North America

As developed wells continue to produce, these completed assets undergo thermodynamic cycling consistent with the production life of the well. The constant loading on these wells induce stresses that are ultimately transmitted to the annular cement sheaths that were intended to provide isolation of formation fluids from the surface. If these cementitious barriers become compromised, integrity issues proliferate and transmit downhole pressures to the surface. These problems are exasperated if the primary cement job was compromised during initial placement due to such complications as losses. Channels and micro-annular leak paths are responsible for these phenomena of observed pressure at the surface.

To remediate these integrity challenges, the unconventional application of resins has proven to be a cost-effective solution for the restoration of isolation. With over 141 successful interventions to date, Wellcem has developed a series of standard operating procedures that help ensure successful remediation of these challenges. Implementation of five critical measures during job execution can assist in the satisfactory sealing of these communicatory pathways.

Read more: Effective alternatives to cement in oil and gas wells

1. 1. Ensure proper functionality of wellhead gate valves
      Pre-job pressure testing should always incorporate verification of all wellhead valves across which annular treatment will ensue. A leaking gate valve can introduce a myriad of problems during initial injection as well as unwanted displacement by annular fluids during the setting of the annular plug.
   2. Injectivity analysis and annular pressure diagnostics should be performed separately and ahead of the scheduled Thermaset® treatment
      Before treatment, a mandatory injection test is performed to verify the communicatory pathway across which Thermaset® can be injected. Water is often the fluid of choice during this analysis, as its Newtonian profile closely models the rheology and fluid dynamics of Thermaset®. It is during these tests that injected water can occupy the void spaces of the compromised cement sheath and fill porosity – potentially preventing their future displacement. This can ultimately heightened circulating pressures required to displace water from these voids with resin. Should such pressures exceed the collapse and burst pressures of downhole tubulars, or the maximum operating pressure of surface equipment, insufficient injection of resin will occur. Therefor, such diagnostics should therefore not be performed in tandem with the remedial operation and executed before treatment to allow evacuation of these voids.
      Read more: Resin curing process
      
   3. During annular diagnostics, every annulus should be monitored for any potential pressure response at the surface
      Well Integrity issues are often non-singular and can manifest themselves as multiple downhole challenges. In some instances, an observed surface pressure is a result of communication from one annulus to another via a shallow casing leak. These leaks often result from galvanic corrosion or oxidation of tubulars. Identifying a shallow communicatory leak from one annulus to the other facilitates complete and successful remediation of the sustained annular pressure on the affected asset. If a shallow leak is initially identified, it should be secured before isolating the source of produced fluids. Sealing the casing leak helps to prevent unwanted displacement of large and wasted volumes of resin into the tubular leak path in an attempt to seal the source. With proper volumetric displacement, the casing leak is solved first, and then the channel or micro-annuli responsible for pressure transmission can be properly sealed.
      
      
   4. Always remediate sustained casing pressure from inner annuli outwards.
      When sustained casing pressure is verified in multiple annuli and are not interconnected, they should be treated from the inner annulus outwards. In other words, if there exists sustained annular pressure on annuli A, B, and C, treatment should first start with annulus A, before progressing to annulus B, and finally conclude with the remediation of the C annulus. This procedure should be employed if tubular integrity is verified and no communication across each annulus has been confirmed. The justification for this methodology is substantiated through the treatment pressures applied to each annulus. As remediation progresses concentrically outwards, the applied treatment pressures and pressure ratings of each casing decreases. Therefore, the pressure that can be applied to the A-annulus will be higher than treatment pressures on the B and C annulus. Once A annular integrity has been restored, the B-annulus will be treated at a lower pressure that will have less influence on the A annulus that was cured first. The lower pressure applied to the B annulus will be less than the pressure that was applied to the A annulus and therefore have less of a chance of disturbing the remediated A. Where execution to progress from outer annuli inwards, the elevated treatment pressures of inner annuli can potentially lead to ballooning of tubulars that can disturb the outer annuli that were treated at lower pressure.
      
      
   5. Pneumatic driven liquid pumps are preferred over high pressure triplex pumps
      Annular leak paths are often geometrically tortuous with limited permeability and minimal volumetric porosity. Thus, the volume required to fill such voids is significantly small. Triplex pumps of assorted plunger diameters result in large displacement volumes at varied rates. These large displacement volumes coupled with high operational pressure capabilities are not preferred, as they can often further compromise the integrity of the damaged annular sheath. Alternatively, small displacement pumps, such as Haskel pumps, are ideal for such applications due to their small displacement volumes and relatively high operating pressures. These pumps efficiently convert compressed air into hydraulic power and are capable of holding a set pressure for a sustained period as is required in these remedial applications.
      As completion of assets with cement continues to be the primary mode of isolation and as wells continue to undergo cyclic stresses attributed to production, annular integrity challenges will continue to manifest themselves. Implementation of such guidelines can help ensure successful remediation of sustained casing pressure /annular pressure on these affected assets through the introduction of this unconventional, rig-less, and cost-effective strategy.

This article was published by Sean Francis and Mohamed Aly Tawfik of Wellcem

Sean has worked as a field engineer in the US and Gulf of Mexico as well as the Dutch, Danish, and Norwegian sectors of the North Sea, and across the middle east in the U.A.E., Oman, and Saudi Arabia. He currently serves as Project Manager of the Middle East for Wellcem. Mohamed Aly Tawfik has been with Wellcem since 2012 working in Saudi Arabia with lost circulation plugs, squeezes and casing to casing leaks. He is now Operations Coordinator at Wellcem.

This article was sourced from Wellcem: https://blog.wellcem.com/5-keys-to-the-successful-remediation-of-sustained-annular-pressure

For more information from Wellcem you can see their blog here: https://blog.wellcem.com

In pursuit of a safer and more cost-effective best practice approach to liquid-based rigless/riserless interventions, the oil and gas industry is engaged in a growing movement to identify new techniques and technologies that can help it to maximize revenues from existing brownfields and new assets by enhancing their output.

For this particular project, EV engineered a simple gas detection indicator, mounted in front of the Optis HD E-line downview camera, to reveal the presence of low-rate gas entry in a gas-filled environment. Under these conditions, conventional technologies fail to detect small gas entries making it impossible for operators to understand and optimise the performance of their wells.

This document can act as starting point for people who want to learn more about composite pipes in offshore applications, and is intended for engineers, Technical Authorities and managers active in the SURF, Subsea Intervention, Drilling and other related fields of activity.

Introduction

The optimum design for offshore wells is one that requires minimal intervention work from the beginning of production to P&A operations. The only intervention that is generally acceptable is wireline work. Operators would prefer to avoid interventions, but even the best thought-out plans and designs may not perform as expected over the life of a well. Furthermore, there is a large inventory of producing wells that will require some form of intervention. With technological advances, many interventions can be done without the need of an expensive offshore rig by using coiled tubing and wireline. Using these deployment methods, operators can run many mechanical tools to correct problems and bring a well back on production. In some instances, however, a mechanical option may not be possible due to restrictions in a wellbore. In that case, inflatable tools can be used to help implement the needed solutions. Some examples of situations benefiting from inflatable tools are:

• Plug-Back Operations
• Squeeze Cementing
• Repair of Leaks
• Setting of Temporary Barriers
• Well Integrity Testing

This article will highlight the typical inflatable products and their uses. Case histories will also be included.

This Video of the Month is from a well in the Gulf of Mexico. An Optis Slickline HD memory camera was run to diagnose the final condition of the well after an acid job. The well is shut-in and clear fluid is present throughout.

As the camera advances through the first section, a sliding sleeve on the high side of the well can be accurately identified as the point of sand entry. Diagnosing sand entry is a challenge for traditional sensors, but as this example shows, an easy feat for EV’s full colour video camera.

In the second section of the video, thanks to the clarity of the fluid, one of EV’s wellbore mysteries makes an appearance. It is possible that the acid, sand and other fluids previously in the well, have reacted to form this gelatinous downhole spectacle.

In the final part of the video the deviation has increased to sixty degrees. Perforations can be seen on the low side of the well along with small piles of sand. As the camera progresses further into the well, the centralisers disturb the sand and a sandstorm is created in front of the camera.

The initial treatment ended with disconnecting from the inflatable bridge plug and associated BHA. The operator attempted to fish the entire BHA 6 times over the next 7 years, even bringing up highly experienced personnel from different parts of the US.

The initial procedure called for pulling the isolation and diverter sleeves to allow for the largest bore size. This is due to the OD of the stuck BHA being larger than the ID of the diverter sleeve. The problem this posed is being able to properly locate and drop into the appropriate lateral, and mores locating the BHA. The HydraShock was first utilized to free the isolation sleeve for the “B” lateral, as the first company utilized to remove it jarred 70 times to no avail. It took 4 ∆nBalls and a single jar hit to remove the isolation sleeve. A 3.0 GS Spear with an extended reach was utilized to fish the BHA, due to the design of the disconnect. Next the “B” lateral was accessed and the fish engaged.

On the second “Red” ∆nBall, 16,000lbs was gained back, and the CT moved down 1.3ft. The first “Yellow” ∆nBall seated, but the upper range for the maximum allowable service pressure for the coiled tubing was reached before it extruded. Due to the multiple laterals, 3 different types of treatment fluids (Slick Diesel, Seawater, lift gas), it was theorized that the extrusion pressures might have a variance, especially with different annular fluid movements. Once engaged, the GS spear cannot be disengaged without circulating, which posed a problem with a ∆nBall on seat. So by pressuring up on the HydraShock, the Hailey jars were cocked, and a 10-15 minute slow bleed utilized to bleed the pressure from the BHA barely keeping the DFCVs open.

This method of floating the DFCVs to alleviate BHA pressure allowed us to utilize the jars in an extended lateral where jars were not able to be cocked in previous runs. On the 9th jar hit and HydraShock pressure cycle the BHA freed and returned to surface. The pressure between the checks and the seated HydraShock ∆nBall was 1,268psi when tested upon returning to the facility in Deadhorse.

This unique set of circumstances displayed both the versatility of the HydraShock as a solution to stuck “anything” as well as the experience of the personnel on location to pivot within the safety constraints to solve problems.