The Buda formation in Texas presents extreme challenges to prevent formation damage during drilling operations. After using many fluid selection variations, several operators have determined that underbalanced drilling with native crude is the most optimum method. The initial startup project for coiled tubing drilling (CTD) operations in this formation has been completed, with more activity to come. However, as the preferred recirculation of the native crude drilling fluid presents two major challenges. First, the formation is up to 2% sour, and the native crude is relatively volatile with a low flash point and high vapor pressure.Recirculation of sour crude will lead to double-sided exposure of the coiled tubing, which historically has resulted in extremely short fatigue life. The use of active fluid property testing, in addition to scavengers and inhibitors with defined mitigation plans, reduces the risk to an acceptable level. Significant laboratory testing of the fluid properties as the material degrades with time, temperature, and mixing have been completed. Additional mitigation actions are utilized in conjunction with the laboratory results to further reduce the volatility properties. Internal technical and operational reviews, along with additional sourced subject matter expertise, have challenged existing safety, operational, and technical limits. Operational procedures have been continuously monitored and adjusted to compensate for the adverse dynamic wellbore conditions encountered during the campaign.The discussions within this paper detail the background challenges, laboratory testing, operational/HSE planning and mitigation practices to allow operations to commence. Additionally, the paper covers operational results as the wells are drilled. These results may provide a basis for future operations utilizing extreme fluid conditions in other applications within the industry due to the economic benefits from native crude.

A deviated newly drilled gas well in Western Caspian Sea in Azerbaijan, with a flowing water reservoir pressure of 17,500-psi and a flowing gas reservoir pressure of 12,200-psi was unable to regain flow after an unsuccessful attempt to bullhead produced water back into the well. During the bullheading operation, there was a peak registered pumping pressure of 12,933-psi without admission of fluid into formation. Producing interval was 5880mTVD with a MASP of 9,700-psi for gas reservoir. Coiled Tubing was the most viable option to identify the problem, to solve it and to regain access to the lower completion and then proceed with interval abandonment program. This being an unconventional well in multiple aspects, presented serious challenges accentuated in Safety, Well Integrity Control, Obstruction Removal, and Well Conditioning Plan Forward. Integrity of completion was believed to be compromised by the high pumping pressures applied during bullheading and a confirmed communication between production tubing and "A annulus". After performing 2 rig site visits, an action plan was issued to adjust the platform for a Coiled Tubing intervention for the first time. Points to be developed in the plan were HSE, Structural Analysis and modifications required for proper equipment accommodation. For well integrity control, it was imperative to evaluate the potential scenarios which could have led to the problematic well status. Completion history and specifications were reviewed to assure each of the potential operating scenarios could be controlled without compromising well integrity. On obstruction removal, simulation software was used to design procedure with optimum string, chemicals, rates and fluids to be used for the operation and which contingency fluids considered to be available offshore. It is challenging to perform effective cleanouts in completions with 2 different sizes of tubings (IDs 3.74" & 2.2") combined with restrictions (1.92" nipple), the success is a function of overcoming limited fluid pumping rates, slow annular velocities, particle sizes, cleaning speeds, among others. Well conditioning for future completion operations was planned depending on successful achievements of the coiled tubing intervention. A total of 14 runs with coiled tubing using different BHA configurations were performed to complete the scope. Well was safely and successfully cleaned from a starting depth of 2,512mMD to a target depth of 5,864mMD (5,610mTVD) by removing mud deposits, consolidated sand bridges and completion restrictions. Throughout the cleanout operation, best practices discussed on planning stage were applied to remove multiple obstructions encountered and dealing with potential corkscrewed casing. By accomplishing the well delivery, it is evident that the methodology followed during the planning stage and execution, was crucial to save the well from being lost or abandoned. There was an uncertainty whether the completion integrity was compromised by the high pressures used during the bullheading operation. Novelty in this intervention was the methodology for the risk assessment for an unconventional live well intervention with a 17,500-psi BHP, unseen pressure in the region. Thorough structural analysis was performed to assure the coiled tubing equipment could be placed safely on the platform to condition the well to regain production

A new horizontal well in Asia was not capable of unassisted flow due to low gas production rates and a wellhead pressure below that required to enter the production gathering system. Two zones were identified at the heel that could increase the gas/oil ratio (GOR). Because these two zones had deviations greater than 80 degrees, coiled tubing (CT) was selected for the perforation and stimulation intervention. In addition, mechanical isolation was required to ensure the stimulation fluids entered only the new zones. Accurate depth control was required for three runs: setting two composite bridge plugs (CBPs); deploying CT-conveyed perforating (TCP) guns for opening two intervals; and milling out the two CBPs without taking returns to surface. All these runs were performed with a 2.875-in. tube wire-enabled CT telemetry (CTT) system. For the first time, a tension, compression and torque (TCT) subassembly was used to improve the milling operation. The CTT system consists of a customized bottomhole assembly (BHA) that instantaneously transmits internal (i.e., inside the BHA) and external (i.e., outside the BHA) pressure and temperature, and casing collar locator (CCL) data to surface through a non-intrusive tube wire installed inside the CT. Monitoring the BHA force and torque data in real time helped improve the motor and mill performance and life because the weight on bit (WOB) could be adjusted to the recommended values. For instance, based on the optimum working ranges for the motor used, the operator decided how and when to modify the working variables to achieve a reliable and efficient milling process. The CTT system alone helped set the first CBP at 5363 m measured depth (MD), set the second CBP at 5281 m MD, and perforate the intervals between 5297 and 5306 m MD and between 5152 and 5164 m MD. In addition, the CTT system with the TCT subassembly was used to mill the two CBPs in shut-in conditions, without any stalls. This created a continuous milling operation, reducing the job time and the working fluid volume compared to similar milling jobs using CTT system alone. Comparing this CBP milling job performance with a previous operation in another well with similar conditions (depth, deviation, etc.) using the CTT system alone reduced the milling time for one CBP by 22%. Although the overall job performance exceeded the operator's expectations, the working parameters used during the CTT system with the TCT sub-assembly job were not constant, leaving a few areas of improvement for the upcoming milling operations. For instance, the constant differential pressure and WOB were not used on every milling pass down. The novelty of using the CTT system and TCT subassembly consists of real-time monitoring of BHA data for positioning two CBPs and opening new intervals exactly at the required depths. In addition, this approach enables removal of two CBPs by adjusting the milling parameters to achieve the optimum working parameters for the motor and mill, providing direct and positive financial impact for the operator.

Operator at the Russian segment of the Caspian sea offshore, engineered a project to drill and complete four experimental horizontal extended reach wells with very aggressive trajectories, into tight Oil & Gas bearing formations with further mission to complete them with multiple hydraulic fracturing. This resulted in a selection of complex completion design with multiple shifting sleeves to allow efficient multistage frac treatment and subsequent production of each zone. Technical challenge of the project was to deliver enough force into shifting sleeves to manipulate them with close-open-close cycle, in a horizontal extended reach wellbore with average 2800mMD (1900mTVD) with anticipated excessive proppant accumulation after each treatment, and it was expected to further restrict the required force delivery in extended reach wellbore. Challenges were addressed during well design stage, by using a proprietary engineering simulation software to analyze the large spectrum of the Coiled tubing string with different mechanical properties. Additionally, feasibility study, considered the application of downhole aids to overcome wellbore cleanout issues, helical buckling and friction lock-up, to deliver required force to the shifting devices. A critical part for the effective delivery of the operations was the time spent designing each intervention individually. Having the expertise to perform proper project management, provided the opportunity to identify several potential challenges that could appear during the campaign. Numerous simulations of tubing force analysis were performed, considering different string configurations, in the intent of overcoming the difficulties resulting from the unconventional trajectories of the wells. One important selection made, was the extended reach auxiliary options, which could aid in reaching the target depths with enough WoB to shift the sleeves. The feasibility study also included extensive simulations on options to remove solids from the wellbore on an efficient manner This paper details out the design specification of the Coiled Tubing technologies selected for the projects as well as address the engineering and operational challenges and solutions proposed to deliver the successful offshore campaign. First time use of the large 2 5/8" OD coiled Tubing string in Offshore Caspian sea and related operational and logistical challenges are the novelties discussed in this paper. Paper also highlights the operation sequence and success of the selected pipe design and downhole approach.

Index of sand production is one of the major issues faced in oil and gas wells on the Caspian region. Although there are multiple technologies to address this issue, the application of these technologies require the well to be cleaned before proceeding with any kind of remedial application. Concentric Coiled Tubing (CCT) sand vacuuming technology has brought a massive advantage for efficiently cleaning the wellbore of sub-hydrostatic wells in Caspian Sea. CCT system is the Coiled tubing string inside of Coiled tubing string which essentially provides a smaller second annular return route for the wellbore solids while simultaneously boosting the return pressure and allowing us to clean the sand where the bottomhole pressure (BHP) is low and not enough to support the circulation of fluids used for the cleanout. Cleanout fluid is pumped through the inner string to power the downhole jet pump comprised in CCT bottomhole assembly (BHA) which creates a drawdown that vacuums the solids and circulates the solids back to surface via the CCT annulus. The solid performance of the CCT system has an established track record worldwide and application of this sand cleanout technology brought a solution for recovering many wells with low BHP and has been successfully implemented since 2013, providing a method for cleaning out tons of accumulated sand particles from challenging wells in Caspian Region. With the complex system being used for cleaning out sand and also surface handling of the solids in the return flow from the wellbore, CCT sand vacuuming technology has proven to be effectively functioning in all cases that it was selected for so far. This Paper reviews the design and mechanism of the CCT sand/well vacuuming system as well as the results of several well intervention cases with its successful execution and lessons learned in Caspian region.