Directional Drilling Candidates
The GeoSteering process begins long before the well starts drilling.
Each reservoir is unique, so obtaining a comprehensive understanding of the reservoir is the first step in planning a GeoSteering project. Optimization of reservoir performance is the primary reason that a horizontal well is drilled, however, each well may also have critical secondary objectives.
There is no standardized wellbore plan that will work in all reservoirs. A development plan should exploit the reservoir morphology, matrix and fracture porosity, permeability and porosity distribution, the type of reservoir drive, and the fluid content. The wellbore plan is based on the reservoir development plan, and the geosteering strategy is based on the wellbore plan. Each of the situations listed below can be addressed through horizontal drilling, and will require the Geosteering Team to develop a different strategy for each.
Reduced Surface Footprint
Horizontal wells can make economic sense, even in conventional reservoirs, when hostile environments (such as deep water), or environmental concerns (as on Alaska’s north slope) would otherwise prohibit economic development. Horizontal drilling is now part of the continued development plan for Prudhoe Bay Alaska and surrounding fields. This development is being conducted at a lower cost, and with less environmental impact, than would occur through vertical development.
Horizontal drilling is also being utilized in the deep-water Gulf of Mexico, offshore Brazil, Africa, the North Sea and many other areas where costs associated with building a platform would make economic development with vertical wells prohibitive. In this instance, where several wells will be drilled from a template, the Geosteering Team will be particularly concerned with collision avoidance. Planning should include detailed maps of pre-existing wellbores.
Laterally Heterogeneous Reservoirs
Reservoirs that are characterized by lateral heterogeneity often provide some of the best targets for horizontal drilling. Such targets are found in:
- Channel sandstones within a specific stratigraphic interval (Figure 1a and Figure 1b: Map and side views of channel sands).
- Karsted reservoirs (Figure 2a and Figure 2b: Map and side views of karsted reservoirs).
- Reservoirs with discontinuous porosity development and stratigraphic pinch out (Figure 3a and Figure 3b: Map and side views of discontinuous or pinched-out zones).
- Fractured reservoirs (Figure 4a and Figure 4b: Map and side views of fractured and faulted reservoirs).
- These reservoirs are especially challenging for the Geosteering Team, and require detailed stratigraphic maps in order to chart the best geosteering strategy and contingency plans.
Reduced Water Coning
When a horizontal wellbore is drilled at a proper distance above an oil / water contact, it will create reduced pressure draw-down along the path of the wellbore as compared to a vertical wellbore, thereby reducing the incidence of water coning. When planning to drill near a water contact, the Geosteering plan should include an LWD package that can detect the proximity of a water zone before the wellbore actually penetrates the contact.
Heavy Oil Reservoirs
Heavy Oil production has reached record levels in Canada, largely because of the successful fulfillment of a development plan that relies extensively on horizontal drilling. Horizontal wells have been drilled on very close spacing ( + 100 m) to efficiently tap huge reserves of heavy crude. One successful horizontal technology being used is Steam Assisted Gravity Drainage (SAGD). This technique is implemented by drilling two horizontal wellbores, one above the other (Figure 5: Oil mobilized and produced through SAGD).
Steam is injected in the upper lateral. The steam heats the oil, thus reducing its viscosity, and allowing it to be produced from the lower lateral.
Another such example of this technique is Conoco’s Petrozuata development in the Orinoco Basin of Venezuela, which is currently producing more than 120,000 BOPD from horizontal wellbores. In these cases, the Geosteering plan will require special attention to maintaining a close spacing between the two wellbores while avoiding collision.
Waterflood Injection / Production
A number of companies, including Shell, EnCana, and Talisman Energy have used horizontal wellbores successfully to water-flood their fields, reviving fields that were already considered very mature. (In some cases, a few fields had already been waterflooded using vertical wells.) Horizontal wellbores used as injector wells will take fluid at higher volumes with less pressure required to inject the fluid. This increases efficiency while reducing the overall cost of injection when compared to a conventional vertical water flood. In this case, the Geosteering Plan will call for maintaining position below the contact, and should include an LWD tool that can indicate proximity to the pay zone.
Infill drilling
Increasingly, when a company is faced with drilling infill wells to increase drainage density, a horizontal well is considered. Using this option, the operator can replace two to four vertical wells with a single horizontal well, thereby increasing wellbore exposure to the pay zone while reducing drilling and operating costs (Figure 6: Replacing multiple vertical wells with a single horizontal wellbore).
For infill wells, the Geosteering Team must locate all pre-existing wells that could potentially interfere with the trajectory of the proposed well, and plan to closely follow structure and stratigraphy of the pay zone.
Gas Storage Fields
Gas storage wells often include multilateral horizontal wellbores to significantly enhance the annual injection and withdrawal rates.
Evaluating Economic Viability of producing horizontal wells
Though a reservoir might possess the right morphology, drive and permeability to support a horizontal well, no drilling will commence until the costs are determined. The prime concern is whether the development costs associated with a horizontal well are lower than the development cost of the vertical wells it is intended to replace. If the cost of drilling a horizontal well is NOT lower than that of a specified number of vertical wells, then the project should not be drilled – despite otherwise favorable geologic conditions.
The following check list can be used to determine the viability of a project.
1. Determine the projected cost of the well through completion and stimulation.
This requirement means that you must not assume that STIMULATION WILL NOT BE REQUIRED in a horizontal wellbore. The general rule of thumb is that if a reservoir needs stimulation in a vertical hole, then that same reservoir is very likely to require stimulation in a horizontal wellbore.It is important to begin by determining whether stimulation will be required, because the type of stimulation will dictate the type of completion needed to effectively produce the well, and also may determine the optimum length of the lateral section. There is no reason to drill more hole than it is possible to complete.The completion type will dictate the hole size, which will affect casing sizes and ultimately impact the entire well plan. It is therefore necessary to break down the to cost per lateral foot through the build section, then determine the estimated cost per foot in the lateral section. Remember, the cost per foot in the lateral section will generally increase as the length of the lateral section increases, due to the increased time required to make a trip, as well as any complications of increased torque and drag, etc. Generally, the formation itself may ultimately determine the length of the lateral.
2. Determine the drilling and completion cost of a vertical well in the same reservoir.
3. Determine the spacing that a vertical well will require, and more importantly, the actual drainage area within those spacing requirements.
4. The vertical replacement index (the number of vertical wells that one horizontal well of a given length will replace) is then determined by the following equation.
Where:
VRI= Vertical replacement index
L= lateral length
DRv= Drainage Radius of vertical well
DAv= Drainage Area of vertical well 
Sv= Spacing of vertical well in acres
Example:
For a forty acre vertical spacing and a 3960-foot lateral (See Figure 7)
L = 3960 feet
DRv = 660
Sv=40 acres
5. Compare the VRI against the Cost Ratio (CR) between the Horizontal well and the vertical well.
In order to justify the cost of drilling a horizontal well, a typical oil company will require the VRI to be at least 1.5 times the cost ratio.For instance, in an area where a vertical well costs $450,000 with a forty acre spacing and a 3960-foot horizontal well costs $970,000, then the 
=2.23, which indicates favorable economics for drilling a horizontal well in this case.Conversely, if a typical vertical well in this area was drilled on 320 acre spacing, then the VRI=2.35 and the CR=2.15 Thus the well would probably not be economic to drill.
6. The next step is to empirically determine the productivity multiplier (PM) for the planned horizontal well. The PM is a ratio of the 1st three months of production from the average horizontal well, divided by the first three months production of the average vertical well (Figure 8: Comparing production from horizontal and vertical wells).
This number can be determined easily if horizontal wells have already been drilled in an area. Simply divide the ultimate cumulative production of an average horizontal well by the ultimate cumulative production of the average nearby vertical wells. Perform this for several wells to get a good average PM.
When few horizontals have been drilled in an area, or the proposed horizontal wellbore is not near any vertical wells, then one must estimate the productivity index using volumetrics. The PI should be equal to or greater than the CR.
