When in shallow offshore environments, the formation in which the conductor is set is normally weak, which means it struggles to contain the pressure that occurs during a gas kick. To avoid an underground blowout, the well should be diverted when a kick is detected in these circumstances. This should also prevent gas reaching the conductor shoe.

Whenever a situation demands a riser for drilling, when drilling for the surface casing, Company Policy will dictate that subsea dump valves and an annular preventer are installed at the mudline. Additionally, the surface should have a normal diverter system.

Thanks to extensive experience, we know that shallow gas blowouts cannot be controlled with current diverter systems alone. Instead, the annular preventer and subsea dump valves can be used at the mudline to control the shallow gas flows at the seabed. Once these are installed, the next step should be to unlatch the LMRP or pin connector before then winching off location (no downwind, only up current).

Prior to spud, a contingency plan should be considered with the Drilling Contractor so three main procedures have been covered;

• Winching the rig from location
• Shallow gas flow
• Any failure in major components of the riser, diverter, or BOP system

All issues and considerations for the contingency plan can be discussed at the pre-spud meeting. If ever the subsea system fails, the surface diverter system will act as a back-up. Furthermore, the surface diverter system can also be a useful feature for diverting gas in the riser (above the stack).

While the surface hole is open, certain precautions should be taken and these are listed below;

• Mud should always be kept on site; enough to fill the hole volume twice over.
• Moorings should allow, after the rig is moored, the rig to be winched some distance away from the plume (around 400 feet is recommended). Only if practical, and after the surface casting is set, the chain stoppers can be applied. Also, the windlasses should remain on their brakes.

• If sudden losses occur, facilities need to be available to allow the annulus to be filled rapidly from the surface.
• To prevent the invasion of voids, hatches should be secured and this should prevent inflammable gas and even downflooding when a loss of heel or buoyancy causes a reduction in the freeboard.
• In the drillstring, a float valve should always be run.
• The annulus shouldn’t become overloaded with cuttings so care must be taken to prevent this, because this can cause liberated gas and losses and therefore the possibility of unloading the annulus.
• While tripping, the hole should remain full and so care must also be taken to monitor this.

What if the well starts to flow?

If this occurs, the following steps may be useful as a guide;

• Start by opening the subsea dump valves and then close the annular preventer – this will allow the gas to vent at the seabed.
• Pump seawater or mud at the maximum rate as an attempt to control the well, assuming there’s no danger to the rig or any personnel nearby. If there is danger to either, consider shearing the pipe or dropping the drillstring. Additionally, winch the rig to a safe position after unlatching the pin connector or LMRP.
• If the subsea diverter system happens to fail, there’s still the option of unlatching the pin connector/LMRP or to divert at the surface; therefore, venting the gas at the wellhead. Although diverting at the surface isn’t recommended, it can become necessary at times and the process starts by maintaining maximum pump rate. Then, space out ensuring that the lower kelly cock is above the rotary table before then closing the shaker valve, opening the diverter lines, and closing the diverter element; the returns should then be diverted overboard. The upwind diverter line should also be closed. From here, all non-essential machinery and equipment should be shut down and this reduces the risk of ignition; as a precaution, deploy firehoses beneath the rig floor. Finally, get ready to unlatch the LMRP or pin connector and winch safely.
• If the situation is steadily getting worse and a loss of control is looking likely, consider shearing the pipe or dropping the drillstring. Once again, winch the rig to safety after releasing the LMRP or pin connector.

References

Cormack, D. (2007). An introduction to well control calculations for drilling operations. 1st ed. Texas: Springer.

Crumpton, H. (2010). Well Control for Completions and Interventions. 1st ed. Texas: Gulf Publishing.

Grace, R. (2003). Blowout and well control handbook [recurso electrónico]. 1st ed. Paises Bajos: Gulf Professional Pub.

Grace, R. and Cudd, B. (1994). Advanced blowout & well control. 1st ed. Houston: Gulf Publishing Company.

Watson, D., Brittenham, T. and Moore, P. (2003). Advanced well control. 1st ed. Richardson, Tex.: Society of Petroleum Engineers.

The post Drilling with a Riser from a Floating Rig for the Surface Casing and Encountering Gas appeared first on Drilling Formulas and Drilling Calculations.

When penetrated from a platform or a jack-up, shallow gas reservoirs have the potential of being more hazardous. Since the conductor almost reaches the floor of the rig, any kick products discharge into the hazardous zone directly.

To direct the flow overboard, the diverter will close automatically when a shallow gas flow occurs. During a period of stress, the diverter system’s reliability is questionable which is why failure should always be considered.

If a restriction forms in the diverter line, a hazardous situation quickly develops on a bottom supported rig. Around the seabed’s casing, gas can actually broach as a result of the pressure build-up. Whenever this occurs, the risk of the seabed becoming fluidized increases and therefore so does the risk of a rapid reduction in spudcan resistance.

Shallow gas encountered on a jack up rig (Ref – officerofthewatch.com)

While the surface hole is open, several precautions need to be taken and these are listed below;

• When sudden losses in the annulus occur, the facilities need to be available for these to be filled quickly.
• On trips, pumping out of the hole should be considered.
• In the drillstring, a float valve should always be run.
• The annulus should never become overloaded with cuttings, so this needs to be monitored. After overloading, this can cause losses or liberated gas from cuttings and this can potentially lead to the annulus unloading. By limiting ROP, drilling the pilot hole, and circulating at a high rate, the drilled gas and cuttings can be distributed and problems prevented.
• The hole should be monitored and the facilities should be available to ensure it remains full while tripping.
• There should always be enough mud on the site to fill the volume of the hole twice over.
• The facilities, tools, and materials should be available to keep the hazardous zones free from the flow (without also imposing backpressure on the well or restricting the flow itself).

If the well begins to flow, the following can be used as a guideline;

• Start by maintaining the maximum pump rate.
• The lower kelly cock should end just above the rotary table after spacing out.
• Returns can be diverted overboard by opening the diverter lines, closing the diverter element, and closing the shaker valve.
• All non-essential machinery and equipment should be shut down and this will reduce the number of potential sites of ignition. Beneath the rig floor, the fire hoses should be deployed. In the meantime, all personnel not considered essential should be evacuated.
• Signs of gas breaking through the sea (outside the conductor) should be monitored. If evidence is detected, all personnel should be evacuated instantly.

References

Cormack, D. (2007). An introduction to well control calculations for drilling operations. 1st ed. Texas: Springer.

Crumpton, H. (2010). Well Control for Completions and Interventions. 1st ed. Texas: Gulf Publishing.

Grace, R. (2003). Blowout and well control handbook [recurso electrónico]. 1st ed. Paises Bajos: Gulf Professional Pub.

Grace, R. and Cudd, B. (1994). Advanced blowout & well control. 1st ed. Houston: Gulf Publishing Company.

Watson, D., Brittenham, T. and Moore, P. (2003). Advanced well control. 1st ed. Richardson, Tex.: Society of Petroleum Engineers.

Watch, O., 2013. Offshore Well Blowout – Investigation Report. [online] Officer of the Watch. Available at: <https://officerofthewatch.com/2013/04/15/offshore-well-blowout/> [Accessed 8 August 2020].

The post Drilling (from a bottom supported rig) for the Surface Casing and Encountering Gas appeared first on Drilling Formulas and Drilling Calculations.

For back-off operations to be successful on the first try, plans must be devised and then carefully followed; this should also keep the risk of injury low for rig floor personnel. Of course, the Contractor Driller/Tool pusher and the Fishing Tool Supervisor need to oversee the process since it’s considered a non-routine operation.

Steps for Safety

1) Firstly, a safety meeting, coordinated by the Drilling Supervisor, should take place before the procedure itself. With all rig personnel in attendance, the meeting will explain the no-go areas during torque application (and when torque is held on the drill string), the hazards of the operation, and the proper use of equipment in order to prevent injury.

For personnel not essential to the task at hand, they should stay well away from the rig floor until completion.

2) To hold right or left-hand torque in the string, sometimes rotary slips and rig tongs will be used. If this is the case, the slip insert dies need to be sharp (while also fitting into the slots themselves). If any dies have signs of wear during an inspection, they should be replaced.

3) While raising and lowering the pipe to work the torque downhole, the surface torque needs to be held in the string and this may require manual drill pipe tongs. Before operation, it’s important to check the snub line on the tong to make sure it has sufficient length.

It’s dangerous to operate with a short snub line; the tong may lose bite on the pipe when raised and this leads to an uncontrolled and potentially harmful backlash. To be extra safe, it’s possible to install extra-long snub lines before then attaching them to a suitable snub point (such as a derrick leg). When working torque downhole, this will ensure sufficient bite.

4) Using rotary slips, torque will work into the pipe; at this time, the positioning of the latched elevators is essential. Located just below the tool joint, this will allow rotation for the pipe through the elevators. While the torque is trapped in the string, elevators can be used to adjust and control the pipe. Depending on whether the blocks are secured to a guide rail system, the hook swivel will need to be Locked (if secured) or Unlocked (if not).

5) Normal procedure will see right-hand torque applied and worked downhole (to reach the planned back-off point) before applying any left-hand torque. If you had to free the drilling assembly by working the pipe hard to the right, this step isn’t a necessity.

6) Using a length of wire rope, slip handles need to be tied together when applying left-hand torque (with rotary slips). If the pipe were to break high, the slips won’t be thrown from the rotary. In turn, the loss of strain won’t cause the pipe to jump.

7) In some cases, a stuffing box and wireline lubricator will need to be used to run the string shot. Two common examples include;

When it’s believed that formation fluids have entered the drill string annulus
When the balance between inside and outside wellbore fluids has been thrown off

8) While running and making up the string shot, users must follow wireline safety procedures for perforating operations.

Identifying the Free Point (If Necessary)

With a stuck tubing assembly, how do we determine the free point?

There are a couple of options, and the first uses the length of free pipe and a measurement of pipe stretch for any given over-pull. This being said, the actual free point normally falls within 500’ either way which makes it useful in planning fishing operations and any subsequent operations. The second option is to use free point indicator tool which will give the precise stuck depth. This option may not available on every location.  In this article, it will demonstrate

Calculate Free Point by Using Pipe Stretch Data

If the impact of hole drag is small in vertical holes, the use of pipe stretch data will lead to the most accurate free point calculations. Although this method can also be applied in directional wells, the effects of hole drag creates a potential of underestimating the free pipe length.

There are five main steps to follow with this particular technique;

1. Pick up to the normal pick up weight and mark the pipe on the rotary table as a reference point.
2. The next step is to set the brake after taking an over-pull of 50,000lb (+/-). Note: it’s vital not to go past 80% of the pipe’s minimum yield strength.
3. After the over-pull, what was the stretch? Write this down in inches.
4. From here, there’s a special equation for calculating the length of free pipe.
   This can be seen below;
   Lf = (L×Ap×E) ÷ (12×P)
   Where;
   Lf = length of free pipe, ft
   L = length change due to over pull, lbs
   Ap = pipe cross sectional area, square inch
   E = steel Young Modulus, psi ( 30,000,000 psi for steel pipe)
   P = overpull applied, lbs
5. Finally, we should note that the calculated length can be checked by increasing the amount of over-pull. If this is done, remember step four (use the reference point and measure the amount of stretch).

Determining String Tension

If ideal conditions are present, zero is the perfect pipe tension at the back-off point. However, achieving this in practice is almost impossible. In our experience, it’s better to have a little tension at the back-off point rather than compression.

To successfully back off at the intended depth, it’s important to calculate the required surface tension before then considering the application of this tension before blind back-off. Whenever the pipe is in compression or there’s too much tension, back off is actually unlikely. In the rare event that it does happen, it will occur much higher up the string than desired. Sadly, this means making up the pipe for a second time and repeating the procedure.

When it comes to determining and optimizing tension at the back-off point, there’s some essential information that needs to be compiled. This includes;

• Drilling fluid density in the well.
• Length of individual components (and weight per foot) in the drilling assembly.
• In the section the drilling assembly is stuck, the average hole inclination.
• Before getting stuck, the off bottom rotating weights (fishing BHA string), pick-up, and slack-off; all measurements should be with the pumps off. Of course, these figures are hard to obtain if the pipe got stuck after engaged. In this case, we recommend estimating using what had been recorded prior to that point.
• After determining the hook load that’s needed for the back-off point to reach zero tension, you need to ensure that the pipe doesn’t go into compression which is why +/- 5,000lb of over-pull should be added. There’s a general equation when calculating the correct weight indicator reading after firing the string shot.

Weight indicator reading should be followed the equation below;

Weight indicator  = Pick-up weight – Buoyed weight of back-off point – 5,000lb over-pull

 In this equation, it assumes that;

• Buoyed weight is the combination of pipes to be free and the Fishing BHA (hole inclination is also considered).
• Pick-up weight includes both pipes to be free and the whole Fishing BHA.

Working Right-Hand Torque Downhole

First things first, the appropriate make-up torque needs to be applied to the pipe before even considering a downhole back-off. When this isn’t done, there’s a risk of a deep open hole back-off or a shallow back-off at the wrong depth.

What’s the perfect amount of right-hand torque when working down the string? There’s no universal answer, and it all depends on the wellbore profile, well depth, and degree of hole drag (torsion and tension). While locating the free point, the correct string tension also needs to be determined so it can be applied at the surface; this ensures torque is worked down to the back-off point.

With this in mind, it’s not necessarily the case that the pipe is worked between the slack-off weight and calculated pick-up weight at the back-off point. When determining the free point, the torque measurements taken provide a guide to correct surface tension not only for applying right-hand torque but left-hand torque too.

There are some important practices when working right-hand torque downhole;

• When following the procedure, a full-scale torque reading needs to be generated at the planned back-off depth plus 30%. When attempting to back-off, this reading will allow for maximum left-hand torque application to the pipe.
• When working the torque down the pipe, it should travel from surface to the free point depth. Between the zero surface tension and calculated free pipe pick-up weight (at the back-off point), the pipe should be lowered and raised because tool joints will only torque correctly with minimum axial tension. At the same time, right-hand torque should progressively increase.
• The goal is to work maximum make-up torque into the string and this can be achieved with three or four applications. It’s important to remember how many total turns were required to reach the maximum make-up torque; additionally, note the estimated number of turns when applying left-hand torque.
• Eventually, as the pipe cycles between the range of slack-off weight and pick-up weight being used, it will be the case that there’s no loss of trapped torque. This indicates a complete make up of all connections.

Working Left-Hand Torque Downhole

When it comes to left-hand torque, the amount applied should the highest possible while still comfortably avoiding a shallow or premature back-off. Since this is a hazardous operation, the safety precautions need to be understood and followed as closely as possible. For example, there are four main guidelines when working left-hand torque downhole.

1) Generally speaking, 70% of the right-hand make-up torque is the maximum for applying left-hand torque at surface; it should never exceed this amount.

2) When there’s a zero axial tension on the connection, there’s a real possibility of the tool joint breaking. Therefore, we recommend starting with maximum surface tension to work the left-hand torque down the hole before progressively working down to the planned back-off tension.

Starting with around half of the suggested left-hand torque, this is something that should happen gradually. At this point, we should note that the torque should only ever be increased to the next step once a given amount of torque has worked into the whole string.

3) As the torque works towards the planned back-off point, keep a record of cumulative left-hand turns going into the pipe.

4) What happens if the string is still not free and you’ve hit 70% of the left-hand torque? If this happens, add 5% of the torque until the pipe is eventually free.

The post Drill Pipe Back-Off Operation appeared first on Drilling Formulas and Drilling Calculations.

Suited towards surface or subsea applications, the Cameron Type ‘U’ preventer is one of well known wellbore pressure assisted ram preventers . It can come with a single ram (Figure 1) or double rams unit (Figure 2). When it comes to see whether the rams is in closed or opened position, this isn’t possible through observation alone and this is due to the operating rod’s tail end being enclosed inside the preventer itself. Since 1979, all Type ‘U’ preventers have required H2S service capabilities. One of key features of this BOP is a capability to pump open the bonnet doors. Once the four bonnet bolts have been removed, top-load ram changing is made easy by  applying closing pressure to push the bonnet out.

Figure 1 – Single Rams Unit – Camron U BOP

Figure 2 – Double Rams Unit – Camron U BOP

For various applications on surface or subsea, the Cameron U BOP actually is one of the most popular options for ram-type blowout preventers (BOPs) used around the world. Additionally, U type rams are wellbore pressure assisted. It means that the rams will seal better when wellbore pressure acts against the rams in a closed position.

The U BOP has many other useful features as listed below;

• On bonnet studs and nuts, the need for high makeup torque is eliminated because of the available bonnet seal carrier.
• To ensure consistent and even stud loading, the larger sizes will have hydraulic stud tensioning available.
• Even after a release in actuating pressure, the rams can be locked hydraulically and held mechanically closed because of the wedgelocks (locking mechanism that utilizes hydraulics). Before the BOP is opened with applied pressure, the wedgelock needs to retract and this can be ensured with sequence caps to interlock the operating system.

Pipe Rams

When using Cameron ram-type BOPs, Cameron pipe rams can be used and this helps to centralize and seal, depending on size, drill collar, casing, tubing, or drill pipe. With a sizeable reservoir of packer rubber and self-feeding in nature, Cameron pipe rams will remain in good condition regardless of environment. Furthermore, they’re suitable for H2S service (NACE MR-01-75) and the packers can be locked without fear of being dislodged by well flow.

For all Cameron pipe rams (except any U BOPs exceeding 13 -3/4 inches), CAMRAM top seals are standard. When concentrations of H2S are expected, and in high temperature service, CAMRAM 350 top seals and packers are also available.

Figure 3 – Pipe Rams Cameron U Type (Courtesy of Cameron)

Variable Bore Rams (VBR)

Variable bore rams will seal around various size of pipe as opposed to a pipe rams which can seal only one size of pipe. The VBR will remove the need for multiple sets of pipe rams (one for each pipe size), only one set of Cameron VBRs will be required regardless of the sizes of pipe or hexagonal kelly. With a single set, it’s possible to receive backup for different sizes; for example, a common set 2-7/8″ × 5″ and 5″ × 7″. Depending on ram range and tool joint size, some will have a limited hang-off capacity. Using surface pressure, it may be possible to force the tool joint through the ram packer but only when the outside diameter (OD) doesn’t exceed the variable ram’s maximum capability.

Figure 4 -Variable Bore Rams (courtesy of SLB)

Within their VBR and VBR II range, the following variable bore rams for U, UM, and UL are provided by Cameron (see the table below);

For those who need different sizes, these may be available from other manufacturers.

Some key interesting features are as follows;

•   Proprietary seals (CAMRAM) are the standard for well

•   Steel reinforcing inserts – when the rams are closed, these will rotate inwards and add support for the rubber (sealed against the pipe).

•   As per NACE MR-01-75, they’ll be perfect for H2S service.

Shearing Blind Rams (SBR)

To contain wellbore pressure, shear/blind rams can actually act as blind rams after cutting the drillpipe; a recess accommodates the pipe stub. Before shearing and if the situation allows, the pipe needs to be in tension and stationary. In addition to this, some cases will require a manifold pressure of more than 1,500psi while operators need to be sure that the tool joint isn’t opposite the rams. In terms of the shear process itself, the size and grade of the pipe can both be limiting factors (even when maximum manifold pressures apply). Unfortunately, for sour service, not all models of blind/shear rams will be suitable.

With Cameron SBRs, the pipe is sheared in the hole before the lower section (of the sheared pipe) is bent and this allows the rams to seal and close. For normal drilling or completion operations, the SBRs may have a use in closing on an open hole. With this in mind, its features contain;

• An ability to cut pipe several times while protecting the cutting edge.
• Integrated cutting edge within the single-piece body.
• Increased service life and reduced pressure for the rubber thanks to a large frontal area of the blade itself.
• For critical service applications, H2S SBRs are available and these will boast hardened high alloy as the blade material.
• All Cameron SBRs have CAMRAM top seals as standard.

With some similarities to SBRs, shearing blind rams called ‘DVS’ rams (double V shear) also exist and they have two main differences;

• They offer the largest-possible blade width while still fitting within the existing ram bores.
• After shearing, the lower section of the tubular will be folded with DVS rams and this allows a sealing between the lower blade and the blade packer.

Figure 5 – Double V Shear (courtesy of SLB)

Cameron U II Blowout Preventer

If you take the U BOP, and then make it suitable for subsea use, we find the Cameron U II BOP (suitable for 18-3/4-10,000 as well as 15,000psi WP sizes). Pressure-energised rams, just like other Cameron preventers, the seal can be maintained and the sealing force increased whenever hydraulic pressure is lost as the wellbore pressure acts on the rams. As wellbore pressure increases, seal integrity improves.

Important features of the U II BOP include;

• On bonnet studs and nuts, the need for high makeup torque is eliminated with the bonnet seal carrier.
• Even and accurate stud loading can be ensured consistently thanks to an internally ported hydraulic stud tensioning system.
• Normally, hydrostatic pressure can cause the wedgelock to unlock; this is removed by a pressure balance chamber.
• When actuating pressure is released and the ram is locked hydraulically, the rams can be held closed mechanically by hydraulically-operated locking wedgelocks (mechanisms).

Additionally, the design boasts a selection of rams depending on the application, hydraulically opening bonnets, and a forged body.

Figure 6 – U II Blowout Preventer (courtesy of SLB)

References

Cormack, D. (2007). An introduction to well control calculations for drilling operations. 1st ed. Texas: Springer.

Crumpton, H. (2010). Well Control for Completions and Interventions. 1st ed. Texas: Gulf Publishing.

Grace, R. (2003). Blowout and well control handbook [recurso electrónico]. 1st ed. Paises Bajos: Gulf Professional Pub.

Grace, R. and Cudd, B. (1994). Advanced blowout & well control. 1st ed. Houston: Gulf Publishing Company.

Watson, D., Brittenham, T. and Moore, P. (2003). Advanced well control. 1st ed. Richardson, Tex.: Society of Petroleum Engineers.

Watch, O., 2013. Offshore Well Blowout – Investigation Report. [online] Officer of the Watch. Available at: <https://officerofthewatch.com/2013/04/15/offshore-well-blowout/> [Accessed 8 August 2020].

Cable double-V shear rams. 2019. Cable double-V shear rams. [online] Available at: <https://www.slb.com/drilling/rigs-and-equipment/pressure-control-equipment/bop-rams/cdvs-ii-cable-double-v-shear-rams> [Accessed 21 June 2021].

The post Basic Understanding about Cameron U BOP – Rams Blow Out Preventer appeared first on Drilling Formulas and Drilling Calculations.

Slug mud is typically pumped into the drill string in order to push the mud inside the drill pipe down so the drill pipe will be clean and ready for pulling out of hole. Since slug is heavier, it will push the lighter mud out of the well. Figure 1 demonstrates how slug displaces current mud out of hole.

Figure 1 – Diagram Shows Volume Gain from Slug

The volume of mud pushed out of the well, typically called “volume gain from slug” can be determined by the equation below;

Volume Gain from Slug = Slug Volume × (Slug Weight – Current Mud Weight) ÷ Current Mud Weight

Calculation Oilfield Unit

Units used in oilfield are listed below;

• Volume Gain from Slug in bbl
• Slug Volume in bbl
• Slug Weight in ppg
• Current Mud Weight in ppg

Example: Determine volume gain from slug with the following parameters.

Volume slug = 30 bbl
Current mud weight = 12 ppg
Slug weight = 15 ppg

Volume Gain from Slug = 30 × (15- 12) ÷ 12
Volume Gain from Slug = 7.5 bbl

Calculation Metric Unit

Units used in metric are listed below;

• Volume Gain from Slug in m³
• Slug Volume in m³
• Slug Weight in kg/m³
• Current Mud Weight in kg/m³

Example: Determine volume gain from slug with the following parameters.

Volume slug = 5 m³
Current mud weight = 1,440 kg/m³
Slug weight = 1,800 kg/m³

Volume Gain from Slug = 5 × (1,800 – 1,440) ÷ 1,440
Volume Gain from Slug = 1.3 m³

The calculation sheet is provided by checking the image below.  This spreadsheet can be modified to suit your work too.

The post Volume Gain from Slug appeared first on Drilling Formulas and Drilling Calculations.

Considering the danger of shallow steam or gas zones requires unique well control considerations. Whenever the necessary casing shoe integrity cannot be obtained due to the shallowness of the zones (before encountering pressure), a kick will need to be diverted because it cannot be shut-in. For this situation, a diverter shown in Figure 1 is a mandatory equipment to divert the undesirable flow to allow personal to have proceed the next plan; i.e., evacuation and/or dynamically kill a well.

Figure 1 – Diverter Package in Well Control (Courtesy of Cansco Dubai LLC)

By directing the flow from an unloading well, diverting allows physical damage to be limited to all equipment and rig personnel. With specialized procedures and equipment, the idea is to impose limited back pressure on the weak downhole formations. Although not strictly a well control procedure, diverting successfully will allow the well to be dynamically killed, to bridge over, or be depleted (without losing equipment or life).

Wherever possible, diverting needs to be avoided. In an ideal situation, if full shut-in will with a strong casing shoe should be chosen instead of a diverter. On conductor casing shoes, leak-off tests need to be performed to assess the likelihood of successfulness of shutting the well in. Any flow from the formation is likely to reach the surface in quick time since the gas is shallow and, therefore, the time available to detect the kick and then divert or shut-in is extremely small.

Purpose of Diverter System

A certain amount of protection can be provided by the diverter system before the rig can install the BOP onto the well. By design, diverter systems will direct the flow to a safe location by packing off around the drill string, Kelly, or casing. For the valves, they allow the well flow to be directed whenever the diverter has been actuated.

Figure 2 – Diverter Diagram

Diverter systems are often defined as a low pressure annular. As the name suggests, the flow cannot be stopped or shut-in with a diverter; the only goal is to direct the flow to a safe location away from the rig. To effectively remove the flow and well debris, the system must equip with a large internal diameter with sufficiently sized vent lines.

High Risk Operation

Associated with shallow gas, diverting presents serious risks. For the drilling industry, many incidents shows that shallow gas divert operations are more dangerous well control hazards than any other. Whether successful technically or not, all divert events are classified as blowouts by the US Minerals Management Service (MMS) because the very definition of a divert involves formation fluids in an uncontrolled flow. For the technical success of the diverting operation, the inherent risk needs to be managed carefully; the best management stance to risk will always be to avoid diverting at all costs.

How can diverting be prevented? Firstly, by not drilling through shallow gas. While seismic data can provide some help in avoiding shallow gas zones, drilling only where potential for shallow gas is non-existent is incredibly difficult. If drilling in this environment is entirely necessary, and the casing program cannot be designed to shut-in after kicks, not taking shallow kicks will be the only diverting avoidance technique possible.

While swabbed kicks are considered ‘avoidable’ kicks, hydrostatic imbalances that cause drilled kicks can be unavoidable with even the best planning. To reach technical success in these circumstances, an effective response plan needs to be in place and all elements of this plan need to be ready; this includes equipment, technique, people, and training.

For subsea and surface diverting, ‘Recommended Practices for Diverter Systems Equipment and Operations’ (Recommended Practice 64) is a reference document provided by the American Petroleum Institute (API). Considered the ‘API RP 64’, this is a useful resource for such events.

Criteria for Diverter or BOP

At the shoe, well integrity is often an issue with shallow casing strings and, in some cases, shutting in the well can cause too much pressure. Whenever a well with little/no shoe integrity is closed-in, this can cause formation fluids to broach to the surface or it can cause a shoe breakdown. When the shoe broaches, a bottom supported rig can be put into danger (along with its crew), including platform, jack-up, and land rig, but it won’t considered as dangerous for a floating vessel. When inadequate casing is present and a shallow gas kick is encountered in a bottom supported rig, diverting is the best alternative to shutting in.

To allow time for remedial action and potential evacuation, and to reduce the risk of damage, the flow needs to be directed as the well begins to unload. When shallow gas potential is seen, a BOP or modified BOP system should be installed before penetrating the formation. By doing this, proven well control procedures can be used. This can only occur when formation integrity will allow for the well to be killed (through the application of back pressure and/or shutting in).

When considering a diverter system over a BOP stack, there are two main considerations;

•   Diverting will be preferred when insufficient formation integrity means shut-in pressure would cause damage (when drilling below conductor). If the well were to be shut-in after a kick, the formation fluids would broach the casing shoe in this scenario.

•   When drilling below drive or structural pipe, diverting will be the chosen method.

As mentioned previously, wherever possible, a shut-in will always be the preferred method.

On the vent line, diverter systems should offer a full opening hydraulic valve. This valve can be opened automatically as the diverter closes when the control system is plumbed correctly, or it will add value to the closing diverter. According to industry best practices, hydraulic ball valves are the suggested types with full bore to the vent line and outlet.

Figure 3 – Diverter Systems – Surface Installations

API also recommend always testing upon installation; from opposite panel, a function test can occur every 24 hours. When installed, any valves and the diverter should be actuated as well as doing so at ‘appropriate times’ to ensure the system is working as expected. To ensure the lines aren’t plugged, fluid should also be pumped through the diverter lines during operation.

Diverting Operations and Equipment – Installation and Equipment Requirements

Below the mud line, a short string of drive pipe or large diameter casing can normally be installed when commencing a well in the water. On land locations, at a shallow depth, casing string can be set and cemented. With the casing or drive pipe in place, it acts as a seal to support the hydrostatic head of the fluid column – between the flow line outlet and the base of the casing. With the diverter installation occurring at the casing or drive pipe, either a low-pressure diverter is required or an annular preventer; if the latter, it requires sufficient internal bore to pass the tools used for drilling operation.

With the vent lines recommended by API RP 64, these extend between the outlets underneath the diverter and a safe space away from the well. The chosen location should allow for proper disposal of the fluid flowing from the well.

In place of proper diverters, some have previously used rotating heads or annular blowout preventers. This being said, it’s now possible to acquire special low pressure diverters in various sizes. In terms of the working pressure of the vent lines and the diverter, this isn’t too important because they’re actually sized to minimize well bore back pressure while diverting well fluids. For land and offshore uses, many Operator Companies will recommend a minimum ID of 10” for vent lines while a diameter is 12” is recommended for floaters.

References 

Cormack, D. (2007). An introduction to well control calculations for drilling operations. 1st ed. Texas: Springer.

Crumpton, H. (2010). Well Control for Completions and Interventions. 1st ed. Texas: Gulf Publishing.

Grace, R. (2003). Blowout and well control handbook [recurso electrónico]. 1st ed. Paises Bajos: Gulf Professional Pub.

Grace, R. and Cudd, B. (1994). Advanced blowout & well control. 1st ed. Houston: Gulf Publishing Company.

Watson, D., Brittenham, T. and Moore, P. (2003). Advanced well control. 1st ed. Richardson, Tex.: Society of Petroleum Engineers.

Cansco.com. 2019. Diverter Packages – Cansco Well Control. [online] Available at: <http://cansco.com/products/diverter-packages/> [Accessed 11 October 2021].

The post Introduction to Diverters in Well Control appeared first on Drilling Formulas and Drilling Calculations.

Of all diverts, many studies show a failure rate of between 50% and 70%. According to the same studies, when it comes to well control issues, shallow gas blowouts is the leading cause of offshore rig damage and loss. On the US Outer Continental Shelf, the MMS agrees with these findings and has suggested a 46% failure rate between 1971 and 1991. Even though mandatory well control training was introduced during this period, the MMS has noted that a reduction in blowout frequency wasn’t experienced during this time.

Why have failure rates not declined?

For the most part, this is not about well control proficiency, it is the fact that drilling into a shallow gas zone is a lot more difficult to handle than typical well control.

Therefore, there needs to be a mindset of ‘when’ the diverter will fail as opposed to ‘if’. During a shallow gas divert, the ideal situation would see a depletion or bridging off before the system has a chance to fail. When it comes to the likelihood of the well bridging or depleting, this increases the longer a system is allowed to divert a shallow gas blow before failure.

Ultimately, three types of diverter failure exist;

•  Excessive back pressure through the diverter system resulting in formation fracture
• Formation fracture as a result of a failure in vent line valves (not opening)
• Metal erosion

With the right-sized vent, the correct vent line valves, and actuating systems, the first two failures can normally be prevented. By following the necessary guidelines, as well as with the right maintenance, the risk of failure can be reduced; excessive back pressure shouldn’t occur, and the vent live valves shouldn’t be prevented from opening because of vent lines that are simply too small.

Metal Erosion

The likelihood of erosion will depend on several factors; the geometry of the diverter system, the type of fluid, fluid viscosity, and even the abrasiveness of particles entrained in the flow. For many erosion failures, the cause is undersized vent lines or turbulence resulting from poor vent line flow paths. Most common, turns in the vent line are the danger spots but they also occur at the diverter spool, downstream of valves or at valves themselves, and at flexible hose connections.

The reason why metal erosion is so difficult to control is because the geometry of the system is the only risk where drilling personnel have control. While the abrasiveness of the particles and the type of formation fluid cannot be controlled by personnel, the geometry of the system and permeability of the formation alongside pressure will decide the fluid viscosity rates.

Thanks to Louisiana State University (LSU) and a study on metal erosion, we can see that it’s influenced heavily by the type of formation fluid. The summaries are as follows;

• Compared to liquid, gas causes metal erosion around 100 times faster.
• The quantity of sand produced with the fluid is also a key component. Erosion rate increases as the amount of sand increases; however, there’s a point when high sand concentration is met, the sand will interfere with itself, and it will protect the metal instead of increasing erosion rate.
•  Metal erosion is deeply affected by fluid viscosity since the square of the fluid viscosity is directly proportionate to erosion. What does this mean? Well, twice the fluid viscosity will lead to four times the erosion. When three times the viscosity, this creates nine times the erosion.
• In terms of the geometry of the system, fluid velocity and turbulence can be reduced with larger-diameter straight vent line systems. Furthermore, a downhole restriction provided by smaller pilot hole sizes can limit fluid velocity too.

Diverting vs Shutting-In – Combination Stack

Depending on the formation integrity at the conductor shoe, the decision to shut-in or divert will be made. However, this cannot be known until the shoe is drilled out which means it’s a tricky decision of whether to nipple up a BOP stack (after cementing conductor casing) or a diverter. These days, combination diverter/BOP stacks can be nippled up on conductor casing and this allows a workaround of the problem. Once the conductor shoe has been tested, the correct decision can be made. According to API, before using a BOP stack, a competent shoe needs to be set and the LOT performed.

Otherwise, the problem can be avoided by rigging up a diverter system designed to enable full shut-in. This should allow diversion through large vent lines and it should allow circulation through a choke manifold and choke line. This can be achieved with two spools (one with large vent lines and one with kill/choke lines). Compared to a BOP stack, using a diverter in this way won’t allow for the same handling of pressure (or redundancy) but the flow rates are expected to be high while the surface pressures are generally expected to be low.

Figure 1 – Combination Stack

Diverter Spool

The diverter spool, for surface applications, must always equal or greater than the annular preventer in terms of pressure rating. Additionally, it should have at least a 10” vent line and two 10” minimum ID side outlets. As long as they’re swaged up to 10” at the spool, some MMS operations will allow for two 8” outlets. To install the divert valves, no other swages or adapters should be used. With some spools, they only have one outlet; in this case, it will need to be 10” and it will need to Tee into two 10” overboard vent lines. In an ideal scenario, two 10” outlets would be used with no swages.

What about onshore operations? Although local policies and regulations may affect this, the spool requires at least one 6” minimum ID outlet. As well as being inspected thoroughly to ensure integrity, the risk of leaks should be reduced by installing all bolts and new ring gaskets.

Figure 2 – Diverter Spool (Courtesy of Cansco.com)

Diverter Valves

Immediately adjacent to the diverter spool, the diverter valves need to be installed and this should protect against valve/spool failures; often, washing can be an issue due to turbulence. With a minimum ID of 10” (or according to local regulations, if a large bore size), the valves should be full opening.

Figure 3 – Diverter Valve

As erosion is accelerated by ID changes, a uniform internal diameter should be promoted by the design of the diverter vent line assembly; this includes valves, spool outlets, and vent lines. Although diverter valves haven’t necessarily been designed to endure shut-in wellbore pressure, sudden vent line plugging could cause this to happen. Over the years, the hydraulic gate valve has been tested extensively with BOP systems and should be chosen with the diverter system over the hydraulic ball valve.

Why choose hydraulic over pneumatic with valve operation?

• Control station fluid and hydraulic fluid allow for consistency.
• Compared to pneumatic operators in a similar service, hydraulic operators will always require a smaller operating chamber to develop more closing force.
• If the rig air supply turns off or is depleted, hydraulic valves can still operate as normal.
• Freezing issues are less common with hydraulic systems.
• Compared to pneumatic tubing, hydraulic control lines are more resistant to damage thanks to their heavy-duty nature and high-pressure steel lines.
• Leaks are easier to locate with hydraulic systems.

Malfunctioning of the divert valves is the most common reason for failure in the system, and a recent study now supports this. With this in mind, wherever possible, a hydraulic gate valve will be preferable. To ensure they aren’t seized up, all valves should be checked every 24 hours alongside the diverter itself.

To reduce lost return problems, some operations will need the installation of a booster pump on the drive pipe. Installed adjacent to the drive pipe, a remote valve will be required when this pump is being used; it should always have a pressure rating close to the system. When the diverter is closed, it needs to close automatically and therefore it needs to be tied into the diverter panel. If a booster pump is not closed automatically when the diverter valve is closed, it will increase wellbore and surface pressure and it can lead to fracturing formation or damaging surface equipment.

Diverter Vent Lines

Just as we saw with divert valves, overboard lines or diverter vent lines need to be set up with the same pressure as the system. Whenever a line plugs, it needs to withstand pressure while the opposite line is being opened. In terms of extent, the lines need to open beyond the edge of decking underneath. Since erosion can be caused by the change in flow direction, lines must be as straight as possible.

Wherever hard piping is possible, use these between the overboard lines and divert valves. If this isn’t an option, divert valves and overboard lines can be connected with flexible hoses. However, they also need to be consistent with the rest of the system in terms of pressure rating. Additionally, they need to be as straight and short as possible while allowing for connection with integral end couplings. While flexible lines can be used, collapsible hoses with dresser sleeves or hose clamps are not acceptable for this use. Since they’re going to experience severe forces, all overboard lines and hoses need to be anchored down securely.

Diverter Control Stations

When it comes to definition in consistency, one component seems to be lacking more than most; the control station. For the diverter system to work effectively, the control station needs to be simple to operate and easily accessible; with this in place, there’s very little room for error. As a remote station to the main accumulator station, Figure 4 shows an example.

Figure 4 – Diverter Control Station

Two levers in a panel will normally be contained within a typical diverter control station, and each would be labelled for simplicity. For the first lever, this controls the diversion of the flow overboard; as soon as it moves to ‘Divert’, the annular preventer will be closed by shifting the four-way valve on the main accumulator. Meanwhile, both overboard lines will be opened as the four-way valve for starboard and port divert valves shift on the main accumulator.

For the second lever, this normally controls the upwind overboard line. For instance, if we need to close a starboard valve which is in the upwind direction, the second lever is switched to ‘Port’ which opens the port divert valve (if closed) and simultaneously closes the starboard four-way valve on the main accumulator. What’s more, regardless of how these levers are operated, no combination will ever cause a shut-in in the well.

With one diverter control station on the rig floor, a separate station will be required somewhere away from the rig floor and in a safe position. Using the rig’s continuous air supply, the stations will be operated by air but they should also hold an air reserve bottle just in case the air supply on the rig is disrupted. Available at both control stations, the bottle should provide enough volume to function each operation twice.

Why offer two separate diverter control systems? In truth, there are several benefits to doing this.

• The stored energy of the system is utilized by using the main accumulator system.
• The control system’s only function is to control the divert operation.
• The control lines going from the component to the unit are high pressure, permanently-installed steel lines.
• With the previous point in mind, it will always be a permanent asset of the rig.
• When diverting a well, the risk of human error is eliminated completely

References 

Cormack, D. (2007). An introduction to well control calculations for drilling operations. 1st ed. Texas: Springer.

Crumpton, H. (2010). Well Control for Completions and Interventions. 1st ed. Texas: Gulf Publishing.

Grace, R. (2003). Blowout and well control handbook [recurso electrónico]. 1st ed. Paises Bajos: Gulf Professional Pub.

Grace, R. and Cudd, B. (1994). Advanced blowout & well control. 1st ed. Houston: Gulf Publishing Company.

Watson, D., Brittenham, T. and Moore, P. (2003). Advanced well control. 1st ed. Richardson, Tex.: Society of Petroleum Engineers.

Cansco.com. 2019. Diverter Packages – Cansco Well Control. [online] Available at: <http://cansco.com/products/diverter-packages/> [Accessed 11 October 2021].

Bsee.gov. 2021. Experimental Study of Erosion Resistant Materials for Use in Diverter Components. [online] Available at: <https://www.bsee.gov/sites/bsee.gov/files/tap-technical-assessment-program/008cb.pdf> [Accessed 23 October 2021].

Bsee.gov. 2021. Integrity of Diverter System Under Abrasive and Multi Phase Flow. [online] Available at: <https://www.bsee.gov/sites/bsee.gov/files/tap-technical-assessment-program/008cb.pdf> [Accessed 23 October 2021].

The post Risks and Equipment Considerations for Surface Diverting (Well Control) appeared first on Drilling Formulas and Drilling Calculations.

In order to fish for wireline tools out of the hole, we must use different equipment than would be used for pipe recovery. Common wireline tool issues center around the cable being tangled or wadded in the hole, as well as the fact that attempts at fishing can pull the wireline out of the rope socket or part, further complicating tool retrieval.

Which Part is Stuck? Cable or Tools

As soon as a wireline assembly becomes stuck, the operator will need to determine whether the problem is in the cable or the tool. Usually, one would apply normal logging tension on the cable and allow it to sit for a few minutes. During this time, four things should be recorded:

• Current depth of the tool
• Type and size of the cable
• Surface tension of the cable just prior to becoming stuck
• Cable-head’s weakpoint rating.

The cable will be marked at the rotary table, and a T-bar clamp will also be securely fitted to the cable just above the table. Should the cable break, then the clamp holds on to the cable end at the surface, so that the whole cable does not fall down the hole and cause additional blockage. The operator will then need to apply 1000 lbf of tension on the cable, and make a note of the distance that the cable mark moves at the rotary table. This figure shows the stretch produced in the elastic cable. It is then possible to estimate the length of free cable, using a stretch chart or from prior knowledge of the cable’s stretch coefficient. Should the length of free cable be the same as the current logging depth, then the problem does not lie with the cable; rather, the tool is stuck, and not the cable. If the length of free cable is less than current logging depth, then the cable is stuck at some higher point in the hole.

If it is the tool which is stuck, and not the cable, then pulling on the cable will cause one of three results. The tool may come free, the weakpoint can break and the tool will remain in the hole but the cable can be removed, or the cable will break at the point of maximum tension.

Causes of Tool Getting Stuck

When the cable cuts through mud cake, differential pressure sticking may occur. This is because one side of the cable is exposed to some degree of formation pressure, whereas the other is exposed to the hydrostatic mud column. Due to this significant difference in pressure, the cable will be pressed harshly into the formation, and friction against the formation stops the cable from moving any longer. Other reasons why sticking may occur include ledges, particularly severe doglegs, borehole caving, or the borehole becoming corkscrewed. As the length of the tool increases, as well as when there has been a long amount of time since the last conditioning trip, the chances of sticking will go up.

Recovery Options

When a wireline tool or cable gets stuck, there are several different ways that they can be recovered.

One option is a side-door overshot as shown in Figure 1. This method is similar to a regular overshot, except that it features a removable side door, so that the tool can be put together around the wireline at the well head itself. It is then possible to run the tool on some tubing or on the drillpipe, downhole alongside the wireline in order to make direct contact with the tool. This stops the wireline from being at risk of parting. It is not recommended that side-door overshots are used with deep open hole intervals. This is because it introduces the potential for keyseating, or differential sticking in the mud cake.

Figure 1 – Wireline Side Door Overshot

Throughout modern drilling, the most successful method to retrieve stuck logging tools is through the cut-and-thread method. This involves cutting the wireline at the surface, and then threading it through a pipe string while the pipe is lowered, until it engages with the logging tool. The line must be secured at the surface, and rope sockets need to be fitted to each end to form a spearhead both emerging from the top of the well, and a spearhead overshot at the logging end. A stand of pipe will then be hung in the derrick, allowing enough of an overshot at the bottom to catch the logging tool, or at least the wireline rope socket. When the upper end of the line is spooled down through the interior of the pipe until the overshot connects with the spearhead at the bottom, then the pipe will be run into the hole. This is repeated with additional stands until the bottom of the string is close enough to the fish. When this is achieved, the spearhead overshot can be disengaged and the overshot can be circulated clean, before it engages with the tool. When the fish has been grasped securely, the wireline will be pulled free from the rope socket, and then spooled out of the hole, and the tool itself recovered with the fishing string. Although the cut-and-thread method takes a lot of time, and comes with a certain amount of risk, it vastly improves the chances of recovering the wireline and tool fully, and is much quicker than trying to engage with the wireline in an open hole.

If it is not possible to use either a side-door overshot or a cut-and-thread, then an alternative is to break the weakpoint, and then recover the cable and use the drill pipe to fish for the logging tool. If tool recovery is not an option, then a last resort is to push it to the very bottom of the hole, and then plug it using cement.

Wirelines that are wadded or tangled can be retrieved with a wireline barb or rope spear. This penetrates the debris, engages with it, and then allows the debris to be pulled away, as shown in Figure 2. This is one of the most basic forms of fishing tool, and gives strong results when used in the right way.

Figure 2 – Rope Spear for Fishing Operation

Junk Removal Tool

Junk refers to any objects or debris which have been dropped into or lost in the hole. Junk can include all manner of things, from downhole tools and bottomhole assembly components, to bit cones, or even hand tools which have been accidentally dropped into the hole. In some cases, it may be clear what the junk is, such as when something has been visibly dropped down the hole. On the other hand, though, it may sometimes be unclear just what is causing the problem. While drilling is taking place, junk can be detected by an irregular torque, or by the drill being unable to move ahead when a new bit has been run. There are three main ways that junk can be dealt with; which method is chosen will depend on the size of the junk itself, and how hard the formation is. The junk can be recovered whole, split into smaller pieces so that these pieces can be recovered or that they are too small to cause any additional issues, or finally pushed into the side of a soft formation or the bottom of a formation with a large enough rathole. If none of these are possible and the junk continues to interfere with well operations, then the well made need to be sidetracked or abandoned.

There are multiple forms of junk baskets available, as shown in Figure 3 and Figure 4. These include core cutting junk baskets (Figure 3), and a combination junk/jet basket (Figure 4). These can be used to recover sidewall core bullets, bit cones, parts of cementing equipment, or other small pieces of debris.

Junk baskets may work in multiple ways:

• The tools might penetrate the formation and cut a relatively short core, digging out debris from the bottom of the hole and then trapping it inside of an inner barrel.
• Alternatively, tools can perform reverse circulation, leading to drilling fluid circulating around the exterior of the basket, and thereby sweeping junk into the top part of the tool before moving further up the annulus. It is also possible for these tools to cut small cores.
• Finally, They should provide a high fluid velocity jetting action, which will force materials into the basket.

Figure 3 – Core Cutting Junk Basket

Figure 4 – A combination junk/jet basket (reverse circulation junk basket)

Magnets can be run either on a wireline or on a drill pipe. Smaller ones can pull around 2 lbf, while larger ones can pull up to 3000 lbf, equivalent to 13345 N. These magnets are designed to only exert their magnetic field downwards, so they do not cause any damage when they are lowered through casing. Permanent magnets will be run on a drill pipe, and include circulating ports to allow for cuttings to be washed away so that the magnet can make contact with metal fish. On the other hand, electromagnets are run on wirelines, and only switched on when they reach the fish. They can be run in and out of holes quickly, but a disadvantage is that they lack any fill-cleaning capabilities, and therefore cannot engage fish that are covered with debris or fill. They are useful for retrieving iron-containing metal objects.

Figure 3 – Fishing Magnet for Drilling and Workover

References 

DeGeare, J. (2003). The Guide to Oilwell Fishing Operations: Tools, Techniques, and Rules of Thumb (Gulf Drilling Guides). 1st ed. Houston: Gulf Professional Publishing.

Jr. Adam T. Bourgoyne , Keith K. Millheim , Martin E. Chenevert , Jr. F. S. Young (1991). Applied drilling engineering textbook. (1991). 2nd ed. United States: Society OF PETROLEUM ENGINEERS OF AIME (TX).

Azar, J. and Samuel, G. (2008). Drilling engineering. 1st ed. Tulsa, Okla.: PennWell.

Slideshare.net. (2018). Drilling Rig Equipment (Drilling Note). [online] Available at: https://www.slideshare.net/markacy/cfakepathdrilling-notes [Accessed 24 Jun. 2018].

The post Wireline Tool Recovery and Junk Removal Equipment for Drilling and Workover first appeared on Drilling Formulas and Drilling Calculations.

The accumulator unit is one of the critical well control equipment and its main aim is to supply the pumps with atmospheric fluid while also storing high pressure operating fluid for operating BOP stack. In this article, we will learn about requirements of critical components of an accumulator unit including  accumulators, reservoir, pneumatic pump, electric motor driven pumps and hydraulic control manifold/valve & fitting.

Surface BOP Control Systems Equipment

Accumulator Bottles

For storing high pressure fluid, accumulators are pressure vessels (ASME coded). Depending on requirements, the accumulators can be found in all sorts of types, sizes, pressure ratings, and capacities. Most commonly, ‘float’ and ‘bladder’ accumulators are used which come in ball or cylindrical shapes. Furthermore, they can be top or bottom loading.

Figure 1 – Accumulator Bottles

If bottom loading, servicing will require them to be removed from the accumulator unit. If top loading, both float and bladder can be removed while mounted on the accumulator unit. Without destroying their stamp of approval, both types of accumulators can actually be repaired in the field whenever necessary.

Reservoir Tank

For storing atmospheric fluid, a rectangle reservoir is normally provided for high pressure pumps. Boasting troubleshoot inspection ports, baffles, and drain/fill ports, the Maintenance section can be reviewed for standard cleaning and filling guidance. The reservoir should be able to keep twice capacity of the usable fluid required.

Figure 2 – Reservoir Tank

Accumulator Piping and valves

Connecting the accumulators/hydraulic manifold with the pump’s high pressure discharge lines, the piping/valve has an important role. In order to protect the accumulators and prevent over pressurizing, the piping should consist of isolator valves, Schedule 80 or 160 pipe (1 or 1 1/2 inches), and a relief valve (3,300psi). To help minimize leaks and line restrictions, cylindrical accumulators can be mounted onto machined headers.

Read more details about 4-way valve > 4-Way Valve Operation in Blow Out Preventer Accumulator (Koomey) Unit

Figure 3 – Valve and Piping

Air Pump Assembly

To provide high pressure operating fluid, one or more hydraulic pumps in the air pump assembly will be connected (parallel) to the accumulator for the BOP control system.

Figure 4 – Air Pump Assembly

Electric Pump Assembly

Driven by an explosion-proof electric motor, the electric pump assembly should always contain a duplex (or triplex) reciprocating plunger pump. To provide high pressure operating fluid to the BOP control system, this should be connected to the accumulator piping. Not only is it available in different voltage ranges, a range of horsepower options can be found too.

Figure 6 – Electric Pump Assembly

Accumulator Requirements

General

Accumulator bottles are pressure-sealed containers that hold hydraulic fluid for use in blowout preventer closure. These containers store energy in the form of compressed nitrogen gas, which can be utilized to close the preventer quickly. In common usage, two accumulator bottles exist including ‘float’ and ‘separator’.

• Float – To separate the hydraulic fluid and the nitrogen gas, a floating piston is utilized with the float type.
• Separator – To effect the separation of hydraulic fluid and nitrogen gas, the separator type uses a flexible diaphragm.

Volumetric Capacity 

All blowout preventer closing units should include accumulator bottles with enough volumetric capacity to produce enough usable fluid volume with pumps turned off to close a maximum of 4 BOP rams and the annular preventer in the stack, as well as enough volume to open the hydraulic choke line valve (HCR). Additionally, the final pressure shall be more than Minimum Operating Pressure (MOP). This is referred to API STD53.

Between 200psi above the pre-charge pressure and the accumulator operating pressure, the amount of fluid recoverable from an accumulator is considered the ‘usable fluid volume’. The accumulator operating pressure is the pressure at which hydraulic fluid is charged into accumulators.

Minimum Operating Pressure (MOP)

Based on the latest requirement from API STD 53 late 2018, Minimum Operating Pressure (MOP) is defined as a minimum pressure differential required for a device to successfully perform its intended function in a particular environment. If the BOP stack contains a shear ram with no dedicated shear accumulator , the calculated MOP must include the maximum pressure required to shear and seal the pipe for that operation. However, if the system has a dedicated shear accumulator, there will be separate MOP figures which are one for shear rams and another one for pipe ram.

API 16D Bottle requirements

The primary accumulator system must be built so that the loss of a single accumulator, bank, or both does not result in a loss of more than 25% of the system’s overall capacity. To decrease the possibility of bladder damage, the pre charge pressure for bladder type accumulators should be larger than 25% of the system hydraulic pressure. The amount of pre-charge pressure varies based on the individual operational needs of the equipment and the operating environment.

Response Time

In terms of response time, 30 seconds is the limit for the closing unit closing each ram preventer. For annual preventers under 18 3/4 inches, closing time should never exceed 30 seconds; for annular preventers larger than 18 3/4 inches, 45 seconds is the maximum.

Operating Pressure and Pre-charge Requirements for Accumulators

When it comes to operating an accumulator bottle, the pressure should never exceed its rated working pressure. During the initial closing unit installation, each accumulator bottle’s pre-charge pressure should be measured; this should occur on each well before then being adjusted, wherever required. For accumulator pre-charge, nitrogen gas should be used only. Finally, during well drill operations, the pre-charge pressure should be checked regularly.

Requirements for Accumulator Valves, Fittings, and Pressure Gauges

Valving should be installed in multi-bottle accumulator banks to ensure bank isolation. Except when the accumulators are isolated for service, testing, or transporting, an isolation valve must have a rated working pressure at least equal to the designed working pressure of the system to which it is connected and must be in the open position. If needed, accumulater bottles can be fitted in banks with a capacity of around 160 gallons, with a minimum of two banks.

On each accumulator bank, the appropriate fittings and valves need to be provided since this allows for the attachment of a pressure gauge without having to take all accumulator banks away from service. For installation, there should always be an accurate pressure gauge available in order to measure the accumulator pre-charge pressure.

Closing Unit Pump Requirements

Requirements for Closing Unit Valves, Fittings, Lines, and Manifold

Pump Capacity Requirements

To perform the operation in this section to a required standard, every closing unit needs sufficient numbers and sizes of pumps. On the size of pipe in use, the pumps should be able to close the annular preventer while the accumulator system is isolated. The hydraulically-operated choke line valve should also be opened and a minimum of 200psi pressure above the accumulator pre-charge should be obtained on the closing unit manifold within around two minutes.

Pump Pressure Rating Requirements

Pumps must be installed in each closing unit to generate a discharge pressure equal to the closing unit’s rated working pressure.

Pump Power Requirement

At all times, closing unit pumps must have power so, when the closing unit manifold pressure decreases, the pumps start automatically; the decrease in pressure should be lower than 90% of the accumulator operating pressure before activating.

On each closing unit, two or three independent power sources should be ready with each having the ability to pump at a rate the Pump Capacity Requirements section suggests. When ‘dual source’ power systems are mentioned, this refers to air and electrical systems in general. The dual air or electric systems are acceptable but less preferred.

The dual power source systems are as follows:

• A dual air and electrical system = a dedicated air compressor for an accumulator + a rig electrical generator to run electric pump
• A dual air system = a dedicated air compressor for an accumulator + a rig electrical generator to run compressor
• A dual air system = a dedicated air compressor for an accumulator + an air storage tank that is separated from both the rig air compressors and the rig air storage tank by check valves.
• A dual electrical system = one electrical power from main generator + another one from a back up generator (emergency generator)
• A dual air/nitrogen =a dedicated air compressor for an accumulator + bottles nitrogen gas.
• A dual electrical/nitrogen = one electrical power from main generator + bottles nitrogen gas.

If surface pressures fall 200psi lower than originally expected, and if the drilled casing is set at less than 500 feet on shallow wells, the closing unit will not require a backup source of power.

Requirements for Closing Unit Valves, Fittings, Lines, and Manifold

Requires Pressure Rating

Between the BOP stack and the closing unit, all fittings and valves should have a rated working pressure equal or above the BOP stack’s working pressure (up to a maximum of 3,000psi) and should also be constructed with steel. For all test pressure requirements, these are available in API Spec 6A: Specification for Wellhead Equipment. Steel should also be used for all lines between the blowout preventer and closing unit; if not steel, an equivalent fire-resistant hose with flexibility. For the end connections, the stack pressure rating (up to 3,000psi) and rated working pressure should be equal.

Valves, Fittings, and Other Components Required

The following should be equipped with each installation;

• Sufficient check valves for each closing unit, or shut-off valves to separate the accumulators and the closing unit pumps from the closing unit manifold; this should also allow for the isolation of the annular preventer regulator.
• Full-opening valve for each closing unit in order to connect a separate operating fluid pump whenever required.
• A pressure regulating valve for each closing unit in order to allow for manual control of the annular preventer operating pressure.
• A regulating valve for each closing unit to control the ram type preventers operating pressure; they should also be equipped with a valve and by-pass line so the closing unit manifold can take the full accumulator pressure whenever required.
• Accurate pressure gauges for each closing unit to indicate the closing unit manifold’s operating pressure; in relation to the annular preventer pressure regulating valve, both downstream and upstream can be important.
• A full-opening plug valve for each annular preventer on both opening and closing lines. Not only should these valves be present, they need to be in the open position while installed adjacent to the preventer itself. When testing operating lines over 1,500psi, open position isn’t applicable if the annular preventer isn’t damaged at all.
• All closing unit control valves should be marked to show the position of the valves as well as which choke line valve or preventer each valve operates. During drilling operations, the BOP control valves should be ‘open’ rather than on ‘neutral’ or ‘block’. During normal operations, the choke line valve should be closed. To avoid accidental operation, the control valve in charge of the blind rams should be covered (over the manual handle). Finally, if the remote unit is activated, the handle shouldn’t be covered to the point where it stops the ram function from working.

Requirements for Closing Unit Fluids and Capacity

For the closing unit control operating fluid, either hydraulic oil or fresh water containing a lubricant should be used. When a closing unit fluid contains water and the expected ambient temperature is below 32F, glycol shall be added. Due to the likelihood of seal damage, there are several substances not recommended for the task; this includes chain oil, diesel oil, motor oil, and kerosene. The reservoir tank capacity must be at least 2 times of usable fluid used in the system.

Closing Unit Location and Remote Control Requirements

For the main pump accumulator, this needs a safe storage space while also being accessible in an emergency for all rig personnel. Additionally, it should prevent a flow back to the reservoir from the operating lines and it should prevent excessive drainage. To compensate for flow back in the closing lines when the main pump accumulator is located some way below the BOP stack, additional accumulator volume can be added.

Control panels should be equipped with each installation to allow the driller to control each control valve and blowout preventer, from a position easily accessible; this point should also be some distance from the rig floor.

References

Cormack, D. (2007). An introduction to well control calculations for drilling operations. 1st ed. Texas: Springer.

Crumpton, H. (2010). Well Control for Completions and Interventions. 1st ed. Texas: Gulf Publishing.

Grace, R. (2003). Blowout and well control handbook [recurso electrónico]. 1st ed. Paises Bajos: Gulf Professional Pub.

Grace, R. and Cudd, B. (1994). Advanced blowout & well control. 1st ed. Houston: Gulf Publishing Company.

Watson, D., Brittenham, T. and Moore, P. (2003). Advanced well control. 1st ed. Richardson, Tex.: Society of Petroleum Engineers.

The post Accumulators for Surface Well Control System and Requirements first appeared on Drilling Formulas and Drilling Calculations.

Oil well cement adheres to API Specification 10 and is categorized into eight classes, labeled A to H, based on its specific properties. Among these, Class G and Class H serve as foundational well cements that can be employed alongside accelerators and retarders to accommodate a broad spectrum of well depths and temperature conditions. One notable distinction between these two classes lies in their particle size, with Class H being notably coarser than Class G.

The details of each cement class are as follows;

Class A: Designed for surface applications up to a depth of 6,000 feet (1,830 meters) where specific properties are not required. Similar to ASTM (American Society for Testing Materials) Type I cement.

Class B: Suitable for use from the surface down to 6,000 feet (1,830 meters) with moderate to high sulphate resistance. Comparable to ASTM Type II cement, with a lower C3A content compared to Class A.

Class C: Intended for surface-to-6,000-foot (1,830-meter) applications when early strength is essential. Available in all three sulphate resistance levels and is roughly equivalent to ASTM Type III cement. Achieves high early strength due to relatively high C3S content and surface area.

Class D: Designed for depths ranging from 6,000 feet (1,830 meters) to 10,000 feet (3,050 meters) under moderately high temperature and pressure conditions. Offered in both moderate sulphate resistance (MSR) and high sulphate resistance (HSR) variations.

Class E: Tailored for use between 10,000 feet (3,050 meters) and 14,000 feet (4,270 meters) in high-temperature and high-pressure conditions. Available in both MSR and HSR types.

Class F: Geared towards depths ranging from 10,000 feet (3,050 meters) to 16,000 feet (4,880 meters) under extremely high-temperature and high-pressure conditions. Offered in both MSR and HSR varieties.

Class G + Class H: Primarily used as fundamental well cement from the surface down to 8,000 feet (2,440 meters) in its original form. Alternatively, it can be used in conjunction with accelerators and retarders to accommodate a wide range of well depths and temperatures. These well cements are manufactured with no additives other than calcium sulphate or water, or both. They are available in both MSR and HSR variations.

<p>The post Classes of Oil Well Cement Used in Petroleum Industry first appeared on Drilling Formulas and Drilling Calculations.</p>

Cementing in the oil and gas industry involves a meticulous process, and cementing additives play a crucial role in fine-tuning the properties of cement slurries. These additives are carefully selected to control slurry density, rheology (flow behavior), fluid loss, and to impart specialized characteristics for effective cement placement in diverse downhole conditions. Let’s explore the various categories of additives used in cementing:

1. Accelerators: Accelerators are chemicals employed to expedite the thickening process of a cement slurry and enhance early strength development. Typically used in conductor and surface casing applications to reduce waiting-on-cement time (WOC), common accelerators include calcium chloride (CaCl2), sodium chloride (NaCl), and seawater.

2. Retarders: Retarders, on the other hand, serve to delay the setting time of a cement slurry, extending its thickening period. They are especially valuable in counteracting the effects of high temperatures. These additives find applications in cement slurries for intermediate and production casings, squeeze and cement plugs, as well as high-temperature wells. Retarders work by adsorbing onto the cement surface, inhibiting contact with water and elongating the hydration process. Common retarders include sugar, lignosulfonates, hydroxycarboxylic acids, inorganic compounds, and cellulose derivatives.

3. Weighting Agents: Weighting agents are substances used to increase the density of the cement slurry. Barite and hematite are commonly employed in this category.

4.  Extenders: Extenders are materials that lower the slurry density while increasing its yield, allowing the cement column to cement weak formations without causing fractures. Examples of extenders include water, bentonite, sodium silicates, pozzolans, gilsonite, expanded perlite, nitrogen, and ceramic microspheres.

5. Fluid-Loss Additives: Excessive fluid loss from the cement slurry to the formation can disrupt the proper setting of cement. Fluid loss additives are used to prevent slurry dehydration and reduce fluid loss to the formation. Examples of such additives include cationic polymers, non-ionic synthetic polymers, anionic synthetic polymers, and cellulose derivatives.

6. Dispersants: Dispersants serve to reduce the viscosity of the slurry and may increase free water by dispersing solid particles within the cement slurry. These additives are solutions of negatively charged polymer molecules that attach themselves to positively charged sites on the hydrating cement grains. This results in increased negative charges on the hydrating cement grains, leading to greater repulsive forces and improved particle dispersion.

7. Strength Retrogression: In high-temperature conditions exceeding 230°F, standard cement can develop high permeability and reduced strength. To counter this, silica flour is often added at a concentration of 30-40% by weight of cement. This addition prevents both strength reduction and the development of permeability at elevated temperatures.

8. Lost Circulation Control Agents: These materials are utilized to manage the loss of cement slurry into weak or fractured formations, preventing wastage.

9. Miscellaneous Agents: This category includes a range of additives like anti-foam agents, fibers, and latex, which are employed for various specialized purposes.

In conclusion, the careful selection and application of these cementing additives are essential for ensuring the success and integrity of oil and gas well constructions, allowing for adaptability to a wide spectrum of downhole conditions.

References

Baker, R. (2001) A primer of oilwell drilling: A basic text of oil and gas drilling. 6th edn. Austin, TX: Petroleum Extension Service, Continuing & Extended Education, University of Texas at Austin.

Mitchell, R.F., Miska, S.Z. and Aadnoy, B.S. (2012) Fundamentals of drilling engineering. Richardson, TX: Society of Petroleum Engineers.

Bourgoyne, A.T. (1986) Applied drilling engineering. Richardson, TX: Society of Petroleum Engineers.

<p>The post What are Cementing Additives to Enhance Cement Properties first appeared on Drilling Formulas and Drilling Calculations.</p>

Cementing operations in the oil and gas industry are a critical component of well construction and integrity. Proper casing and cementing hardware play a crucial role in ensuring the successful execution of these operations. In this article, we will explore the various equipment used in cementing operations, including guide shoes, float collars, centralizers, cement wiper plugs, and multi-stage collars.

casing and cement hardware

Guide Shoes and Float Shoes:

Guide shoes are essential tools used to guide casing strings through the wellbore without encountering issues such as jamming in washed-out zones or deviations. They can be simple guides or more advanced float shoes, which incorporate valves to prevent cement from flowing back into the casing once it is displaced behind the casing. These shoes can be made with inner parts composed of either aluminum or cement, both of which are easily drillable. Cement offers greater impact resistance, making it a popular choice. However, it’s important to note that float shoes may add time to the casing running process due to the need to temporarily halt operations to fill the casing from the top. To expedite this process, orifice fill shoes (automatic fill-up shoes) can be used to fill the casing while it is being run in the hole.

Guide and Float shoe

Float Collars:

Float collars serve as one-way valves placed one or two joints above the shoe. They serve the same purpose as float shoes, preventing fluid backflow into the casing during various stages of the cementing process, including mud backflow during casing insertion and cement slurry backflow after displacement. Float collars may employ ball-type or flapper-type valves, with flapper valves being preferred when minimal hydrostatic pressure difference is expected due to their superior sealing capabilities.

Float collar

Casing Centralizers:

Casing centralizers are mechanical devices designed to maintain a uniform annular space around the casing, ensuring that cement can effectively seal the casing to the borehole wall. Two main types of centralizers are bow-spring and rigid blade designs. Bow-spring centralizers, while cost-effective, are better suited for vertical or slightly deviated wells. Rigid-blade centralizers, although slightly more expensive, are more rugged and can provide good centralization even in deviated wellbores. Proper centralization is crucial for cementing success, but the choice between these two types should consider wellbore conditions.

Bow spring and rigid blade centralizer

Cement Wiper Plugs

Cement wiper plugs are rubber plugs employed to separate the cement slurry from other fluids, maintaining the integrity and predictability of the slurry’s performance. Two types of cementing plugs are used during operations: the bottom plug and the top plug. The bottom plug precedes the cement slurry to minimize contamination, rupturing upon reaching the landing collar to allow cement flow. The top plug provides a clear indication of contact with the landing collar through increased pump pressure. These plugs play a vital role in ensuring the separation of mud and cement, preventing over-displacement of cement, confirming cement placement, and enabling casing pressure testing.

Cement Wiper Plug (Top and Bottom Plug)

Multi-Stage Collars:

Multi-stage collars, also known as DV (Dual Valve) tools, are employed to facilitate cementing in two stages, mitigating excessive hydrostatic pressure on weak formations. These tools consist of a section of casing with similar strength properties as the rest of the string, featuring two internal sleeves and openings covered by the lower sleeve. The lower sleeve is opened by dropping a bomb, allowing cement to be pumped through the casing and placed around it. After reaching the desired cement volume, a closing plug is dropped, causing an upper sleeve to cover the holes in the stage collar. Multi-stage cementing is utilized to reduce pumping pressure or time, lower hydrostatic pressure on formations, selectively cement specific zones, and ensure complete casing cementation, with the positioning determined by the cement column length and formation strength.

Multi-Stage Collars

Conclusion:

Casing and cementing hardware are integral components of cementing operations in the oil and gas industry. Properly selected and deployed equipment, including guide shoes, float collars, centralizers, cement wiper plugs, and multi-stage collars, ensure the successful execution of these critical operations, contributing to well integrity and overall operational success.

References

Baker, R. (2001) A primer of oilwell drilling: A basic text of oil and gas drilling. 6th edn. Austin, TX: Petroleum Extension Service, Continuing & Extended Education, University of Texas at Austin.

Mitchell, R.F., Miska, S.Z. and Aadnoy, B.S. (2012) Fundamentals of drilling engineering. Richardson, TX: Society of Petroleum Engineers.

Bourgoyne, A.T. (1986) Applied drilling engineering. Richardson, TX: Society of Petroleum Engineers.

<p>The post Casing and Cementing Hardware in Oil Well Operations first appeared on Drilling Formulas and Drilling Calculations.</p>

To achieve a successful oil well cementing and ensure zonal isolation in oil well cementing, efficient mud displacement is crucial. Inadequate mud removal can lead to problems like cement channeling, permitting the intrusion of hydrocarbons and communication between permeable zones. The following factors are essential for ensuring a good cement bond:

1. Conditioning the Drilling Mud: Before removing the drill pipe from the well, it’s essential to reduce the mud’s viscosity to the lowest practical level. Focus should be on decreasing the low shear-rate rheology of the mud, such as gel strengths and yield points. However, caution should be exercised to maintain the mud rheology above the minimum level required to suspend weighting agents like barite.After the casing is run, additional mud conditioning is necessary to remove gelled mud that may have formed beneath the casing due to poor centralization. Typically, two to three hole volumes suffice for this purpose, but the actual requirement depends on the mud’s viscosity and casing centralization. Gelled mud becomes increasingly challenging to remove over time.It’s important to note that the removal of gelled mud requires shear stress to overcome its strength. This shear stress can be generated through pipe movement or the mobile mud. Increasing mud flow rate or modifying drilling fluid properties can enhance shear stresses. Ideally, mud should be conditioned during circulation before casing installation to minimize gelled mud issues.
2. Casing Movement: Whenever possible, casing should be reciprocated or rotated. Various studies have shown that pipe movement enhances displacement efficiency by breaking up gelled mud pockets. The debate continues regarding whether casing reciprocation or rotation is more effective. For liners, rotation is recommended, considering liner setting and gas swabbing concerns. Common guidelines suggest reciprocating 20-40 ft strokes over 2-5 minutes or rotating at rates of 10-40 rpm.
3. Centralization: When running casing in deviated wells, eccentricity can lead to trapped pockets of mud on the low side of the wellbore, potentially causing cement channeling or incomplete zonal isolation. To ensure unhindered circulation beneath the casing, it is advisable to maintain a minimum standoff of 70%, especially after optimizing mud rheology and displacement rates. Centralizers should be positioned to allow casing reciprocation or rotation in cases where casing movement is necessary. A centralizer program should consider the entire casing string’s mechanics, along with buoyancy and density differential effects during displacement. If washouts are expected, centralizer quantities should be adjusted to account for the increased hole size.
4. Displacement Rate: Turbulent flow in the displacing fluid leads to highly effective displacement. However, achieving turbulence across an eccentric annulus can be challenging, and it often results in gelled mud remaining in the narrow section of the annulus. In cases where turbulence is feasible, a higher displacement rate should be employed for the best results. In situations where turbulence cannot be maintained, a well-designed laminar displacement can still achieve effective results. Careful consideration of density, viscosity, and annular flow rate is crucial for laminar displacements.
5. Washes and Spacers: In a successful primary cementing operation, the cement slurry must displace the fluid surrounding the casing. The incompatibility of mud and cement can lead to channeling or viscous masses. To address this issue, an intermediate fluid is used as a pre-flush to remove drilling mud from the annulus. Optimal mud removal is achieved with a simple wash, which creates turbulence at low annular velocities. However, weighted spacers may be necessary for well control, and a combination of a thin wash with a weighted spacer can effectively remove mud. When turbulent wash or spacer is used, a minimum contact time of 10 minutes should be ensured.

In conclusion, a successful oil well cementing operation relies on addressing these critical factors to ensure efficient mud displacement, proper centralization, casing movement, effective washes and spacers, and appropriate displacement rates. Tailoring these considerations to the specific well conditions is essential for optimal results.

References

Baker, R. (2001) A primer of oilwell drilling: A basic text of oil and gas drilling. 6th edn. Austin, TX: Petroleum Extension Service, Continuing & Extended Education, University of Texas at Austin.

Mitchell, R.F., Miska, S.Z. and Aadnoy, B.S. (2012) Fundamentals of drilling engineering. Richardson, TX: Society of Petroleum Engineers.

Bourgoyne, A.T. (1986) Applied drilling engineering. Richardson, TX: Society of Petroleum Engineers.

<p>The post Key Factors for Successful Oil Well Cementing first appeared on Drilling Formulas and Drilling Calculations.</p>

Squeeze cementing represents a critical process in the oil and gas industry, where a cement slurry is squeezed through perforations in casing to create a seal in specific locations, bridging undesired gaps. It is a common misconception that the cement penetrates the pores of the rock. Instead, the cement slurry dehydrates against the formation walls, forming a seal cement filter cake. It must be clear that cement does not infiltrate the pores of the rock. Given that cement slurries have particles with a mean size ranging from 20 to 50 microns, the permeability of the formation must be between 2-100 darcies for cement grains to penetrate the formation successfully.

Reasons for Squeeze Cementing

The necessity for squeeze cementing arises for various reasons during drilling and production phases, including:

1. Zone Isolation Before Production Perforations: This ensures that specific zones are sealed off before the commencement of production.
2. Rectifying Faulty or Inadequate Primary Cement Jobs: When the primary cementing job does not meet requirement, squeeze cementing comes to the rescue.
3. Fixing Casing Leaks: Squeeze cementing is instrumental in addressing any breaches in the casing.
4. Shutting off Unwanted Reservoir Water or Gas Inflows: To control and stop the unwanted flow of water or gas.
5. Abandoning Non-Productive or Depleted Zones: When zones become unproductive or depleted, squeeze cementing is conducted to ensure their abandonment.

Three Main Techniques for Squeeze Cementing

Hesitation Squeeze:

The hesitation squeeze method involves the gradual buildup of a cement filter cake inside perforation tunnels. This process relies on the application of differential pressure to induce slurry dehydration. Given the minimal amount of filtrate lost from the slurry, continuous pumping becomes impractical. Instead, pressure is intermittently applied, allowing pressure to bleed off as the filter cake develops. This technique proves effective in ensuring that the pressure increases steadily as the filter cake builds up.

Hesitation Squeeze Example

Low Pressure Squeeze:

During low-pressure squeeze operations, cement slurry is forced through perforations at pressures below the formation’s fracture pressure. The primary goal here is to fill perforation cavities and interconnected voids with dehydrated cement. Importantly, no slurry is pumped directly into the formation. This technique is commonly recommended in squeeze cementing procedures.

High Pressure Squeeze:

In certain scenarios, a low-pressure squeeze may not suffice to achieve the desired results. High-pressure squeezes are used when channels behind the casing aren’t directly connected to perforations, or when small cracks or micro-annuli permit gas flow but not cement slurry. Furthermore, some low-pressure operations face challenges due to the displacement of plugging fluids, such as drilling muds or solids-carrying completion brines. To carry out high-pressure squeezes, formations close to the perforations are broken down to create space for the cement slurry. This technique is particularly effective when displacing fluids and ensuring that all channels, from fractures to perforations, are filled with cement cake.

What is the Preferred Method?

Among these techniques, the hesitation squeeze is often preferred, involving the pumping of small cement volumes at intervals to allow gelling before squeezing.

Conclusion

Squeeze cementing techniques are essential for ensuring well integrity, addressing various challenges during drilling and production. By understanding and implementing advanced methods like hesitation squeezes, low-pressure squeezes, and high-pressure squeezes, oil and gas professionals can effectively seal undesirable gaps, enhancing the overall efficiency and safety of well operations.

References

Baker, R. (2001) A primer of oilwell drilling: A basic text of oil and gas drilling. 6th edn. Austin, TX: Petroleum Extension Service, Continuing & Extended Education, University of Texas at Austin.

Mitchell, R.F., Miska, S.Z. and Aadnoy, B.S. (2012) Fundamentals of drilling engineering. Richardson, TX: Society of Petroleum Engineers.

Bourgoyne, A.T. (1986) Applied drilling engineering. Richardson, TX: Society of Petroleum Engineers.

<p>The post What are Squeeze Cementing Techniques? first appeared on Drilling Formulas and Drilling Calculations.</p>

We Keep Cement Samples Because of The Following Reasons

Cement samples are kept after pumping cement in oil well operations for several important reasons. The two images below shoes cement samples, one collected while cement is in liquid phase and another one is when cement is set for awhile.

Cement Sample in Liquid Phase

Cement Sample After Set

Quality control

Cement samples allow operators to assess the quality of the cement used in well construction. The samples can be analyzed for various properties, such as compressive strength, setting time, and density, to ensure that the cement meets the required specifications and standards. This is crucial for maintaining the integrity and safety of the well.

Verification

Cement samples serve as a reference to verify that the cement placed downhole matches the intended composition and properties. By comparing the downhole cement with the sample, operators can confirm that the correct cement was used and that it has set properly.

Troubleshooting

In case of any issues with the cementing process, such as poor bonding or incomplete setting, having samples allows engineers to investigate the problem and make necessary adjustments for future operations.

Regulatory compliance

In the oil and gas industry, there are often regulatory requirements related to well construction and cementing. Keeping samples can provide evidence of compliance with these regulations and may be required for audits or reporting.

Research and development

Cement samples can also be valuable for research and development purposes. They can be used to develop and test new cement formulations, additives, and techniques to improve wellbore stability and integrity.

Litigation and liability

In the event of disputes, accidents, or liability claims related to well construction, having cement samples can serve as valuable evidence to support claims or defend against them.

Additionally, cement samples are also required by law in some jurisdictions. For instance, such as the United States, the Environmental Protection Agency (EPA) mandates that oil and gas companies retain cement samples for a stipulated period of three years.

Summary

Retaining cement samples in oil well operations is a standard practice that is essential for ensuring the quality, performance, and compliance of the cement used in the well construction process. This is critical for maintaining the safety and productivity of oil and gas wells.

In addition to practical applications, such as quality control and troubleshooting, cement samples are also indispensable for compliance with legal requirements. By keeping cement samples, oil well operators can demonstrate that they are operating within the regulatory framework set by authorities like the EPA.

In short, cement samples play a vital role in ensuring the safety and integrity of oil and gas wells.

<p>The post Why Do We Keep Cement Samples in Oil Well Operations? first appeared on Drilling Formulas and Drilling Calculations.</p>

Tripping pipe into and out of a well constitutes a commonplace activity in completion and workover operations. However, alarming statistics reveal that a significant number of kicks occur during these trips. Consequently, gaining a profound understanding of the fundamental principles associated with tripping is imperative in completion and workover endeavors.

What is Surge?

The descent of tubing into the well (tripping in) generates pressure exerted at the well’s bottom. As the tubing is introduced into the well, the well’s fluid must ascend to exit the volume being encroached upon by the tubing. This simultaneous downward movement of the tubing and upward movement of the fluid, often referred to as the piston effect, leads to a rise in pressure at any given point in the well. This pressure escalation is commonly termed surge pressure.

What is Swab?

Conversely, the ascent of tubing from the well (tripping out) impacts the pressure applied at the well’s bottom. When withdrawing pipe from the well, fluid must descend to fill the void left by the tubing. The collective result of the tubing’s upward movement and the fluid’s downward movement is a reduction in bottom hole pressure. This pressure decrease is known as swab pressure.

Key Parameters Affecting Surge and Swab

Both surge and swab pressures are influenced by several key parameters:

• Velocity of the pipe, or tripping speed
• Wellbore geometry (annular clearance between tools and casing, tubing open-ended or closed off)
• Fluid viscosity
• Fluid density
• Fluid gel strength

It is evident that higher tripping speeds lead to increased surge and swab pressure effects. Similarly, greater fluid density, viscosity, and gel strength amplify the tendency for surge and swab effects. Additionally, downhole tools like packers and scrapers, characterized by minimal annular clearance, further accentuate surge and swab pressure effects.

Accurate determination of surge and swab pressures can be achieved through the utilization of drilling hydraulic calculator programs, or by referencing hydraulic manuals.

References

Cormack, D. (2007). An introduction to well control calculations for drilling operations. 1st ed. Texas: Springer.

Crumpton, H. (2010). Well Control for Completions and Interventions. 1st ed. Texas: Gulf Publishing.

Grace, R. (2003). Blowout and well control handbook [recurso electrónico]. 1st ed. Paises Bajos: Gulf Professional Pub.

<p>The post Understanding the Dynamics of Tripping Pipe in Well Completions and Workovers first appeared on Drilling Formulas and Drilling Calculations.</p>

In the realm of well control, encompassing both drilling and completion operations, the terms kick and influx hold significant importance. This article aims to explain the distinctions between these two terms, offering insights into their unique characteristics within the context of well control.

What is Kick?

Kick : A kick is the unwanted influx of formation fluid into the wellbore, typically occurring when the pressure exerted by the column of drilling fluid is insufficient to overcome the pressure from fluids in a permeable formation. Unintentional kicks, such as drilling into abnormally pressured formations or inadequately maintaining hole fullness during tripping, constitute the majority of kick incidents. Vigilance throughout rig operations is crucial to prevent kicks, especially considering historical industry data indicating a higher likelihood of kicks during rig operations.

While intentional flows of formation fluids are desirable in certain situations, such as during well production or drill stem testing, unintentional kicks during completion, workover, or drilling operations pose a significant threat to well control if immediate action is not taken.

What is Influx?

 Influx: An influx is the entry of formation fluid into the wellbore, with varying potential to reduce hydrostatic pressure below formation pressure. Regardless of its impact on pressure, an influx signals that the exposed, porous, and permeable formation’s pressure has surpassed the adjacent wellbore pressure at some point. Failure to promptly recognize an influx, especially one involving gas, can lead to further reductions in hydrostatic pressure, ultimately risking the loss of well control.

Wells experience kicks when the reservoir pressure of an exposed, permeable formation exceeds the wellbore pressure at that depth. Several factors contribute to this underbalanced condition, including:

• Low-density drilling fluid.
• Abnormal formation pressure.
• Swabbing.
• Insufficient hole fullness during trips.
• Lost circulation.

References

Cormack, D. (2007). An introduction to well control calculations for drilling operations. 1st ed. Texas: Springer.
Crumpton, H. (2010). Well Control for Completions and Interventions. 1st ed. Texas: Gulf Publishing.
Grace, R. (2003). Blowout and well control handbook [recurso electrónico]. 1st ed. Paises Bajos: Gulf Professional Pub.

<p>The post Understanding Kick and Influx in Drilling and Completion Operations first appeared on Drilling Formulas and Drilling Calculations.</p>

The density of drilling fluid plays a critical role in well control during both drilling and completion operations. This article aims to explore the various factors that can result in low-density drilling fluid, potentially leading to well control challenges.

Accidental Dilution and Fluid Addition

Maintaining the hydrostatic pressure necessary to balance or slightly exceed formation pressure requires constant monitoring and adjustment of drilling fluid density. Accidental dilution of drilling fluid with makeup water in surface pits or the addition of low-density formation fluids into the mud column can reduce fluid density, triggering a potential kick. Rigorous vigilance in monitoring mud pits is essential to ensure the required fluid density is consistently maintained.

Gas Cutting

Large volumes of gas in the returns can cause a drop in the average density and hydrostatic pressure of the drilling fluid. Notably, gas cutting often occurs in an overbalanced condition downhole. If a formation containing gas is drilled, the gas within drilled cuttings can expand as it moves up the annulus, leading to gas cutting at the surface. Detecting this is crucial, as a flowing well indicates a kick, necessitating immediate well shut-in and initiation of the proper kill procedure.

Oil or Saltwater Cutting

Invasions of oil or saltwater from drilled cuttings or swabbing can reduce the average mud column density, causing a drop in mud hydrostatic pressure. While the effect of these liquids on average density is less pronounced than gas, the impact on bottomhole pressure can be substantial. Liquids, being less compressible, result in uniform density reduction throughout the mud column.

Settling of Mud Weighting Materials

The settling of desirable solids or drilled cuttings in a mud can significantly reduce mud density, affecting hydrostatic pressure. Barite sag, more prevalent in highly deviated wells, requires a combination of sound mud design and operational practices for management.

Loss of Equivalent Circulating Density (ECD)

Shutting down pumps during drilling connection can lead to a reduction in dynamic bottomhole pressure, causing the loss of ECD. This loss can allow formation fluids to enter the wellbore, known as “connection gas.” Observation of connection gas is an indication that static mud overbalance is lost, necessitating a potential increase in mud weight.

Cementing Operations

Improper cement mixing, lost circulation, or casing float equipment failure can compromise cement density and reduce hydrostatic pressure, leading to well control issues.

Cement Slurry Transition

As cement transitions from a slurry to a solid state, there’s a temporary reduction in hydrostatic pressure due to self-supporting cement solids before the structure becomes impermeable. This can potentially lead to an influx.

Closely monitoring the well throughout all phases of drilling, completion, and cementing operations is imperative for preventing and mitigating well control events. Nurturing a proactive approach ensures the integrity and safety of the wellbore.

To prevent well control events caused by low drilling fluid density, it’s essential to:

• Maintain strict pit discipline and monitor fluid properties regularly.
• Use appropriate mud additives to prevent gas cutting and control fluid rheology.
• Monitor for oil or saltwater invasions and address them promptly.
• Implement proper mud design and operational practices to minimize barite sag.
• Maintain pumps running during pipe connections to avoid ECD loss.
• Exercise caution during cementing operations and closely monitor pressure changes.

References

Cormack, D. (2007). An introduction to well control calculations for drilling operations. 1st ed. Texas: Springer.
Crumpton, H. (2010). Well Control for Completions and Interventions. 1st ed. Texas: Gulf Publishing.
Grace, R. (2003). Blowout and well control handbook [recurso electrónico]. 1st ed. Paises Bajos: Gulf Professional Pub.

<p>The post Understanding Factors Leading to Low Density Drilling Fluid and Potential Well Control Events first appeared on Drilling Formulas and Drilling Calculations.</p>

An HCR valve, also recognized as a High Closing Ratio valve, is a specialized type of gate valve widely employed in well control systems, particularly within the blowout preventer (BOP) stack. Its purpose is to deliver a dependable and efficient method for managing wellbore pressure and averting uncontrolled fluid flow during drilling, completion, and production activities.

Distinguished by a remarkable closing ratio, which represents the ratio of fluid pressure upstream of the valve to the hydraulic pressure needed for closure, HCR valves excel in sealing against elevated wellbore pressures, even in the face of sudden pressure surges.

Typically featuring a double-acting design, HCR valves possess two hydraulic chambers that can be pressurized for both valve opening and closure. This dual-system redundancy ensures continued operability, even if one hydraulic system encounters a failure. Operating at a typical pressure of 1,500 psi, HCR valves are engineered with a rising stem design, offering enhanced control during operations. Unlike some valve designs, HCR valves do not incorporate back-seating allowance, emphasizing their commitment to reliable and secure fluid control.

Engineered to endure challenging wellbore conditions, such as high temperatures, corrosive fluids, and abrasive sand, HCR valves are crafted from robust materials like forged steel or stainless steel. Protective coatings are applied to resist corrosion, enhancing their durability.

As integral components of well control systems, HCR valves play a pivotal role in ensuring the safety of personnel and environmental protection during drilling and production operations. Their high closing ratio, redundant systems, and robust design collectively contribute to their reliability and effectiveness in managing wellbore pressure and preventing uncontrolled fluid flow.

References

Cormack, D. (2007). An introduction to well control calculations for drilling operations. 1st ed. Texas: Springer.
Crumpton, H. (2010). Well Control for Completions and Interventions. 1st ed. Texas: Gulf Publishing.
Grace, R. (2003). Blowout and well control handbook [recurso electrónico]. 1st ed. Paises Bajos: Gulf Professional Pub.

<p>The post What are HCR Valves? first appeared on Drilling Formulas and Drilling Calculations.</p>

A Back Pressure Valve (BPV), also known as a tubing plug, serves as a one-way check valve typically placed within a specially machined profile in the tubing hanger or plug bushing. Its primary function is to impede the flow of fluids and gases through the hanger while permitting the pumping of fluid into the tubing string. These valves find application in various well operations such as removing the production tree, facilitating the initial nipple up of the Blowout Preventer (BOP) stack, installing the tree during the nippling down of the BOP stack, and handling heavy lifts over the wellhead.

The installation or removal of BPVs can be carried out with either the tree or BOP stack nipple up on the tubing head. Moreover, they can be installed with or without pressure on the tubing. If the BPV needs to be installed through the tree with pressure on the well, a lubricator is necessary. Wellhead manufacturers offer diverse designs for Back Pressure Valves, which depend on the size and make of the hanger and wellhead. It’s crucial to note that only personnel specifically trained by wellhead manufacturers should undertake the installation and removal of these valves.

There are typically two types of BPVs: type “B” and type “H,” illustrated in the diagram below. Both types fulfill the same function. The choice between type “B” and “H” depends on the tubing hanger models. Some hangers may be equipped with type “B,” while others may require type “H.” Therefore, wellhead manufacturers can provide guidance on which types of tubing hangers are suitable for specific models.

References

Cormack, D. (2007). An introduction to well control calculations for drilling operations. 1st ed. Texas: Springer.
Crumpton, H. (2010). Well Control for Completions and Interventions. 1st ed. Texas: Gulf Publishing.
Grace, R. (2003). Blowout and well control handbook [recurso electrónico]. 1st ed. Paises Bajos: Gulf Professional Pub.

<p>The post What is a Back Pressure Valve (BPV)? first appeared on Drilling Formulas and Drilling Calculations.</p>