Permanent instruments to measure pressure and temperature are a regular feature of oil and gas well completions. As wells are drilled in deepwater, high-pressure, high-temperature, high-porosity reservoirs or other challenging environments, these measurements provide valuable data to evaluate reservoir quality and wellbore integrity. Pressure data is routinely used to determine the flow properties of the reservoir with transient analysis. Key performance indicators (KPI?s) are selected by the well operator such as reservoir permeability, pressure, and formation damage index or skin factor; these KPI?s are archived and trended with time to identify production impairments and opportunities for well intervention. Aside from routine well production surveillance, the pressure history allows for assessment of geomechanical changes such as the degree of reservoir compaction and to evaluate the potential of wellbore failure due to compaction-induced displacements. This paper illustrates the use of the pressure and temperature data from a deepwater well completion in the Gulf of Mexico (GOM) to monitor compaction and to understand the possible mechanisms behind a sudden drop of production that took place in early 2007.
1. INTRODUCTION
Oil and gas wells may be instrumented with several different sensors such as fiber optic cables, multi-phase flowmeters, or solids-monitoring devices. Although new measurements and new devices are continuously emerging, the instruments most likely to be found in a wellbore are the pressure and temperature gauges. Permanent pressure recorders have been installed in oil and gas wells for several years, some as early as 1963 as described by Nestlerode[1]. By 1978, ExxonMobil had installed their first permanent bottomhole pressure sensors[2]. In the decades since, the permanent pressure and temperature sensors have become a staple of offshore well installations. Efficient data handling, transmission and archive systems have evolved to ease the process of acquiring data for engineering analysis. Pressure and temperature data are collected and recorded every few seconds. Over the productive life of a well, this will result in gigabytes of data storage requirements. The oil and gas industry has established workflows for using these highfrequency data for production management concerns such as well stimulation[3], measuring reservoir depletion[4], and optimizing future well placement[5]. By following these workflows, engineers are able to efficiently transform the raw data into useful reservoir and production parameters and quickly take action on the well. One of the most common workflows is to use the pressure data and the transient response during a shut-in to determine the reservoir flow properties. Steady-state flow in a porous media is described by Darcy?s Law, which is given in Eq. (1). The transient analysis yields the data necessary for understanding the flow behavior:
(available in full paper)
Key parameters include the product of the reservoir permeability and its thickness, kh, the current reservoir pressure, Pr, and a dimensionless formation damage indicator known as the skin factor, s. As each of these properties is dynamic, it is crucial to the production engineer to know how these properties are evolving with time in order to understand whether the well is performing at its full potential.
