UNIVERSITY OF PETROLEUM & ENERGY STUDIES
Institute of Drilling Technology, Dehradun
Directional Drilling Technology
Kon Aguek Deng
Email ID: email@example.com
Phone number: +918755394548
Oil and Natural Gas Corporation Limited (ONGC) is an Indian multinational oil and gas company headquartered in Dehradun, India. A Maharatna public sector undertaking which is also one of the largest Asia-based oil and gas exploration and production companies and produces around 72% of India’s crude oil (equivalent to around 30% of the country’s total demand) and around 48% of its natural gas. It is one of the largest publicly traded companies by market capitalization in India.
The Oil and Natural Gas Corporation Limited was incorporated under the companies Act, 1956 on 23rd. June 1993 after conversion from Oil and Natural Gas Commission, a statutory body established under ONGC Act 1956. It is involved in exploring for and exploiting hydrocarbons in 26 sedimentary basins of India, and owns and operates over 11,000 kilometers of pipelines in the country. Its international subsidiary ONGC Videsh currently has projects in 15 countries. ONGC has discovered 6 of the 7 commercially-producing Indian Basins, in the last 50 years, adding over 7.1 billion tons of In-place Oil & Gas volume of hydrocarbons in Indian basins. Against a global decline of production from matured fields, ONGC has maintained production from its brownfields like Mumbai High, with the help of aggressive investments in various IOR (Improved Oil Recovery) and EOR (Enhanced Oil Recovery) schemes. Recovery Factor has improved from 28% (in 2000) to 33.5% (in 2011).
Significantly Reserve Replenishment Ratio for the last 7 years has been more than one.
• Only Indian energy major in fortune’s most admired list 2012 under Mining, Crude Oil Production category.
• It is ranked 171th in Forbes Global 2000 list of the World’s biggest companies for 2012 based on Sales (US $ 26.3 billion), profits (US $5 billion).
• ONGC has been ranked 39th among the world’s 105 largest listed companies in ‘transparency in corporate reporting’ by transparency international making it the most transparent company in India.
The Institute of Drilling Technology (IDT) was setup in 1978 at Dehradun. Located in the picturesque valley of Doon between the green Shivaliks and the lower Himalayas, it is engaged in relentless effort in R&D and has rendered excellent services in the area of oil and gas well drilling technology. Over the years, the Institute has emerged as a premier R&D centre in South East Asia, capable of providing advance knowledge through training and offering plausible solution to field problems.
The Institute with highly qualified and experienced scientists and engineers carries out applied research in all facets of drilling related activities technical excellence in R&D efforts and assimilation of emerging technologies.
The integrated HRD division imparts training to participants from both national and international oil companies in various aspects of oil well drilling technologies. The renowned Well Control School at IDT has been accredited by International Well Control Forum, The Netherlands, and International Alliance for Well Control, the Netherlands and also from International Association of Drilling Contractors, USA.
The infrastructure for applied R&D has been developed with the state of the art equipment and machines to achieve qualitative experimental results. Focus of R&D is directed towards drilling technology, drilling fluid engineering and cementation and cementing materials to meet challenges of drilling industry. The technologists and scientists provide solutions to the downhole drilling problems, improving design of the systems and thereby contributing towards the development of excellent, efficient and cost effective operations.
Directional Drilling has been an integral part of the oil and gas industry since the 1920s. While the technology has improved over the years, the concept of directional drilling remains the same: drilling wells at multiple angles, not just vertically, to better reach and produce oil and gas reserves. Additionally, directional drilling allows for multiple wells from the same vertical well bore, minimizing the wells' environmental impact. Improvements in drilling sensors and global positioning technology have helped to make vast improvements in directional drilling technology. Today, the drillbit is controlled with intense accuracy through real-time technologies, providing the industry with multiple solutions to drilling challenges, increasing efficiency and decreasing costs.
Tools utilized in achieving directional drills include whipstock, bottomhole assembly (BHA) configurations, three-dimensional measuring devices, mud motors and specialized drillbits.Now, from a single location, various wells can be drilled at myriad angles, tapping reserves miles away and more than a mile below the surface Many times, a non-vertical well is drilled by simply pointing the drill in the direction it needs to drill. A more complex way of directional drilling utilizes a bend near the bit, as well as a downhole steerable mud motor. In this case, the bend directs the bit in a different direction from the wellbore axis when the entire drillstring is not rotating, which is achieved by pumping drilling fluid through the mud motor which in turn rotates the Bit. Then, once the planned angle is achieved, the complete drillstring is rotated, including the bent motor, ensuring the drillbit does not drill in a different direction from the planned curve.
One type of directional drilling, horizontal drilling, is used to drastically increase production. Here, a horizontal well is drilled across an oil and gas formation, increasing production by as much as 20 times more than that of its vertical counterpart. Horizontal drilling is any wellbore that exceeds 80 degrees, and it can even include more than a 90-degree angle (drilling upward).
Directional Drilling – History Many prerequisites enabled this suite of technologies to become productive. Probably, the first requirement was the realization that oil wells, or water wells, are not necessarily vertical. This realization was quite slow, and did not really grasp the attention of the oil industry until the late 1920s when there were several lawsuits alleging that wells drilled from a rig on one property had crossed the boundary and were penetrating a reservoir on an adjacent property. Initially, proxy evidence such as production changes in other wells was accepted, but such cases fueled the development of small diameter tools capable of surveying wells during drilling. Measuring the inclination of a wellbore (its deviation from the vertical) is comparatively simple, requiring only a pendulum. Measuring the azimuth (direction with respect to the geographic grid in which the wellbore is running from the vertical), however, was more difficult. In certain circumstances, magnetic fields could be used, but could be influenced by metalwork used inside wellbores, as well as the metalwork used in drilling equipment. The next advance was in the modification of small gyroscopic compasses by the Sperry Corporation, which was making similar compasses for aeronautical navigation. Sperry did this under contract to Sun Oil (which was involved in a lawsuit as described above), and a spin-off company "Sperry Sun" was formed, which brand continues to this day, absorbed into Halliburton. Three components are measured at any given point in a wellbore in order to determine its position: the depth of the point along the course of the borehole (measured depth), the inclination at the point, and the magnetic azimuth at the point. These three components combined are referred to as a "survey". A series of consecutive surveys are needed to track the progress and location of a wellbore. Many of the earliest innovations such as photographic single shot technology and crow's feet baffle plates for landing survey tools were developed by Robert Richardson, an independent directional driller who first drilled in the 1940s and was still working in 2012. Prior experience with rotary drilling had established several principles for the configuration of drilling equipment down hole ("Bottom Hole Assembly" or "BHA") that would be prone to "drilling crooked hole" (i.e., initial accidental deviations from the vertical would be increased). Counter-experience had also given early directional drillers ("DD's") principles of BHA design and drilling practice that would help bring a crooked hole nearer the vertical. In 1934, H. John Eastman of Long Beach, California, became a pioneer in directional drilling when he and George Failing of Enid, Oklahoma, saved the Conroe, Texas, oil field. Failing had recently patented a portable drilling truck. He had started his company in 1931 when he mated a drilling rig to a truck and a power take-off assembly. The innovation allowed rapid drilling of a series of slanted wells. This capacity to quickly drill multiple relief wells and relieve the enormous gas pressure was critical to extinguishing the Conroe fire. (E&P, "Making a hole was hard work," Kris Wells, American Oil & Gas Historical Society Contributing Editor, 1 Nov. 2006 and "Technology and the Conroe Crater"). In a May, 1934, Popular Science Monthly article, it was stated that "Only a handful of men in the world have the strange power to make a bit, rotating a mile below ground at the end of a steel drill pipe, snake its way in a curve or around a dog-leg angle, to reach a desired objective." Eastman Whip stock, Inc., would become the world's largest directional company in 1973. Combined, these survey tools and BHA designs made directional drilling possible, but it was perceived as arcane. The next major advance was in the 1970s, when down hole drilling motors (aka mud motors, driven by the hydraulic power of drilling mud circulated down the drill string) became common. These allowed the bit to be rotated on the bottom of the hole, while most of the drill pipe was held stationary. A piece of bent pipe (a "bent sub") between the stationary drill pipe and the top of the motor allowed the direction of the wellbore to be changed without needing to pull all the drill pipe out and place another whip stock. Coupled with the development of Measurement While Drilling tools (using mud pulse telemetry, networked or wired pipe or EM telemetry, which allows tools down hole to send directional data back to the surface without disturbing drilling operations), directional drilling became easier. Certain profiles could not be drilled without the drill string rotating at all times. Drilling directionally with a motor requires occasionally "sliding" the drill pipe, which means stopping the pipe rotation and pushing the pipe in the hole as the motor cuts a curved section of hole in the desired direction. "Sliding" can be difficult in some formations, and it is almost always slower and therefore more expensive than drilling while rotating and also hole cleaning during sliding is poorer, so the ability to control wellbore direction while rotating is desirable. Several companies have developed tools which allow directional control while rotating. These tools are referred to as Rotary Steerable systems, or RSS. RSS technology has allowed access to and/or directional control in previously inaccessible or uncontrollable formations. Robert Zilles pioneered many of the RSS drilling procedures for Baker Hughes Inteq and is considered the Grandfather of RSS technology. In 2010 he became the first BHI directional driller to drill a well in each of the last 7 decades.
Advantages of Directional drilling
There are many purposes and advantages of directional drilling which includes.
1. Increasing the area of contact with the reservoir by drilling at an angle
2. Drilling into the reservoir where vertical access is difficult or not possible. For instance, an oilfield under a town, under a lake, or underneath a difficult-to-drill formation
3. Allowing more wellheads to be grouped together on one surface location can allow fewer rig moves, less surface area disturbance, and make it easier and cheaper to complete and produce the wells. For instance, on an oil platform or jacket offshore, 40 or more wells can be grouped together. The wells will fan out from the
platform into the reservoir(s) below. This concept is being applied to land wells, allowing multiple subsurface locations to be reached from one pad, reducing costs.
4. Drilling along the underside of a reservoir-constraining fault allows multiple productive sands to be completed at the highest stratigraphic points. 5. Drilling a "relief well" to relieve the pressure of a well producing without restraint (a "blowout"). In this scenario, another well could be drilled starting at a safe distance away from the blowout, but intersecting the troubled wellbore. Then, heavy fluid (kill fluid) is pumped into the relief wellbore to suppress the high pressure in the original wellbore causing the blowout.
Disadvantages of directional drilling
1. It meant that more footage than necessary had to be drilled in order to reach the producing zone. Deviated drill therefore take more time to be drilled and more expensive than a straight vertical well.
2. The “Cone of Uncertainty” in a deviated wellbore, makes planning of future well more difficult and increase the level of uncertainty in the well.
3. Deviated well increase the wear of the drilling string and bottom-hole assembly (BHA), making failure more likely to happen, the deviated well also make any subsequent fishing job difficult.
Until the arrival of modern down hole motors and better tools to measure inclination and azimuth of the hole , directional drilling and horizontal drilling was much slower
than vertical drilling due to the need to stop regularly and take time consuming surveys, and due to slower progress in drilling itself (lower rate of penetration). These disadvantages have shrunk over time as down hole motors became more efficient and semi-continuous surveying became possible.
What remains is a difference in operating costs: for wells with an inclination of less than 40 degrees, tools to carry out adjustments or repair work can be lowered by gravity on cable into the hole. For higher inclinations, more expensive equipment has to be mobilized to push tools down the hole.
Another disadvantage of wells with a high inclination was that prevention of sand influx into the well was less reliable and needed higher effort. Again, this disadvantage has diminished such that, provided sand control is adequately planned, it is possible to carry it out reliably.
Applications of directional drilling
For the oil and gas industry there are many applications for directional drilling which includes the followings: -
b) Drilling to avoid geological problems
A. Fault formation
B. Salt dome formations
c) Controlling vertical well
d) Inaccessible locations
e) Multiple wells from single location
f) Relief well drilling
g) Multilateral well
Extended reach (ERD) wells
Extended reach (ERD) wells are defined as wells that have a horizontal departure (HD) at least twice the true vertical depth (TVD) of the well. ERD wells are kicked off from vertical near the surface and built to an inclination angle that allows sufficient horizontal displacement from the surface to the desired target. This inclination is held constant until the wellbore reaches the zone of interest and is then kicked off to near horizontal and extended into reservoir. This technology enables optimization of field development through the reduction of drilling sites and structures, and allows the operator to reach portions of the reservoir at a much greater distance than possible with a conventionally drilled directional well. These efficiencies increase profit margins on viable projects and can make the difference whether or not the project is financially viable. It is well known that ERD introduces factors that can compromise well delivery, and the first challenge prior to drilling an ERD well is to identify and minimize risk.
Technologies that have been found to be critical to the success of ERD are torque and drag, drillstring design, wellbore stability, hole cleaning, casing design, directional drilling optimization, drilling dynamics and rig sizing. Other technologies of vital importance are the use of rotary steerable systems (RSS) together with measurement while drilling (MWD) and logging while drilling (LWD) to geosteer the well into the geological target. Many of the wells drilled at Wytch Farm would not have been possible to drill without RSS, because steering beyond 8,500 m was not possible as axial drags
were too high to allow the orientated steerable motor and bit to slide.
Drilling ERD wells in deep waters is the next step, even though there are some experiences offshore, they are related to wells drilled on shallow waters from fixed platforms. In Brazil, where the major oil fields are located in deep waters, ERD wells might be, in some cases, the only economically viable solution
When we drill for oil and gas in different formation structures, the drilling string and the down-hole assembly (BHA) equipment goes through a differential pressure down the hole which can cause it stuck or fail. No further progress in the same well bore can be made in the same well if the fish can’t be removed from the well bore. Drilling a new well is not an option at all. A cement plug is placed on top of the fish and allow it to set firmly. This forms a good foundation for which the new section of the can be kicked off. Now we can start drilling a new direction well from the kick off point on top of the fish. As in the figure (1).
RELIEF WELL DRILLING
The objective of a directional relief well is to intercept the borehole of a well which is blowing out and allow a tap into it to be ableto kill the blowing well. The bore hole causing the problem is thesize of the target. To locate and intercept the blowing well at acertain depth, a carefully planned directional well must be drilledwith great precisionToolsLost
DRILLING TO AVOID GEOLOGICAL PROBLEMS
Drilling for petroleum is not always a clear path with no geological problems. Petroleum reservoirs are sometimes associated with salt dome and faults structures. A salt dome may be directly on the above the oil reservoir, so it no possible to drill a vertical well through the salt dome formation. Drilling through it will introduce many problems such as large washout, lost circulations and corrosion. Now in this situation we can avoid drilling a vertical well and drill a directional well as show in the figure (2).
Considering an oil reservoir under a fault formation, drilling a vertical well will alsointroduce many problems as drilling through salt dome. In that case we have to drill a directional well to avoid the fault as in the figure (2)
CONTROLLING STRAIGHT WELLS
When we drill for oil and gas there are different problems that risers like the vertical well drifting and straying across lease boundaries and move away from the target, for that directional drilling techniques have to be used. Small deviations from the planned course can be corrected by altering certain drilling parameters or changing the bottom hole-assembly (BHA). More serious deviation may require the use of a down-hole motor and bent sub to make a correction run or drill a sidetrack.
Petroleum reservoir are often located directly beneath natural or man-made obstructions. Which can’t be destroyed for various reasons which can also be economical or environmental. In this case it may be possible to used directional drilling methods. As shown in the figure blow.
When a blowout destroys or damages the rig in such a way that capping operations are impossible, relief wells are drilled to bring the blowout safely under control. Improved directional drilling techniques have enabled relief wells or reach target less than 10 ft from the blowout. Often two relief wells are drilled simultaneously from different surface locations to ensure that the blowout is killed.
MULTIPLE WELLS FROM SINGLE LOCALTION
In oil and gas industry the wells are designed and drilled based on some budgets from the operating company. Directional drilling changed the oil and gas industry be enabling drilling multiple wells from a single platform which is more economical, as we don’t have to build a platform for every discovered reservoir. We can drill multiple wells from a single location and produce from different reservoirs from a single platform as in the figure blow.
The drilling of small-diameter boreholes in rock to measure thickness of the strata and to obtain core samples is well established. Indeed, some of the techniques used in the oil industry were adopted from earlier techniques used in mining (e.g. borehole surveying to measure inclination and direction). Directional wells are used to produce methane gas that is contained in coal seams. The methane presents a safety hazard and must be drained off before mining operations can begin. In deep coal seams that are beyond the reach of conventional mining techniques, directional wells have been drilled for in situ gasification projects.Construction Industry
An unusual application of directional drilling is the installation of pipelines beneath river bed. A small-diameter pilot hole is drilled in a smooth are beneath the river until it emerges on the other side. This acts as a guide for the larger- diameter pipe that forms the conduit. The pilot hole is drilled using a down-hole motor and bent sub.
Construction of tunnelGeothermal Energy
In certain areas of the world the high geothermal gradient found in some rocks can be harnessed to provide energy. The source rock (e.g. granite) is generally impermeable except for vertical fractures. Extracting the heat from this rock requires the drilling of injection and production wells. The wells are directionally drilled to take advantage of the orientation of the fractures. The high temperature and hardness of the rock cause some major drilling problemWell ProfilesWell profile is a term used in directional drilling which can be simply defined as the structure of a directional well.Well profile is determined before directional drilling, there are three factors required before determining a well profile:
a. The distance between the total vertical depth and the target depth of the reservoir location
b. Type of formation
c. The production policy
Types of well profiles
Well profiles are of three types, they are “L” profile or type 1,” S” profile or type2 and “J” profile or type 3
1) L type profile
L-type wells have a bore with a straight section, a build section, and a tangent section.
This type of well profile is also known as build and hold type, the
most common and the simplest profile. It can be used where large displacements are required at relatively shallow depths.
One of its advantages is fewer directional problems.
Horizontal wells-a variant of “L” profile well have a bore with a straight section, a build section, tangent section, a second build section (most of the time), and a horizontal section. The well is drilled to a point above the reservoir; then it is deflected and the angle increases until it reaches 90 degrees or more.
When properly applied, one horizontal borehole can produce a reservoir better than several vertically drilled wells.
2. “S” type profile
S-type wells have a bore with a straight section, a build section, a tangent section, and a drop section. This type of well is drilled to improve the efficiency of the well and to assist in the location of a blown-out well. In offshore drilling, S-type wells can ensure accuracy in bottom-hole spacing when multiple wells are drilled from the same platform.
The S type well consists of five parts:
I. Top vertical section (straight section)
II. Build section
III. Hold portion (tangent portion)
IV. Drop portion (Drop section)
V. Bottom Vertical Portion
S type profile is also known as the build hold and drop. It is adopted for those situations where the horizontal horizontal drift requirement is much less vis-à-vis the TVD of the well. This profile is also useful where the gum boo formations or steeply dipping beds are to be drilled vertically.
3. J type profile
J-type profile, sometimes called deep kick off and build type, have a bore with a straight section, a build section, and a tangent section straight to the target Slant or J-type wells are drilled where it is not desirable or possible to locate the surface location directly above the target or a multi-well platform.
This type is used in particular situations like salt dome drilling, fault drilling and side tracking or repositioning of target.
Some disadvantages of this type are:
Formation maybe harder and less responsive to deflection. More tripping time to change BHA BUR more difficult to control.
Directional Drilling terminologies
3D directional well - a directional well with a planned well path that is not entirely vertically-planar; azimuthal turn exists over a segment or segments of the planned well path.
Actual well path - a best estimate of where a well bore exists in 3D space, as computed with directional survey data and the minimum curvature survey calculation method.
Azimuth - the angle of the well bore direction as projected to a horizontal plane and relative to due north. By industry convention, 0
degree azimuth coincides with North, 90 degree azimuth with East, 180 degree azimuth with South, and 270 degree azimuth with West.
Azimuthal deviation - the difference in azimuth between actual and planned well paths, typically at a specific measured depth. Same as msAD.
Build - drilling directionally with the intent to increase well bore inclination; also refers to increasing and orienting lateral bit force magnitude to or towards the high side of the drill hole.
Cognitive map - a sketch that presents a causal picture of the association of components within a complex dynamic system, for the primary purpose of better understanding dependency relationships and general cause/effect.
Controllable - a general term given to a system component for which the control thereof is direct. For example, consider driving an automobile with an automatic transmission. Gear selection, the gas pedal (accelerator), and the brake pedal are examples of controllable, while speed is an observable.
Directional drilling - the field/industry that encompasses the act of drilling a section of well bore that is intentionally oriented non-vertically; horizontal drilling is a subset of directional drilling.
Directional plan view - a plot that displays (North/South, East/West) Cartesian coordinates of a well path projected to a horizontal surface plane; also known as map view.
Directional survey - a summary of geometric information--calculated with directional survey data and a directional survey calculation method (e.g., minimum curvature method)--that pertains to spatial properties (e.g., Cartesian coordinates) of a directional well; sometimes synonymous with directional survey data or directional survey station.
Directional survey data - typically refers to the "raw" data acquired at a directional survey station, namely, well bore inclination and azimuth at specific measured depths.
Directional survey station - a reference point that corresponds to a measured depth along the (typically actual) well path where well bore inclination and azimuth are observed/measured and recorded.
Directional vertical section view - a plot that displays vertical section versus true vertical depth of a well path. Vertical section is the horizontal distance (departure) of a well path projected to a vertical plane of specific azimuth. The specific azimuth typically coincides with the final target azimuth.
Directional well - a well bore created by drilling directionally.
Dogleg severity - a normalized estimate (e.g., degrees / 100 feet) of the overall curvature of an actual well path between two consecutive directional survey stations, according to the minimum curvature survey calculation method. With respect to a planned well path, dogleg severity may at times be synonymous with build gradient and/or turn gradient. (Degrees / 100 feet or degrees / 30 meters)
Drilling directionally - the process of drilling a well bore with sustained and proactive attention to a preferred path; such preferred trajectory comprising non-vertical hole sections.
Kick off Point (KOP): The kick off point is defined as the point below the surface location from where the well is deflected from the vertical. The position of the kick off depends on several parameters including: geological considerations, geometry of well and proximity of other wells. Build Section: That portion of the hole in which the inclination angle is increased; rate of buildup is usually expressed as the angular increase per 100 feet of measured depth.
Build Up Rate (BUR): It is the rate of change (degrees/100 feet or degrees/30 meter) of the increasing angle in the hole. Drop off: It is the act of reducing the inclination of the drilled hole with respect to the vertical. Drop Section: That portion of the hole in which the inclination angle is decreased; rate of drop off is usually expressed as the angular increase per 100 feet of measured depth. Drop off Rate: The rate of change of the inclination in the part of the wellbore where the inclination angle is purposely returned toward vertical, usually expressed in degrees per feet or course length. Hold: The act of maintaining the inclination and azimuth of the wellbore to remain constant as it is. Tangent or Hold Section: The portion of hole in which the inclination and azimuth is maintained the same throughout the section.
Drop - drilling directionally with the intent to decrease well bore inclination; also refers to increasing and orienting lateral bit force magnitude to or towards the low side of the drill hole.
Inclination - the angle of the well bore defined by a tangent line and a vertical line. The vertical line is always parallel to the direction of earth's gravity. By industry standard, 0 degree inclination is vertical (downward pointing) and 90 degrees inclination is horizontal. An inclination (angle) greater than 90 degrees coincides with the term "drilling up".
MD - the measured depth along the planned well path that coincides with the point along the planned well path that minimizes the 3D distance between where the bottomhole location actually is, and where it is thus preferred. (Feet or meters).
Geographic North: In geographic coordinates directions are referred to true north, or a true azimuth. Geographic north points to the North Pole; this direction is indicated by the polar star.
Grid North: Grid north is an arbitrary direction and is always in the direction of the positive ordinate axis of the specific grid used for a particular survey. Magnetic North: Magnetic north can be measured by a simple magnetic compass. Magnetic azimuths are not constant due to the movement of the north and south magnetic poles and hence magnetic measurements may be in error due to local magnetic field variations. In oil wells, all surveys with ‘magnetic type’ tools are initially given an azimuth reading referenced to Magnetic North. However, the final calculated coordinates are always converted to either True North or Grid North.
Magnetic Declination: Magnetic north and true north do not coincide. The divergence between true north and magnetic north is different for most points on the earth’s surface, and in addition to this the magnetic north pole changes its position very slightly each year. The angle in degrees between true and magnetic north is called the declination angle. The declination angle is negative if magnetic north lies to the west of true north and is positive if the magnetic north lies to the east of true north (refer figure below).
Planned well path - as a function of measured depth, the Cartesian coordinates, inclination, and azimuth that define the preferred spatial existence of a well bore. The planned well path can be piece-wise continuous, meaning it can change abruptly, typically as the result of new information acquired while drilling (e.g. fault crossing).
Trajectory - same as well path, either actual or planned; the traverse that defines the actual or preferred existence of a well bore via spatial properties.
METHODS OF SURVEY CALCULATIONS
During drilling it is next to impossible to make the actual trajectory precisely match the designed well path. For that reason, it is important to monitor the well trajectory and take corrective actions as the well is being drilled. To achieve this goal there must be reliable survey measurement tools and techniques that determine inclination, azimuth and perhaps the tool face orientation at different points along the well path. Survey tools only provide an incremental departure from a known starting point. The known point
is referred to as the tie-on, or ties line. The first survey station is recorded deeper than the tie-on. The tools measure inclination and azimuth, the MD is known. The points of measurements are called survey stations. The measured parameters are then used to calculate the wellbore position in terms of the 3D coordinates N, E and TVD. Inclination angle is measured with respect to the vertical while azimuth is measured with respect to either magnetic or true north. But azimuth is typically reported in reference to true or grid north. As a result, the azimuth needs to be corrected before being reported or used in calculations. True north is the absolute north reference. Magnetic Declination is the angle from true north to magnetic north, and Grid Convergence is the angle from true north to grid north.
When planning a 3D well trajectory for any directional well, one of the most important considerations is torque and drag. If the torque and drag are not carefully considered, the drill string might fail. The torque and drag model used makes special assumptions that simplify the analysis and are used to model real drill strings. The most important factor influencing the torque and drag forces is the hole-curvature. The well path should be redesigned with a smaller build-up rate if the drill string seems to fail when simulating these forces during the design stage. There are many causes for excessive torque and drag such as: sliding friction, tight hole, collapsing or swelling clay/shale, key seats, differential sticking and cuttings build-up. The minimum curvature method assumes the bending part in the equilibrium equation used to calculate torque and drag is discontinuous at survey stations. Some authors mean this is one of the main weaknesses of using the minimum curvature method. Due
to the missing bending stresses, the method might not represent the real drill string configuration
Methods of survey calculations
There are several methods of computing directional surveys (Figure). However, only four are commonly used today. The main methods are:
I. Average angle
III. Balanced tangential (rarely used)
IV. Radius of curvature
V. Minimum curvature.
The tangential method gives significant errors throughout the wellbore path, as well as the bottom-hole location. The balanced tangential method is included as it is the basis for the minimum curvature method. These methods use inclination and azimuth at a specified measured depth. The difference between these methods is how they process the raw survey data of inclination, azimuth, and measured depth. The following paragraphs are a description of these methods
Average angle method
The average angle method (Figure) uses the average of the inclinations and azimuths measured at the upper and lower survey stations. The average of the two sets of angles is assumed to be the inclination and the azimuth over the incremental measured depth. The wellbore path is then calculated using simple trigonometric functions
Average angle calculations
MD = Measured depth between surveys (m)
I1 = Inclination (angle) at upper survey (°)
I2 = Inclination (angle) at lower survey (°)
Az1 = Azimuth direction at upper survey (°)
Az2 = Azimuth direction at lower survey (°).
From Average Angle Method, following values are obtained:
ΔTVD = ΔMD. Cos(I1+I2)/2
ΔNorth = ΔMD. Sin (I1+I2)/2 . Cos(A1+A2)/2
ΔEast = ΔMD/2. Sin (I1+I2)/2 . Sin(A1+A2)/2
The tangential method (Figure) uses the inclination and azimuth at the lower end of the course length to calculate a straight line that represents the well bore, and passes through the lower end of the course length. The wellbore is assumed to be a straight line throughout the course length. This method is the most inaccurate of the methods discussed and should not be used in the determination of survey results unless the course lengths are not longer than the length of the survey tool
Angle A = angle I2
AI2 = assumed well course = ΔMD (change in measured depth for this interval)
AB = AI2 Cos I2 = ΔTVD (This will be equal to the TVD for this interval)
BI2 = Departure
ΔNorth = ΔMD SinI2 x Cos A2 .
ΔEast = ΔMD SinI2 x Sin A2 .
Radius of curvature method
The radius of curvature method is currently considered to be one of the most accurate methods available. The method assumes the wellbore course is a smooth curve between the upper and lower survey stations. The curvature of the arc is determined by the survey inclinations and azimuths at the upper and lower survey stations as shown in Figure below. The length of the arc between I1 and I2 is the measured depth between surveys.
The following values are obtained using radius of curvature method:
ΔTVD = [(180) (ΔMD) (SinI2 – SinI1)] / π (I2 - I1)
ΔNorth = [(180)2 (ΔMD) (CosI1 – CosI2) (SinA2 – SinA1)] / π2 (I2 - I1) (A2 - A1)
ΔEast = [(180)2 (ΔMD) (CosI1 – CosI2) (CosA1 – CosA2)] / π2 (I2 - I1) (A2 - A1)
DEP = [(180) (ΔMD) (CosI1 – CosI2)] / π (I2 - I1)
r = 180 / π (DLS)
ΔMD = (I2 - I1) / Br
π = 3.1415926
DLS = Dog Leg Severity
Br =Build Rate
COMPONENTS OF A DIRECTIONAL BHA
ANDERDRIFT “VERTICAL INCLINATION INDICATOR”
Run as part of the BHA; working parts inside a “drill collar”.
The tool resets whenever the pump stops.
The weighted bob latches into one of the grooves, depending on the inclination.
When the pumps start, the inner parts move down causing a number of pressure pulses visible to the driller on his standpipe gauge.
Gives a “free” survey; takes no extra time. Eliminates the risk of fishing a totco in a vertical well.
Heavy-weight Drill Pipe (HWDP)
A joint of HWDP has a greater wall thickness and longer tool joints than normal drill pipe. Midway between the tool joints is an integral wear pad which acts as a stabilizer .HWDP has basically the same functions as a drill collar but has much less contact area with the formation. Like the drill collars, HWDP can be run in compression. The use of HWDP in a directional well will therefore
(i) Reduce torque and drag on the drill string;
(ii) Reduce the risk of differential sticking;
(iii) Reduce the risk of tool joint failures when drilling through dog-legs.
The BHA in a directional well may have 20 or more joints of HWDP between the drill collars and drill pipe. The effect of bending can be assessed by calculating the section modulus for adjacent drill string components
Stabilizers are fairly short subs which have blades attached to their external surface. By providing support for the BRA at certain points they can be used to control the trajectory of the well. The blades can be either straight or spiral in shape. Spiral blades can give 3600 contact with the borehole. Various different types of stabilizers are available run in tandem if necessary ("piggy-back"). Stabilizers are inserted at drill collar connections. This limits their spacing to 30ft or multiples of 30 ft. Closer spacing can be achieved by using shorter drill collars (pony collars) that are 10-15ft long. "Clamp on" stabilizers can be used to provide support at some point along the length of a collar. Any stabilizer that is placed near a magnetic surveying tool must be made of non-magnetic material, to prevent distortion of the survey results.
(a) Welded blade.
Steel blades are welded on to the body of the stabilizer. The mud in the annulus flows between the blades. The blades make contact with the wall and may cause hole-enlargement
in soft formations. This type of stabilizer can be used when the gauge size remains constant.
(b) Integral blade.
These are more expensive than welded blade type stabilizers, since they are machined from one piece of metal. They are generally used to provide a larger contact area. Tungsten carbide can be used on the blades to provide better wear resistance in more abrasive formations.
(c) Sleeve stabilizers.
These consist of replaceable sleeves that are mounted on the stabilizer body. They offer the advantage of changing out a sleeve with worn blades or replacing it with one of another gauge size. The blades can be dressed with tungsten carbide inserts for abrasive formations.
(d) Non-rotating stabilizers.
These stabilizers are used to centralize the drill collars, but the rubber sleeve allows the string to rotate while the sleeve remains stationary. The wear on the blades is therefore much less than in other stabilizers and so they can be used in harder formations. Stabilizers can be installed just above the bit (near-bit stabilizers) or at any point within the BHA (string stabilizers). Two stabilizers can also be run in tandem if necessary ("piggy-back"). Stabilizers are inserted at drill collar connections. This limits their spacing to 30ft or multiples of 30 ft. Closer spacing can be achieved by using shorter drill collars (pony collars) that are 10-15ft long. "Clamp on" stabilizers can be used to provide support at some point
along the length of a collar. Any stabilizer that is placed near a magnetic surveying tool must be made of non-magnetic material, to prevent distortion of the survey results.
Bottom-hole assemblies (BHA) include all drilling equipment connected to the bottom of the drill pipe. They provide bit weight and stability for faster drilling rates and aid in drilling a smooth, straight or smooth, curved hole. Stabilizers give varying degrees of rigidity or limberness. Heavy BHAs are a concentrated weight at the bottom of the drill string, so the hole drills vertically downward aided by gravity. Directional equipment on the bottom part of assemblies causes the bit to drill direction ally away from axis of the immediate upper-hole section.
The basic Rotary Assemblies
Only one “Near Bit Stabilizer” which tends to increase the inclination of the wellbore. Used after kicking off the well until the planned maximum inclination is achieved.
Once the inclination has been built to the required angle, the tangential section of the well is drilled using a holding assembly. The object here is to reduce the tendency of the BHA to build or drop angle. In practice this is difficult to achieve, since formation effects and gravity may alter the hole-angle. To eliminate building and dropping tendencies, stabilizers should be placed at close intervals, using pony collars if necessary. Assembly has been used successfully in soft formations. The under gauge stabilizer in assembly builds slightly to counter gravity. In harder formations the near-bit stabilizer is replaced by a reamer. Generally, only three stabilizers should be used, unless differential sticking is expected. Changes in WOB will not affect the directional behavior of this type of assembly, and so optimum WOB can be applied to achieve maximum penetration rates. A packed hole-assembly with several stabilizers should not be run immediately after a down-hole motor run.
One string stabilizer 9 m to 18 m away from the bit is used. The portion of the BHA from the bit to the first string
stabilizer hangs like a pendulum and, because of its own weight, presses the bit towards the low side of the hole.
This causes reduction in the inclination of the hole.
Measuring instruments record drift, direction, and tool face, the basic measurements for directional and horizontal operations. Measurement while drilling (MWD) instruments also record other data. Regular surveying instruments operate in temperature environments up to 250°-300° F. Higher temperatures degrade the electronics, batteries, and other parts of the measuring equipment. Heat shields insulate instruments and allow operation at higher well temperatures for a limited time.
The magnetic declination is defined as the angle between the true north and magnetic north. If the magnetic north deflects towards the east, it is called east declination and if the magnetic north deflects towards west, then it called west declination. It varies irregularly over the earth’s surface but does tend to be smaller near the equator and greater in higher latitudes. The pattern of earth’s field is not permanent; declination also changes gradually with time. The azimuth read from the magnetic survey instrument must be corrected for declinationMAGNETIC DECLINATION CORRECTION
Before survey calculation, all magnetic directions must be corrected with respect to ‘True North. The azimuth recorded from the magnetic survey instruments must be corrected for declination. Magnetic declination is the angle between Magnetic North and True North.
Declination at certain place can be read from isogonic charts.
The Magnetic declination may be either East declination, West declination or Zero. Zero angle declination: No correction is required in magnetic reading. East declination: Magnetic north lies east to true north. West declination: Magnetic north lies west to true north.
The drift indicator was the first reliable instrument to measure the drift or angle of inclination of the wellbore. It does not record direction. A modified version of the tool is in use today. It has a free hanging plumb bob with a pin on the bottom. This suspends over a paper disk marked with concentric circles calibrated in degrees. A
timing device actuates a mechanism that causes a pin to puncture the disk.
There are various modifications. One has a light source and light sensitive disk. Another records two measurements. After recording the first measurement, the disk rotates a half turn and records a second measurement as a verification of the first measurement. A motion sensor replaces the timer on drift indicators. It senses motion and will not actuate until the measuring instrument is at rest (motionless) for a predetermined period of time, usually about 30 seconds. This system has the advantages of fewer recording failures, less surveying time, and reduced risk of sticking.
In operation, the timer is set as required to allow time for running, and positioning with an interval so that the plumb bob can come to a complete rest. The instrument is placed in a centralized position inside a steel container. The carrier is lowered into the cased or open hole on a single-strand wire line to the measurement depth, where it aligns with the axes of the hole. The drift angle is recorded, the tool is lifted out of the hole and the disk is examined.
The position of the point on the disk chart is the drift angle of the wellbore at the measurement point. Drift may be recorded at other points by repeating the procedure. In another method, the instrument is dropped inside the drill pipe before tripping and recovered after pulling the pipe. This instrument is commonly used for regular vertical drilling and in some common directional operations.
The magnetic single-shot measures both the drift and direction of the wellbore. The instrument has a precision floating compass, a device to superimpose concentric circles calibrated in degrees with a plumb-bob-type indicator. A camera photographs the plumb bob and compass face to record both drift and direction. Otherwise the magnetic single-shot is similar to the drift indicator and operates similarly. It cannot record compass directions inside steel pipe or casing because they blank off the earth's magnetic lines of force. It records measurements inside nonmagnetic drill collars. It was first used in an old method of orienting by the ''high side." A special version of this tool has limited use for high- or low-side orientation. A later version of the magnetic single-shot includes a pointer that indicates the direction of the tool face. It is in a fixed direction relative to the measuring instrument. The measuring instrument fits in a fixed, specific position inside the carrier container. The carrier has a mule shoe guide on bottom. When the carrier is lowered into the hole, this guide fits over a key slot in the orientation or measurement sub connected to the deviation assembly. This aligns the pointer relative to the key slot. Either the key slot should be aligned with the tool face when connecting the measurement sub in the deviation assembly, or the relative difference should be
measured. During operation, a measurement records drift and magnetic direction of the wellbore and the relative direction of the tool face. Sometimes the mule shoe and key lock system restrict flow rates. An improved version replaces the mule shoe and key lock with a magnetic tool face indicating pointer. The measuring instrument has two compasses. One is the floating type for drift and direction. The other is a needle-type tool face pointer. The measurement or orientation sub has two rows of small magnets positioned vertically along the axis of the sub and 180° apart. The magnets in each row are a few inches apart. Magnets in one row have their north pole facing outward from the center of the sub. Magnets in the other row have their south pole facing outward. This creates an induced magnetic field for the magnetic tool face indicating pointer. Then the angular difference between the tool face and the rows of magnets is measured. As with the mule shoe version, drift and magnetic direction of the wellbore and the relative direction of the tool face are recorded. Magnetic single-shots are designed to measure angles within specific ranges. For example a 5° instrument measures drift angle between 0° and 5°. Likewise a 20° instrument measures angles between 0° and 20°. Generally an instrument is selected so that the drift angle is in the upper one half of the range for the best reading accuracy. Various instruments have different displays. The plumb bob position usually is located by either a small X or cross hairs, or, less frequently, a dot enclosed in a small circle. Most instruments use the set of concentric circles for measuring drift. A small circle in the margin or a radial line (or both) indicate the direction of the tool face.
Single magnetic shot Instruments
The TOTCO Drift Indicator is a simple surveying instrument consisting of a mechanical timer and an angle unit.
The timer is set assuming a descent rate of 300ft/min in mud. Angle units are available in a variety of inclination ranges (1º, 3º, 5º, 7º, 8º, 14º, 16º, 21º, 24º and 90º). When the timer fires, the angle unit presses a calibrated paper disc against a pendulum and the inclination can be read directly from the indentation created
ERRORS IN RECORDING SURVEYS
INACCURACY IN AZIMUTH READING
All tools in use earth’s magnetic field to record azimuth at a particular survey point. So, all the recordings are referred to the magnetic north and not to the true north. To get a correct azimuth we have to consider the following:- Magnetic declination Magnetic interference from nearby wells Solar activity Errors in the tool itself
When the bit is lowered down the hole the tapered side of wedge deflected the bit away from the vertical. A new section of hole could then be drilled at a slight angle to the vertical. Whip stocks were later used to kick-off directional wells with the aid of directional surveying instruments to check the orientation of the tapered edge. The direction in which the tapered edge was facing became known as the "tool face". There are several different types of whip stock available. A "removable whip stock" can be used to initiate deflection in open hole, or straighten vertical wells that have become crooked. The whip stock consists of a steel wedge with a chisel-shaped point at the bottom to prevent movement once drilling begins. The tapered concave section has hard facing to reduce wear. At the top of the whip stock is a collar that is used to withdraw the tool after the first section of hole has been drilled. The whip stock is attached to the drill string by means of a shear pin. Having run into the hole, the drill string is rotated until the tool face of the Whip stock is correctly positioned. By applying weight from surface, the chisel point is set firmly into the formation or cement plug. The retaining pin is sheared off and drilling can begin. Once the deflected section of hole has been started, a rotary building assembly can be run to continue the sidetrack. If there is a build-up of cuttings at the bottom of the hole, it may be difficult to position the whipstock properly. This led to the introduction of the "circulating whipstock", which contains a passageway to allow mud to wash out these cuttings or fill from the bottom of the hole. A "permanent whipstock" is used mainly in cased hole for sidetracking around a fish or by-passing collapsed casing. A casing packer is set at the kick-off point to provide a base for the whipstock. The whipstock is run with a mill that will cut a "window" in the casing. After setting the whipstock in the required direction and shearing the retaining pin, the milling operation begins. Once the window has been cut, the mill is replaced by a small diameter pilot bit. The pilot hole is subsequently reamed out to full size. If used correctly the whipstock is a reliable and effective deflecting tool.Disadvantages
The rat-hole that is drilled initially must be reamed out, requiring a new BHA to be run
While drilling the whipstock may rotate, deflecting the bit away from its intended direction
As the bit drills off the whipstock, some drop in inclination may occur
As the bit drills off the whipstock, some drop in inclination may occur.
When using a permanent whipstock to mill a window in the casing, the window itself is often too small. It may be advisable to use a section mill to cut out a larger length of casing, then set a cement plug and deflect the wellbore with a mud motor and bent sub
Motor with bent sub A common method of deflecting wellbores is to use a down-hole motor and a bent sub. As illustrated in, the bent sub is placed directly above the motor and the bent sub which makes this a deflection assembly. Its lower thread (on the pin) is inclined 1° - 3° from the axis of the sub body. The bent sub acts as the pivot of a lever and the bit is pushed sideways as well as downwards. This sideways component of force at the bit gives the motor a tendency to drill a curved path, provided there is no rotation of the drill string. The degree of curvature (dogleg severity) depends on the bent sub angle and the OD of the motor, bent sub and drill collars in relation to the diameter of the hole. It also depends on the length of the motor. A down-hole motor and bent sub assembly may be used for kicking off wells, and for correction runs or for sidetracking. Notice the absence of any stabilizers in the lower part of this assembly. Usually there would be no stabilizers for at least 90 feet above the bent sub. In fact, it is not uncommon for the entire BHA to be "slick" when a motor and bent sub is used for kicking off at shallow depths.
Jet deflection is a technique best suited to soft-medium formations in which the compressive strength is relatively low. The hydraulic power of the drilling fluid is used to wash away a pocket of the formation and initiate deflection. A specially modified bit must be used that has one nozzle much larger than the other two. A two-cone bit with a large "eye" may also be used. The bit is run on an assembly which includes an orienting sub and a full-gauge stabilizer near the bit once on bottom, the large nozzle is oriented in the required direction. Maximum circulation rate is used to begin washing without rotating the drill string. The pipe is worked up and down while jetting continues, until a pocket is washed away. At this stage the drill string can be rotated to ream out the pocket and continue building angle as more WOB is applied. Surveys must be taken frequently to ensure the inclination and direction are correct. If it is found that the deflected section of the well is not following the planned trajectory, the large nozzle can be re-oriented and jetting can be repeated.ASSEMBLY IN JETTING
Conventional jet bit with one large nozzle and two blinds
Full gauge near bit stabilizer
Mule shoe sub (UBHO sub)
Non-magnetic drill collar
Spiral drill collars
Heavy weight drill pipes
Jet Deflection Advantages
A full gauge hole can be drilled from the beginning (although a pilot hole may be necessary in some cases).
Several attempts can be made to initiate deflection without pulling out of the hole
Jet Deflection disadvantages
The technique is limited to soft-medium formations (in very soft rocks too much erosion will cause problems).
Severe dog-legs can occur if the jetting is not carefully controlled (if the drilling is fast, surveys must be taken at close intervals).
On smaller rigs there may not be enough pump capacity to wash away the formation.
Measurement While Drilling
Measurement While Drilling (MWD) system allows the driller to gather and transmit information from the bottom of the hole back to the surface, without interrupting normal drilling operations. This information can include directional deviation data, data related to the petrophysical properties of the formations and drilling data, such as WOB and torque. The information is gathered and transmitted to surface by the relevant sensors and transmission equipment, which is housed in a non-magnetic drill collar in the bottom hole-assembly (BHA). This tool is known as a Measurement While Drilling Tool (MWD). The data is transmitted through the mud column in the drill-string, to surface. At surface the signal is then decoded and presented to the driller in an appropriate format. The transmission system is known as mud pulse telemetry, and does not involve any wireline operations. Commercial MWD systems were first introduced as a more cost effective method of taking directional surveys. To take a directional survey using conventional wireline methods may take 1-2 hours. Using an MWD system a survey takes less than 4 minutes. Although MWD operations are more expensive than wireline surveying an operating company can save valuable rig time, which is usually more significant in terms of cost. More recently MWD companies have developed more complicated tools which will provide not only directional information and drilling parameters (e.g. torque, WOB), but also geological data (e.g. gamma ray, resistivity logs). The latter tools are generally referred to as Logging While Drilling (LWD) tools. As more sensors are added the transmission system must be improved, therefore MWD tools are becoming much more sophisticated. Great improvements have been made over the past few years,
and MWD tools are now becoming a standard tool for drilling operations.
Measurement While Drilling (MWD)
All MWD systems have certain basic similarities
1. A downhole system which consists of a power source, sensors, transmitter and control system.
2. A telemetry channel (mud column) through which pulses are sent to surface.
3. A surface system which detects pulses, decodes the signal and presents results (numerical display, geological log, etc.).
The main difference between MWD systems is the method by which the information is transmitted to surface. All encode the data to be transmitted into a binary code, and transmit this data as a series of pressure pulses up the inside of the drill-string. The process of coding and decoding the data will be described below. The only difference between systems is the way in which the pressure pulses are generated.
Features of MWD
MWD can include the following features
It provides directional drilling data for example (azimuth, inclination, tool face – magnetic a gravity).
It can detect gamma ray in the formation and measure it and give type of formation we are drilling through.
It contain thermal and pressure instruments which can measure the annular temperature and annular pressure.
Real-time telemetry for logging while drilling (LWD) data.
Training : Industry training and Learning Resources. (n.d.). Retrieved August 2014, from Rigzone: https://www.rigzone.com/training/Jackuprigs/insight.asp?i_id=195
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Introduction to Directional and Horizontal Drilling - Jim Short
directional drilling – inglis
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Horizontal and Vertical Drilling
Joshi, S. D. - Horizontal Well Tecnology