1. Formation Pressure
This is the result of the geological processes that have influenced the sub-surface environment. It is also influenced by the fluid content and density contained within the sub-surface rocks.
In general the greater the depth the greater the formation pressure as a result of the increased load distributed through the grain to grain contact. So long as there is hydrostatic continuity, equilibrium will be maintained.
In drilling you may encounter abnormal formation pressures, these may cause problems that may result in costly drilling operation or may in the worst case scenario cause the shutting down of operations or loss of life.
There are 4 main mechanisms that account for abnormal pressures:
- Compaction effects
- Diagenetic effects
- Differential Density effects
- Fluid Migration effects
This occurs when particles are compressed closely together such that pore space is reduced. This results in increased pressure
This is the result of chemical alteration of the rocks by the geological process.
This is as a result the fluid within a formation having a significantly different density relative to the surrounding normal fluid densities.
This results in from the movement of fluids from one higher pressured formation moving into another lower pressured formation, usually from deeper to a shallower formation. This will usually result in the shallower formation having an abnormally higher formation pressure.
There are five main systems that compose the drilling rig:
- Fluid Handling/Circulating
- Well Control
- Pipe Handling
Responsible for the lifting of the loads that the rig is supposed to bear during its operations. Typically the major load that the equipment is responsible for is the lifting of drill pipe, tubulars and the drilling assemblies.
The equipment will be responsible for lifting the pipe into position as well as bearing the weight of the continuous length of drill pipe and assembly in the hole from the rotary table to the bottom of the wellbore.
- Derrick – The frame work that supports hoisting equipment and transmits the load to the substructure.
- Crown Block – The uppermost point of the derrick. It consists of a series of sheaves which the drill line is wound on. It is the stationary part of the block and tackle hoisting arrangement that hoists the drill pipe.
- Travelling Block – this is the moving part of the block and tackle arrangement that lifts the drill pipe and assembly. It consists of a series of sheaves upon which drill line is wound continuously between itself the crown block and the draw works.
- Drill Line – a continuous length of wire that is wound around the draw works, crown block and travelling block. It is eventually secured to a point on the derrick.
- Draw Works – this is drum that the drill line is wound on. It is powered by either an engine or electric motor depending on the rig. It provides the power needed to lift the load that the derrick will bear.
These are the prime movers that are needed for the rig to function.
- Rotary Drive – This is the system that provides/imparts rotational motion to the still string via the rotary table. Typically the motor or engine uses a chain or gear drive to turn the rotary table.
- Top Drive – The modern way of imparting rotational motion to the drill string. Usually the top drives sits atop the drill string and is a self contained electric motor or hydraulic unit that provides the rotational motion.
- Kelly/Power Sub – This is the mechanical device that transmits the rotational from the rotary table or top drive to the drill string.
- Rig Engines – These provide power to do many things. Chief among them is to run the generators to generate electricity. In older rigs they may help in moving the rig (Carrier Borne land rigs) and in providing power to the rotary drive.
Concerned with the equipment that is used in the formulation and maintenance of the drilling fluid used during rig operations.
- Mud Pumps – This provides the drilling fluid with the pressure to move throughout the circulating system. These are critical when considering the hydraulic work the BHA and the bit will do when drilling.
They must be able to provide the necessary pressure head to overcome the pressure loss the that fluid will experience from the rig through the standpipe, down the drill string, across the BHA and bit up the annulus and back into the pits.
- Shale Shakers – A basic means of controlling and removing the solids from the drilling fluid returning from the well bore. Typically they are located above the “Possum Belly”. They work by sifting the return fluid through sieves (which can be changed depending on drilled cutting size) allowing the fluid to return to the circulating system. The solids are then dis-carded.
- Other Solid Control Equipment (Centrifuges and Desanders) – These pieces of equipment allow for more sophisticated solids removal or for fine solids where shale shakers can’t properly filter. They can be used for special purposes such as barite recovery or for environmental purposes when disposal of mud waste is difficult or regulated.
- Degasser – Used in cases when the returning mud has gas. It helps to quickly remove the gas physically by agitating the mud.
- Mud Pits – These are the tanks that allow for the storage and the formulation of the drilling fluids.
- Slug Pit – Part of the mud pit system that allows for the mixing of special chemicals to be added to the fluid system.
- Possum Belly – This is an old and affectionate name for the tank that sits below the shale shakers. It is the first tank that returning mud collects in.
- Standpipe – This is a vertical pipe that runs along the derrick, it carries fluid from the mud pumps to the top of the drill string. It attaches to the kelly hose which accommodates the motion of the system up and down.
This is the system of piping, and valves that allows for the controlling of well pressures when the rig in on site. This type of system is not usually sized by engineers in the field. This is often a component of the rig and comes with it as part of the rig design. You can however purchase individual pieces and create your own, however it is best to keep to (rig) manufacturers guidelines.
- The BOP – this is the device responsible for the opening and closing of the well bore when the rig is onsite. It allows for the isolation of the well bore from the rig in the event of an emergency.
- Ram Type – This type of BOP uses a rams to close the well or to close the annular space around the pipe.
- Pipe rams have attachments at the end to fit securely around the pipe thus ensuring a good seal with the pipe remaining in the hole. Only the annulus is sealed a fluid path is maintained through the pipe.
- Blind rams will only close across if there is no pipe in the hole, they do however allow for isolation of the wellbore and the rig.
- Shear rams have attachments that can in the worst case scenario severe the pipe entirely, totally isolating the rig and wellbore.
- Annular Preventers – These use a packing element instead of rams to seal the annular area around the pipe.
- Diverter – This only allows for the rig to divert the well bore fluid ONLY. It does not allow for the rig to isolate the wellbore. Typically this is only used to drill the upper hole sections between 0’ to 750’.
- Accumulators – These are essentially pressure bottles that store the compressed air to rapidly actuate the rams in the event of a well control incident.
This is the structure upon which the drilling floor and the rotary table is mounted on/within. This area provides the space for the drilling crews to work on, make and break connections, and conduct operations. The sub-structure on a land rig is placed on the ground atop the wellbore and encloses the well control equipment. It connects to other areas of the rig by means of catwalks, ramps and stairs.
In the case of the off shore rig the substructure is mounted to a hull or pontoon that allows for it to float of has a mechanism for it to imbed itself on the seabed (think the legs of a jack-up).
These are the accompanying tools that are used in the execution of drilling operations. Such tools are specific to the drilling floor and are specific to the drilling operations.
Wrenches – These are commonly known as “tongs” and they are used to apply to torque to make and break pipe connections
Elevators – These are specific to the diameter of the pipe and are used to lift the individual sections as well as the drill string. They are engineered to cradle the pipe at the shouldered connection ends. They are attached to travelling block which allow for the hoisting.
Kelly Spinner – Used to slowly rotate the Kelly and drill pipe on making a connection. They do not apply a significant amount to torque.
Hooks – Allows for the attachment of links to the travelling block.
Links – Allows the elevators to be attached to the hooks. In a top drive system
Slips – These allow for the drill pipe to be suspended from the rotary table. It “chucks” the drill string in the rotary table.
Slings – Chain or rope lengths that are used to lift the tubular and tools from the pipe rack to the drill floor. These are usually attached to the sand line or an auxiliary hoist independent of the draw works line.
Pipe Handling/Racking – Specific machines and hoists that are external to the derrick that aid in the lifting of drilling tubular to and from the drilling floor.
3. Rig Sizing
3.1. Derrick Sizing
The static load is determined from the maximum drilling depth and load that the rig will carry to that depth. Typically the heaviest load is 9 5/8” 43.5lbs/ft. casing as this is the largest conventional casing size to be used for completions.
The other load added to this is the full complement of drill pipe that is racked back in the derrick a good average for this is 5” 19.5lb/ft. drill pipe.
The last load added is to account for drilling operations that require the derrick to withstand the grip of the formation on the drill string. This is the over pull the amount of force above the other combined loads the derrick can with stand. This is set at 100,000lbs as a guideline.
3.2. Pump Sizing
This requires some work to be done before hand to calculate the maximum pressure losses that will be encountered by the rig. In addition the optimum flow rates for the hole needs to be known. Typically the hydraulic calculations are done for the longest hole section to be drilled. Generally for an 8.5” hole flow rates vary between 200 – 425 gpm
3.3. Draw Works Power
This is the power required to loft the loads both the drill pipe and the casing. This involves the weight of tubulars being moves and the vertical or trip seed, typically 50 fpm for casing and 80 fpm for drill pipe.
3.4. Rotary/Top Drive Power
This is the power required to rotate the drill string. Done in two stages, the torque to move the drill string is calculated, then this is multiplied by the drill string rotational rpm, typically 110-120rpm, is a conservative estimate, however 200+rpm could be applied. Be warned this could lead to an over estimation.
3.5. Total Power
This is divided into two sections the drilling power systems and the fluid power systems which isolate the systems critical to the drilling operations:
- Draw Works
The rig engines handle the rotary and the draw works so there power requirements are summed. The pumps engines are considered separate.
Additional to this is the electrical system required to run the other rig systems (eg. accommodation, housing and offices). This is typically a given for any rig and not specifically sized.
In a modern rig with electrical systems the values listed above are converted to kW to facilitate comparison with actual rigs.
3.6. Notes on Sizing
It must be noted that with all design/sizing situations, especially using rule of thumb calculations, you design for worst case scenario and a safety factor is also added typically between 1.10-1.25.
These calculations are guidelines for rig selection, they are not meant to be used to specifically build a rig to these said specifications. They are meant to be used to SELECT the rig that best approximates the values calculated. The actual rig values should be higher.
- Rig down drilling equipment and rig up cementing head.
- Spacer is pumped.
- Bottom wiper plug is dropped.
- Bottom wiper plug reaches the float shoe, the plug is “bumped”. The diaphragm in the plug is ruptured and allows the cement to pass through and enter the annulus.
- Lead Cement is plugged.
- Tail cement is pumped.
- The second/top plug is dropped.
- Mud is used as a displacement fluid to push it down until the plug is seated in the float collar.
- Cement now occupies the annulus and the volume between the float collar and the shoe.
- The cement pumps are then used to pressure test the casing to ensure the plugs are holding.
- Pressure is then bled off.
- Cementing head is then rigged down and casing head rigged up.
To support the vertical and radial loads applied to the casing
Isolate porous formations from the producing zone formations
Exclude unwanted sub-surface fluids from the producing interval
Protect casing from corrosion
Resist chemical deterioration of cement
Confine abnormal pore pressure
Cement is introduced into the well by means of a cementing head. It helps in pumping cement between the running of the top and bottom plugs.
The most important function of cementing is to achieve zonal isolation. Another purpose of cementing is to achieve good cement to pipe bond. Too low an effective confining pressure the cement may become ductile.
For cement one thing to note is that there is no correlation between the shear and compressive strength. Another fact to note is that cement strength ranges between 1000 – 1800psi and for reservoir pressures > 1000psi this means that the pipe cement bond will fail first. This would lead to the development of micro-annuli along the pipe.
There are 8 general categories of additives.
- Accelerators – Reduces setting time and increases the rate of compressive strength build up.
- Retarders – Extends the Setting time.
- Extenders – Lowers the density.
- Weighting Agents – Increases density.
- Dispersants – Reduces viscosity.
- Fluid Loss Control Agents.
- Lost Circulation Control Agents.
- Specialty Agents.
Can be added, to shorten the setting time, or to accelerate, the hardening process.
The mechanism is difficult to understand but there are four major theories put forward.
It affects the hydration phase by one of the following theories;
- Cl– ions enhance the formation of ettingite (crystalline). Increase the hydration of Aluminate phase/gypsum system. Accelerate the hydration n of C3 Changes the C-S-H structure.
- Controls the diffusion of water and ionic species.
- C-S-H gel has a higher area and will react faster.
- Diffusion of the chloride ions;
- Cl– ions diffuse into the C-S-H gel faster this producing the precipitation of portlandite sooner.
- The smaller size of the Cl– ions causes a greater tendency to diffuse into the C-S-H membrane. Eventually the C-S-H membrane bursts and the hydration process is accerated.
- Changes the aqueous phase composition.
Calcium chloride also produces a high heat of hydration. This heat could accelerate the hydration process.
This heat will cause the casing to expand and contract as it dissipates. The differing rates of expansion and contraction could result in the casing pulling away from the cement and lead to the formation of micro-annuli.
It also has the ability to affect the cement rheology, the compressive strength development, produce shrinkage by 10-15%, increases the permeability with time and lowers the sulphate resistance.
They work by one of 4 main theories;
- Adsorption Theory – the retarder is adsorbed & inhibits water content.
- Precipitation Theory – reacts with aqueous phase to form an impermeable and insoluble layer around the cement grains.
- Nucleation Theory – retarder poisons the hydration product and prevents future growth.
- Complexation Theory – Ca+ ions are chelated by the retarder. A nucleus can’t be properly formed.
Lignosulphonates – Wood pulp derived polymers. Effective in all Portland cements and added in concentrations of 0.1% to 1.5% BWOC. It absorbs into the C-S-H gel and causes a change of morphology to a more impermeable structure.
Hydroxycarboxylic Acids – They have hydroxyl carboxyl groups in their molecular structure. Below 93°C they can cause over retardation. They are efficient to temperature of 150°C. One acid used in citric acid with an effective concentration of 0.1% to 0.3% BWOC.
Saccaride Compounds – Sugars are excellent retarders of Portland cement. Such compounds are not commonly used due to the degree of retardation being very sensitive to variation of concentration. It also depends on the compound’s susceptibility to alkaline hydrolysis.
Organophosphates – Alkylene phosponic acids.
Acids and accompanying salts
Sodium Chloride, used in concentrations of up to 5.0% used with bottom hole temperatures less than 160 deg F. it will improve compressive strength and reduce thickening and setting time.
Reduce slurry density – reduces hydrostatic pressure during cement.
Increases slurry yield – reduces the amount of cement required to produce a given volume.
Water Extenders – Allows/facilitates the addition of water to help extend the cement blend/slurry.
Low Density Aggregates – Materials with densities less than Portland cement (13.5 g/cm3)
Gaseous extenders – Nitrogen or air can be used to prepare foam.
Clays – Hydrous aluminum silicates. Most common is bentonite (85% mineral clay smectite). Can be used to obtain a cement of density 11.5 to 15.0ppg, with concentrations up to 20%. Used with an API ratio of 5.3% water to 1.0% bentonite.
Bentonite – this is added in conjunction with additional water, used for specific weight control but will make for poor cement.
Pozzolan – finely ground pumice of fly ash. Pozzolan costs very little but does not achieve very high weight reduction of the slurry.
Diatomaceous Earth – also requires additional water to be added. Properties are similar to that of bentonite.
Silica – α quartz and condensed slilica fume. α quartz is ised to prevent strength retrogression in thermal wells. Silica fume (micro fume) is highlt reactive the most effective pozzolanic material available. The high surface area increases the water demand to get pumpable slurry. Such a mixture can produce a cement slurry as low as 11.0ppg.
Normal concentration = 15% BWOC but can be as high as 28% BWOC.
Can sometimes be used to prevent annular fluid migration
Expanded Pearlite – Used to reduce the weight as water is added with its addition. Without bentonite the pearlite separates and floats to the upper part of the slurry.
Can be used to achieve a slurry weight as low as 12.0ppg. Bentonite in concentrations of 2-4% is also added to prevent segregation of particles and slurry.
Gilsonite – Used to obtain slurry weights as low as 12.0ppg. in high concentrations mixing is a problem.
Powdered coal – Can be used to obtain a slurry with a density as low as 11.9ppg, 12.5-25lbs per sack are usually added.
Microspheres – Small gas filled beads that promote densities as low as 8.5ppg., they can be either glass or ceramic.
Nitrogen – Nitrogen is used as the density reducing medium. The base slurry needs to be homogenous with high compressive strength and low permeability. Could achieve densities as low as 7.0ppg.
Ilmenite – Can attain densities in excess of 20.0ppg. The viscous nature of the slurry may promote sedimentation. It must be adjusted.
Hematite – Used to increase the specific weight of the cement. It is an iron oxide ore. Has minimal effect on the thickening time or compressive strength of the cement. Can prepare slurries up to 19.0ppg but can go as hig as 22.0ppg. A much finer particle size distribution.
Barite – Requires more water to be added to the slurry and as such the compressive strength of the cement is reduced. Can prepare slurry weights as high as 19.0ppg.
Limenite – requires no additional water to be added to the slurry. Minima effect on the thickening time or compressive strength.
Sand – no additional water is needed and it has little effect on the pumpability of the cement. When set the cement will form a very hard surface.
Gypsum – blended with Portland cement to produce a cement blend with reduced thickening and setting time for low temperature applications. i.e. less than 140 deg F. However a significant amount of water is needed when using gypsum.
Sodium Silicate – used for great depths. Used to retard the thickening and setting time, especially good at very low concentrations. For high temperature applications it is necessary to add organic acid.
Highly concentrated suspensions of solid particles in water. With concentration as high as 10%.
When cement goes across a zone the aqueous phase of the slurry goes into the formation, leaving the cement particles.
As the aqueous phase decreases, the slurry density increases and the slurry performance diverges from the original design. If enough fluid is lost the slurry becomes difficult to pump to the point where it may be able to be pumped.
To maintain API standards for adequate slurry performance you need a fluid loss rate of less than 50ml/30min.
Such fluid loss matter act by;
Filter cake formation across the zone.
Reducing the permeability of the filter cake.
Increasing the viscosity of the aqueous phase.
Uses latex additives to achieve fluid loss. Emulsion polymers are supplied as suspensions of polymer particles. They contain about 50% solids. Such particles can physically plug the pores in the filter cake.
Water Soluble Polymers
They increase the viscosity of the aqueous phase and decrease the filter cake permeability.
Organic proteins (polypeptides). Not used above temperatures of 93°C.
Non-Ionic Synthetic Polymers
Can lower fluid loss rates from 500ml/30min to 20ml/30min.
There is also Anionic Synthetic Polymers and Cationic polymers.
Lost Circulation Prevention
The addition of materials that can physically bridge fractured or weak zones. Eg Gilsonite and Sellophane flakes added in quantities of 0.125-0.500lbs/sack.
These are cement slurries that upon entering the formation they begin the gel and eventually become self-supporting.
This is an integral part of the completion of a well and helps to ensure its integrity. The choosing of the right type of casing will help in determining the type of completion that can be run in the well and as such it can determine the production characteristics of the well.
On a technical level the casing helps to prevent the borehole family, isolates the borehole fluids from the formation fluids and at the same time prevent formation fluids from mingling. It also helps to provide an environment to control the sub-surface environment from the surface.
A good example would be that the placement of the casing during drilling, which gives the rig a point to mount the BOPs and as such help to control the pressure of sub-surface fluids.
Similarly during the production the casing allows for the mounting of surface control equipment and valves to control fluid flow, also, the casing slows for the mounting of sub-surface equipment that can monitor and control the fluid flow and as such well production rates.
One of the major points to consider in casing design is the depth to which the casing is set. To do this it is necessary to know the pore pressure gradient and the fracture gradient.
- Plot pore pressure gradient, mud pressure gradient, and fracture gradient on a graph of depth vs. pressure.
- Start at the highest mud weight.
- From this point draw a line vertically from mud point to fracture gradient line.
- This depth point is the depth for a casing point.
- From this point draw a line horizontally to intersect the mud curve.
- Draw a line vertically until it intersects the fracture curve.
- This depth is the depth for the next casing point.
- This is repeated until the surface is reached.
- On looking at the graph the horizontal lines would represent where to set the casing shoe.
The production casing is set above the zone of interest before drilling the zone. The zone is open to the well bore. In this case little expense is generated with perforations log interpretation is not critical. The well can be deepened easily and it is easily converted to screen and liner. However, excessive gas and water production is difficult to control, and may require frequent clean outs. Also the interval can’t be selectively stimulated.
In this case the casing is set above the primary zone. An un-cemented screen and liner assembly is installed across the pay section. This technique minimizes formation damage and gives the ability to control sand. It also makes cleanout easy. Perforating expense is also low to non-existent. However gas and water build up is difficult to control and selective stimulation not possible the well can’t be easily deepened and additional rig time may be needed.
Casing is set above the producing zone, the zone is drilled and the liner casing is cemented in place. The liner is then perforated for production. This time additional expense in perforating the casing is incurred also log interpretation critical and it may be difficult to obtain good quality cement jobs.
Production casing is cemented through the zone and the pay section is selectively perforated. Gas and water are easily controlled as is sand. The formation can be selectively stimulated and the well can be deepened. This selection is adaptable to other completion configurations and logs are available to assist casing decisions. Much better primary casing. It can however cause damage to zones and needs good log interpretation. The perforating cost can be very high.
Casing Flow; means that the producing fluid flow has only one path to the surface through the casing.
Casing and tubing Flow; means that the there is tubing within the casing that allows fluid to reach the surface. This tubing can be used as a kill string for chemical injection. The tubing may have a “no-go” nipple at the end as a means of pressure testing.
Pumping Flow; The tubing and pump are run to a depth beneath the working fluid. The pump and rod string are installed concentrically within the tubing. A tubing anchor prevents tubing movement while pumping.
Tubing Flow; A tubing string and a production packer are installed. The packer means that all the flow goes through the tubing. Within the tubing you can mount a combination of tools that will help to control fluid flow through the tubing.
Gas Lift Well; Gas is fed into valves installed in mandrels in the tubing strip. The hydrostatic head is lowered and the fluid is gas lifted to the surface.
Single Well Alternate Completion; In this instance you have a well with two zones. In order to produce from both the zones are isolated with packers. Blast joints may be used on the tubing within the region of the perforations. These are thick walled subs that can withstand the fluid abrasion from the producing zone.
This arrangement can also work if you have to produce from a higher zone given the depletion of a lower zone. The tubing may also have flow control mechanism.
Single Well Concentric Kill String; Within the well a small diameter concentric kill string is used to circulate kill fluids when needed.
Single Well 2 Tubing Completion; in this instance 2 tubing strings are inserted down 1 well. They are connected at the lower end by a circulating head. Chemicals can be circulated down one tube and production can continue up the other.
Single Well High rate Low pressure; A packer isolates well and diverts flow through a nipple through the packer and then again diverts flow out of the tubing. Some flow is allowed to continue through the tubing. This feature is located at a shallow depth in the well.
Multiple Completions; used when multiple zones are encountered within a single wellbore.
Simultaneously Completion of all zones; several intervals are produced simultaneously in a single tubing.
Single zone completion with alternatives; production is done one zone at a time and starts with the lowermost zone.
Multiple “Reduced Diameter” Completions; Multiple completions have higher total producing rate per well bore, faster well payout. Simultaneous and/or segregated flow of fluids at different pressures.
Dual Completions Single packer & Single Tubing; The simplest configuration. The lower zone is produced through tubing and the upper zone through the annulus. The zones are separated by a packer. This method is the cheapest. However the casing is exposed to well pressure and fluids and you must kill the lower zone before working over the upper interval.
Cross-Over Dual Completion Single Tubing; this uses a flow choke or a cross-over to produce the different zones. It still exposes the casing and you need to kill the lower before working on the upper, but you can select how to produce the zone.
Dual Completion Prorated flow Single Tubing; Proration control is accomplished by regulating flow from each of the producing zones through specifically sized orifices, within dual flow choke. The two streams are then combined in the tubing above the choke. A packer may be used to protect the upper casing from exposure to well pressure. In this case both zones can be artificially lifted.
Parallel Dual Completion; This uses two tubing strings and two packers to produce two zones simultaneously. Separate flow can be achieved from each tubing and each zone can be achieved from each tubing and each zone can receive selective artificial lift control. However it is more expensive and workovers are more difficult.
Parallel Dual with Alternative Completions; Installed in both long and short string completion. Triple completions use two or three tubing strings and packers. Achieves high yield per well but difficult to install.
Tubing less Completions; miniature versions of conventional configurations. This is an attempt to lower cost and to be able to work over wells selectively. They are easier to install. Lower productivity, stimulation rate, corrosion problems and the inability to get a good primary cement job are the down sides of this method.
Single Flowing Well; Miniaturized version of single tube “perforated” casing. A landing nipple is used for safety valve service.
Single and Dual Completions; Combination tubing less completion with variation. Single and dual flow artificial lift perforated and un-perforated.
Triple Completions; Comparable to conventional triple completion. However the casing is removed and the packers replaced by cement.
The typical pump consists of –
- The electric motor section
- The seal section
- The intake section
- The multi-stage centrifugal pump
- The electric cable
- Surface installed control panel and complementary equipment.
The electric motor is usually a 2 pole, 3 phase squirrel cage induction motor. The horsepower is obtained by increasing the motor length and the number of rotors.
The seal section does four main functions.
- Houses the axial thrust bearings
- Prevents the entry of well fluid into the motor
- Equalizes the pressure between the motor and the well bore
- Compensates for expansion and contraction of the motor during operation.
Intake section/Gas separator is essentially a suction manifold that is attached to the pump intake section in the event that a high amount of gas is expected.
Multi-stage centrifugal pump have two main parts. The parts are an impeller and a diffuser. To get the high pressures needed then several sections can be attached/stacked together. The impeller can be either fixed or floating. The floater, the impellers can move axially along the shaft. In a fixed pump the impeller is fixed to the shaft. Wear on the pump parts is considerably reduced in a fixed pump.
The thrust developed by the impeller is dependent on the design and operating point of the pump.
The maximum size of the pump is determined by:
- Horsepower rating of the pump shaft
- Pressure rating of the pump housing
- Load carrying capacity of the thrust bearing
Check and bleeder valve installed 2-3 tubing joints (20-30m) above the pump assembly. It helps to maintain a fluid head above the pump. If the check valve is not there then their can be reverse circulation and rotation of the motor. They are combined with a bleeder valve to prevent pulling a string with fluid.
Electric cable is run to power the device in the wellbore. The cable is usually round and is sized for the power requirements of the pump.
Surface equipment usually includes the electrical and standard control panels that house the electrical control, interface and safety equipment.
This is done to provide affective flow communication between reservoir and wellbore. The perforating jobs is irreversible and as such requires good planning.
The shaped jet perforator is mechanically simple and reliable, with generally higher performance. Suits a wider range of completion needs.
The wireline methods have offered depth control, selective firing speed and low cost.
Shaped charge – these used shaped charges and special “quick” explosives (PDX-Cyclonite) to pierce the tubing casing to make the perforations. This type of propellant is faster than that used in bullet guns. Penetration times are about 100-300 microseconds.
The charge may be lined or unlined. The lined charge is deeper but narrower than the unlined. The liner is usually copper.
The primer is initiated this then detonates the main charge. The detonation wave causes the liner to disintegrate and form a jet then penetrates the casing. Not all of the liner goes into the jet. ½ goes into the jet and the other forms a slower moving slug section within the jet. Since the slug moves slower and behind the advanced jet it can plug the perforations as such new technologies have developed liners that disintegrate better or vaporize so as to not form a slug.
Gun Categories –
- retrievable hollow carrier
The retrievable hollow carrier – this is a hollow tube to which the charges are secured. The charges are surrounded by air at atmospheric pressure. The charge then fires but the debris fall within the carrier wall and can be fully retrieved from the well.
The non-retrievable – consists of individually pressure sealed cases. There is no carrier to contain the blast. Everything disintegrates and the debris remains within the well. Good gun to casing clearance is ½”.
- Have minimum amounts of debris
- Improved debris character
- Improved pressure capability
- Facilitates 0° phasing
Retrievable hollow Carrier
- High reliability mechanically strong/rugged
- Fast running high pressure and temperature
- No debris, easily adaptable to desired shot density
- No casing deformation, high charge performance
- Gas tight and resistant to well bore chemicals
The only upside to fully expendable guns is that they are cheap and they can be hooked together to form longer lengths.
- Flexibility permits handling long lengths
- Can deform casing when fired
- Leaves debris in the well
- Explosive components are exposed to the wellbore environment
- Not gas proof, and can’t resist acid
- Not mechanically competent, prone to wear
- Low tolerance for high pressure and temperatures
They are used in shallow holes that don’t tax their mechanical and operational abilities.
The number and size of the shots are governed by hydraulic considerations i.e. differential pressure, flow rates etc. Some give you the option to fire selectively by carrier or shot by shot.
Limited penetration devices are used to perforate tubing or drill pipe without damaging casing. This is done to establish circulation or squeeze cement. In some cases shaped charges are used to cut the casing. In most cases casing cutters are expendable and tubing cutters are retrievable.
Hydraulic perforators use fluid laden with sand to punch a hole in the casing. Their operation is timely and costly. Mechanical perforators use a mechanical means to create a hole, used even less than hydraulic methods for the same reasons.
Depending on the type of explosive damage may be done to the casing. It may result in hairline fractures or a split in the casing. Hydrostatic pressure minimizes deformation but cement strength has little effect on casing deformation. However deformation increased with increased cement thickness. Expandable gun type perforations should be avoided in old wells where casing may be damaged by corrosion.
- Shot density is of greater importance than penetration depth
- Penetration depth is important if there is skin damage
- The penetration has to be able to go beyond the skin damage to be productive
- Positive pressure perforation is done when perforating in drilling mud. In this case the mud may plug the perforations.
- Reverse pressure is for perforating with a lower pressure within the well bore. In some cases perforation is conducted in a clean fluid/acid to enhance perforation.
- To minimize rig costs remove rig from the well and perforate through tubing.
- Shoot through tubing at reverse pressure.
- Utilize a positioning device to assure gun performance.
- Avoid mud shooting, use salt water, oil or completion fluid.
- Use modern designs for the best/cleanest perforations.
- Gun size and type should satisfy the well conditions.
- Use the appropriate well head pressure control equipment.
- Insist on good depth control techniques to ensure that perforations are placed correctly.
Drilling bits are essentially where the rubber meets the road in drilling the wellbore. There are two commonly used types of bits currently used in the industry: drag bits and roller cone bits. Drag bits typically have no moving parts, they consist of stationary cutters embedded within a matrix. The roller cone does have moving parts, the cone is essentially mounted on bearing that allows it to rotate, and the bearing in return is mounted to the bit leg.
Rock upon contact with the drill bit will fail, this will allow for the material to be broken up and removed from the well. However depending on the amount of force applied via the bit, the general characteristics of the rock and the use of fluid force, it will fail in a particular way.
- Scraping and grinding
- Erosion by fluid jet action
- Percussion or crushing
- Torsion or twisting
- Remove cutting from the wellbore.
- Control formation pressures
- Suspend and release cuttings
- Seal permeable formations
- Maintain wellbore stability
- Minimize reservoir damage
- Cool, lubricate and support the bit and the drilling assembly
- Transmit hydraulic energy to the tools and the bit
- Ensure adequate formation evaluation
- Control Corrosion
- Facilitate cementing and completing
- Minimize impact on the environment
As the cuttings are drilled they must be removed and brought to the surface through the annulus. The removal of the cuttings is a function of the size, shape and density in combination with the rate of penetration (ROP), drill string rotation, viscosity, density and annular velocity of the drilling fluid.
Viscosity- higher viscosities help to circulate cuttings out of the hole better. Most muds are thixotropic which means they will gel in static hole conditions. Such a characteristic can help to suspend cuttings when the mud is not being circulated (eg. between connections). For best hole cleaning fluids that are shear thinning and have elevated viscosities at low annular velocities are best used.
Velocity- higher annular velocities promote better hole cleaning. It must be noted that thinner muds reach turbulence faster which will help with hole cleaning but promote washouts. The rate at which the cuttings settle is called the slip velocity. In general the annular velocity should be greater than the slip velocity.
The net cuttings velocity = Annular velocity – Slip velocity
Cuttings transport in high angle and horizontal holes is more difficult than in vertical holes. This is due to fluid and cuttings settling on the low side of the hole. this accumulation with time may form a cuttings bed such a bed would narrow the bore hole restricting flow and increasing torque. If not used with proper hole cleaning techniques then they can be difficult to remove and may jeopardize the well bore.
While static this means that the hydrostatic presence of the fluid column is able to mitigate the normal formation pressure.
In general the well control means that there is no uncontrolled flow of fluids into the wellbore. The hydrostatic pressure is also used to balance the tectonic stresses. The inclination of the wellbore may also permit instability which could be helped by the presence of the fluid in the wellbore.
In practice the mud weight is limited to the minimum necessary for the wellbore control and stability.
The mud must trap the cuttings while drilling but at the same time it must allow the solids control equipment to be able to remove the drilled solids.
If cuttings settle out during the drilling process then this may bridge the wellbore and cause problems. Also if the fluid is not designed properly then sag will occur and the solids will settle out of solution. Usually it will happen in a high angle well where the fluid is flowing at low annular velocities.
When cuttings get too high in concentration it will be detrimental to drilling efficiency and ROP. This would increase the mud viscosity and weight which increase the maintenance and dilution costs. The properties that promote cuttings removal must be balanced with that of solids removal.
To suspend requires high viscosity thixotropic properties while solids removal requires fluids of lower viscosity. For the best solids control the cuttings must be removed on the first circulation out of the hole. If not they are re-circulated and they may be broken down into smaller particles that may be even more difficult to remove.
Permeability refers to the ability of fluids to flow though porous formations. When the mud pressure is greater than formation mud filtrate will invade the formation. Mud filer cake/ mid solids will be deposited on the wellbore wall.
A properly designed fluid system allows the deposition of a thin low permeable filter cake on the formation. This limits the further invasion of fluids. This improves wellbore stability and prevents production problems.
However if the filter cakes is too thick then the hole may be “tight” this may result in increase torque and drag, stuck pipe, lost circulation and formation damage. A thick filter cake can also reduce log quality.
For formations that are known to be highly permeable whole mud may invade the formation. In such a case effective bridging agents should be used (½ the size of the largest opening).
To achieve a good filter cake you can add bentonite, natural and synthetic polymers, asphalt, gilsonite and organic deflocculating agents.
This is the maintenance of the balance of the complex mechanical and chemical factors of the mud.
The density and the hydrostatic properties must help to maintain pressures and stresses. However the chemical properties must help to provide an environment that won’t react with the formation.
Regardless of the chemical composition the mud weight must be maintained within the necessary range to balance the forces acting on the wellbore. Wellbore instability is often identified by sloughing shale. This often makes it necessary to ream.
When the hole maintains its original size the wellbore stability will be a maximum.
Larger hole sizes only complicate the matter at hand. When going through sand a conservative hydraulic program should be used. Sands that are poorly unconsolidated and weak require slightly overbalance to limit wellbore enlargement.
If mud weight can balance these formation pressures then this is enough and the well shall be stable. However if a water based mud is used care must be taken to avoid unnecessary interactions between the drilling fluid and the formations, chemical inhibitors may have to be added to minimize the interactions.
Highly fractured highly dipped formations can be extremely unstable when drilled. Such a failure is due to the mechanical interaction between the fluid and the rock.
Systems with high levels of calcium and potassium or other chemical inhibitors are best for drilling into salt water sensitive formations. Shale is so varied that no single additive may be applicable.
For sensitive formations oil or a synthetic bas fluid is used. They provide better shale inhibition then water based fluids. The continuous phase prevents swelling in clays and shale.
Salts may be added to further prevent inhibition. The salts prevent absorption on the water by the shale by osmosis.
The drilling fluid should not impair or damage the formation reservoir in any way.
If lubrication fails the BHA may fail. Poor lubrication results in high torque and drag, abnormal wear. However this is not the only thing that causes these problems.
The fluid acts like a fluid an helps to support weight of the well bore tools. this reduces the hook load on the derrick. This is of use when you may want to overdesign and exceed the rig load/parameters.
Transmits power to the mud motor, as well as power to the MWD/LWD tools.
The hydraulic programme is based on sizing the bit for maximum pressure drop across the bit (50-65%). With higher densities, viscosities and solids then the pressure losses are greater.
The drilling fluid should allow for the of or aid in the analysis of the chemical and physical composition of the formation. The fluid should allow for the proper analysis of cuttings for the hydrocarbons.
The drilling fluids must be able to transport the cuttings to the surface such that the mud logger is able to quickly analyze the formation.
When running wire-line logs the drilling fluids may affect the conductivity of the signal to and from the formation. This may affect the reading that is produced. The mud must be appropriately conditioned for the least interference to the logging job.
In general for optimum logging conditions the mud should not be too thick bit it must keep the borehole open and stable and must suspend cuttings. Too large a bore hole or to thick a filter cake may affect the logging results. This may also increase the chance of sticking the tool.
In some instances a “bland” mud is used when no effect on the formation is wanted.
The fluid must be able to get rid of gases in the mud such that it does not accelerate the corrosion of the down hole metals and tools. Also the pH should be high, lower pH tends to aggravate corrosion.
Sometimes chemical inhibitors may be added to help mitigate corrosion.
Care should be taken especially when drilling in hydrogen sulphide environments. This can lower mud pH to a point where it is dangerous to the tools in the hole. it is best to drill with high pH and use sulphide scavenging chemicals in the fluid.
Just as with logging the drilling fluid must provide an environment that eases the running of casing as well as cementing.
During casing running the mud should not gel, it should remain fluid so as to minimize pressure surges so as not to induce lost circulation. The mud should have a thin slick filter cake.
To properly cement then the mud must be effectively displaced by the cement spacer. For good displacement the mud should have a low viscosity and low progressive gel strength.
Eventually the mud has to be gotten rid of. The mud can be reused and reconditioned depending on the exiting condition. However it will eventually be disposed off and in this instance it must be treated properly such that it is not in breach of the environmental policies of the block that is being drilled.
Baker Hughes Inteq. 1995. Drilling Engineering Workbook. Houston Texas: Baker Hughes.
Bill, Mitchell. 1995. Advanced Oil Well Drilling Engineering. Richardson Texas: Society of Petroleum Engineers of the AIME.
Bourgoyne Jr., Adam T., Keith K. Millheim, Martin E. Chenevert, and F.S. Young Jr. 1991. Applied Drilling Engineering. Richardson Texas: Society of Petroleum Engineers.
Economides, M.J. 1990. Well Cememting. Edited by Erik B. Nelson. Sugar Land Texas: Schlumberger Educational Services.
Mitchell, Bill. 1995. Advanced Oilwell Drilling Engineering. 10th Edition. Richardson, Texas: Society of Petroleum Engineers of the AIME.