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Data collection for well planning
The most important aspect of preparing the well plan, and subsequent drilling engineering, is determining the expected characteristics and problems to be encountered in the well. A well cannot be planned properly if these environments are unknown. Therefore, the drilling engineer must initially pursue various types of data to gain insight used to develop the projected drilling conditions.
The drilling engineer is usually not responsible for selecting well sites. However, he must work with the geologist for the following reasons:
- Develop an understanding of the expected drilling geology.
- Define fault-block structures to help select offset wells similar in nature to the prospect well.
- Identify geological anomalies as they may be encountered in drilling the prospect well.
A close working relationship between drilling and geology groups can be the difference between a producer and an abandoned well.
An example of geological information that the drilling group may receive is shown in Fig. 1. The geologists have found significant production from E.B. White #2. Contouring the pay zones produces the map in Fig. 1. The prospect well should encounter the producing structure at the approximate depth as the E.B. White #2.
Maps showing the surface location of offset wells are available from commercial cartographers (Fig. 2). These maps normally provide the well location relative to other wells, operator, well name, depth, and type of produced fluids. In addition, some maps contour regional formation tops.
The map in Fig. 2 is defined according to a United States land grant system using townships, ranges, and sections. Important terms used with this system are defined next.
- Section: Basic unit of the system—a square tract of land 1 × 1 mile containing 640 acres.
- Township: 36 sections arranged in a 6 × 6 array measuring 6 × 6 miles. Sections are numbered beginning with the northeast-most section, proceeding west to 6, then south along the west edge of the township and then back to the east.
- Range: Assigned to a township by measuring east or west of a principle meridian.
- Range Lines: North-to-south lines that mark township boundaries.
- Township Lines: East to west lines that mark township boundaries.
- Principal Meridian: Reference or beginning point for measuring east or west ranges.
- Base Line: Reference or beginning point for measuring north or south townships.
In rare cases, a specific township and range may have several hundred sections. This scheme is used throughout the United States, except in a few states including Texas, where the location is described in terms of trees, streams, rocks, and neighboring landowners (Fig. 3).
The latitude/longitude mapping system is widely used worldwide, except in the United States. This approach is more orderly and easily allows the wells to be located in relation to other known wells or landmarks. The “lat/long” system is now being introduced in the United States in conjunction with the township/range scheme.
Selecting offset wells to be used in data collection is important. Using Fig. 2 as an example, assume that a 13,000-ft prospect is to be drilled in the northeast corner of Section 30, T18S, R15E. The best candidates for offset analyses are shown in Table 1. Although these wells were selected for control analysis, available data from any well in the area should be analyzed.
Data sources should be available for virtually every well drilled in the United States. Drilling costs prohibit the rank wildcatting that occurred years ago. Although wildcats are currently being drilled, seismic data, as a minimum, should be available for pore-pressure estimation.
Common data types used by the drilling engineer are listed next:
- Bit, mud, mud-logging, and operator’s drilling records.
- Drilling reports from operators or the Intl. Assn. of Drilling Contractors (IADC).
- Scout tickets.
- Log headers.
- Production history.
- Seismic studies.
- Well surveys.
- Geological contours.
- Databases of service company files.
Each record contains data that may not be available with other sources. For example, log headers and seismic work are useful, particularly if these data are the only available sources.
Many data sources exist in the industry. Some operators consider the records confidential, when the important information, such as well-testing and production data, becomes public domain a short time after the well is completed. The drilling engineer must assume the role of “detective” to define and locate the required data.
Data sources include bit manufacturers and mud companies who regularly record pertinent information on well recaps. Bit and mud companies usually make these data available to the operator. Log libraries provide log headers and scout tickets. Internal company files often contain drilling reports, IADC reports, and mud logs. Many operators share old offset information if they have no further leasing interest.
An excellent source of offset drilling information is the bit record. It contains data relative to the actual on-bottom drilling operation. A typical record for a relatively shallow well is shown in Fig. 4.
The heading of the bit record provides information such as:
- The operator.
- The Contractor.
- The rig number.
- The well location.
- Drillstring characteristics.
- Pump data.
In addition, the bit heading provides dates for spudding, drilling out from under the surface casing, intermediate-casing depth, and reaching the hole bottom.
The main body of the bit record provides the:
- Number and type of bits.
- Jet sizes.
- Footage and drill rates per bit.
- Bit weight and rotary operating conditions.
- Hole deviation.
- Pump data.
- Mud properties.
- Dull-bit grading.
The vertical deviation is useful in detecting potential dogleg problems.
Comments throughout the various bit runs are informative. Typical notes such as “stuck pipe” and washout in drillstring can explain drilling times greater than expected. Drilling engineers often consider the comments section on bit (and mud) records to be as important as the information in the main body of the record.
Bit-grading data can be valuable, if the operator assumes the observed data are correct and representative of the actual bit condition. The bit grades assist in preparation of a bit program identifying the most (and least) successful bits in the area. Bit running problems such as broken teeth, gauge wear, and premature failures can be observed, and preventive measures can be formulated for the new well.
Bit records can provide additional useful data if the raw information is analyzed. Plots can be prepared that detect lithology changes and trends. Cost-per-foot analyses can be made. Crude, but often useful, pore-pressure plots can be prepared.
Raw drill-rate data from a well and an area can detect trends and anomalies. Fig. 5 shows drill-rate data from a well in south Louisiana. A drill rate that decreases with depth is expected as shown.
Changes in the trend might suggest an anomaly, as in Fig. 6. This illustration is the composite drill rates for all wells in a south Louisiana township and range. The trend change at approximately 10,000 ft was later defined as the entrance into a massive shale section.
Cost-per-foot studies are useful in defining optimum, minimum-cost drilling conditions. A cost comparison of each bit run on all available wells in the area will identify bits and operating conditions for minimum drilling costs. The drilling engineer provides his expected rig costs, bit costs, and assumed average trip times. The cost-per-foot calculations are completed with Eq. 1.
|$/ft||=||cost per foot, U.S dollars;|
|CB||=||bit cost, U.S. dollars;|
|CR||=||rig cost, U.S dollars;|
|TR||=||rotating time, hours;|
|TT||=||trip time, hours;|
|Y||=||footage per bit run.|
A cost-per-foot analysis for Fig. 4 is shown in Fig. 7.
Trip times should be averaged for various depth intervals. Several operators have conducted field studies to develop trip-time relationships (Table 2). The most significant factors affecting trip time include depth and hole geometry (i.e., number and size of collars, and downhole tools). Table 2 can be used in the cost-per-foot equation (Eq. 1).
Calculate the cost per foot and the cumulative section costs for the following data. Assume a rig cost of U.S. $12,000/day.
Determine which drilling conditions, Well A or B, should be followed in the prospect well. Use a 9.875-in. bit.
1. The hourly rig cost is U.S. $500. Trip times from 7,150 and 8,000 ft are 6.0 and 6.5 hours, respectively.
2. The cost per foot for Bit 1 on Well A (6,000 to 7,150 ft) is
For Bit 2,
3. The cumulative cost for Well A is
4. The cost per foot for Well B is
The section cost is $27,230.
5. Because the cost per foot is lower in Well B, drilling conditions for Well B should be implemented.
Drilling-mud records describe the physical and chemical characteristics of mud system. The reports are usually prepared daily. In addition to the mud data, hole and drilling conditions can be inferred. Most personnel believe this record is important and useful.
Mud engineers usually prepare a daily mud-check report form. Copies are distributed to the operator and drilling contractor. The form contains current drilling data such as well depth, bit size and number, pit volume, pump data, solids-control equipment, and drillstring data. The report also contains mud-properties data such as mud weight; pH; funnel viscosity; plastic viscosity; yield point; gel strength; chloride, calcium, and solids content; cation-exchange capacity; and fluid loss.
An analysis of these characteristics taken in the context of the drilling conditions can provide clues to possible hole problems or changes in the drilling environment. For example, an unusual increase in the yield point, water loss, and chloride content suggests that salt (or salt water) has contaminated a freshwater mud. If kick-control problems had not been encountered, it is probable that salt zones were drilled.
A composite mud recap form is usually prepared. It contains a daily properties summary. It may also include comments pertaining to hole problems.
Daily reports prepared by the mud engineer are useful in generating depths-vs.-days plots (Fig. 8). These plots are as important to well-cost estimating as pore pressures are to the overall well plan. Other types of records (i.e., bit records and log headers) do not provide sufficient daily detail to construct the plot as accurately as mud records.
An analysis of the plots in the offset area surrounding the prospect well can provide:
- Expected drilling times for various intervals.
- Identification of improved operating conditions by examining the lowest drilling times in the offset wells.
- Location of potential problem zones by comparing common difficulties in the wells.
After the offset wells have been analyzed, a projected-depth vs. days plot is prepared for the prospect well.
The drilling contractor maintains a daily log of the drilling operations recorded on the standard IADC-API report. It contains hourly reports for drilling operations, drillstring characteristics, mud properties, bit performance, and time breakdowns for all operations. These reports are usually unavailable to other contractors or operators and, as a result, cannot be obtained for offset-well analysis without the operator ’ s cooperation. Back to top
Scout tickets have been available as a commercial service for many years. The tickets were originally prepared by oil company representatives who "scouted" operations of other oil companies. Current scout tickets contain a brief summary of the well (Fig. 9). The data usually include:
- Well name, location, and operator.
- Spud and completion dates.
- Casing geometries and cement volumes.
- Production-test data.
- Completion information.
- Tops of various geological zones.
The data source for scout tickets are the state or federal report forms filed by oil companies during the course of drilling the well.
A mud log is a foot-by-foot record of drilling, mud, and formation parameters. Mud-logging units are often used on high-pressure or troublesome wells. Many engineers consider the mud log to be the best source of penetration-rate data. Mud logging records are seldom available to groups other than the well operators.
A section of a mud log is shown in Fig. 10. Drilling parameters normally included are penetration rate, bit weight and rotary speed, bit number and type, and rotary torque.
Mud-logging scales are often arranged so the drill-rate curve can be compared to the spontaneous potential (SP) or gamma ray curve on offset logs. The mud log may contain drilling-related parameters such as mud temperatures; chlorides; gas content in the mud and cuttings, usually measured in ’ units’
- lithology; and pore-pressure analysis. The pore pressure can be computed from models such as the d-exponent or other proprietary equations or can be measured by drillstem tests.
Drilling records similar to the previously described information are not available on all offset wells. In these cases, log headers can yield useful drilling data. Easily attainable data from the log headers include logging depths, mud weight and viscosity at each logging depth, bit sizes, inferred casing sizes, and actual setting depths. If enough logging runs were made, a useful depth-vs.-days plot can be constructed.
Production records in the offset area can provide clues to problems that may be encountered in the prospect well. Oil/gas production can reduce the formation pressure and cause differential pipe sticking. Production records provide pressure data from the flowing zones. Unfortunately, pressures in the over- and underlying formations will not change appreciably. This obscures detection with drilling parameters.
A prospect well has the Concordia B sand as its intermediate target zone. Production records indicate the original bottomhole pressure (BHP), before production from the B sand, was 5,389 psia at 9,890 ft true vertical depth (TVD). Currently, the producing BHP is 3,812 psia, and the product is gas. A 10.7-lbm/gal mud was required to drill the intermediate shale sections contiguous to the Concordia sand. A 12.1-lbm/gal mud is required to drill to 12,050 ft. If a maximum pressure of 2,000 psi is used as the upper differential limit, can the well be drilled with the Concordia sand exposed or must the casing be set below the sand before reaching 12,050 ft? (Convert all mud hydrostatic pressures to absolute pressure by adding 15 psia for atmospheric conditions.)
Solution. 1. The mud required to balance the Concordia sand is 10.7 lbm/gal, which exerts a hydrostatic pressure of
2. The differential pressure with 10.7 lbm/gal is
Therefore, pipe sticking should not be a problem with the 10.7-lbm/gal mud.
3. A 12.1-lbm/gal mud is required to reach 12,050 ft. This mud weight will create a hydrostatic pressure at 9,890 ft of
The differential pressure will be
4. A casing string, or liner, must be set below 9,890 ft because the 12.1 lbm/gal required at the bottom creates a differential pressure at the Concordia B sand in excess of the 2,000-psi upper limit.
Wildcat wells are seldom drilled without preliminary seismic work being done in the area. Analysis of seismic reflections can eliminate the "wildcat" status of the well by predicting pore pressures. Several authors have shown that good agreement on the pore pressures can be attained with seismic and sonic-log data.