Every project targeting an underground resource ends up with some sort of excavation. When looking for water, oil and gas, or geothermal energy to name a few, it means drilling a well. Projects that start with drilling a hole in the ground, and pass it on later to others that will make use of it, are seldom successful. The well designers have to know what is expected from the wellbore to select the most appropriate method to construct it. The well will be the place of measurements, of fluid movement (inflow or outflow, placement of a treatment, stimulation or plugging), the place where tools must be run in and safely retrieved.

Because the operations performed at the bottom are the very purpose of drilling, a well is always designed from bottom to top. In other words, what is expected at the bottom and what will be done there determines some design parameters such as completion technique, stimulation methods, placement issues, selectivity, minimum diameter, etc... To design a well that fulfils its missions, the bottom hole completion technique and any inner well requirements must be determined before the casing strings and hole size diameters can be designed.

A well can be defined as a hole in the ground, but it only achieves it propose when equipped accordingly. The main elements to consider are:

• a target (reservoir rock, fault, temperature, etc.)
• a trajectory (from the surface location to the defined target)
• an internal diameter (optimized for the project purposes)
• an isolation system to prevent annular flow, i.e. isolating rock formations from the well, but also between themselves.
• a system that ensures good communication between the target (geological formation) and the well.

The above-itemized elements have to sustain for the lifespan of a well and therefore need to be designed carefully. The internal diameter will limit the size of the equipment that can be run in. It also determines the frictions associated to fluid flow, and therefore the energy efficiency of the entire project.

Additional equipment can be deployed in wells such as pumps, tubing, packer or valves. These are usually retrievable and do not necessarily need to be designed to function for the life span of a well. However, the well has to accommodate them.

The trajectory will determine how the target is penetrated, and will therefore affect reservoir flow conditions. It may also limit wellbore intervention options; when the deviation from the vertical is below 60°, tools can be conveyed with slick line (cable), at a bigger angle, a coiled tubing, a motorized tractor or a work-over rig will be necessary to perform these tasks. A high dogleg severity will prevent running the tools that would be damaged when bent through sharp curvatures.

Isolation is most often provided by steel pipes (casing strings) that are cemented in place. The cement prevents annular flow (outside the casing) and supports the borehole wall. The cement is injected in a liquid slurry form inside the casing and flows upward in the annular space. The drillers wait for the cement to set before drilling can be resumed. Achieving a good zonal isolation can be challenging: It starts with a well in-gauge hole and involves the application of best cementing practices. These practices include efficient pipe centralization and pipe movement during the cementing operation. The cement formulation must prevent its degradation with time and respective to the high temperature associated with geothermal production. The pipe itself has to be construed for the fluids it will accommodate (especially in a corrosive environment). The connections used have to bear the tension as well as the compressions linked to the installation and to the thermal stresses during injection and production phases.

The connection between the reservoir and the wellbore will determine many parameters:

• the reservoir flow pattern and fluid velocity
• the near wellbore pressure drop often referred to as “skin effect”
• the ability to place stimulation treatments where they are needed (and not necessarily where they want to go)
• the ability to plug zones that are not desired anymore.

1. A well is always designed from bottom to top. When stimulation is contemplated, the treatment placement technique will determine the connection method between the reservoir formation and the well. If wellbore stabilities issues are expected, the design must also include a procedure to ensure that the well stays open for its purpose and lifetime. In a long open hole, control is extremely limited, both when circulating fluid during the geothermal plant operation, and when injecting hydraulic or chemical stimulation fluids.
2. It is much more difficult to achieve successful injector wells than producers. Because the reservoir rock is a very large and efficient filter, every solid in the drilling, completion and injection fluids will be filtered at the reservoir face and plug the reservoir. All injector wells should be flowed back (produced) after completion and before injection starts. Whenever solids are used for well control purposes, they must be either removed through flowback or through dissolution, hence selected accordingly. To flowback a well, reservoir pressure helps. Therefore, it is always wise to drill injector wells when sufficient reservoir pressure is still available for that purpose.
3. Blind chemical stimulation (almost) never works. Efficient chemical stimulation requires:
   • knowledge of the damaging product to be removed
   • location of the damage
   • means of properly placing the chemical treatment to the damage location
   • fluid additives and pumping sequence that will prevent additional damage through corrosion, pitting, or precipitation.
4. Wellbore long-term integrity is the driver for casing selection and zonal isolation. Load cases and stress checks must be performed on all casing and liner strings. Cement slurry design and best cementing practice must be applied.

Casing

Steel pipe that is run in the hole after drilling, it is cemented in place to support the hole and isolates the annular space from the inner space.          

Coiled tubing

Steel pipe of small diameter that is used for intervention, i.e. conveying tools or circulating fluid into a well. The pipe is coiled onto a reel and run in the hole with a hydraulic injector.

Completion

All hardware run and operation performed after the well is drilled, cased and cemented. Completion is often referred to as bottom hole completion for the aspects dealing with the connection between the well and the reservoir (open-hole, perforations, sand screen, etc.) and upper completion for the system the safely conveys the fluids between the bottom and the surface (pumps, tubings, packers, etc.)

Damage

Impairment to flow generally creating a pressure drop next to the wellbore thus reducing the productivity or injectivity. Damages include scaling, solid invasion, mechanical impairment, emulsions, etc.

Dogleg

Dogleg refers to the curvature of the well trajectory: the higher the dogleg severity, the sharper the turn or the shorter the curvature radius.

Packer

Hardware equipment composed of a steel mandrel mounted with elastomeric sealing elements (packings). A packer seals the annular space around a piece of pipe such as a tubing.

Placement

Often used for fluid injection, placement refers to defining an accurate spot where the treating fluid is to be injected.

Plugging

In well intervention, plugging often refers to injecting a very viscous fluid (polymer) or particulate material (solids, cement) or any fluid that will create enough damage into or in front or a permeable rock formation to eliminate further leaking into or inflow from that formation. A plugged formation is sealed from the wellbore.

Reservoir

Rock mass with some ability to hold and circulate fluid (porosity, permeability, transmissibility) used for injection or production. A well normally connects the surface to a reservoir.

Selectivity

Ability of a completion to produce or inject from and into specific locations. This feature is desirable when a single well penetrates multiple targets that need to be accessed independently. 

Stimulation

Technique used to enhance the productivity or injectivity of a well. Most common stimulation techniques include hydraulic fracturing and matrix acidizing.

Tractor

Hydraulic or electric device used in highly deviated wellbores to pull either cables of coiled tubings when gravity is insufficient the tractors runs them to bottom.

Treatment

Any service performed in a well for a specific purpose. Treatments include stimulation, perforation with explosive, remedial work of all sorts.

Tubing

Steel pipe conveying production or injection fluids between the reservoir and the surface. Many geothermal wells do not have tubings and use the full diameter of the casing for that purpose.

Work-over

Light rig with limited drilling capabilities usually used to run tubings and perform any kind of well completion or intervention.