Study Uses Wellbore, Reservoir, Fracture Models To Determine Productivity

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Inconsistent production performance from wells completed in similar pay zones has been observed when shale formations are exploited through horizontal wells. This paper demonstrates the need to couple the wellbore model to the reservoir-simulation and hydraulic-fracturing model in shale formations to optimize well landing, trajectory profile, and long-term productivity. The authors aim to demonstrate and deconvolute the well-trajectory plan with an integrated parametric study that helps to improve well productivity.


To plan a well profile, two critical pieces of information are required: Lateral landing depth, and well trajectory originating from the landing depth. To reach the targeted landing depth, the well trajectory undergoes a certain buildup of curvature deviating from the vertical section and, eventually, when the landing depth is reached, the designed trajectory profile is maintained and continued for the horizontal wellbore. The authors evaluated well trajectory and well productivity on the basis of the effect of the following parameters to guide well-trajectory planning:

  • Hydraulic-fracturing fluid
  • Natural fracture network
  • Wellbore trajectory, undulations, toe up, toe down, or combinations
  • Production operations such as proppant flowback, fracturing choke management, and well shutdown

Geological Review of the Model

A 3D earth model in the Permian Basin for the Wolfcamp shale was used to develop a work flow for determining well landing and well trajectory. The Wolfcamp shale covers most of the Midland Basin and ranges in thickness from 200 ft in the north of the basin to 2,600 ft in the south. The entire play is dominated by a fine-grained, naturally fractured source rock. The depths range from 5,500 to 11,000 ft. The Wolfcamp is slightly overpressured, with the pressure gradient varying between 0.55 and 0.70 psi/ft. In the past few years, the Wolfcamp has become one of the most profitable and exploited unconventional plays in the US. Almost all of the operators are collecting a significant share of their well inventory, which yields over 1,000 BOPD routinely in initial-production rate. The production declines within a short period (6 to 9 months). The recovery factors remain in the single digits for most operators. The Wolfcamp, Spraberry, and Bone Spring formations are the most prolific in the basin.

Defining Landing Depth

The proposed solution considers applying an end-to-end cycle of a streamlined work flow that starts with sampling engineered landing location points in the geomodel defined by the user on the basis of reservoir-quality (RQ) cutoffs. The first step is building the geological model around the sweet spot. This geological model contains petrophysical and mechanical properties of the rock along the depth of the targeted interval.

With the selected choice of landing-depth intervals, hydraulic-fracture geometry is verified for producibility. With an assumed or probable hydraulic-fracture-pumping schedule, hydraulic-fracture simulation is run on multiple injection points selected within these landing depths using a high-resolution, fully gridded hydraulic-fracture model. The depths with hydraulic fractures having the volume best-connected to the injection point are then selected as the possible landing depths for the driller. With the advent of high-­performance computing, the hydraulic-fracture simulations and sensitivity of various injection depths can also be completed in parallel to provide real-time answers to the drilling and completion team.

In the current study, a pilot wellbore with logs is selected to determine the potential landing interval in the Upper Wolfcamp. Analysis of the potential targets uses the data acquired on the vertical pilot wellbore.

Effect of Fracturing-Fluid Selection

After the targeted intervals for landing in the Upper Wolfcamp are filtered using RQ and completion-quality (CQ) analysis, the intervals are evaluated for the hydraulic-fracture geometry using a 3D hydraulic-fracture model. Because the hydraulic-fracture geometry on the planned horizontal wellbore would be dependent on the choice of fracturing fluid, different fracturing fluids are evaluated in this study to determine the optimal landing target. Hydraulic fracture height, connectivity to the wellbore, and pinchout profile are the most important factors in determining the optimal fracturing fluid and the landing target. Therefore, a fully gridded, 3D hydraulic-fracturing model is required. It appears that slickwater with higher viscosity is the most-reasonable fracturing fluid for uniform coverage of the Upper Wolfcamp.

Effect of Natural Fracture Network

To study the effect of the natural fracture network, a horizontal well was landed at Interval 6, and hydraulic fractures were simulated using three sets of synthetic natural-fracture-distribution sets. The hydraulic-fracture geometry was thus generated and the production performance for each case was compared.

The authors have defined three discrete natural fracture (DFN) sets—dense, medium, and rare—to determine the effect of the natural fractures. The density (spacing) of the fractures is the only variable changing between these classifications of fracture networks. Length and orientation of the fractures have been held constant among the fracture sets.

Fig. 1 shows the production comparison for the hydraulic-fracture network created in the three cases. The rare case shows the highest production, whereas the dense case shows the least. Although the dense natural fractures develop the largest surface area, not all of the area can be filled with proppant. High-­viscosity slickwater can penetrate the natural fractures and develop a complex fracture network, but the proppant may not be able to enter the entire hydraulic length because of its larger size. The case of rare natural fractures has the longest fracture length, which extends far into the reservoir and records the highest production.

Fig. 1—Cumulative oil production normalized by the length of the lateral for the three natural-fracture-network cases.

Effect of Wellbore Trajectory

The authors consider 10 well trajectories with different landing points and investigate how these changes affect hydraulic fracturing and production performance:

  • Horizontal well
  • Toe up
  • Toe down
  • Shallow well in low-stress layer
  • Deeper well in low-stress layer
  • Hold horizontal followed by toe down
  • Hold horizontal followed by toe up
  • Landed in good permeability
  • Landed in good saturation
  • Following a surface

High-viscosity slickwater was used to simulate hydraulic fractures in each of the trajectories.

The best production performance is shown by a horizontal well landed at the best RQ and CQ interval identified through the lateral-landing study.

Coupling the Wellbore Hydraulic Model With Reservoir and Completion Models

To understand well-trajectory effect on well production fully, a wellbore hydraulic model is manually coupled with the reservoir and completion model. The 5-year reservoir-completion simulation provides parameters such as oil-phase-productivity index, gas/oil ratio, and water cut as inputs for the wellbore hydraulic simulations. This integrated modeling investigated five out of the 10 well trajectories:

  • Horizontal well
  • Toe up
  • Toe down
  • Hold horizontal followed by toe down
  • Hold horizontal followed by toe up

Of the five well trajectories, the horizontal well produces the most cumulative liquid volume. This result from the wellbore hydraulic model is consistent with the standalone reservoir-­simulation result. The toe-down and hold-toe-down wells underperform compared with others. This is because of liquid accumulation near the toe, which impairs the production from stages close to the toe.


Reservoir quality dictates the maximum productivity of the wellbore, which is then harnessed through completion practices. These completion practices are, however, governed by the completion quality of the rock around which the wellbore has been completed with hydraulic fractures. The combination of these two quality indicators is not enough to determine well productivity. The third element, wellbore trajectory, affects the pressure losses in the wellbore and productivity of the system comprising the wellbore, hydraulic fractures, and the reservoir. Therefore, the authors define the wellbore quality (WQ) as the third parameter to determine the well performance from the unconventional reservoir wellbore.

The WQ consists of a combination of factors that affect pressure losses as soon as the reservoir fluid begins to enter the wellbore, including the connection of the hydraulic fractures to the wellbore, sinuosity of the wellbore, and the production and flowback practices from the completions.


  1. WQ has been defined in this study as an important indicator of the reservoir-to-wellbore and wellbore-to-surface connection. To improve well performance and estimate the production potential of a well in unconventional reservoirs, it is important not only to drive well landing and trajectory profile while considering the RQ and CQ parameters, but also to improve the WQ.
  2. High-viscosity slickwater was the most-appropriate fracturing fluid to be used for the Upper Wolfcamp from the perspective of in-pay connectivity and containment, and achieved over 92% higher cumulative production over slickwater fluid in 5 years.
  3. The natural fracture network has a major effect in determining fracture geometry.
  4. Ten different wellbore trajectories were considered in this study. The horizontal well landed, drilled, and completed in the best RQ, CQ, and WQ shows improved production.
  5. Wellbore hydraulic modeling indicates that the horizontal well trajectory has the best performance in cumulative liquid production compared with the toe-up, toe-down, hold-toe up, and hold-toe-down trajectories.
  6. Most of the well trajectories will experience slugging behavior in the life of the well. A toe-down trajectory tends to delay the onset of the slugging.
  7. In the well shut-in scenarios (described in detail in the complete paper), liquid slugs will form at the lateral for toe-down and hold-toe-down trajectories. The liquid slugs will be a significant challenge for the surface facility when the well is restarted.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190860, “Evaluating the Impact of Lateral Landing, Wellbore Trajectory, and Hydraulic Fractures To Determine Unconventional Reservoir Productivity,” by Piyush Pankaj, Priyavrat Shukla, SPE, Ge Yuan, and Xu Zhang, Schlumberger, prepared for the 2018 SPE Europec featured at the 80th EAGE Annual Conference and Exhibition, Copenhagen, Denmark, 11–14 June. The paper has not been peer reviewed.

Study Uses Wellbore, Reservoir, Fracture Models To Determine Productivity

01 July 2019

Volume: 71 | Issue: 7