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Telemetry systems with coiled tubing (CT) have been extensively used in the last decade for many types of operations, such as stimulation and logging. Many studies, reporting improved safety, and efficiency and reduced cost, have been published about using CT-conveyed telemetry systems with electrical wires, optical fibers, and, in the last year, hybrid wire-optical fiber tubes. In this paper, a new telemetry system consisting of multiple single-point sensors in the bottom hole assembly (BHA) and CT-conveyed electrical wire is reported to help optimize matrix acidizing stimulation in real time. While distributed temperature sensing (DTS) and distributed acoustic sensing (DAS) with CT-enabled optical fiber telemetry systems have been traditionally used for improving the treatment placement during matrix acidizing operations, they have several limitations. Firstly, the optical fiber is placed inside CT. Thus, the distributed data is acquired over several-hour-long periods with the CT stationary in the well, after pumping has stopped. Secondly, the mathematical models published in literature to convert the distributed data into flow rates along the CT length are very complex. All distributed data is qualitatively visualized in the CT cabin and interpreted by the personnel on location. Quantitative data interpretation is usually performed after the operation was completed. These two limitations can be overcome by using multiple single-point temperature sensors in the BHA, that are in direct contact with the wellbore fluids. The results from two matrix acidizing operations performed in the Middle East in 2020 with two different CT-conveyed telemetry systems are discussed and compared. The first telemetry system used an optical fiber inside the CT. DTS data was used to qualitatively visualize the temperature profile during several hours after bullheading the treatment. The second telemetry system used an electrical wire and three single-point temperature sensors located in the BHA to qualitatively visualize the temperature profile along the BHA while pumping the treatment through the CT and jetting it radially through the BHA. The advantage of the optical fiber system was that distributed temperature data was acquired along the entire CT length. The advantage of the multiple single-point sensors system was that the temperature data was acquired in real time, promptly helping the personnel on location decide to adjust the treatment pumping schedule on the fly. This is the first study available in literature consisting of field data acquired by using two different CT-conveyed telemetry systems during two matrix acidizing operations. Temperature data and learnings from the two telemetry systems are explicitly compared, helping the industry understand how the matrix acidizing operations can be improved by placing the optimum volume of acid at the required depth for best post-stimulation well productivity and lowest stimulation cost.
Telemetry systems with coiled tubing (CT) have been extensively used in the last decade for many types of operations, such as stimulation and logging. Many studies, reporting improved safety, and efficiency and reduced cost, have been published about using CT-conveyed telemetry systems with electrical wires, optical fibers, and, in the last year, hybrid wire-optical fiber tubes. In this paper, a new telemetry system consisting of multiple single-point sensors in the bottom hole assembly (BHA) and CT-conveyed electrical wire is reported to help optimize matrix acidizing stimulation in real time. While distributed temperature sensing (DTS) and distributed acoustic sensing (DAS) with CT-enabled optical fiber telemetry systems have been traditionally used for improving the treatment placement during matrix acidizing operations, they have several limitations. Firstly, the optical fiber is placed inside CT. Thus, the distributed data is acquired over several-hour-long periods with the CT stationary in the well, after pumping has stopped. Secondly, the mathematical models published in literature to convert the distributed data into flow rates along the CT length are very complex. All distributed data is qualitatively visualized in the CT cabin and interpreted by the personnel on location. Quantitative data interpretation is usually performed after the operation was completed. These two limitations can be overcome by using multiple single-point temperature sensors in the BHA, that are in direct contact with the wellbore fluids. The results from two matrix acidizing operations performed in the Middle East in 2020 with two different CT-conveyed telemetry systems are discussed and compared. The first telemetry system used an optical fiber inside the CT. DTS data was used to qualitatively visualize the temperature profile during several hours after bullheading the treatment. The second telemetry system used an electrical wire and three single-point temperature sensors located in the BHA to qualitatively visualize the temperature profile along the BHA while pumping the treatment through the CT and jetting it radially through the BHA. The advantage of the optical fiber system was that distributed temperature data was acquired along the entire CT length. The advantage of the multiple single-point sensors system was that the temperature data was acquired in real time, promptly helping the personnel on location decide to adjust the treatment pumping schedule on the fly. This is the first study available in literature consisting of field data acquired by using two different CT-conveyed telemetry systems during two matrix acidizing operations. Temperature data and learnings from the two telemetry systems are explicitly compared, helping the industry understand how the matrix acidizing operations can be improved by placing the optimum volume of acid at the required depth for best post-stimulation well productivity and lowest stimulation cost.
Many unforeseen circumstances can occur when coiled tubing (CT) is deployed into a well with differential pressure sticking being one such potential problem. Diagnosing wellbore data before operating on a well is important but does not eliminate the possibility of stuck CT. With the increase in use of CT on wells with extreme conditions, the requirement to find solutions that can help retrieve the CT and its bottom hole assembly (BHA) is crucial. When using conventional CT equipment, the operator will have access to several parameters, such as weight, circulating pressure, wellhead pressure (WHP), and depth. However, all these are surface parameters, meaning they are obtained based on the surface conditions. Having accurate downhole information to accompany the surface data can be much more helpful when encountering differential pressure sticking situations. This paper presents the application of real-time hybrid CT (RTHCT) technology to overcome stuck CT. The technology incorporates a 4mm hybrid cable injected into a CT string and includes a modular sensing bottom-hole assembly (MSBHA) providing key downhole information. Internal and external pressure and temperature, casing collar locator, gamma-ray, compression, and tension are all examples of the downhole data. A flow-through camera was also added to the BHA to provide 360° visibility in the multilateral well, resulting in a high-value BHA with a total length of approximately 36ft. The RTHCT technology was initially utilized to stimulate a multi-lateral well composed of 2 legs. The CT became stuck while displacing L1 lateral, which had 6-1/8in internal diameter and 2,647ft lateral length. The reason the CT became stuck was ambiguous. But upon careful evaluation of the wellbore information, it was determined that it was likely due to the differential pressure because L1's lateral open-hole section had a large variance in reservoir pressure (up to 680psi difference). This paper presents some lessons learned when encountering a stuck CT scenario and the benefits of utilizing the RTHCT technology in challenging well conditions to successfully retrieve the CT. With the RTHCT technology, the bottom hole pressure (BHP) was determined allowing the downhole sticking point to be estimated. Higher overpull values were then applied along with additional pumping whilst remaining within the operating limits of the BHA.
Inflatable packers have been the preferred technique for the selective placement of chemical treatments in a wellbore with Coiled Tubing (CT). Traditionally, these have come with some limitations, such as power supply, Real-Time (RT) positioning, surface control, differential pressure activation, ball drop setting, tension, reciprocating set systems, and the ability to quickly change the tool flow path based on treatment response. This paper discusses the first electrically controlled packer implementation that drastically improved operational efficiency in Iraq. This case relates to a mature field in Iraq where precise selective acidization of vuggy carbonate zones with high permeability contrasts was required. The operation was carried out successfully with an electrically controlled packer suitable for acid that provided real-time downhole insight to improve the decision-making process and a precise, flawless acidizing operation. Additionally, the electric actuation system enabled independent control of the flow path position throughout the operation, allowing fluid injection above or below the element to suit the requirements of the operation as needed. The unique solution provided in this paper confirms the benefits of customizing fiber optic and electric technology with an inflatable packer to accurately place the element and selectively stimulate zones with high permeability contrast. A RT downhole sensor module also provides critical information to ensure the operation is carried out as intended. The particular sensors that helped carry out this operation included the Casing Collar Locator (CCL) and Gamma-Ray (GR) to correlate depth, internal and external temperatures, a load module, and internal and external pressure measurements to precisely position the packer in between two layers of a narrow interval without exceeding either the reservoir frac pressure or the packer element differential pressure. This revolutionary technique was successfully implemented on an injection well, saving more than 24 hours of intervention time and allowing early injection to reduce costs for the customer. The CT Electric Inflatable Packer (EIP) enabled the splitting of the operation into two treatments, above and below the packer, during the same run. The approach to this intervention increased operational efficiency while reducing waste to optimize the overall well intervention cost with RT data. This paper describes how a new versatile EIP technology can improve operational efficiency and reduce non-productive time on various applications, such as selective treatments, multiple selective acidizing of sleeves, clusters, intervals, water shut off with sealant fluids, or chemical sand consolation with resins.
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