Bottom Hole Assembly
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From Wikipedia, the free encyclopedia
^ William C. Lyons, ed. (1996). Standard Handbook of Petroleum and Natural Gas Engineers . Houston Texas: Gulf Publishing Company.
^ Michael L. Payne; Lance D. Underwood. Michael J. Economides; Larry T. Watters; ShariDunn-Norman (eds.). Halliburton: Petroleum Well Construction . John Wiley and Sons.
^ Tom H. Hill; Randy C. Money. (1992). Drill Stem Design and Inspection . Houston Texas: T.H. Hill and Associates Inc.
A bottom hole assembly (BHA) is a component of a drilling rig . It is the lowest part of the drill string , extending from the bit to the drill pipe . The assembly can consist of drill collars, subs such as stabilisers, reamers, shocks, hole-openers, and the bit sub and bit. [1]
The BHA design is based upon the requirements of having enough weight transfer to the bit (WOB) to be able to drill and achieve a sufficient Rate of Penetration (ROP), giving the Driller or Directional Driller directional control to drill as per the planned trajectory and to also include whatever Logging While Drilling (LWD) / Measurement While Drilling (MWD) tools for formation evaluation. As such BHA design can vary greatly from simple vertical wells with little or now LWD requirements to complex directional wells which must run multi-combo LWD suites.
Prior to running a BHA most oilfield service providers have software to model the BHA behaviour such as the maximum WOB achievable, the directional tendencies & capabilities and even the natural harmonics of the assembly as to avoid vibration brought about by exciting natural frequencies.
Rotary assemblies [2] are commonly used where formations are predictable and the rig economics are an issue. In such an assembly the weight of the drill collars gives the BHA the tendency to sag or flex to the low side of the hole, collar stiffness length and stabiliser diameter and placement are engineered as a means of controlling the flex of the BHA. This will bring about the desired hold, build or drop tendency.
The ability to vary the directional tendency of the assembly comes from varying the weight on the bit. A fixed assembly has only one directional tendency. The weight on bit allows you to tune that tendency.
The bottom-hole assembly (BHA) can be:
Bottom-hole assemblies are also described as
This assembly is used to build angle. The assembly usually incorporates a near bit stabiliser. Behind this would be a selection of drill collars and Heavy Weight Drill Pipe (HWDP). The length of the section AFTER the near bit stabilizer would determine the extent of the angle build rate.
After the appropriate length of pipe after the near bit stabiliser you would place a drill string stabiliser.
In short the longer the gap between the near bit and the drill string stabiliser the greater the angle building rate. Care must be taken to not have this section too long as the pipe may sag too much and rub against the borehole wall. This could result in key seating and pipe digging into the borehole wall.
This assembly is usually used to maintain borehole angle. This assembly is very rigid allowing little movement of the bit.
Such an assembly would mean that the stabilisers are closely packed: a near bit stabiliser within 0–30 feet of the drill bit, and two more spaced 30 and 60 feet beyond it. If a short drill collar is used, then the stabilisers can be even closer together.
The shorter the distance between the stabilisers means that the drill collars bend less and the weight on bit (WOB) pushes directly on the bit, hence maintaining the angle.
A pendulum assembly is used to reduce the angle build rate or reduce well-bore angle.
In this assembly there is no near bit assembly. The front portion of the (BHA) is allowed to hang as a result of its own weight. In such a case the first stabiliser is placed 30–45 feet behind the bit.
This hanging means that there is a force acting on the low side of the hole, which causes the deviation. In the case of a straight hole then the bit simply continues downward.
There are three types of BHA configurations. [3] These configurations addressed are usually concerned with the use or layout of drill collars, heavy weight drill pipe and standard drill pipe.
Type 1, standard simple configuration, uses only drill pipe and drill collars. In this instance the drill collars provide the necessary weight on the bit.
Type 2 uses heavy weight drill pipe as a transition between the drill collars and the drill pipe. Weight on bit is achieved by the drill collars.
Type 3 uses the drill collars to achieve directional control. The heavy weight drill pipe applies the weight on the bit. Such a layout promotes faster rig floor BHA handling. It may also reduce the tendency for differential sticking.
In most cases the above three types of configurations usually apply to straight/vertical wellbores at most low to medium angle wellbores. For high angle and horizontal wellbore careful weight control of the BHA is a must. In this instance the weight may be applied by running the drill pipe in compression in the high angle section. The high angle may help to stabilise the drill pipe allowing it to carry some compression.
A stabiliser is used within a column of drill collars. They help guide the bit in the hole. They play a major part in directional drilling as it helps determine the well-bore path and angle.
Solid stabilisers have no moving or replaceable parts. The blades and the mandrel can be one piece (integral) or welded to the mandrel (weld-on/welded blade). The blades may be either straight or spiral. The working surface can be impregnated with tungsten carbide or diamonds inserts.
Replaceable blade stabilisers can maintain full gauge stabilization, but their blades can be changed with tools no machining or welding required
Sleeve type stabilisers have replaceable sleeves that can be changed in the field. The sleeves are either rotating or non-rotating.
Reamers are stabilisers that have cutting elements embedded on their fins, and are used to maintain a gauged well-bore. They can be used to drill out doglegs and key-seats in hard formations. Due to the cutting ability of the reamer the bit does less work in maintaining well-bore gauge and more work drilling.
An underreamer is used to enlarge the well-bore, usually beginning at some point under the surface. It does this by utilizing expandable cutters that only deploy at the designated time or depth. It is not to be confused with hole opening which occurs from the surface and in most cases the hole opener tool is of a fixed diameter.
The underreamer utilises an increase in mud pressure or flow rate to deploy the expandable cutters. A corresponding pressure drop across the tool would indicate that the tool has fully deployed.
Bottom Hole Assembly 101
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The Bottom Hole Assembly (BHA) is a key component of the drilling system, consisting of various components and tools (including the drill bit itself) which operate at the bottom of the wellbore and physically drill the rock.
The BHA is connected to the drilling rig by the drill pipe, an extendable hollow tube which conveys the mechanical and hydraulic energy and movement from the surface rig systems to the bottom hole assembly. This complex arrangement of tools varies considerably depending on requirements, and can stack up to 1,000 ft long. The BHA has become more complex over time to suit the needs of drilling operations and to accommodate different tools that have been developed. This article will explain the desirable objectives of the BHA in both vertical and directional drilling. We will also highlight the different key components of a bottom hole assembly and their functions. The main purpose of a BHA is to effectively load and control the drill bit, but it also serves other functions that will be discussed below.
When designing the BHA, drillers must consider the operational objectives, characteristics of the rock being drilled, anticipated drilling parameters, and available tools. Operational objectives that should be considered include the angle being drilled, directional and depth targets, the expected ROP, and how to achieve designed build/drop rate. The geological characteristics that should influence the design of the BHA include the abrasiveness and competency of the rock, bed dip angles, and the pressure regime in the hole being drilled. The drilling parameters that must be anticipated to design the BHA include the applied RPM range, desired WOB, torque, and the anticipated shock or vibration pattern.
Since drilling cost is so dependent on time, employing drill bits and proper BHA tools is crucial for faster and less expensive drilling. Drilling time is greatly affected by both the rate of penetration (ROP) of the drill bit, and the number of times the BHA has to be retrieved from the bore hole. Every time a new bit is required, the entire drill string must be retrieved section by section to pull the bottom hole assembly to surface and change it out. This process is known as a round trip, or “trip” and requires time, money, and intervention from the drill crew which puts them at risk. If any part of the BHA is defective or fails, the drill string must also be pulled out from the borehole to replace or repair the defective component, an undesirable condition which we must try to avoid through careful selection of components.
It is crucial to review bottom hole assembly components, such as the drill bit, reamers, and stabilizers in terms of functionality and layout in order to limit possible damaging vibrations. Adjustments and additions to the BHA can lower the potential for vibration improving cost-effectiveness and reducing the risk of failure. To configure the bottom hole assembly, design optimization software is used to help in mitigating cost and eliminating ineffective drilling operations. Also, downhole tool measurements and data must be observed continuously to identify and record the behavior of the bottomhole assembly.
The BHA is the business end of the drilling system that attaches to the drill string and is lowered down in to the hole. The threaded male and female ends of the drill pipe allow for more pipe and tools to be attached so that the drill string extends down to the thousands of feet required to drill an oil and gas well. Individual drill pipe segments, drill collars, and tools are all connected on the rig floor and then deployed downhole. These tools enhance the drilling operations and all serve different functions to work together to accomplish drilling objectives. The key structural components of the BHA are as follows:
In addition to the main components listed above, the BHA typically includes a downhole motor or a Rotary Steerable System (RSS), and Measurement While Drilling (MWD), and Logging While Drilling (LWD) tools. These are the main drilling, steering, and recording components that, along with the bit itself, do the work of the bottom hole assembly:
As mentioned earlier, the drilling parameters, and more importantly the direction of the wellbore, determine the necessary tools that make up the bottom hole assembly.
A vertical hole is a hole that is drilled straight down in to the earth’s surface, with some minor vertical deviation allowed. There are many different layouts of BHA that are used to drill vertically, but most use little or no stabilization near the drill bit, combined with the weight of the drill collars, to allow the BHA to constantly drop back to vertical under gravity and maintain a vertical hole. A down hole motor with a straight housing is sometimes used to improve performance in vertical drilling by adding extra RPM and power directly to the bit.
Directional drilling is any type of drilling method that is intended to hit a predetermined subsurface target. These targets are precisely pre-planned so that the drilled well goes exactly where needed within the reservoir rock, often when the target reservoir cannot be accessed using a straight vertical hole from surface. This can occur if multiple wells are required from the same surface pad or platform, if the area is inaccessible for various reasons, or simply just to maximize the recovery potential by having more hole through the reservoir rock. A directional bottom hole assembly has almost an infinite number of layouts depending on what targets are required and what tools will be incorporated. Typically though, the BHA for a directional hole will incorporate either a down hole motor or a rotary steerable system in order to point, push, or steer the bit in the correct direction. The directional BHA will also contain an MWD tool which measures the angles and trajectories of the well bore and relays them back to surface to make sure the well is still on target.
In drilling operations, the bottom hole assembly consists of components of the drilling system that act as penetrating, stabilizing, and maximizing tools to help aid in discovering hydrocarbons. The BHA provides the weight exerted on the drill bit to effectively break rock and so it also functions to provide the strength and stability needed to run in compression. The stabilizers that are in the bottom hole assembly help in preventing bit instability from the vibrations and wobbling that occur when shearing through rock formations. The BHA also helps in maximizing directional control by providing both stiffness and the precision tools necessary to steer the bit in the correct direction. Factors including hole shape, direction, and well characteristics are determined by the BHA, and so proper design of the bottom hole assembly must be made to control direction, ensure safety, and increase drilling efficiency.
Located at the end of the bottomhole assembly is the drill bit, which cuts through the rock structure to explore and exploit oil and gas reservoirs. Using a bit that is right for your drilling application is important, and having the right bottom hole assembly provides support, direction, weight, torque, and capabilities to maximize drilling performance. The bit design and the BHA layout should be carefully planned and matched in order to maximize the performance of both. Proper selection of the BHA and the drill bit help deliver drilling functionality, effectiveness, and overall results. Through examination of field results and research, our team works to constantly improve to ensure that our PDC bits and downhole tools are not the limiting factors in drilling operations.
At Ulterra, we develop groundbreaking technology to suit our customer’s drilling operations. Our patent-pending CounterForce® technology is a true advancement in PDC bit design. Unlike conventional PDC bits, CounterForce technology has a unique cutter orientation that allows the cutters to work together and force the bit to grasp the bottom hole pattern. Our CounterForce technology reins-in lateral forces and redirects them.
Ulterra is dedicated to maximizing the efficiency of oil and gas drilling operations through the use of groundbreaking drill bits and application specific technologies. Throughout the world’s drilling basins, we are building our reputation on performance.
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