Abstract
This paper highlights the first successful application of a field deployment of a high-temperature (HT) downhole shut-in tool (DHSIT) in multistage fracturing completions (MSF) producing retrograde gas condensate and from sour carbonate reservoirs. Many gas operators and service providers have made various attempts in the past to evaluate the long-term benefit of MSF completions while deploying DHSIT devices but have achieved only limited success (Ref. 1 and 2). During such deployments, many challenges and difficulties were faced in the attempt to deploy and retrieve those tools as well as to complete sound data interpretation to successfully identify both reservoir, stimulation, and downhole productivity parameters, and especially when having a combination of both heterogeneous rocks having retrograde gas pressure-volume-temperature (PVT) complexities.
Therefore, a robust design of a DHSIT was needed to accurately shut-in the well, hold differential pressure, capture downhole pressure transient data, and thereby identify acid fracture design/conductivity, evaluate total KH, reduce wellbore storage effects, properly evaluate transient pressure effects, and then obtain a better understanding of frac geometry, reservoir parameters, and geologic uncertainties. Several aspects were taken into consideration for overcoming those challenges when preparing the DHSIT tool design including but not limited to proper metallurgy selection, enough gas flow area, impact on well drawdown, tool differential pressure, proper elastomer selection, shut-in time programming, internal completion diameter, and battery operation life and temperature.
This paper is based on the first successful deployment and retrieval of the DHSIT in a 4-½" MSF sour carbonate gas well. The trial proved that all design considerations were important and took into consideration all well parameters. This project confirmed that DHSIT devices can successfully withstand the challenges of operating in sour carbonate MSF gas wells as well as minimize operational risk. This successful trial demonstrates the value of utilizing the DHSIT, and confirms more tangible values for wellbore conductivity post stimulation. All this was achieved by the proper metallurgy selection, maximizing gas flow area, minimizing the impact on well drawdown, and reducing well shut-in time and deferred gas production. Proper battery selection and elastomer design also enabled the tool to be operated at temperatures as high as 350 °F. The case study includes the detailed analysis of deployment and retrieval lessons learned, and includes equalization procedures, which added to the complexity of the operation.
The paper captures all engineering concepts, tool design, setting packer mechanism, deployment procedures, and tool equalization and retrieval along with data evaluation and interpretation. In addition to lessons learned based on the field trial, various recommendations will be presented to minimize operational risk, optimize shut-in time and maximize data quality and interpretation. Utilizing the lessons learned and the developed procedures presented in this paper will allow for the expansion of this technology to different gas well types and formations as well as standardize use to proper evaluate the value of future MSF completions and stimulation designs.
Gas flow modeling in wells
