Diagnostic Tool Identifies Factors in Well-Productivity Decline

Abstract

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 195331, “Identification of the Decline in Well-Productivity Index Caused by Wellbore Damage Through the Removal of Fluid and Formation Effects,” by Samiha Morsy, SPE, Yan Pan, and Usman Lari, Chevron, et al., prepared for the 2019 SPE Western Regional Meeting, San Jose, California, USA, 23–26 April. The paper has not been peer reviewed. Wells in deepwater reservoirs show significant rate decline with time as the result of various causes. A diagnostic tool for quantification of factors influencing well-productivity decline is presented in this paper. The diagnostic tool helps identify well-stimulation candidates and potentially can help increase production. The work flow presented provides a tool for monitoring well-productivity changes to identify the main causes of productivity decline and to quantify effects on the normalized productivity index (PI). Introduction Most current and future deepwater reservoirs are in structurally deep, high-pressure environments in which reservoir and rock mechanisms that affect long-term well productivity are poorly understood. PI trends derived from field production and pressure data reflect the composite effects of wellbore damage along with changes caused by multiphase-flow and pressure-depletion effects on fluid properties and permeability. However, only PI decline caused by wellbore damage should drive well-stimulation decisions because only stimulation can improve the permeability of the near-wellbore region. In addition, reservoir simulation input PI multipliers used to match well performance should be adjusted appropriately to ensure that the resulting simulated output PI trends are consistent and reliable and to avoid duplication of reservoir and fluid effects that are already captured in the simulation model. Effect of Reference Pressure on Well PI Calculations PI theoretically is estimated with the average reservoir pressure; however, average reservoir pressure may not be estimated accurately for fields where reservoir size and shape are highly uncertain. In cases where the average reservoir pressure is not available, initial reservoir pressure, or the buildup pressure at 1 hour after shut-in, have been used by different operators to estimate well PI. A need exists to understand how these different reference pressures can affect the reliability of the estimated well PI. Equations used to derive well PI, including under pseudosteady-state (PSS) flow conditions, are presented in the complete paper. Effect of Using Different Reference Pressures on PI Estimation: Synthetic Cases A numerical synthetic case is generated to investigate the effect of the reference pressure on well PI. The case represents a circular reservoir 50,000 ft in radius and 30 ft thick. The fluid viscosity is 3.6 cp, and the formation volume factor is 1.1 RB/STB. The reservoir porosity is 10%, and the permeability is 300 md. The skin is increasing with time. The flow rate is constant at 1,000 STB/D, and the well is shut in for 21 periods. PI is calculated at each buildup using a reference pressure from each recognized flow regime. PI using the initial reservoir pressure was also estimated. The first reference pressure is chosen from the wellbore storage flow regime period at 0.01 hours, while other reference pressures are chosen from the infinite acting radial flow (IARF) regime. The PI is calculated finally using the average reservoir pressure during transient and PSS conditions.