies (BHAs) consist of drive systems containing a positive displacement motor or rotary steerable system (RSS) and measurement-while-drilling (MWD) tool. The MWD tool includes the survey package that measures the inclination and direction of the wellbore, and a similar package is installed within the RSS. The technique, introduced in a massive field in the Middle East, uses the two survey packages within the same BHA to reduce the TVD uncertainty. Additionally, it increases the survey frequency without impacting rig time and mathematically reorients both survey packages to the center of the wellbore. Results obtained by implementing this technique for the first time in the region are encouraging. The main factors affecting calculating TVD while drilling are measured depth, measured inclination, and survey frequency. The presented technique successfully minimized the errors associated with the measured inclination and errors associated with TVD calculation due to insufficient survey frequency. The presented advanced TVD survey management technique allows the well to be placed according to the plan and maximizes reservoir production. The accuracy of the calculated TVD using traditional MWD surveys is compared with that of this presented technique and shows a significant accuracy improvement. Consequently, when implementing this advanced technique, the formation tops are encountered as predicted by the reservoir structure model. Without implementing this technique, the encountered formation tops were found to be shallower in some wells and deeper in others due to the high uncertainty in the calculated TVD using the standard MWD surveys while drilling. This high uncertainty directly affects the correct well placement within the planned layers and negatively impacts the hydrocarbon production rate. The benefits of this advanced TVD survey management technique in real time are significant. This technique provides high-accuracy wellbore positioning and TVD while drilling with well trajectory corrections being made available to accurately penetrate the target. Additionally, the advanced technique reduces the ambiguity in the different formation tops while drilling to enhance the reservoir production recovery, and eliminates the costs associated with drilling longer sections required to penetrate the target zone.

The island development strategy of the giant offshore oilfield requires the use of extended reach drilling (ERD) design wells. Compared to the typical wells drilled from the wellhead towers in the same field, higher inclinations are required in both the surface hole and intermediate hole to facilitate drilling three dimensional wells of more than 35, 000 ft. While the challenges of drilling the intermediate hole at higher angles had been identified early on due to field experience, the challenges leading to stuck pipe events encountered in the surface hole were not anticipated due to limited experience drilling high angle surface holes in the region. Historically total loss of returns has been a common issue in the region when drilling the surface hole. Typically when drilling from the Jack Ups, the wells are drilled with sea water and high viscosity sweeps once total losses has been encountered. Any potential aquifer flows are diverted overboard. In order to divert the aquifer flows on the newly built Artificial Islands, the fluids must be pumped 200 or more meters to the gulf. Mud cap drilling (drilling with seawater down the drill string with heavy mud in the annulus to control well flows) was implemented to solve the issue of losses and flows on the island. The early wells with surface holes drilled at high angle experienced stuck pipe while tripping out of the hole after reaching casing point, leading to significant non-productive time (NPT) and risking project objectives and planned designs. A detailed investigation was performed, including running six arm caliper logs to better understand the mechanism for stuck pipe events. After analyzing and understanding the issue, operational practices and bottom hole assembly designs have been changed to reduce the stuck pipe risk, and specially designed stabilizers have been manufactured and used to mitigate stuck pipe events. Geologically, significant data gathering within the overburden sequence to characterize lithological, stratigraphic, and diagenetic heterogeneities, as well as structural discontinuities, has improved understanding of aspect ratio and vertical scale of features being drilled that may have caused the previous hole morphology effects. No stuck pipe events have been experienced to date in the surface hole due to the same effects after implementation of the new equipment designs and improved drilling practices.

Most of the industry operators and service companies have developed and implemented a directional drilling collision avoidance rules based on strict controls to prevent well collisions and subsequent human and environmental damage. These rules are formulated based on best practices and mitigation procedures across the industry experience. However, these rules are sometimes found to be severely restricted to the optimal wellbore positioning of wells representing mainly the safe drilling to prevent surface or deep collision risks with offset wells. Historically ADMA-OPCO and ZADCO were adapting the basic collision avoidance rules from its shareholders policy and mainly depends on service companies' internal policy to rely on execution phase which was creating huge well spacing among drilled wells resulting in extreme narrow path for future well placement which was affecting field development severely. The need for a comprehensive collision avoidance practice and policy was eminent when the world- class ERD project with artificial Islands as drill centers was commenced in 2013, which instigated the process for developing a Wellbore positioning and collision avoidance policy for ADNOC offshore concessions operated by ADMA and ZADCO. In general the collision avoidance procedure should define on how to maximize the safety by avoiding or managing the collision with critical offset wells during the planning and execution phases of the drilling program. The scope of this document includes, but is not limited to, a set of anti-collision policies including standards, practices and guidelines to manage the master database structure and integrity, position uncertainty, surface location, survey program, collision avoidance procedure, wellbore survey operation, quality assurance, data integration and communication protocols to the interested parties, etc. Developed policies helped the drilling team to standardize the technical and operational consistency for safe planning, supervision and execution of directional drilling operation activities greatly. Outlining the roles and responsibilities of the well collision avoidance and wellbore positioning procedures eased the operation greatly in an offshore Artificial Island drill center environment with 100s of ERD wells being planned to be drilled. The brief technical details of verity survey technologies and surveys management advancements are covered in the guidelines to get an general education on subject matter to the end user which will help them to identify and finalize the survey program to drill the well safely. The detailed collision risk matrix and risk mitigation procedure guidelines has helped the drilling engineers to conduct the required risk assessment and mitigation plans in place during planning phase itself and supervise it during execution with enough control measures in place. The roles and responsibilities of each service companies involved is categorically mentioned in the policy allowing all parties to implement their contribution without failure.