The success of drilling new horizontal wells depends on connecting the well’s surface location with the targeted formation while achieving the desired lateral length. However, the choice of the surface locations can be limited due to difficulties obtaining the permits to drill on these locations. This creates more deviated wellbore designs and decreases the optimized lateral length. To avoid this, a risk matrix will be developed to evaluate the maximum lateral length for different surface locations.

The first step to creating the risk matrix is to derive a geometry-focused torque and drag model. This model will utilize the wellbore’s step-out and geometrical torsion, which are resulting of both a deviated well design and a far surface location. In this paper, the step-out for any given well path design will be considered as the sum of the horizontal projections of all the deviated segments of the well trajectory above the last curve’s KOP. The calculation of the step-out will be incorporated into the model, then will be used to calculate the maximum lateral length versus the step-out.

A torque and drag model with the simplicity of the soft-string model was created while taking into consideration the wellbore’s geometrical torsion to capture the effect of the well’s trajectory on the axial forces and the torque. This effect will partially simulate the deformation of the drill pipe using simplified mathematical expressions comparing to the calculations of the stiff-string model. This methodology resulted in the model to be more sensitive to the axial force than the torque.

The built risk matrix uses the derived model to highlight one of two mechanisms that determine the dominant constraint that limits the drilling process: either reaching the maximum hook load or the maximum torque, based on the wellbore design. These limits depend on the rig’s capacity and the drilling company. The risk matrix summarizes multiple designs to conveniently compare between different step-out values and their respective maximum later lengths. The risk assessment is quantitative rather than qualitative and is reflected as the percentage used of the dominant constraint for the given designs and the interval of the lateral lengths at which this percentage is reached. The optimum surface location with its step-out is then chosen easily from the created risk matrix.

The built model takes a middle position between the soft-string model and the stiff-string model by capturing the geometrical torsion along the wellbore trajectory. This approach enhances the geometrical optimization when calculating the axial force and the torque. The simplified mathematical derivation incorporates the step-out into the model, thus creating the risk matrix to optimize the lateral length based on the surface location.