Middle East

Engineered Perforating Solution Saves Operator 13 Days Valued At $7.8 Million

CASE STUDY: OIL COMPANY CHALLENGE

Perforate the inner 9 5/8 in. casing of a well whose bottomhole temperature ranged between 300°F – 400°F using the largest possible diameter gun system to deliver 0.7 in. entry holes and less than 0.1 in. damage to the inner surface of the 13 3/8 in. outer casing.

OWEN SOLUTION

Develop, test, validate, build and deliver a unique gun system with the required performance characteristics.

SUCCESSFUL RESULTS

Acustom PAC™ casing puncher system was designed that exceeded the client’s requirements. On the first well, a 7.0 in. diameter 21-ft gun loaded 18 shots/ft with HMX explosives was fired successfully saving 13 days of on-site work compared with section milling. A successful cement plug was squeezed through the perforations to fully comply with abandonment regulations. Entry hole size averaged 0.75 in. and actual damage to the 13 3/8 in. casing was 0.01 in. to 0.015 in.

TIME SAVED = $7.8 million

Owen Oil Tools’ Energetics Technology Group undertook a special project for a major North Sea Service Company. Owen’s new PAC™, was designed, tested and produced to enable the operator to penetrate the inner string of two concentric casings as part of an abandonment program previously enabled by a time-consuming section milling technique.

Once the physical limits (9 5/8 in. casing ID) were considered, the engineering team addressed charge and gun system variables to achieve the requested performance. Maximum gun size imposed by the casing ID was 7.0 in. To ensure hydraulic isolation, the operator requested an 18 spf shot density to maximize communication of cement to the annulus. Explosive load, stand-off and shaped charge liner design along with casing properties were considered to determine entry hole size and depth of penetration. Centralization using a traditional bow-spring or solid fin stand-off ensured equal 360-deg performance around the casing.

Single prototype charges were tested using gun carrier sections and concentric casing targets under worst-case conditions to assess ballistic results. Tests confirmed the through hole size and damage to the outer string were within specifications.

Figure 1: Single charge test results (9 5/8 in. plate above, and 13 3/8 in. plate below)

A full system test confirmed that results could be achieved in a fluid-filled environment. Gun swell was checked to ensure the fired gun would not become stuck in the 9 5/8 in. casing. The last step was making a full production run of gun systems to satisfy the operator’s needs.

Owen Oil Tools
P.O. Box 568, 12001 County Road 1000
Godley, Texas 76044
P. 800.333.6936 – www.corelab.com/owen

A ghost from the past started hunting me when I went through my files. Ashamed of what I discovered I decided to tell everyone, especially young engineers, what not to do when setting a cement plug.

A few weeks back I was in the process of re-organizing my external hard drive. If you are like me, you have one of those external discs where you keep all your “work stuff.” My disc literally contains my entire professional life work.

Sometimes I am amazed by the stuff that pops-out when I search for something; exams from my early days as a drilling fluid engineer or as a cementer, CVs of candidates that I interviewed over a decade ago… you name it…

So, I decided to organize my hard drive with these objectives in mind:

• • To get rid of the stuff that does not help me anymore
  • To establish a structure that makes sense no matter where I work (or for whom!)
  • To find what I am looking for in the shortest time

One folder containing quite a few megabytes is labeled “Investigations.” There I keep lessons learned, technical and safety alerts and investigation reports from my former teams.

The folder sadly has documents from each and every single district I have worked.

A Safety instructor once told me, “company standards are written in blood.” Today I understand what he meant. Standards trail behind failures and accidents, and organizations and governments try to prevent their re-occurrence.

While organizing this folder, I realized that grouping the investigations by their topic instead of “by district” serves me far better in my current role as a well integrity “expert”.

Where the events took place is no longer relevant for me. The important thing is what those investigations addressed, so I can show young engineers how to deal with certain well situations, and how to prevent the occurrence of similar events.

Reading tip: Free water in Cement: Why is it critical?

When I focused on the investigations related to service delivery who had caused downtime or other types of “red money” (wasted money), the one ghost that chased me from everywhere I have worked was “The Failure of cement plugs”.

It is embarrassing how the reports reveal that the same mistakes are made over and over again in places as distant as Cabinda, Angola and Offshore Guyana, South America.

Free guide: The most common causes for leaks in oil wells and 8 questions to consider before you select solution.

To stop the feeling of shame, I will give you a quick summary of the more common causes of job failures when setting a cement plug:

1. 1. Length, insufficient cement slurry volume
      Operators that opt for saving money on slurry volume end up spending far more on rig time due to job repetitions. Plugs of less than 500 ft or less than 20 bbls of slurry are susceptible to fail.
   2. Slurry contamination due:
      1. 1. Inadequate base to set the plug
            Poor viscous pill design or no use of pills to support plugs placed off bottom. The density of the cement will force it to go downhole as shown in the picture below. Make sure you design a pill capable of supporting the slurry on top of it.
            
         2. Slurry contaminated during placement
            Fluids get intermixed when there are no physical barriers to separate them inside large drill pipes.
         3. Slurry jetting into the viscous pill
            The slurry, due to its weight, and assisted by gravity and the pump pressure, tend to jet into the viscous pill. Diversion in the annulus to force an upward flow is required to reduce the volume of slurry “lost” into the pill and on the bottom of the hole.
         4. Inadequate fluid displacement techniques
            Frictions in the wellbore caused by displacing fluids must exceed those of the fluids being displaced. That is why reviewing fluid properties is necessary. Hole geometry must be known to allow proper displacement. Sections of the hole with adequate size must be chosen to place the plug.
         5. Use of drill strings with large tool boxes that disturb the plug when the string is pulled out of the hole.
         6. Reversing too close to the top of the cement will cause contamination due to jetting of the displacement fluid into the cement matrix.
   3. Excessive slurry thickening time
      The longer the slurry remains fluid, the bigger the chances of the slurry getting contaminated.
   4. Poor quality control of slurry density before pumping
      Mostly due to the use of non-pressurized mud balances.
   5. No control of displacement volumes
      Due to the use of rig pumps or no use of cement truck displacement tanks.
   6. Inadequate waiting-on-cement times
      Anxious drillers that run and tag or attempt to drill out too soon.

The guidelines attached to this article (see also below) reveals more details on the reasons behind these failures and suggests how you ensure a successful cement job.

If you follow them, I am certain that your chances of getting it right the first time will increase significantly.

Best of Luck!

Posted by Miguel Diaz

Miguel has 20 years’ experience from operations, technical advisor, quality assurance, business development and management positions in the oil & gas industry from all areas of the high-pressure pumping services. He has worked in South America, the Caribbean Sea, central and eastern Europe, Sub-Sahara Africa and the middle east. Miguel serves as one of our cementing experts and is our Business Development Manager for the Middle East and North Africa region.

This article was sourced from Wellcem: https://blog.wellcem.com/cement-plugs-a-routine-or-a-nightmare

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

There are different definitions of Well Integrity. The most widely accepted definition is given by NORSOK D-010:

“Application of technical, operational and organizational solutions to reduce risk of uncontrolled release of formation fluids throughout the life cycle of a well”.

Another accepted definition is given by ISO TS 16530-2:

“Containment and the prevention of the escape of fluids (i.e. liquids or gases) to subterranean formations or surface’’.

Well Integrity is undoubtedly a multidisciplinary approach. Therefore, well integrity engineers need to interact constantly with different disciplines (e.g. well intervention and drilling) to assess the status of well barriers and well barrier envelopes at all times.

Introduction

The Middle East offshore market generally has shallow water depth operations in high salinity water environments. As fields in the Arabia Peninsula mature and production declines they need extensive recovery enhancement and workovers which place added stress on the asset. In conjunction with the age and salinity of the water these works can effect the structural integrity of aging wells. This forces further works to take place, including diagnostic runs and tubing remediation.

In the Middle East companies including Saudi Aramco, QP, Zadco and ADMA-OPCO have become experts in dealing with mature offshore wellstock, and below is a case study from the region highlighting the best practice that has been learnt.

Middle East Experience of Aging Well Stock Management

With a global slowing of drilling activities, we are often finding ourselves working over mature fields with old well stock to encourage greater recovery volumes and meet the demand for hydrocarbons. Mature assets have unpredictable behaviors, and this demands highly skilled teams and well thought out intervention activities to ensure the continued production of these assets. >Case One: The Well

In one example the Middle East operator observed live wells having fluid mobility into annulus space, resulting in the bleeding of hydrocarbons at the surface. The Annulus-B pressures were reaching 1000psi, and there was clear evidence of communication within casings. The hydro-testing of annulus space showed the wells were unable to withstand the test pressures, so ultrasonic testing, cement bond logging, and other logging techniques were used to quantify the integrity and accurately identify leak paths ahead of restoring the well integrity of failed Annulus-B wells. It was decided to repair the conductor pipe and perform casing patches externally and internally and cement consolidated rock formations, then cover with a tie back. As a remediation strategy, a cement barrier was placed in production casing above the reservoir using sleeves, patches, perforating two-zone techniques and milling to mention a few.

The utilization of section milling as a remediation measure is interesting. Its effectiveness was later verified with cement bond logging to ensure that integrity was assured. The operational challenge faced from leveraging milling technology was a failure to pass the bottom of section mill cut. This was then solved by using a taper mill to drill the required section.

The root cause of the integrity issues were understood to be generic aging (the wells were approximately thirty-years old), poor cement jobs and the possibility of ineffective drilling practices used at the initial stages of the well’s life. The core objective was to restore to well integrity of production and injection wells and rule out well abandonment as an option. This was achieved and the programme was a success – resulting in the extension of the mature asset’s life.

Case Two: The Conductor

In this case the operator discusses two fields in the Arabian Peninsula, one consisting of 99 wellhead towers, and the other having 116 wellheads towers – cumulatively the integrity department is having to manage 217 wellhead towers. The technical challenge faced by the operator is that over 60% of these wellheads towers are in life extension phase.

If offshore conductors corrode to the point their structural integrity fails, they are bound to buckle leading X-mas tree and other related critical equipment to fail.

The wellhead towers are typically 3-legged and 4-legged (with 9 slots) having above water guide support and near seabed conductor support. One of the main issues the operator is facing is having 9 slots conductor’s exposure to the huge amount of wave load which may transfer through conductor guides followed by jackets to piles. It is important to highlight conductor guides support for the wellhead towers is necessary, otherwise, the conductor will be free standing and may subject to vortex induced vibrations which could fail under free vibration or due to fatigue.

When designing conductor supports it is essential that the weight from X-mass tree, BOP, lateral support, vortex induced vibration, corrosion protection and marine growth should be considered among other requirements with respecting code and standards established by NORSOK, API, and ISO.

In the region operators have typical well conductor loading depth varying from 100ft to 300ft, having two types of loadings axial compression and global bending. The operational integrity is assured by conducting scheduled screen inspection (visual inspection) followed by detailed inspection using Saturated Low-Frequency Eddy Current (SLOFEC) and Pulsed Eddy Current (PEC) quantifying the minimum wall thickness, external and internal detections, separate mapping and other techniques.

By executing these inspections and then coupling them quickly with remedial works, abnormalities in the aging conductor were identified and rectified within the scheduled inspection window. In one example it was discovered there was at least a minimum wall thickness and therefore efficient strength to assure the stability of the asset against atmospheric, splash and full submerged segments of the conductor – and therefore its ability to cope with the stress of a work over for production enhancement applications was established.

The results of applying this conductor programme across the two fields showed that a robust remedial strategy, as emphasized by this operator, reduced rig intervention for replacement and fewer rig repair strategies such as reinforced cement, bolted clamps and welded sleeves just to mention a few.

Conclusion

Well integrity is becoming increasingly important in maturing fields in the Middle East. The asset integrity lifecycle is ever evolving, and lessons learned must be added to our codes of practice and become ‘the norm’ for future projects. This will ensure that collectively we are able to continue the efficient production from our existing assets for the benefit of future generations.

The insights captured in this document are indicative of a culture where we need a continuous improvement across training our personnel to increase competency, safety and cost-effectiveness of operations and use innovative approaches in low price environment.

From these examples, a scheduled approach to preventative maintenance workovers are shown to be more cost-effective overtime rather than dealing with sever and critical integrity works which are bound to follow.