United Arab Emirates is seeking to become self-sufficient in gas supply by 2030. This has led the country to initiate several exploratory and appraisal projects to achieve this goal. This study covers one such pilot project targeting production from tight gas reservoirs in three wells through coiled tubing (CT) underbalanced drilling (UBD). CT pressure control equipment was rigged up on top of production trees with wells already completed and cemented. A CT tower was used to accommodate the drilling bottomhole assembly (BHA) and eliminate risks related to its deployment. CT strings were designed to reach target intervals with sufficient weight on bit (WOB), suitable for sour environment, and able to withstand high pumping rates with mild circulating pressures. To address the hazards of H2S handling at surface, a custom-fit closed-loop system was deployed. The recovered water was treated on surface and reused for drilling to decrease the water consumption throughout the operations. The plan was to drill three 3/4-in. horizontal laterals in all candidate wells. Each well was completed with a combination of a 4 1/2-in. and a 5 1/2-in. tubing and a 7-in. liner. Five laterals were drilled across the three candidate wells targeting carbonate reservoirs with each lateral having an average length of ~4,000 ft. The achieved rates of penetration varied significantly from 15 ft/min to 30 ft/min while drilling through the various formations. Over the course of the pilot project, several challenges had to be addressed, such as material accretion on the CT string during wiper trips, treatment of return fluids having high H2S content and rock cuttings and ensuring integrity of the CT pipe while operating in severe downhole environments. Solutions and lessons learnt from each well were implemented subsequently in the campaign, such as the use of increased concentrations of H2S inhibitor to coat the CT string, use of nitrified fluids based on changing well parameters to maintain underbalance, thorough pipe management through real-time CT inspection, and adding a fixed quantity of fresh water to the drilling system every day to avoid chemical reactions between the drilling fluid additives and hydrocarbons. The wells completed with this method exceeded production expectations by 35 to 50% across the project, while reconfirming the value of the technology. The use of CT for UBD is still considered a challenging intervention worldwide. Such cases in high H2S environments are rare. This study outlines best practices for a CT UBD and a setup that can be replicated in other locations to implement this methodology with high H2S and when rig sourcing is a concern.

Leak identification across well completions is a crucial operation in the oil and gas industry. A failure of well barriers can result in uncontrolled release of hydrocarbons and pose major risks to personnel and environment. Downhole gauges are widely used to provide pinpoint measurements of pressure and temperature across the completion; however, those measurements alone are insufficient to properly diagnose single or multiple well integrity issues. Alternative well intervention methods are needed to qualitatively estimate the location and number of potential leaks. For the past decade, distributed temperature sensing (DTS) has been used in wellbore completions and surface pipelines with preinstalled fiber optic lines to identify leaks by monitoring and processing temperature profiles across the length of the installation. The proposed methodology makes use of a similar principle, relying on coiled tubing (CT) to deploy the fiber optics and conduct DTS integrity assessment in wells completed without fiber optic lines. This use of fiber optics inside a CT pipe also provides simultaneous real-time downhole measurements, which include CT internal and annulus pressures, and casing collar locator (CCL), for precise depth control and accurate correlation of well parameters. In the south of Pakistan, the tubing-casing annulus pressure of a high-temperature gas well increased to near flowing wellhead pressure at the tubing, giving a clear indication that at least one of the completion components had failed, resulting in flow of hydrocarbons to the annulus. Yet, the high wellbore temperature limited conveyance of conventional logging tools to assess downhole completion integrity. A thorough analysis of well hydraulics was first conducted to gather the possible options to identify the leak using DTS. This enabled the determination of a workflow aiming to create enough differential pressure to generate particular temperature disturbance. CT equipped with fiber optics was run and stationed across the complete wellbore length, and DTS data were acquired for approximately twelve hours under changing well conditions, including shut-in and flowing periods. The acquired temperature information for each phase, along with pressure information, helped to narrow down the location of possible leak points. This methodology enabled the identification of a single, major leak point located at an expansion joint in the completion. The operator was able to riglessly set an annular plug to restore integrity, thus saving significant workover cost and time.

Conventional production logging with electric line is sometimes challenged by the presence of mechanical restrictions in the wellbore. The fragility of production logging tools also impedes the use of electric-line coiled tubing (CT) with the risk of damaging tools across sections with little clearance. This study showcases conclusive flow profiling using distributed temperature sensing (DTS) via fiber optics deployed with CT in a gas condensate well where wellbore access prevented the use of logging tools. Flow profiling via DTS has been used globally in completions where fiber optic lines are permanently installed. Interpretation of those logs usually leverages months of acquired data to invert temperature information and obtain the evolution of flow distribution over time. The proposed methodology instead relies on hours of DTS acquisition through the temporary deployment of fiber optics with CT. A comprehensive sensitivity analysis on key unknown parameters is then performed using a fit-for-purpose thermal-flow simulator to match simulated and acquired temperature profiles, leading to a flow distribution of gas, condensate, and oil in the wellbore. Before the intervention, an evaluation study was run using a flow-thermal simulator to evaluate the expected sensitivity of wellbore temperature to poorly characterized downhole parameters, such as permeability, pressure, or skin. This allows determining the downhole conditions under which DTS is able to detect flow contribution for a specific candidate. During the operation, the CT equipped with fiber optics was stationed across production zones for a total of 06 hours. The data was processed and fed back to the simulator along with reservoir, well data, and surface rates. To further constrain data processing, pressure surveys were acquired during the CT run using a downhole gauge, both during flow and shut-in periods. Unknown reservoir properties were sensitized during data interpretation to obtain a match between acquired DTS profiles and simulated wellbore temperature evolution, which, in turn, yielded an associated flow distribution. The matching exercise being an open-ended mathematical problem, several scenarios were considered, and their results checked against further production characterization of the wellbore and the field. The proposed case study illustrates how this methodology enabled logging in a mechanically-restricted zone and helped determining that the top interval was not contributing to flow. Flow profiling can be performed using a wide range of complementary logging tools, but the evolution of completions over the past few years is increasingly introducing mechanical restrictions that prevent the conveyance of such tools altogether. This study demonstrates that DTS can be a viable alternative for assessing zonal flow contributions. It also discusses the conditions under which this methodology is achievable.

Reservoir heterogeneity, presence of faults, lower coiled tubing (CT) injection rates, precise fluid placement, and uncertainty of downhole dynamics are the major challenges for matrix stimulation of openhole horizontal water injector wells completed across tight carbonate reservoirs in the onshore Middle East. The stimulation strategy implemented over the past decade to address those challenges was deemed ineffective, often leading to a rapid decline in injection rates after the treatments and, therefore, frequent restimulation. Since 2019, a different intervention approach has been implemented, leveraging a workflow based on CT equipped with fiber optics for real-time downhole telemetry and distributed temperature sensing (DTS). Results to date have been encouraging, yielding significant injectivity gains along initial trials. The workflow recently evolved with the inclusion of petrophysics and seismic data during candidate validation to determine a baseline zonation of the openhole section. This critical new step in the stimulation strategy is made necessary by the presence of faults or high-conductivity streaks, whose presence require additional engineering of the fluid placement to avoid early water breakthrough in the producers. During job execution, after the wellbore has been conditioned using a high-pressure rotary jetting tool, DTS surveying is conducted to confirm the conductivity of faults crossing the uncased section and determine the distribution of high- and low-intake sections along the open hole. Adjustment to the pumping sequence—including zonal coverage, volumes, and diversion techniques—are decided based on that information. The prestimulation injection profile, together with petrophysics and seismic data, enables segmenting the open hole into intervals requiring different levels of stimulation, so each section can benefit from a customized treatment that increases injectivity and improves uniformity of injection. Complementary fluid placement techniques and diversion requirements, such as dual injection, are also identified at this stage and generally determined by the level of conductivity of the fault system detected with DTS. During the stimulation stage, fiber-optic telemetry is used to optimize jetting pressure and monitor downhole pressure in real time to ensure fracture pressure is not exceeded. Upon completion of the acidizing stage, another DTS acquisition is conducted to assess the poststimulation injection profile. The workflow enables incremental assessments through the course of the operation, adding flexibility to the operational sequence and the possibility to repeat steps when the expected injectivity gains are not achieved, or a new segmentation of the open hole is required. This reinvention of the matrix stimulation workflow brings new perspectives for acidizing openhole horizontal tight carbonate water injectors featuring highly conductive streaks or faults. Using this methodology can significantly improve results over conventional practices more than twofold based on initial results. It is particularly adapted to wells where reservoir heterogeneities lead to nonuniform injection profiles and the risk to unbalance pressure support in the formation.

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