EV’s video of the month comes from an operator in the middle east who had challenges that required an EV solution for two separate wells. Without the experience and technical capability of the EV equipment the operator would not have been able to find a solution and have continued issues with each well.
TGT has recently taken its electromagnetic EmPulse® well inspection system to new, more complex and challenging levels with recent successful surveys on wells with very high-chromium tubulars. EmPulse’s capabilities are likely to be particularly applicable for Middle East operators, and also some fields in the Gulf of Mexico, the North Sea and offshore Brazil.
As downhole well conditions become more corrosive, alternative steels and corrosion resistant materials are being considered in the completion process – particularly chrome, nickel and molybdenum. Increasing chromium content helps protect well completions from highly corrosive fluids, such as carbon dioxide, hydrogen sulphide and chloride.
The increase in chrome and the resulting decrease in ferrous content, however, cause electromagnetic [EM] signals to decay too quickly for ordinary EM inspection systems.
Designed and manufactured completely in-house by TGT scientists and engineers, the EmPulse system combines ultra-fast sensor technology with ‘time-domain’ measurement techniques to capture EM signals rapidly and accurately in a wide range of pipe materials, including those with high-chrome content. This enables operators to evaluate pipe thickness and metal loss in multiple casing strings simultaneously, ensuring long-term well performance even in the most challenging production environments.
In three Middle East deployments – one an operator witnessed ‘yard test’ and the others in two live wells – TGT engineers demonstrated that the EmPulse system can quantitatively determine the individual tubular thickness for up to four concentric barriers, even when there are high amounts of chrome in the tubulars.
The Middle East operator-witnessed ‘yard test’ consisted of a 28% chrome pipe with built-in mechanical defects where EmPulse’s high-speed EM sensor technology correctly identified the man-made problems in a controlled environment.
The second operation took place in two live Middle East wells in a very high hydrogen sulphide gas production scenario with 28% chrome tubulars. In this case, the EmPulse system again functioned as planned, and recorded the status of three concentric well barriers. Additionally, a multi-finger caliper recording confirmed the electromagnetic results for condition of the inner pipe.
This ability to take measurements when facing specialised materials in certain well tubulars marks a significant breakthrough for TGT and the industry as a whole. The tests demonstrate how the EmPulse system can deliver accurate corrosion information, address a crucial information gap, and help protect well integrity in challenging production environments.
This article is a direct result of inspiring presentations on a novel technology from the 2nd Annual Well Intervention Workshop for the Middle East in Abu Dhabi. What I picked up there, made me replace my scheduled article and write about the PWC® (Perforate, Wash, Cement) technology.
We have published two pieces of what was supposed to be a series of three posts on Plug & Abandonment. The first article focused on legislation and standards of design for P&As, and the second one discussed materials that meet the requirements to be used for P&As.
The third article was supposed to focus on deployment methods. In the meantime, I attended the forementioned Well Intervention Workshop; the presentations that I witnessed changed the original plan.
The event gathered specialists in well integrity from different oil and gas operators from the Middle East such as ADNOC, Aramco, Dragon Oil, Agiba, ADMA, and ONGC. These operators handle complicated wells from which they presented case studies. There were workshops on P&A, annulus pressure management and coiled tubing interventions. The latest technologies, like downhole video analytics, casing patches and well integrity in multi-lateral wells and extended reach wells, also had their fair share of attention.
From one of these sessions, I ran across a technology that is being extensively used by one of the operators in the UAE. The subject was so interesting that I decided to change the plans for the third P&A article and cover this technology instead.
Initially, the post was to evolve around cementing thru Coiled tubing (and maybe a little about dump bailors) as a deployment technique for P&As, since most of the conventional techniques are already covered in other articles on the blog. Besides, you can download the guideline for cement plugs, which address most, if not all, aspects of the conventional placement methods.
What we will do then is to go ahead with this article on the new technology and then leave for a fourth article to discuss coiled tubing cementing.
The article you are reading is co-written with Mr. Dave Ringrose, VP for the Middle East in Hydrawell intervention, the company behind the PWC® (Perforate, Wash, Cement) technology.
You may remember the discussion on the legislation and basis of design for P&As and how we discussed that the barriers should be set in front of a suitable caprock (impermeable, laterally continuous and with adequate strength and thickness) and overlap with annular cement. See figure 1 for more details.
For cased hole sections, casing alone is not considered a barrier to the lateral flow, due to the potential for casing leaks, but cemented casing could be sufficient “as long as there is sufficient confidence in the quantity and quality of the cement in the annulus.” What this means is: If a log is available, 100 ft of good cement will do. If no logs are available, then 1,000 ft of cement, using the theoretical top of cement as calculated by “differential pressures or monitored volumes during the original cement job,” would be required to allow for uncertainty.
When cement behind the casing is not good, the operators were forced to perforate-squeeze and, in some cases, mill out the casing completely to achieve proper zonal isolation across the wellbore. Here is where PWC® becomes a very interesting alternative.
PWC® is a single run assembly with these main parts:
According to Hydrawell records, PWC® has been used to set 215 annulus cement plugs in different areas round the world exceeding 97% success rate as measured by 15 different operators.
Click on picture for larger version
Figure 1. Source: Guidelines for the Abandonment of Wells, p12 (OGUK, 2015)
From the presentations delivered at OWI and the conversations held with Mr. Ringrose, I could summarize two keys aspects of the PWC® technology:
PWC® is not only valuable for wells requiring P&A interventions aiming at fulfilling the annulus barrier requirements in the UKOG guidelines; PWC® can also be useful in wells that are shut-in due to unbleedable annulus pressure in annulus B or C. The technique can provide a reliable method of placing annular barrier(s) -closer to the leak source- and returning these wells to production or injection.
Along the same line of thought, this deployment method can be utilized to repair “wet casing shoes” and achieve the required isolation – before drilling into the next zone after a poorly executed primary cement job. Or to allow the setting of a side-track whipstock across an uncemented (or poorly cemented) area, setting a casing exit support plug in the annulus.
Needless to say, the capabilities of the tool left me and other delegates at the OWI convention astonished. A topic of discussion that came up during one of the presentations was the use of conventional cement versus micro-cement together with the PWC® tool. But then it wasn’t long before the conversation revolved around the combination of PWC® and resins as a mechanism of achieving deeper penetration and enhanced isolation behind the annulus.
Hydrawell partnered up in joint R&D studies with Wellcem to evaluate the use of resins through their PWC® tool to further enhance penetration into the annulus behind the casing. The solid- free resin offered by Wellcem can penetrate narrow cracks and channels where not even micro-cement can penetrate. The combination of the PWC® tool with resins is expected to enable operators to properly place isolation barriers even under the more challenging placement conditions.
Figure 2. Test assembly for pumping the resin thru 1.7 mm nozzles.
In one of these studies, the objective was to verify the possibility of pumping high-density ThermaSet® (Wellcem polyester resin) through the ¼ inch nozzles in the HydraWash® tool under a certain allowable pressure at high pumping rates (several Bbl/min), see figure 2. To execute the test in a workshop environment, calculations were carried out to downscale the test parameters. A reduced size prototype nozzle with 1.7 mm opening and 5 litter/min flow rate (based on estimates) was considered the optimum settings for observing the pump pressure during the test.
Test results and observations confirmed that 2.3 SG (19.2 PPG) resin can be pumped through the 1.7mm nozzle at 5.0 litter/min with ~310 psi pressure differential -1,400 psi applied pressure- (Pressure losses in the nozzle with water were 280 psi in comparison).
Quality check of the samples taken before and after pumping showed similar results – leading to the conclusion that the nozzle size has no visible effect on the properties of the resin plug.
All in all, it seems like we should be up for some more exciting case histories from the combination of these two new technologies used in an environment that would have been too hard for conventional methods to succeed.
We’ll leave it here – stay tuned for our next piece on Coiled Tubing Cementing, which will complete this series on P&A operations.
Gracias!
Click on this link to see an animation of the PWC® single run assembly
Miguel Diaz is Wellcem’s Business Development Manager for the Middle East and North Africa region. He 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. Dave Ringrose has 40 years varied experience in drilling management, drilling engineering, drilling operations and project and operational support work. He is highly experienced in all aspects of drilling and workover management and currently responsible for all HydraWell operations and business development in the Middle East
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:
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:
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
![[Free eBook] Guidelines for setting Cement Plugs](https://cdn2.hubspot.net/hubfs/2922560/hub_generated/resized/6564f313-ade6-4ad5-ba0d-1ab08f43e101.png)
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.
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.
This Video of the Month is from a well in the Middle East. The operator utilized EV’s Optis™ HD Memory camera to inspect the flow tube and flapper valve condition of a surface-controlled safety valve. Earlier intervention work had resulted in the need to fish tools at the valve but now the functionality of the valve was in question. There was communication across the valve but there was no access through it.
First, the operator decided to run a Lead Impression Block, which returned to surface with a half-moon shape impression. After seeing the impression, the Operator was not satisfied the results were conclusive and wanted a visual answer to identify what the obstruction was down hole.
EV were called in as an urgent service to give a clear answer. EV’s Optis™ HD colour memory camera capable of capturing 30 frames per second for up to 4 hours was deployed on Slickline to investigate. Once the camera program had completed, tools were pulled out of hole, footage was quickly downloaded and all soon became apparent.
The video shows the tubing had parted just below the DHSV. The camera exits the upper section of parted tubing and continues to run in. 4m below, the lower section of the parting can be seen, answering the half-moon shape on the LIB. With the assistance of the collapsible bowspring centralizers, the 1 11/16” OD toolstring was able to re-enter the lower section of tubing and continued to run in a further few meters.
While Pulling out of hole the camera exits the lower section of parting and re-enters the upper section of tubing capturing the DHSV components found to be in good condition.
The quick reaction from call-out to wellsite for EV to run EV their Optis™ Memory Camera allowed a definitive answer to the problem downhole in a matter of hours, saving the operator vital time & cost from making further unnecessary runs in hole, instead allowing them to plan ahead for the problem at hand.
This Video of the Month is from a well in the Middle East. The operator utilized EV’s Optis™ HD Memory camera to inspect the flow tube and flapper valve condition of a surface-controlled safety valve. Earlier intervention work had resulted in the need to fish tools at the valve but now the functionality of the valve was in question. There was communication across the valve but not access through it.
EV’s HD memory camera was deployed on slickline and here we find the actuated flow tube shifting up and down properly while the camera is stationary. The operator prepped the well by pumping clear water and shutting the well in to allow a gas phase to build at this shallow depth from the surface. On the same camera run but one meter deeper is the flapper valve which should open as the flow tube is cycled. However, the flapper is jammed in a partly open position allowing fluid to pass by but not equipment.
The operator decided to mill through the flapper with a hydraulic workover unit and requested EV’s HD memory camera to check milling progress if there were issues. The flapper valve was successful milled through but a subsequent gauge run stacked out 32m below the valve. The camera was deployed to inspect the milled area of the safety valve and the cause of the deeper obstruction. The video shows a very clean milling job in the flapper area with no potential hazards to hang up tools. 32m deeper we find part of the milled flapper has fallen and is now stuck across the well bore. The operator elected to install a temporary safety valve and return the well to production and will attempt to recover the fish at a later date.
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By Mark Plummer MSc BEng
Stuart Wright Pte Ltd’s (SW) CEO, Colin Stuart, and Well Engineer, Mark Plummer recently completed a one-year project supporting the Department of Natural Resources Mines & Energy (DNRME) in Queensland, Brisbane to perform a Well Programme Assurance Design and Construction Review (WEPA DCR) for high risk and complex wells.
The objectives of the WEPA DCR were to understand, by observation, how operators are meeting the relevant statutory provisions in the legislation; including subsidiary mandatory safety requirements, the Queensland Code of Practice and recognised industry standards. Consistent with the Queensland government policy, the Inspectorate is collaborating with the industry to promote the safety and technical standards for petroleum and gas operations.
Following consultation and dialogue with industry, seven (7) Operators were selected as suitable candidates for the well programme assurance review. The programme was conducted in three stages as outlined in Figure 1 below.
Figure 1 – WEPA Design & Construction Review Process
WEPA Stage 1 – Understand with the petroleum operator, their well design protocols and standards, and agree specific well selection;
WEPA Stage 2 – Engage in well design and planning process of the selected well programmes; and finally; and
WEPA Stage 3 – Oversee well construction against the plan in the well execution stage. In particular to carry out well barrier monitoring and validation using SW’s proprietary Right Time Barrier Condition (RTBC) well barrier monitoring system.
Well Design Phase Review Methodology
Through discussion between the Regulator and each individual Operator, eight (8) suitable candidate wells were identified for the Well Programme Assurance review. Subsequently, a copy of Operator standards and well specific documents (e.g. Well Basis of Design, Drilling Programme, Drilling Fluids Programme, Cementing Programme, Casing and Tubing Design, Well Barrier Programme) were provided by the Operator for review by Well Inspectors.
The design phase review methodology was as follows:
Well Construction Phase Review Methodology
Stuart Wright’s proprietary well barrier monitoring and validation system, RTBC, was used by DNRME to monitor drilling operations for selected wells. This exercise was the final stage for a given selected well, in DNRME’s WEPA DCR programme.
The system was used to assess each well for compliance, with their own standards and mandatory regulatory requirements. Specific barrier acceptance criteria were created in RTBC, which were extracted from Operator standards, the drilling programme and relevant legislation. Each barrier element during well construction was then assessed for reported validation, and assigned a traffic light colour (red, amber, green) rating depending on the result of the rating.
RTBC creates a Daily Integrity Report (DIR) capturing the barrier validation result.
The process of assessing compliance during well construction was as follows:
Figure 2A – Example Daily Integrity Report (Pg.1) – sent to Operator on a Daily Basis
Figure 2B – Example Daily Integrity Report (Pg.2) – sent to Operator on a Daily Basis
Key Findings
A range of useful findings arose from the WEPA study and, in particular, the use of RTBC to track barrier validation during well construction provided close monitoring and feedback which was beneficial to both the Regulator and Operator:
KF #1 – In general, the Operator standards compliance with mandatory regulatory requirements was good, but with individual exceptions which were fed back to Operators and improvement processes agreed.
KF #2 – Maintaining an overbalance margin to the bottom hole pressure (BHP) is a critical barrier during well construction. Operator standards for petroleum wells reviewed by DNRME could be further enhanced by stipulating a minimum overbalance to BHP requirement.
KF #3 – Several Operators did not achieve regulatory compliance with the minimum 70% standoff for casing centralisation in their well design. The primary reason cited for this non-compliance was that the centralisation modeling simulation called for large sections of the casing having 2 centralisers per joint to achieve the required 70% standoff and Operators opined that the risks associated with running this many centralisers outweighs the benefit.
KF #4 – During the WEPA study, DNRME noted that the Operator’s design and planning process was often completed very late and, in many cases, only a few days prior to well spud which has an impact on risk during the well construction phase.
KF #5 – 75% of the gas-producing petroleum wells reviewed during the WEPA study were designed with standard Buttress Thread Connections (BTC) or Long Thread Connections (LTC) in the production casing string, which is common practice, deemed to be adequate as reservoir pressures were less than 3,000 psi. For gas-producing petroleum wells, the selection of premium (gas-tight) connections would help to mitigate, over time, the risk of a leak path for hydrocarbon gas into the B-Annulus with associated consequences, though DNRME accepted that current industry standards support the common practice and the risk assessment approach currently used is valid.
KF #6 – The use of a barrier monitoring system demonstrated that Operators could not, in a limited number of cases, show compliance in all respects with their own standards and regulatory requirements during well construction given the conventions and format of the standard DDR reporting process. The Inspectorate had to review documents and data other than the DDR to complete the barrier validation picture.
KF #7 – The integrity reporting system used (RTBC) did give regulator and operator insight into escalating compliance risks. Furthermore, it allowed the Inspectorate to demonstrate in the captured database, a record that the operator is in compliance with regulation OR where they are not, it is transparent, and a flag raised.
KF #8 – The Daily Drilling Reports (DDR) focus is typically around performance and Occupational Health and Safety (OHS). However, no clear picture emerges in a typical DDR of an equal focus on well integrity and specifically loss of control risk.
Preliminary Conclusions of the WEPA Study
The findings and preliminary conclusions of the WEPA study were presented, on behalf of DNRME, by Colin Stuart at the Oil & Gas UK “Safety 30 – Piper Alpha Legacy: Securing a Safer Future” conference which was held in Aberdeen in June, 2018. A summary of the preliminary conclusions of the WEPA study is detailed below:
This project summary has been approved by DNRME.
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