Multiphase-Flow Simulation Helps Find Optimal Lateral Length for Best Production
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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 man-made 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.
Analysis of Well Performance
The team first built a single-cluster dual-porosity model for each well by assuming that all clusters drain symmetrically and then calibrated the models with corresponding production history. The fracture half-length was first estimated from rate transient analysis (RTA) and then further tuned through history matching. The grid thicknesses along the wellbore are logarithmically changed to optimize for high fluid velocities around the wellbore and hydraulic fractures. The porosity of the matrix was estimated from petrophysical analysis. Permeabilities of the matrix and fracture were determined through RTA and petrophysical analysis initially and later tuned through history matching pressure and production data. The models were calibrated by use of historical production data (i.e., bottomhole flowing pressure, oil-production rate, water-production rate, and gas/oil ratio).
The objective of the wellbore-flow simulator is to study the level of drawdown throughout the lateral and liquid holdup by combining reservoir productivity for any given time. Casing and tubing parameters were consistent with the real candidate setups, with the exception of synthetic cases’ trajectories. The tubular rugosity for the lateral length is consistent with the standard rugosity for new production casing along the lateral, allowing the team to investigate friction pressure losses. For each case, wellbore trajectory with an 800-ft vertical section from the heel was modeled in the flow simulator.
On the basis of reservoir numerical-simulation outputs, the team imported the forecast reservoir pressure, gas/oil ratio, and water cut directly into the wellbore-flow-simulation models. To investigate the pressure drop along the lateral accurately, the formation productivity first was calculated with the forecast production and predetermined drawdown-pressure profile. Then, the formation productivity was normalized by the completed lateral length for the candidate wells. The team then used the normalized productivity index (PI) with respect to the original lateral length of the well for all of the synthetic cases in the same formation. The team did not consider the effect of possible completion complexity for longer lateral lengths, instead assuming the same PI for a given timestep. Therefore, the normalized PI value would be the same for cases that have 15,000-ft or greater lateral lengths in the same formation discussed in this paper.
The simulator requires pressure-boundary conditions with respect to the top of the wellbore. In these truncated cases, the “top” would be the top of the vertical section. These pressures were determined by using the flowing bottomhole pressures from the reservoir-simulator outputs as a reference. Then, the group subtracted the hydrostatic and significant frictional pressure losses to obtain an accurate estimate of the pressures at the top of the vertical section.
To investigate the effect of lateral length and trajectory on oil and gas production, the team developed a work flow by integrating a reservoir-performance model and a horizontal-wellbore-flow model.
From a well-production perspective, the toe-up wellbore trajectory appears to result in the best oil and liquid production consistently, while the undulated wellbore trajectory results in the worst oil and liquid production given the two sets of fluid pressure/volume/temperature (PVT) data and reservoir properties that the team studied.
Similar to the findings from previous studies, this study revealed that scaling well performance is not conclusive through lateral length. However, on the basis of the limited case-study results, the team determined the effectiveness of the aforementioned scaling factors to estimate EUR by assuming homogenous reservoir properties and homogenous completion. More case studies are needed to cover wide ranges of reservoir-fluid PVT conditions and other reservoir properties.
Assuming consistent drilling and completion times for all trajectories for the same lateral length, perfect toe-up trajectories will yield higher EURs. However, to determine the optimal lateral length and trajectory, one should consider not only the numerical-model-based EURs but also formation geology, drilling and completion time and corresponding cost, increased completion complexity for longer laterals, surface footprint, and other economic factors.
Trajectories could dictate wellbore contributions and drawdown per lateral foot. With toe-up-trajectory cases, the majority of the wellbore contribution could come from the toe-side perforations; with the toe-down-well cases, the majority of the wellbore contribution could come from heel-side perforations. A perfectly uniform trajectory could optimize wellbore contribution throughout the lateral by limiting liquid holdup at earlier times, with an exception at the heel.
For a limited time, the complete paper SPE 187502 is free to SPE members.
Multiphase-Flow Simulation Helps Find Optimal Lateral Length for Best Production
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