During most hydraulic fracturing operations, coiled tubing (CT) is used as a contingency option for well cleanup in the case of sand screenout. An alternative improvised solution is presented introducing a single-shot circulating valve into the frac string to help minimize additional resources related to CT procedures, thus reducing costs and enhancing operational performance. The tool is positioned above the retrievable frac packer to provide circulation capability to reverse out proppant sand without well intervention activities. Setup, operating procedures, concept evaluation, and performance of the single-shot circulating valve used to reverse proppant sand from the frac string are discussed. A single-shot circulating valve in the frac string provides additional liquid flow pass for recovering excess sand inside the frac string to the surface. Intensive laboratory testing was performed to evaluate tool function in worst-case scenarios of a highly deviated well with proppant sand packed above the circulating ports. During field operations, activated pressure tolerance was defined by incorporating rupture-disk reliability and temperature decrement effects during hydraulic fracturing to help ensure the operating pressure did not impair the fracturing operation or well integrity. Lastly, a cleanout procedure was meticulously planned to help prevent pipe sticking situations caused by sand fallout in the annulus. The single-shot circulating valve, typically deployed during drillstem testing (DST) operations, proved successful circulating out the proppant-sand column packed inside the tool during both laboratory testing and field operations. With precise hydrostatic pressure calculations, the burst pressure was reliable, meaning no premature activation occurred, and the rupture-disk burst within the designed surface pressure tolerance of ±400 psi. During reverse circulation, pumping pressure was maintained within an acceptable range (the maximum pumping rate across the circulating ports was 8 bbl/min) and no visual tool damage occurred. Deploying comprehensive engineering and operating procedures (e.g., defining the operating envelope to maintain a higher casing pressure than drillpipe pressure), the frac string and retrievable downhole frac packer were free of sand and successfully retrieved, even during a screenout scenario. Based on the success of the prolonged two-year fracturing operations, the proposed approach is appropriate for fracturing using a single-shot circulating valve as the primary contingency equipment during screenout, replacing CT intervention for this application. This alternative method resulted in improved safety and operational efficiency by eliminating on-rig CT operations when screenout pressure is trapped in the string in addition to significant cost savings attributed to eliminating the extra standby resources of a CT package. This innovative approach, which applies functions of a downhole well-testing tool during hydraulic fracturing, requires both circumspect engineering consideration to define a proper operating envelope and comprehensive operational procedures to help mitigate operational risks.

Bottomhole pressure is one of the most important sources of data used to determine reservoir characteristics. By analyzing the manner in which bottomhole pressures change with time and flow rate, properties can be derived such as permeability, skin, boundaries, and reservoir pressure, which can enable the evaluation of hydrocarbon reserves and make economically feasible decisions. Downhole pressure data in production wells are most commonly acquired by running downhole pressure gauges on slickline into the wellbore. However, in offshore wells in remote locations, there can be major deterrents to capturing bottomhole pressures using slickline. Examples of these limitations include equipment and manpower availability, crane functionality, and offshore accommodations. Furthermore, there can be physical limitations to data acquisition from the presence of sour gas, high bottomhole temperatures, high wellbore deviation, or mechanical obstructions that can prevent the use of downhole gauges in the well. This paper presents an innovative method for acquiring the needed bottomhole pressures in production wells when traditionally used methods may present challenges. An operator in the Gulf of Thailand wanted to obtain downhole pressures on their production wells but did not wish to run slickline and downhole gauges because of the concerns specified above. A new self-powered intelligent data-retriever system was suggested to the operator as it offered a method that could derive accurate bottomhole pressures without running downhole gauges. The new system consists of a high accuracy, high resolution pressure gauge and a companion bottomhole pressure conversion algorithm. The pressure gauge is installed on the wellhead and captures high-frequency surface-pressure data. The conversion algorithm uses the surface pressure data, along with wellbore information, and fluid properties to calculate downhole pressures. The results of a series of tests with the self-powered intelligent data-retriever system demonstrated that the system can provide accurate bottomhole pressure results in production wells. These facts will be verified by the test results as well as the case history, both of which will be presented in this paper. This technology was designed to reduce the cost of capturing downhole pressure data, lessen many of the logistical concerns that could occur when using traditional systems, eliminate the risks of a downhole gauge getting stuck in the wellbore, and acquire necessary data when downhole environments are corrosive.