A wellbore survey, also known as a borehole survey, refers to the process of collecting accurate measurements and data about the orientation and trajectory of a wellbore, which is the hole drilled into the earth during the exploration and production of oil and gas. The purpose of conducting a wellbore survey is to precisely determine the position, direction, and inclination of the wellbore at various depths.
An oilfield survey must have at least three measurements, typically recorded in real time.
The survey information is entered into a computer database by the Measurement While Drilling Field Engineer and the Directional Driller. The computer system then calculates all other navigational measurements (e.g., True Vertical Depth [TVD], Dogleg Severity [DLS], Total Depth [TD], Vertical Deviation [VD], Vertical Section [VS], Horizontal Deviation, Easting, Northing). These measurements are required to be submitted to the government and various project stakeholders.
Simple definition: Borehole length.
Background: While drilling new borehole, it's necessary to stop periodically and take a survey. By law or operator requirement, surveys must be taken at specific distance intervals. This is typically done with a Measurement While Drilling (MWD) tool that contains multiple sensors and means for telemetry. The MWD sensor can be placed in various locations depending on the design of the Bottom Hole Assembly. In a traditional drill string design, the MWD takes the survey at a depth 40-60 feet behind the drill bit. The driller will pick up the drill string off-bottom by about 3 feet, stop rotation, cycle the mud pumps and/or make a pipe connection. For mud-pulse telemetry, the MWD tool is triggered to take a survey by pump cycling.
Example calculation: Currently, the borehole is 18,542 feet. Lifting the drill string off-bottom 3 feet and securing it in slips, with the MWD sensor 53 feet behind the drill bit results in a survey station's measured depth [MD] of 18,486 feet.
Simple definition: Deviation from vertical hole, measured in degrees.
Background: Zero 0° degrees inclination is straight down. 90° is horizontal. 92° is slightly upwards.
How it's calculated: Within a downhole tool like an MWD tool, triaxial sensors are utilized to gauge the strength of the earth's gravitational and magnetic fields, thereby calculating inclination.
Simple Definition: The wellbore direction is represented in clockwise degrees from 0 to 360°, with reference to either (1) Magnetic North, (2) Grid North, or (3) True North.
How it's calculated: The Measurement While Drilling Field Engineer will use a world magnetic model based on the date, elevation, latitude, and longitude to determine the local magnetic field. Drilling contractors subscribe to use magnetic data provided by the British Geological Survey. A downhole tool known as a Measurement While Drilling [MWD] tool has triaxial sensors used to measure the strength of the earth's gravitational and magnetic fields. The magnetic field sensors determine the direction of magnetic north. Subsequent adjustments can be applied to convert data to either Grid North or True North. Another type of tool called a gyroscope single shot or Gyroscope While Drilling [GWD], measures True North due to earth's rotation.
Critical Error Potential: Care must be taken when applying north corrections because the conversion depends on the well plan, survey tool type, geolocation, and cartography. A common error is not using the correct north reference corrections when combining surveys from two different types of survey tools that measure different north references. Another common error is selecting the incorrect north reference in the survey database. A third common error is when different stakeholders are using different north references. Best to refer to the navigational rosebud on the well plan or wall plot from the drilling engineer. A trained directional driller must double check for errors prior to starting the job. Significant consequences arise from drilling in the wrong direction. If the error is discovered too late, the well will be drilled in the wrong direction which frequently leads to property right issues. If the borehole collides with another well there are significant risks to health, safety, and the environment.
Magnetic Interference: It is well known that magnetic interference requires correction by the Measurement While Drilling Field Engineer. External magnetic forces arise from the drilling string itself, magnetic formations, adjacent wells, the casing shoe, and solar flares. The drilling engineer will design the bottom hole assembly [BHA] to use non-magnetic drill collars [NMDC] such as Monel to isolate the MWD sensors from the magnetic field created by the drill string. For example, three miles of continuous steel drill pipe creates magnetic interference.
Final Notes: When drilling near the north pole, you have to apply corrections to account for the movement of the magnetic north pole. Another issue that arises is solar flares from the sun.
Simple definition: A bottom hole assembly consists of a range of tools, including drill bits, mud motors or rotary steerable tools, MWD/LWD tools, pipe crossovers, and more. Additionally, the assembly features an extended series of pipe connections, comprising drill pipe and heavy-weight drill pipe. Specialized items, such as Jars and vibration excitation tools, can also be strategically placed within the drill string.
Design process: A drilling engineer utilizes a computer program to meticulously design a wellpath. At specific depth intervals, the engineer recommends a drill string configuration to accomplish the drilling objectives. On-site, a directional driller assembles the bottom hole assembly and subsequently lowers it into the borehole. Based on experience, the directional driller may make changes to the BHA to improve drilling performance.
Simple definition: A job performed by highly skilled tradespeople in the oil and gas industry. The primary responsibility of the directional driller [DD] is to complete the drilling of the well plan by intentionally deviating the borehole in such a way to optimize the later production of oil and gas from the reservoir. The driller will be responsible for hitting drilling targets, staying within the pay zone, avoiding other wells (anti-collision), and overall project management.
Illustrative example: In locations like Killdeer, North Dakota, USA, typical drilling depths can extend to around 23,000 feet measured depth (MD). First the driller drills a vertical hole section to approximately 9,000 feet MD. Then the directional driller will kick-off the borehole from vertical hole into a curve section that may be approximately 1,000 feet long until the borehole has an inclination of approximately 90° degrees. After running steel casing and cement, the next size smaller hole section will be drilled into what is called the horizontal section. The horizontal section can be 1-3 miles long.
Simple Definition: A job performed by highly skilled tradespeople in the oil and gas industry. This person will record surveys, build and repair measurement equipment in the field, maintain telemetry between downhole tools and the surface sensor equipment, troubleshoot equipment failures, etc. The most common types of MWD tools measure the earth's magnetic and gravitational field and communicate to surface sensors with mud-pulse or electical-pulse telemetry. In well documented oilfields, it is possible for the directional driller and geologist to use Gamma Ray measurements to determine the lithology at various depths. Of note, this information is corroborated by analyzing cuttings samples under a microscope. All information is documented in drilling logs.
Simple definition: Drilling logs are visual representations of the rock layers within a borehole. These charts display different measurements taken as the depth increases. By comparing logs from other wells, ongoing drilling can be improved.
Illustrative example 1: On a simple drilling project, the directional driller uses gamma ray measurements as a function of True Vertical Depth [TVD] to determine where to initiate the "kick-off" the from vertical hole. This is called the Kick-off Point [KOP]. On all drilling projects, geological markers are used to confirm depth and avoid errors. The modern oilfield is well documented with measurement data from offset wells. To corroborate these downhole measurements, the geologist will analyze rock cutting samples which are returned to the surface by circulating drilling mud. Notes will be added to the drilling logs by the geologist.
Illustrative example 2: While drilling the horizontal well section, the directional driller will monitor gamma ray measurements to ensure that the wellbore is optimal placed in the payzone. In this example, the directional driller will attempt to maintain a narrow window of true vertical depth in a sandstone that has a shale above and below. As the driller approaches a shale, showing a different gamma ray measurement, the driller and geologist will decide to drill away from the shale. Drilling into the shale has the potential to cost workers their jobs, as the corrective action is very expensive.
Simple definition: A kink in the borehole that prevents effective weight transfer to the drill bit. This will also significantly increase torque and drag while drilling. Removing cuttings from the borehole will become an increasing problem.
Illustrative example: The directional driller is instructed to drill upwards at 93° becuase other project stakeholders, (e.g., company man, geologist, drilling engineer) believe the formation dip angle has changed from 91° to 93°. The driller decides to put in a 22-foot slide upwards using a mud motor with 1.5° bend. Unfortunately, inclination changed too fast and now there is a kink in the wellbore trajectory. When the MWD sensor, 40 feet behind the drill bit, detects a steep rate of inclination change in real-time, the driller decides to overcorrect and slide downwards for 15 feet hoping that no-one notices. Thus, a kink or dogleg in the borehole is created. The company man notices the issue by monitoring the real-time hole inclination and decides to spot check the directional driller's work. Surveys are taken at every tool joint of pipe, about every 31 feet. Now the wellbore has a 8° dogleg and the company man decides to ream the hole with the drill bit for 2 hours to prevent future issues with torque and drag. Issues that will likely prevent the wellbore from reaching the total depth originally planned.
Usage: Whether intentionally by design, or means to salvage an undesirable wellbore trajectory, sidetracking is an important part of directional drilling. Quite simply, it is a new hole that stems off of an existing borehole. Sidetracking starts with time-drilling, which takes a very long time and is extremely difficult to do. Only the best directional drillers can perform a sidetrack. Furthermore, each time the driller trips pipe in and out of the sidetrack window, there is the potential that the window may be lost for various reasons. As such, the operator will frequently do a cement squeeze to improve the likelihood of success.
Examples: The sidetracked borehole is added to improve the optimization of wellbore placement in the pay-zone. Sidetracks are commonly used in multi-lateral drilling by definition. Another example is much more costly, the unplanned drilling out of the pay zone.
Simple Definition: Mechanical Specific Energy [MSE] is method of calculating drilling performance as a function of drilling parameters: ROP, WOB, and bit revolutions per minute. It is commonly used to diagnose bit wear, motor performance, vibration, and pump issues.
Usage: Various rock types require different amounts of energy to drill. Referencing offset well drilling logs, it is possible to compare drilling performance in each lithological formation. For the same formation in offset wells, the directional driller identifies a change in MSE. The corrective action is initially to use different drilling parameters. If no improvement in Rate of Penetration [ROP] or Mechanical Specific Energy [MSE] occurs, it can be a sign of downhole issues like vibration, poor hole cleaning, mud motor failure, or an underperforming PDC drill bit. Surface issues can also be the root cause, comprising mud pumps failure, or mud property insufficiencies.
PDC bits are the industry standard for durability and efficiency. Since they are made from synthetic diamond cutters, they are very expensive and very durable. The cutting mechanism for a PDC bit is shearing the rock. The layout of the PDC cutters and blades are optimized by bit engineers to for each basin and target formation. Over time, the PDC cutters will become chipped, reduce in size, and eventually fall out. PDC bits will decrease in performance and eventually need to be replaced. The primary metric of tracking performance is the Rate of Penetration [ROP]. When drilling slows significantly it may be time to trip the pipe and change or "lay down" the bit [LD BIT]. There are other factors to consider before Pulling-out-of-Hole [POOH], comprising, weight transfer to bottom, torque and drag, mud motor performance, hole cleaning issues caused by poor mud design, abrasive formations, lithological stringers, and doglegs.
This product has been around for nearly 100 years and was invented by two engineers at Hughes. Drillers optimize the performance of roller cone bits by changing the size of the jets. The jet size determines the hydraulic horsepower (HHP), which is significantly more important with a roller cone bit than a PDC bit. Mud flows through the jets and sprays on the rock with incredible pressure while the rotating cones crush the rock. The mud system circulates the rock cuttings up the annulus of the borehole. These bits are lower cost than PDC drill bits. A major drawback of these bits is that the driller must keep track of the number of rotations on the bearings, circulating hours, and the time spent drilling on bottom. Especially when drilling in hard formations, cones can dislodge at the bottom of the borehole, and they must be fished out of the hole. If the bit is used too long, the teeth on the roller cones will wear down and become useless. Unlike PDC bits, roller cones will decrease Rate of Penetration [ROP] abruptly when they fail due to the loss of a cone.
An underreamer bit is used in the BHA to enlarge the borehole. These bits have teeth on the side of a pipe segment and are usually far back of the primary drill bit. Hydraulics may be a concern when these bits are used because they reduce the size of the annulus cross section. They also increase the torque and drag profile of the bottom hole assembly [BHA]. As such, it will be more difficult to transfer weight to the bottom of the borehole.
When wildcat wells are being drilled in a new basin or at a new true vertical depth, it is common for the operator to take coring samples to analyze the lithology. Coring takes a very long time to collect, and it is therefore extremely expensive.