Multiphase-Flow Simulation Helps Find Optimal Lateral Length for Best Production
- Adam Wilson (JPT Special Publications Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- November 2018
- Document Type
- Journal Paper
- 84 - 85
- 2017. Society of Petroleum Engineers
- 4 in the last 30 days
- 67 since 2007
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This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 187502, “Production Optimization in the Midland Basin Through Lateral Multiphase-Flow Simulation,” by Yogashri Pradhan, SPE, and Hongjie Xiong, SPE, Texas Oil and Gas Institute, prepared for the 2017 SPE Liquids-Rich Basins Conference—North America, Midland, Texas, USA, 13–14 September. The paper has not been peer reviewed.
Wellbore lateral lengths and uniformity are important for production optimization, affecting liquid holdup and productivity throughout well production life. However, wellbore construction designed for holding leases and completed under time constraints could negatively affect production and limit operators’ potential for their acreage. This paper demonstrates a work flow to determine optimal lateral lengths and trajectories in the Midland Basin by studying the effect of the lateral length and trajectory on well production.
Operators often use a scalar to determine wellbore contributions for wells with an atypical lateral length on their leases. The work flow presented here provides realizations to justify use of this scalar, evaluating whether lateral lengths proportionally increase production, whether wellbore contributions are uniform throughout the lateral length of the wells, and whether various wellbore deviations and tortuosities should have the same scalar applied for estimating well production.
A team investigated the effect of lateral length on well estimated ultimate recovery (EUR). The EURs were calculated from daily production data from 15 operators and then normalized by well lateral length from the top perforation to the bottom perforation. The modified hyperbolic method was used to perform the decline-curve analysis. Simply applying a scalar for the lateral length among the wells would not yield proportionate EURs. When drilled and completed in unconventional reservoirs with multiple-stage hydraulic fracturing, horizontal wells experience a decline in productivity with time because the conductivity of those manmade fractures deteriorates with production and time. Therefore, in order to understand the effect of wellbore trajectory and lateral length on production fully, the team developed a work flow to incorporate an in-depth analysis on transient effects of wellbore hydraulics combined with unconventional reservoir performance over time.
To develop an understanding of reservoir performance over time, numerical models are developed on the basis of previous knowledge, geology, and reservoir data. With respect to the Lower Spraberry and Wolfcamp B wells considered in this study, case studies for which are presented in the complete paper, the numerical models were first calibrated with historical pressure and production data. Fig. 1 displays the work flow that the team developed to combine long-term reservoir performance with wellbore hydraulics.
The team used several production metrics to compare wellbore contributions throughout the lateral affected by the trajectory with respect to different times throughout the well life, including drawdown pressure, pressure decline throughout the lateral, and liquid-holdup results.
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