After oil companies have drilled an exploration well, a delineation well will be drilled to conclude the gas and oil reserves. To bypass the mud filtrate invasion, the new well is perforated with deep penetration perforator, starting from the bottom-most layer. A well test is then conducted to get flow test data, fluid sampling as an addition to previously available data such as structure and isopach maps, water-oil contact (WOC), and porosity distributions. After doing some overlays, production forecasts, bubble mapping, and economic analysis, an engineering team including drilling engineering and subsurface prepare a proposal to drill more wells completed with the coordinates to drain the hydrocarbon and put the field into the development stage and submit it to the top management for approval.
Generally, every well has a similar completion design and type. However, after drilling operation is completed to Total Depth (TD) required, additional data collected during drilling will determine the final completion structure. In a drilling campaign, only a slight change from the original plan is allowed for final completion to prevent unnecessary unplanned costs.
Some engineers prefer completing the wells horizontally since it maximizes the well contact with the reservoir making it more feasible for the low permeability reservoir. Unfortunately, the cost to drill a horizontal well is much higher than a vertical well. The project NPV (Net Present Value) will determine the final completion types.
There are many completion types and designs to choose from based on the reservoir and geomechanical data. Traditionally, the completion decisions are only for drilling concerns to minimize costs and risks (related to wellbore stability) in drilling operations. Figure 1 shows additional consideration to complete a well for better NPV based on probable reservoir failure mechanism.
The probability of a reservoir failure mechanism is evaluated after doing reservoir modeling, geo-mechanical modeling, and material modeling. This is a complicated process and involving multi departments, not just drilling groups.
A geological model combined with a geophysical model is required to build a reservoir model. A reservoir simulator will use the models and other available data such as core data, BHP, fluid data, WOC, and flow test. A production forecast will be produced by the reservoir simulator which will be fed into economic modeling to find the NPV of the projects.
An open hole caliper data and leak-off test data are also considered to determine the distributions of stress magnitudes, stress orientation, and pore pressure dependence. A geo-mechanic model might conclude that the reservoir has a reservoir compaction problem. An oil reservoir that has compaction and shear failure might require a horizontal well completion. If the permeability is low, hydraulic fracturing will be suggested and then a frac pack or gravel pack is required to keep the reservoir strong. To anticipate significant reservoir stress changes during production, the well trajectory must be away from existing wells.
A production correlation to other wells must be considered to see the possibility of multiphase liquid flow, for example, if the second well was watering after 30 days, we expect multiphase flow from the next well at the same horizon. Sometimes, a reservoir that has been compacted well has a positive impact since it could contribute to giving drive energy. A low permeability due to compaction can be improved by hydraulic fracturing.
Finally, Figure 1 can be used as guidance to design well completion. There is four failure mechanism which are reservoir compaction, shear failure, fault-reactivation, and multi-phase flow. Most oil and gas wells have one of the problems. Oil wells in mature oil and gas fields have multiphase liquid flow. A periodic stimulation is a common practice in that kind of field.