North America

The discussions subjects covered in these postings are covered in my well integrity training courses. Go to www.internationalwellintegrity.com for more details. In this article I would like to comment on the issue of sand production and its measurement. This is a high-level view of the problem, representing the tip of the iceberg.

The technology of spectral noise logging is very powerful when in the right hands and can really provide a much direction in problem solving downhole issues. As a tool that listens for sound and does not transmit sound provides a more direct answer of downhole issues, simply relying on a pressure change OR sound of moving particles such as sand. BUT coming back to the issue of calibration, this critical element must be available, repeatable and transparent.

Your service provider should provide comprehensive details of calibrations and especially with dates, times and environmental conditions. Crucially, when calibrating the environment must be insulated from background noise, so having trucks thundering past, that vibrate and shake the work surfaces or having to tip toe past the calibration cell for fear of extraneous interference is not acceptable. But is something I have witnessed recently in one service provider facility, and questions the validity of the calibration and associated logging results.

Reviewing the service provider to ensure and validate their calibration process is key to success. Additionally, auditing of tool servicing and maintenance is crucial, especially as we are coming out of a downturn and cut backs have been severe.

Sand in the flow stream if not fully understood and correctly measured can be catastrophic. Therefore, knowledge of the sand source, the rate it is producing at and where in the well system it reaches when on production, provides a greater understanding of the problem complexity and how it might be mitigated.

A small checklist will help in the diagnostic process -:

1.      Sand detection at the surface tells you straight away that you have a problem, but what is the rate of this sand production? How many pounds of sand per million standard cubic feet or thousand barrels?

2.      Is the sand production rate dependant? If so, what is maximum rate the well can be produced at without sand at the surface?

3.      Is there evidence in the surface equipment of sand? If so, try to sample and analyse and with a geologist determine where in the well is this coming from.

4.      Measure wall thickness of elbows and compare to original construction dimensions to help measure the surface rate of metal loss

5.      If an intervention is planned choose the logging company carefully, and only accept logging companies who can provide you with a numerical answer to the sand production rate. Just ticking a box to confirm its in the flow stream will not provide you with a full answer. You need to know the sand rate production versus well production rate.

6.      Using slickline tools try to determine if the sump depth of the well has changed as this will suggest that the sand is dropping down the well and not all being produced to the surface.

7.      Once the sand is better understood, you are then in a position to review, risk assess and determine a course of action that provides a working environment with an action plan if problems occur.

By Simon Sparke – International Well Integrity

‘If you don’t monitor it you can’t measure it’, while this is probably fully understood, what is missing is ‘ensuring your measurement equipment is properly calibrated’, as a measurement is meaningless if the equipment response cannot be relied upon. As well integrity engineers, we need ONE source of truth and this must be reliable, repeatable and transparent.

Technology advances but are we missing something? In this digital age there seems to be less overall adherence to this critical task of calibration of downhole tools, even to the point where I have been told it was not necessary as the tool is self-calibrating which has the same amusement levels being told that gas wells have a bubble point.

Calibration is the act of comparing a device under test of an unknown value with a reference standard of a known value and in so doing, provides us with the means to determine the error or verify the accuracy of the device under test.

As well integrity engineers, one of our concerns is the status of the well tubulars through the field life, so that we need to understand the sources or causes of sustained annulus pressure and the location(s) of metal loss over and above that of allowable metal loss during manufacture. The change in wall thickness will help determine the MAASP or MAWOP and how this impacts the well operating status.

I use the phrase ‘metal loss’ as this is important. Pipe wall thickness variations occur for several reasons; manufacturing tolerance, wear caused by interventions, erosion, and corrosion. These various attributes need to be understood by any analyst including the logging company and form part of a rational discussion about well status and the causes for change.

A range of tools are available to help determine remaining wall thickness in our well tubulars. These include -:

·      The multi fingered caliper measures the internal status of a single tubular; recording metal loss due to corrosion but also recording wall thickness gains such as scale(s), paraffins and asphaltenes.

·      Electro magnetics, can make measurements of multiple tubular strings in a single logging pass and these tools are NOT influenced by scale, paraffin or asphaltenes

·      Sonic based tools can measure wall thickness and surface tubular status but can only record a single string and require a liquid filled environment

·      Cameras now provide a comprehensive ‘view’ of the tubular and the associated completion jewellery but can only measure a single tubular string.

How do we move forward and who or what do we believe? As well integrity requires rigorous charted, signed and witnessed pressure tests on much of our pressure control equipment, then surely it is correct for logging tools etc to be subject to a similar test(s) in order to qualify their effective readings, especially as the results could have an impact on well integrity and the safety of our colleagues. The data required should include; pipe size(s), weight, wall thickness and metal grade. It should be signed and dated. Review this calibration before logging starts and ensure it passes the ‘sniff test’. Therefore, if the service provider cannot or will not support their reports with repeatable calibration data, we must question their standards.

What must be used are the allowable wall thickness variations in the tubular manufacturing process. Two key documents are available; API-5CT for regular tubing and casing (OCTG) provides for a variation in wall thickness of -12.5%

API-5CRA for corrosion resistant alloy tubulars provides for a variation in wall thickness of -10.0% OR -12.5% which is driven by the heat treatment process.

To piece all this together and provide a meaningful result, several elements are needed. These include; logging results, API wall thickness tolerance, completion design + the well production characteristics + well history and a degree of common sense. However, and most crucially, calibration data is very important.

The pictures below show tools to measure metal loss in multiple tubing/casing strings. Operators use this data to determine well status, re-calculate MAASP and if/when a workover might be required to replace strings.

Setting a good industry example. My belief is that we should have similarly high expectations of service providers and they should demonstrate tool calibration as shown in the picture below. This company, Ginnovo, sends tools to the wellsite complete with a calibration cell. This provides the opportunity to confirm the accuracy of the collected data, while still in the field. It withstands scrutiny and demonstrates the appropriate level of professionalism that we as responsible companies should demand. If they can’t deliver, then my recommendation is to seek alternative providers and in this field there are several. 

See the successful deployment of the TRIDENT® System, which performed two cuts and recovered casing to surface in a single trip.

Understand what the new regulatory updates mean for those involved in Gulf of Mexico well intervention and hear BSEE’s comments relating to both riserless well intervention systems and BSEE’s final rule.

Offshore Network have created a forecast of the well intervention service demand in the Eagle Ford and Permian basins. The whitepaper highlights the likely path of the oil price throughout 2018 and the correlating well services which will be in demand.

A deepwater Gulf of Mexico operator began Gas Lift Valve Change Out operations with the intent to optimize production in a producing well. The operation encountered access issues while attempting to run through the downhole safety valve.

With the memory camera deployed on slickline and positioned one foot above the flapper valve, the operator attempts to cycle open the safety valve from the surface while the camera captures the action. The stunning clarity of the well bore conditions have been achieved by simply shutting the well in and injecting gas to displacing the oil column below the flapper of the subsurface safety valve.

With no indication at the surface there are any safety valve problems but downhole tools stacking out in the valve, the operator was kept guessing on how best to address the problem. This Video of the Month case story illustrates how being proactive and deploying EV’s MemoryHD downhole camera results in knowing the next best step to contend with the issue. The camera records the action of the flow tube movement as hydraulic pressure is applied, pushing it downward until it finally makes contact with the flapper.

Once the contact is made, the flapper is seen becoming slightly misaligned, possibly due to a broken or bent hinge assembly, and it cannot open to allow wellbore access. In response, the Customer chose to rectify the problem by running an explosive knockout tool designed to shatter the flapper into pieces small enough to fall downhole and thereby remove the obstruction.

The customer decided to verify the complete removal of the flapper in a post inspection camera run. In the next run, we can clearly see that the explosive projectile was fired successfully, however, it did not completely shatter the flapper as hoped, but instead, shot a hole through the middle section, leaving remnants around the outside edges that could cause problems with subsequent runs

EV’s Video data enabled the decision to be made quickly to continue to produce the well, and return in the future with coiled tubing, to mill out the remaining flapper remnants. Additionally, EV’s Integrated Video Caliper tool can be ran after the mill-out is completed to inspect the condition of the downhole safety valve and its profile to assess any damage possibly caused by the milling operation.

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.