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AFE: projected drilling time
The time required to drill the well has a significant impact on many items in the cost estimate. Properly estimating the time required is an important part of well planning that must be reflected in the authority for expenditure (AFE).
- 1 Factors affecting drilling time
- 2 Drilling-time information
- 3 Dry hole vs. completed wells
- 4 Time considerations
- 5 References
- 6 See also
- 7 Noteworthy papers in OnePetro
- 8 External links
Factors affecting drilling time
Factors affecting the time required to drill the well include:
- Drilling rig
- Offshore transportation
- Rental tools
- Support services
The effect of these items on the overall well cost is dependent on the actual unit cost (i.e., U.S. $15,000/day for a land rig vs. U.S. $250,000/day for a drillship, and the amount of drilling time).
Consider the well in Fig. 1. Assume the well will be drilled in east Texas. Table 1 summarizes the projected times for the well in three cases and illustrates the cost differences. The worst case has a 21%; greater cost than the best drilling times. This example illustrates the importance of preparing accurate projections for drilling time, or “depth vs. days,” as it is often termed. A typical depth-vs.-days plot is shown in Fig. 2.
Numerous sources are available to estimate drilling times for a well. These include:
- Bit records.
- Mud records.
- Log header information.
- Operator’s well histories.
- Scout tickets and production histories provide information that will affect the time projections.
Bit records are valuable sources to estimate drilling time. Although few bit manufacturers incorporate a column for dates in the depth-record forms, most drilling engineers who routinely complete the forms make notes in the remarks column as to the time or date the bits were run. In addition, most records contain the dates for well spudding, completion, and pipe setting. Additional inferences can be made from the individual bit-life hours and the cumulative drilling time for each well.
Mud records usually provide the most authoritative information about the drilling-time data. These records are maintained daily and usually contain remarks about the time required for each drilling activity. In addition, time allocated to hole problems can be evaluated to determine if the same amount of time should be included in the upcoming well. For example, hole sloughing may be an expected occurrence in an area, while kicks and twist-offs are unusual activities.
Log header information
Log header data contain some drilling-time information and dates for each successive logging run. In addition, scout tickets attached to some logs include spud and completion dates.
Operator well history
The operator well histories provide a comprehensive evaluation of drilling times and offset wells. Although not generally available to noncompany personnel, the histories should contain all previously described sources of information as well as geological and production data. These operator records, when available, should be the basis for the drilling-time projections on the prospect.
Scout tickets and production histories
Scout tickets and production histories can be valuable to supplement depth-vs.-days projections. Significant production from a zone may significantly reduce formation pressures, which can induce pipe sticking or lost-circulation problems. Infill drilling, or drilling adjacent to two producing wells or fields, must include this factor in the time estimate for the new well.
Dry hole vs. completed wells
Drilling times are usually categorized for dry holes and completed wells. These categories are important as the management decision guide to evaluate potential risk vs. production economics.
The dry hole assumes that all casing strings had been run except for production casing and tubing. Dry holes must include time allotments for setting several cased and openhole plugs and the possible retrieval of some casing. Completed wells normally include all well-completion operations up to the point of building production facilities. Well testing is usually included in the time for completion.
Several factors affect the amount of time spent in drilling a well.
- Drill rate
- Trip time
- Hole problems
- Casing running
- Directional drilling
- Completion type
- Move-in and move-out with the rig
Each factor may vary with geology, geographical location, operator philosophy and efficiency.
The cumulative drilling time spent on a well depends primarily on rock type and bit selection. Hard-rock drilling usually needs significantly more drilling time than soft-rock drilling. In addition, the wide variety of bits available to the industry makes bit selection an important factor in drilling hard and soft formations. Other items that usually affect the drill rate are:
- Proper selection of weight and rotary speeds for optimum drilling.
- Mud type.
- Differential pressure.
Pulling and running the drillstring is an important item in estimating total rotating time. In many cases, it is equal to or exceeds the on-bottom drilling time. Trip time is dependent on:
- Well depth.
- Amount of mud trip margin.
- Hole problems.
- Rig capacity.
- Crew efficiency.
A rule-of-thumb for trip-time estimations is 1 hr/1,000 ft of a well.
Long bit runs from 50 to 200 hours often require a short trip of several thousand feet out of and back into the hole. The purpose of the short trip is to remove or reduce any buildup of filter cake that significantly increases the swabbing tendencies of the drillstring. Short trips are dependent on:
- Company philosophy
- Mud type
- Bit life
Various hole problems are routinely addressed in the drilling-time projections, while others are considered improbable. For example, severe kicks and blowouts are usually unlikely if the operator devotes sufficient attention to drilling activities. The geological conditions and drilling histories and the area of the prospect well will often define other pertinent hole problems.
The type of problems often regarded as standard are:
- Hole sloughing
- Lost circulation
- Slow drilling rates
Many operators have encountered formations that slough or heave into the wellbore regardless of the amount of attention given to the mud systems or well plan. Lost circulation will occur in some formations even if the mud density is approximately equal to that of freshwater. Slow drilling rates will usually occur in environments with high differential pressures, such as the case of formation-pressure regressions while maintaining consistent mud weights. However, these hole problems can be eliminated or mitigated in most areas by exercising good engineering judgment in preparing the well plan.
The time required to run casing into the well is dependent on casing size and depth, hole conditions, crew efficiency, and use special equipment such as pickup machines or electric stabbing boards. A heavy casing string may require that the drillstring be laid down rather than setback in the derrick. In addition, nippling-up the blowout preventers and testing the casing and formation must be considered.
Directional control of a well requires increases in the drilling time. These increases apply to:
- Attempting to drill a well directionally
- Maintain vertical control of a well that has deviation tendencies
The increases in drilling time usually result from obtaining surveys and from the inability to apply desired weights or rotary speeds. Many operators increase the expected drilling time in a directional well by a factor two.
Completion systems vary in complexity and, as a result, have a significant variation in time to implement the system. A standard single, perforated completion can be finished in 6 to 8 days. Dual-completed wells usually require an additional 2 to 3 days. Gravel packs, acidizing, fracturing, and other forms of well treatments must be evaluated on a case-by-case basis. Needless to say, the efficiency of all associated personnel and their experiences with a particular type of completion has a major impact on the required time.
Rig move-in and move-out
Rig moving affects several areas of the cost estimate and must be considered in the time projections. Move-in and rig-up occur before spudding the well. Rig-down and move-out occur after well completion. If a completion rig is used rather than the drilling rig for the completion work, an additional rig move must be considered from both a cost and time standpoint.
A rule of thumb for estimating rig moving times is based on the International Association of Drilling Contractors (IADC) rig hydraulics code of 1, 2, 3, or 4, where the higher numbers represent larger rigs. Codes 1 and 2 can usually move in and out in 4 days, because they are frequently mobile and truck mounted. Codes 3 and 4 require approximately 8 days to move in, rig up, and move out. These time estimates affect the move-in cost, supervision time, and overhead allocations.
The affect of weather on the projected time is not considered in most well plans. As an example, hurricanes and tornadoes cannot be routinely expected. However, weather problems, such as those that routinely occur in the North Sea, must be considered in the plan.