In this second part of my article series on SCP, I will discuss how to define whether you have an SCP scenario that needs intervention or not. In the first article in this series, I talked about a framework from which we can deal with the problems related to SCP. I also gave an overview of which guidelines from different industry bodies that address this topic.
Following the advice given by these guidelines and listening to what operators in the Middle East are telling us, I suggest you look into four aspects of your well annulus behaviour to define whether you have an SCP scenario that needs intervention or not:
Leak nature
Leak rate
Annulus pressure
In a less conventional manner; hydrocarbon gas mass.
LEAK NATURE
There may be a risk of introduction of toxic material such as H2S or radioactive agents into the annuli through the SCP. Such materials imply a considerable risk to personnel safety, and their presence, no matter the other parameters, indicate that the leak needs to be remediated.
LEAK RATE
Excessive leak rates increase the consequences if containment is lost. The magnitude of the leak will dictate the operator’s ability to normalize the situation since it defines the amount of energy released, its impact on the affected area, and in general, the leak escalation potential. So while a significant leak needs immediate attention, there is a value at which it doesn’t.
API RP 14B states acceptance criteria for leakage rate through a closed subsurface safety valve system, and although the norm is not directly applicable for SCP, its reasoning may still be regarded as an appropriate analogy for determining acceptance criteria for SCP. OGN117 use it as its acceptance criteria for annulus leaks.
The acceptance criteria for leak rate, when hydrocarbons are present in the source of influx, are:
15 scf/min (0.42m3/min) for gas
0.4 liter/min for liquid
ANNULUS PRESSURE
What sounds like a reasonable and empiric statement anywhere you hear it is that the pressure in the annulus should never reach the maximum allowable annulus surface pressure at the wellhead (MAASP). However, in this regard, OGN 117 only advise operators to take into consideration all aspects that detrimentally affect the normal rating of the wellbore hardware when setting the MAASP.
Instead, API-90 (Offshore wells) goes into detail on how to establish an acceptable level of risk for annular casing pressure, using two parameters.
First, sustained annular casing pressure that is greater than 100 psig must bleed to zero psig. If it does, it indicates that the leak rate is small and the barriers to flow are still effective. Second, a procedure is offered to calculate a Maximum Allowable Wellhead Operating Pressure (MAWOP) which sums up to:
MAWOP is based on Minimum Internal Yield Pressure (MIYP) of both tubulars (the one being evaluated and the next outer one) as well as the Minimum Collapse Pressure (MCP) for the inner tubular which are calculated according to API Bulletin 5C3.
MAWOP for an annulus is expected to be less than the following:
50% of the Minimum Internal Yield Pressure (MIYP) of casing string being evaluated; or
80% of the MIYP of the next outer casing; or
75% of the Minimum Collapse Pressure of the inner tubular pipe body o In case of the outer most pressure containing casing, the MAWOP can’t exceed 30% of its MIYP
If there is pressure communication between two or more outer casing annuli (e.g., communication between the “B” and “C” annuli or between the “C” and “D” annuli, etc.), then the casing separating these annuli is not considered a competent barrier and should not be used in the MAWOP calculation.
Figure 3 shows an example of MAWOP calculations, note the MAWOP is controlled by MIYP of the next outer casing for the “B” annulus, while the MIYP pressure of the casing being evaluated dictates the MAWOP of the annulus “A” and “C”. Finally, annulus “D” MWAOP is set by the MYIP of the outer most casing rule.
Figure 3. Example of MAWOP calculations for a well with no communication between annuli as per API-90.
Finally, API-90-2 incorporated two alternative cases with a slight deviation in the MAWOP calculations. The first one, called the “Default Designation Method” (DDM), does not require data or analysis to be applied. It can be used in a vast majority of onshore wells where poor data is available. It’s the least precise of the methods, and it’s appropriate for wells that operate at low levels of annular pressure. In the DDM, the MAWOP for the annulus being evaluated is 100 psi (700 kPa) for the outermost annulus, and 200 psi (1400 kPa) for all other annuli, and it requires no further calculations.
If a casing string has significant drill string wear, suspected or known erosion or corrosion, or is operating under high temperature, API-90-2 suggest a second deviation to API-90 for the calculation of MAWOP. This is called “Explicit De-rating Method” (EDM); in this alternative method, the operator would apply a specific reduction in the wall thickness or material properties in calculating the MIYP and MCP.
Using the EDM approach for the inner and outer tubulars, the tubular de-rating component of MAWOP for the annulus being evaluated is the minimum of one of the following:
80 % of the adjusted MIYP of the outer tubular string
80 % of the adjusted MCP of the inner tubular string
100 % of the adjusted MIYP of the next outer tubular string (provides an additional factor of safety)
100 % of the adjusted MCP of the outer tubular string, (i.e., the inner tubular of the next outer adjacent annulus)
The MIYP and the MCP for the tubing and casing strings can be calculated per API 5C3, but their adjusted values are calculated by the following:
MIYPAdj = [(MIYP ⋅ UFb) – ΔPwcd] and MCPAdj = [(MCP ⋅ UFc) – ΔPwcd]
Where MIYP and MCP are the minimum internal yield and collapse pressures; UFb and UFc are the burst and collapse utilization factors (1.0 equals 100 %); ΔPwcd is the pressure differential from the inside to the outside of the casing at worst case depth (i.e., the depth that yields the maximum ΔP). There is no industry standard for the utilization factors, and operators would choose them as part of their safety factors assumptions.
HYDROCARBON GAS MASS
An aspect often overlooked in the Middle East, and not covered by API, but well defined in the Norwegian sector of the North-Sea, is the mass of gas which will result in limited consequences and as low as reasonably practicable probability of escalation if released (OGN 117). Although not directly applicable to SCP, NORSOK S-001 Technical Safety contains an analog requirement to determine acceptance criteria for hydrocarbon gas mass:
“…For pressure vessels and piping segments without a depressurizing system, containing gas or unstabilized oil with high gas/oil-ratio, the maximum containment should be considerably lower than 1000kg…”
This item is typically ignored in the Gulf region as all tubulars have cement to surface either as part of their primary cement jobs or as a result of top-up jobs done afterward. So typically, the SCP leak paths are through cracks/channels in the cement sheet and/or micro-annuli between the cement and the casings. Therefore, the mass of hydrocarbon in the annulus tends to be below any known pre-set criteria. However, for those of you out there trying to come up with a set of criteria for your wells, this is an item worth keeping in mind.
We’ll leave it here for now, next articles will be around how to characterize the SCP to establish when an intervention is required, choosing the ideal solution and how to evaluate the success of any potential treatment.
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 Regional Manager for the Middle East and North Africa region.
In this second part of my article series on SCP, I will discuss how to define
whether you have an SCP scenario that needs intervention or not. In the
first article in this series, I talked about a framework from which we can
deal with the problems related to SCP. I also gave an overview of which
guidelines from different industry bodies that address this topic.
Following the advice given by these guidelines and listening to what
operators in the Middle East are telling us, I suggest you look into four
aspects of your well annulus behaviour to define whether you have an SCP
scenario that needs intervention or not:
Leak nature
Leak rate
Annulus pressure
In a less conventional manner; hydrocarbon gas mass.
LEAK NATURE
There may be a risk of introduction of toxic material such as H2S or
radioactive agents into the annuli through the SCP. Such materials imply a
considerable risk to personnel safety, and their presence, no matter the
other parameters, indicate that the leak needs to be remediated.
LEAK RATE
Excessive leak rates increase the consequences if containment is lost. The
magnitude of the leak will dictate the operator’s ability to normalize the
situation since it defines the amount of energy released, its impact on the
affected area, and in general, the leak escalation potential. So while a
significant leak needs immediate attention, there is a value at which it
doesn’t.
API RP 14B states acceptance criteria for leakage rate through a closed
subsurface safety valve system, and although the norm is not directly
applicable for SCP, its reasoning may still be regarded as an appropriate
analogy for determining acceptance criteria for SCP. OGN117 use it as its
acceptance criteria for annulus leaks.
The acceptance criteria for leak rate, when hydrocarbons are present in the
source of influx, are:
15 scf/min (0.42m3/min) for gas
0.4 liter/min for liquid
ANNULUS PRESSURE
What sounds like a reasonable and empiric statement anywhere you hear it is
that the pressure in the annulus should never reach the maximum allowable
annulus surface pressure at the wellhead (MAASP). However, in this regard,
OGN 117 only advise operators to take into consideration all aspects that
detrimentally affect the normal rating of the wellbore hardware when setting
the MAASP.
Instead, API-90 (Offshore wells) goes into detail on how to establish an
acceptable level of risk for annular casing pressure, using two parameters.
First, sustained annular casing pressure that is greater than 100 psig must
bleed to zero psig. If it does, it indicates that the leak rate is small and
the barriers to flow are still effective. Second, a procedure is offered to
calculate a Maximum Allowable Wellhead Operating Pressure (MAWOP) which sums
up to:
MAWOP is based on Minimum Internal Yield Pressure (MIYP) of both tubulars
(the one being evaluated and the next outer one) as well as the Minimum
Collapse Pressure (MCP) for the inner tubular which are calculated according
to API Bulletin 5C3.
MAWOP for an annulus is expected to be less than the following:
50% of the Minimum Internal Yield Pressure (MIYP) of casing string being
evaluated; or
80% of the MIYP of the next outer casing; or
75% of the Minimum Collapse Pressure of the inner tubular pipe body o In
case of the outer most pressure containing casing, the MAWOP can’t
exceed
30% of its MIYP
If there is pressure communication between two or more outer casing
annuli
(e.g., communication between the “B” and “C” annuli or between the “C” and
“D” annuli, etc.), then the casing separating these annuli is not considered
a competent barrier and should not be used in the MAWOP calculation.
Figure 3 shows an example of MAWOP calculations, note the MAWOP is
controlled by MIYP of the next outer casing for the “B” annulus, while the
MIYP pressure of the casing being evaluated dictates the MAWOP of the
annulus “A” and “C”. Finally, annulus “D” MWAOP is set by the MYIP of the
outer most casing rule.
Figure 3. Example of MAWOP calculations for a well with no communication between annuli as per API-90.
Finally, API-90-2 incorporated two alternative cases with a slight deviation
in the MAWOP calculations. The first one, called the “Default Designation
Method” (DDM), does not require data or analysis to be applied. It can be
used in a vast majority of onshore wells where poor data is available. It’s
the least precise of the methods, and it’s appropriate for wells that
operate at low levels of annular pressure. In the DDM, the MAWOP for the
annulus being evaluated is 100 psi (700 kPa) for the outermost annulus, and
200 psi (1400 kPa) for all other annuli, and it requires no further
calculations.
If a casing string has significant drill string wear, suspected or known
erosion or corrosion, or is operating under high temperature, API-90-2
suggest a second deviation to API-90 for the calculation of MAWOP. This is
called “Explicit De-rating Method” (EDM); in this alternative method, the
operator would apply a specific reduction in the wall thickness or material
properties in calculating the MIYP and MCP.
Using the EDM approach for the inner and outer tubulars, the tubular
de-rating component of MAWOP for the annulus being evaluated is the minimum
of one of the following:
80 % of the adjusted MIYP of the outer tubular string
80 % of the adjusted MCP of the inner tubular string
100 % of the adjusted MIYP of the next outer tubular string (provides an
additional factor of safety)
100 % of the adjusted MCP of the outer tubular string, (i.e., the inner
tubular of the next outer adjacent annulus)
The MIYP and the MCP for the tubing and casing strings can be calculated per
API 5C3, but their adjusted values are calculated by the following:
MIYPAdj = [(MIYP ⋅ UFb) – ΔPwcd] and MCPAdj = [(MCP ⋅ UFc) – ΔPwcd]
Where MIYP and MCP are the minimum internal yield and collapse pressures;
UFb and UFc are the burst and collapse utilization factors (1.0 equals 100
%); ΔPwcd is the pressure differential from the inside to the outside of the
casing at worst case depth (i.e., the depth that yields the maximum ΔP).
There is no industry standard for the utilization factors, and operators
would choose them as part of their safety factors assumptions.
HYDROCARBON GAS MASS
An aspect often overlooked in the Middle East, and not covered by API, but
well defined in the Norwegian sector of the North-Sea, is the mass of gas
which will result in limited consequences and as low as reasonably
practicable probability of escalation if released (OGN 117). Although not
directly applicable to SCP, NORSOK S-001 Technical Safety contains an analog
requirement to determine acceptance criteria for hydrocarbon gas mass:
“…For pressure vessels and piping segments without a depressurizing
system,
containing gas or unstabilized oil with high gas/oil-ratio, the maximum
containment should be considerably lower than 1000kg…”
This item is typically ignored in the Gulf region as all tubulars have
cement to surface either as part of their primary cement jobs or as a result
of top-up jobs done afterward. So typically, the SCP leak paths are through
cracks/channels in the cement sheet and/or micro-annuli between the cement
and the casings. Therefore, the mass of hydrocarbon in the annulus tends to
be below any known pre-set criteria. However, for those of you out there
trying to come up with a set of criteria for your wells, this is an item
worth keeping in mind.
We’ll leave it here for now, next articles will be around how to
characterize the SCP to establish when an intervention is required, choosing
the ideal solution and how to evaluate the success of any potential
treatment.
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 Regional Manager for the Middle East and North Africa region.
Resin chemistry, including epoxies, phenolics, and furans, has been widely utilized in a variety of applications in well construction, completion, and production. This broad class of thermosetting polymers is physically characterized as free-flowing polymer solutions that can be irreversibly set to hard, rigid solids.
These resin systems are designed to solve a variety of well integrity challenges and offers common resin properties such as superior adhesion, resistance to many corrosive chemicals, excellent mechanical properties, low viscosity in the liquid state and flexibility and toughness after curing.
Reading tip: Materials for Plug and
Abandonment of Oil and Gas Wells
Despite these promises of performance, practical application of resin requires easy mixing and pumping without hardening before placement. What separates the different resin systems are the curing process. The best ones are developed with highly tunable gel time (from minutes to hours) over a broad temperature range, which offers a powerful tool for wellbore applications.
Read more: Effective alternatives to
cement in oil and gas wells
Mixing such a resin system is fast and straightforward, and it is all about adding a curing initiator to a resin solution. The curing initiators do not take part in the chemical reaction but only activates the process.
Two fundamental steps are vital to the understanding of this curing mechanism: Initiation and chain-growth. The reaction is initiated by the introduction of free radicals to the liquid system. Free radicals are created from initiators, typically by heat. The free radicals are then transferred to the monomer, forming active centers that can attack other monomers. This is called chain propagation.
At a certain point, there is an abrupt change in the viscosity of resin liquid, with irreversible transformation from a viscous liquid to an elastic gel, called gel point. At the gel point, a resin solution undergoes gelation as reflected in a loss in fluidity. This marks the beginning of the formation of an infinite molecular network. Ultimately, all the molecules are added to the chain, resulting in the solid cured resin material.
Different from conventional cement slurries and epoxies where the reaction starts as soon as mixing part A and part B is in a fixed ratio, the major benefit with free radical curing systems is that they can be cured predictably. This is due to the formation of free radicals is trigged by heat, and the rate of reaction is controlled by temperature. Therefore, such resin system remains liquid while mixing at the surface as long as it is not exposed to heat, and won't react before it reaches its designed target temperature. It would avoid hardening before placement, causing damage downhole or to the surface equipment used for mixing and pumping.
Read more: Cement plugs: A routine or a nightmare?
Read more: Plugging in depleted
reservoirs
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. What if these cementitious barriers become compromised?
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
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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.
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