This paper documents some of the key findings on the data required and methods used to detect and correct issues with drilling control systems such as auto drillers, top drive active torsional damping systems, and heave compensation systems. It has been found that the rig control systems and how they are tuned can have a significant impact on drilling dynamics. Issues related to drilling dynamics have varied widely among rigs, even among those that are in the same field and that have the same equipment and specifications. The standard answer has been that drilling is different on the ‘other side of the road, river, or anticline', or that one rig crew is better than the other. While there are significant differences in the drilling environment and between crews, recognition of the effects of the control systems employed can explain many of these differences and expand the tools and techniques available to improve drilling performance and reduce dysfunctions. Once the fundamental elements of a control system are understood, the performance limiters identified can often be applied to other rigs in the fleet with different systems via effective documentation of the changes made and their results. Opportunities abound for improvement in oilfield drilling control systems, their basic design, and documentation on how they should be tuned and best used. There are also opportunities in crew training catered to different audiences: Drilling Engineers, Rig Supervisors, Drillers, Directional Drillers, and Rig Electricians. Lastly, there is often a knowledge and communication gap between the software/control/user experience and engineers designing the control systems. Since rig control systems are not usually identified as the source of drilling dysfunction, requests for software or interface redesign have not often been initiated in the past. Not surprisingly, the best progress has been made when four way work groups were formed with all key stakeholders involved: the operator's drill team, internal technical experts, rig contractor and crew, and OEM control systems experts. Investing the time and personnel in this process and establishing group trust has helped prevent gaps in understanding of overall system performance. It also allows each stakeholder to contribute their expertise, raise concerns, and get buy in from their extended teams. This process takes commitment from all parties to change the way work is done, but the performance improvements are immediate and can be clearly seen. Challenges for the future are to continue to upgrade rig site manuals, arrange for more crew training, upgrade the control system design, and to incorporate the control system response as part of the topside boundary condition for future drilling dynamics models.

This paper covers the seven year history of the reservoir drilling campaign offshore Abu Dhabi, from the early use of a solids free, brine/water-based mud to the recent application of non-damaging, non-aqueous fluids with micronized acid-soluble ilmenite. Details are provided on the integration of the filter-cake breakers with the various types of drilling fluids, from dormant drilling fluid additives to delayed, pH and temperature activated breakers. The paper will cover on the operational implementation and lessons learned from applying all these fluids, both in the drilling and completion/breaker placement phases and describes the avenues undertaken to achieve these performance goals. Data related to well information, reservoir rock type and completion type was gathered and analysed. Fluid Interaction and other studies were performed to determine the suitable fluid type, formulation etc. Various additional things were taken into consideration such as offset well data, drilling requirements, environmental considerations, logging requirements and likely mud damaging mechanisms. Extensive lab tests were conducted, some of which included compatibility of various fluids, return permeability, changes to the oil-water ratio, internal phase composition (heavier CaBr2 instead of CaCl2) and a micronized, acid soluble ilmenite as a weighting agent. The breaker systems saw the same extent of refinement, from enzymes to delayed organic acid precursors and chelating agents to evaluate the removal of the fluid filter cake by the breaker. Fluids formulations were evaluated and optimized based on observations. Over eighty extended reach drilling (ERD) wells have been drilled using both Reservoir Drill-in Fluid (RDF) systems: water-based mud RDF, and Non-Aqueous Fluid (NAF) RDF, each with specially formulated Breakers. These wells provided lessons learned which contributed to the current design and formulations which are in use today. Friction Factors (FF) obtained using RDF NAF proved to be much lower than those with RDF WBM. The lower friction factors enabled wells with longer horizontal sections within the reservoir to be drilled successfully and at significantly higher Rates of Penetration (ROP). The use of micronized, acid soluble ilmenite also led to achieving lower ECD as compared to sized calcium carbonate. The evolution of breaker formulations also allowed for longer breakthrough time to be obtained which allowed for better coverage of the lateral, better removal of the filter cake, and ultimately enhanced production through improved inflow profiles. The end result of the continuous improvement in reservoir drilling fluid was a first of its kind non-aqueous fluid that combined the desired properties of low rheological profile for ECD management, low coefficient of friction and being non-damaging.

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.

A giant oilfield offshore Abu Dhabi is being further developed with artificial islands and extended reach drilling (ERD). Several lost returns events while drilling the intermediate intervals using non-aqueous fluid (NAF) have occured. NAF and high mud weights are required to stabilize the shale intervals in the overburden due to high inclinations, but have increased the frequency and severity of the mud losses. To prevent losses while drilling with higher mud weights, combinations of sized ground marble, fibers, and resilient graphite are used to reinforce the NAF fluid to control losses in the formation. With the reinforcement material added to the NAF losses were still experienced on some wells. Traditional leak off type loss circulation material (LCM) pills were trialed but unsuccessful. Due to the NAF damaging the permeability of the rock, treating losses with NAF mud are difficult because the leak off rates are reduced. Reverse gunk was selected as a good option to treat losses in NAF due to the fact that it does not require leak off to cure the losses. The reverse gunk pill relies on downhole mixing to build integrity. Reverse gunk pills were used successfully in wells to build sufficient integrity to maintain shale stability mud weight. This enabled drilling through the unstable shales and to casing point. The successful application of the reverse gunk prevented the need for the contingency liner, which eliminated a hole section and allowed use of the originally planned completion size.

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