Horizontal Well

  • Planning a Horizontal Well


Planning a horizontal wellbore is different from planning a normal directional well. In a normal directional wellbore, the target is usually described in terms of a departure at a certain TVD. The target has tolerances in the horizontal plane (North and East). Unless drilled from a platform or pad, a horizontal wellbore seldom has a target described by the departure. The target is most commonly described by the TVD plus or minus a tolerance.
 
For example, a formation top may be at a true vertical depth of 1200m (3936 feet) and the formation is 6m (19.7’) thick. The placement of a horizontal well in this formation will require the wellbore to be horizontal at a TVD of 1203m (3946 feet), plus or minus 3m. There have been some horizontal wells drilled with a TVD target tolerance of plus or minus 0.5m (1.6 feet) requiring the wellbore to stay within a 1m vertical zone. These tight tolerances can be very expensive to maintain since the ROP will likely have to be controlled and more survey stations will be required to meet these objectives. As you can see, target tolerances for horizontal wellbores are much smaller than typical directional wells. Consequently, they are a little harder to hit and greater care must be exercised in drilling a horizontal wellbore.
 
  • Data Collection
The first step in planning a horizontal wellbore is to gather all the information possible about the well and the formation to be drilled. Available data from offset wells, even vertical wells should be collected. Items of interest are well logs, bit records, mud logs, directional data, daily reports and any other data that might be helpful. Even vertical offset wells can provide valuable information for drilling a horizontal well including target depths. There are few if any horizontal exploratory wells therefore, offset well information is always available.
The reason for drilling the horizontal wellbore must be defined. Is the horizontal well being drilled to prevent water or gas coning or to intersect vertical fractures. Many times the reason for drilling the horizontal well drives the completion which in turn, drives the drilling program. The type of completion must always be considered in horizontal well planning.
The geology of the target is very important. Remember, TVD targets can be very small and bed dip is a major consideration. A bed dip of only two or three degrees can cause the horizontal wellbore to fall outside the target interval in only a short distance. Also, the geology of a formation can be slightly more complicated than originally expected. Figure below is an example of what can happen in a horizontal well. The left side of the figure was the planned wellbore path and geology but the right side is the actual wellbore path and geology. The actual conditions in the formation did not match the predicted conditions. As a result, the operator ended up with a poor horizontal well. Knowing the exact geology of the formation is extremely important.
 
Planning a horizontal wellbore’s path must take into consideration all the geologic constraints. It must also take into consideration the reason for drilling the horizontal well. If the well is being drilled to prevent water coning, then the wellbore will be placed near the top of the producing interval away from the water. Gas coning would require that the well be placed near the bottom of the producing interval. If the well is being drilled to intersect natural fractures, the wellbore may be drilled from the top of the reservoir at the end of the build curve to the bottom of the formation at the end of the horizontal section as shown in Figure below.       

 

It may also be that the geology of the formations is not precisely known. The planning may require that the formation be drilled vertically and logged and/or cored before drilling horizontally. The vertical well defines the target TVD and also provides information about the lithology changes within the formation. Then, the wellbore is plugged back, sidetracked and drilled horizontally in a favourable position. Remember, a lot of money is being spent to drill the well horizontally and if the geologic data is inadequate, the chances of a commercially viable horizontal wellbore decrease significantly.

  • Casing Design

Once the target constraints have been defined, the wellbore must be planned. Review the offset data to determine where casing must be set. Decide what bit size will be required to drill the horizontal section. In many horizontal wells, casing is set through the build curve to eliminate any potential problems with formations above the pay zone. However, casing set through the build curve is not a requirement. It depends upon the stability of the formations above the pay zone and the completion method. The horizontal well takes longer to drill than a vertical well and formations above the pay zone may deteriorate with time. Even though these formations may not be a problem in a vertical well, they may start to be a problem due to the longer drilling time in a horizontal well. Each well must be considered individually.

If the horizontal well is to be completed open hole or with a slotted liner, water producing formations above the pay zone may have to be cased. They can be cased before drilling the horizontal or after the horizontal section is drilled. Casing the build section after the horizontal portion has been drilled will require running an external casing packer for isolation and cementing above the packer. In open hole completions, the formation above the pay zone may not be stable over a long period of time. For example, a horizontal well is to be drilled in a limestone formation. The limestone is sufficiently stable to allow an open hole completion but the shale section immediately above the limestone may not be stable and will have to be cased.

The type of casing connection used in the build section should be checked to confirm it can handle the bending stresses it will be subjected to both during running and its producing life. An ST & C connection is not recommended for any casing in the build section. It may be able to handle the bending stresses but its lower tensile capability makes it a poor choice of connection for an expensive horizontal well. The operator must consider if the casing will be also rotated during the cementing operation and special connections should be investigated for these jobs.

  • Selection of Build Rate
Planning the build rate has to take a number of considerations into account. First the preferred build rate (long, medium or short radius) must be decided. Long radius builds are time consuming and more expensive to drill. Medium radius build rates are more common but require higher build rates resulting in a smaller

TVD tolerance if the formation tops come in at different depths than planned. Short radius build rates definitely require the most accurate geological information and because of their specialization and special equipment needs the directional costs are higher. Also the bending stresses produced by these build rates require different tubulars (2 7/8” high strength tubing). Typically a short radius build rate is used on re-entry wells and where the geology changes rapidly as the distance from the surface location increases. When determining the build rate the result of an error in achieved build rate should be considered. Figure 9-3 shows how the TVD of the wellbore will change when the build rate is ±10%.



Long Radius = less than 6o/30m

Medium Radius = less than 40o/30m but greater than 6o/30m

Short Radius = greater than 40o/30m, quite often build rates of 100o/30m

The above classifications should be applied to hole size versus a generic build value but are suitable for purposes of this manual.
 
The actual build rate is usually based on preference or available kick off points. Typically, higher build rates are used in smaller diameter holes and lower build rates are used in larger diameter holes. The dogleg severity limit for 4 ½” drill pipe is about 18o/30m whereas, the limit for 3 ½” drill pipe is 24o/30m. Above these limits, fatigue can be a problem. Also, the tools used to build inclination cannot build as fast in a large diameter hole as a small diameter hole. An 8 ½” hole is limited to about 15 to 18o/30m build rates depending upon who’s motor configuration is being used. A 6 inch hole is limited to about a 25o/30m build rate though some short radius tools are now available for higher build rates.
 

The operator must decide upon what build rate to use. Generally, the higher build rates will yield less time drilling and, therefore, less cost. The build rate may also be determined by hole problems or casing setting depths. If the kick off point is selected, the build rate is calculated and vise versa.

When the target requirements are small, it may be necessary to make some adjustments to the build curve to hit the intended target. The build rate of most motor assemblies is somewhat predictable to within ten to fifteen percent. With previous experience in a specific area, the build rates are even more predictable. In areas with little experience drilling horizontal wells, it is not uncommon to plan the well with either a tangent section or a soft landing. A tangent section is a short portion of the build curve drilled at a relatively constant inclination. For example, the wellbore may build inclination at 12o/30m to 45o, then a 30m section is drilled at 45o before continuing to build inclination at 12o/30m.
 

The tangent section allows for differences between planned and actual build rates. If the actual build rate is less than the planned build rate, the well reaches 90o too deep. If it is greater than the planned rate, the wellbore will reach 90o too shallow. The tangent section can be used to compensate for the differences. If the build rate is greater than anticipated, the tangent section can be lengthened to consume more TVD. Conversely, if the build rate is less than anticipated, the tangent section is shortened providing more TVD to work with. At one time, it was very common to plan a tangent section for a horizontal well, but they are not as common as they use to be. Tangent sections are not needed for wells with large TVD targets. Tangent sections cost money, and should be avoided if possible.

The other option is to plan the build section with a “soft land”. This refers to a reduced build rate for the last 3 to 10m of TVD. This section again will allow for slight changes in casing landing depth to be made. Typically the difference between the first and second build rate is 2 or 3o/30m. It is important to be aware of the motor setting required for these different build rates. The operator would rather not make a special trip to change the motor setting. In both cases it is important to know if the motor can be safely rotated or if a trip is required to reduce the setting. This can be very costly and should be avoided where possible or timed with a bit trip.

The other option is to plan the build section with a “soft land”. This refers to a reduced build rate for the last 3 to 10m of TVD. This section again will allow for slight changes in casing landing depth to be made. Typically the difference between the first and second build rate is 2 or 3o/30m. It is important to be aware of the motor setting required for these different build rates. The operator would rather not make a special trip to change the motor setting. In both cases it is important to know if the motor can be safely rotated or if a trip is required to reduce the setting. This can be very costly and should be avoided where possible or timed with a bit trip.
 
  • Planning Team

As should be evident by now, horizontal well planning is a multi-disciplined project. Horizontal planning must include personnel from

  • Geology
  • Drilling
  • Reservoir
  • Production
  • Service Companies
The effect of geology on the horizontal well has already been discussed. The reservoir and production personnel should be involved in the planning. There may be certain portions of the reservoir where the horizontal wellbore will be more effective. What are the pressures within the section that will be penetrated by the horizontal well? What kind of formation damage can be expected from the drilling fluid? Will the horizontal wellbore require stimulation to produce effectively? Will the well have to be produced using artificial lift and what volumes can be expected? There are many questions to be answered before the drilling plan can be finalized and the reservoir and production groups will have to help answer these questions.
Service company personnel must be involved in the planning phase. They have more experience with their equipment than anyone and can help the operator during the planning phase. It is best to know the limits of the equipment before the drilling operations begin. This includes the equipment used to drill the well and the equipment used in the completion of the horizontal well. It has been said many times that “failing to plan is the same as planning to fail”. In horizontal drilling, this is certainly true. Planning is one of the most important steps in drilling a horizontal well.
In planning any directional well profile, certain information is required. Horizontal drilling is no different. As stated earlier, the target for a horizontal well is usually a TVD target and the departure is seldom a consideration unless drilled from a platform or pad. With a platform or pad, the wellbore must first reach the portion of the reservoir where the horizontal well is to be placed. In that case, the upper portion of the well is drilled like a normal directional well and the lower portion is drilled like a normal horizontal well. Generally, planning the directional drilling profile is a trial and error process.
 
  • Planning
Once you have selected either the build rate or horizontal displacement to casing point, quick estimates can be made to determine the KOP. Assuming no tangent and a constant build rate to casing point set at 90 degrees is used the following equation will determine either build rate or horizontal displacement and thereby the KOP.
 
Although this is a very simplified approach it immediately establishes a potential kick off point which can then be checked against the expected formations to determine the suitability of this depth. All directional companies have computer programs to aid in planning the best trajectory for your well path and can adjust for many requirements as dictated by the “planning team”.
When bed dips are taken into consideration, planning the horizontal well can be more complicated. The inclination of the horizontal section will be a function of the apparent bed dip in the plane the well is being drilled not the bed dip perpendicular to the bed strike. Generally the apparent dip can be obtained from the geology department. The inclination of the horizontal section also depends upon the position of the horizontal section within the producing formation. Obviously this is starting to get complicated and as it is important with all horizontal wells a diagram is very important.

 

The following formula can be used to determine the inclination of the angle of the horizontal section (IH) of the well in the target plane:


IH = 90 – arcTan[ Tan(Idip) x Cos(AZdip – AZWELL)] - degrees

Idip = dip of the target plane - degrees

AZdip = target plane dip azimuth - degrees

AZWELL = planned azimuth of the horizontal well - degrees

 



TVDEOC = TVDTP + DISPL[Tan(Idip) x Cos(AZdip – AZWELL)]

TVDEOC = TVD at end of curve in the target plane – ft or m

TVDTP = TVD of target plane under the surface location – ft or m

DISPL = horizontal displacement length from surface to EOC – ft or m

IDIP = dip of target plane - degrees

AZdip = target plane dip azimuth - degrees

AZWELL = azimuth of horizontal well - degrees 

            = arcTan (East/North)

Example:

Dip angle equals 5o, Idip

 

Dip azimuth = 135o, AZdip

 

TVD of target under surface is 9000’, TVDTP

 

a) well direction is due East = 90o AZWELL

 

b) well direction is due West = 270o AZWELL

 

If well direction is due East

IH = 90 – arcTan[Tan5 x Cos(135 – 90)]

 

= 90 – (3.54) = 86.46o

 

If well direction is due West

IH = 90 – arcTan[Tan5 x Cos(135 – 270)]

 

= 90 – (-3.54) = 93.54o

 

If the EOC is 800’ due East of surface location the target TVD is

 

TVDEOC = TVDTP + DISPL[Tan(Idip) x Cos(AZdip – AZWELL)]

 

= 9000 + 800[Tan(5) x Cos(135-90)]

= 9000 + 49.41

= 9049.41 feet

 

Summary – land curve at 9049.41 feet TVD, at an inclination of 86.46o.

 

 The radius of curvature equations can also be used to provide quick estimates of KOP and build rates provided you know at least two of the unknowns.

 

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