In West Africa’s deepwater oil and gas patch, Riserless Light Well Intervention (RLWI) conducted from drilling or other support vessels is proving to be an important resource – providing a much faster and cheaper alternative to using rigs. A rising well intervention backlog and tight budgets means this effective solution needs to be quickly and widely deployed if legacy production declines are to be addressed.
This publication is a Special Report focused on Deepwater Solutions For West Africa’s Oil and Gas Industry, featuring the region’s major industry event, West African Offshore Well Intervention Conference (OWI WA). The event is focused on Subsea Well Intervention in the West Africa offshore market. It also covers latest trends and innovation in the industry.
This paper is designed to outline well intervention and P&A opportunities available to contractors in the West Coast of Africa by analysing regional levels of activity, operator well stock and major projects (part 1).
This paper is designed to outline well intervention and P&A opportunities available to contractors in the West Coast of Africa by analysing regional levels of activity, operator well stock and major projects (part 2).
Production decline in mature fields is a common challenge to offshore operators throughout the globe. And in West Africa especially, where developing new fields often requires delving into unexplored deepwater and ultra- deepwater territories, many have decided to take advantage of innovative technical developments in enhanced oil recovery technologies to recover the maximum from their existing oil reserves.
Sonangol EP is one of those companies who, despite recent positive discoveries in its offshore pre-salt acreage which should comfortably allow Angola to maintain its status as Africa’s second largest oil producer, sees the need to ensure additional reserves are extracted from existing wells. Today, we speak with Geraldo Ramos, Senior Production Engineer at Sonangol EP who is currently undertaking a PhD at the University of Aberdeen focusing on Advanced Enhanced Oil Recovery techniques with specific focus on Angolan onshore/offshore fields. We discuss his results so far, his vision for Angola’s 2018 production landscape and the experience he gained from the North Sea.
Sonangol’s Geraldo Ramos shares a unique case study outlining the results of a new approach to EOR in West Africa.
This video of the month showcases how the application of CorrosionVA, supported by Integrated Video Caliper technology, helped an operator in Tunisia overcome a well integrity issue and maintain the safe operation of one of their high-rate production wells.
Wells operate under extreme conditions, involving exposure to challenging temperatures and pressures for extended periods of time.
Access an exclusive podcast with Saudi Aramco, Baker Hughes and NOV exploring the most effective strategies to implement new well intervention technologies. Hear the essential information Middle East operators need to ensure technology is successfully implemented and contract/tendering times are kept to a minimum.
Questions explored include:
What are the key challenges service providers face when trying to implement new technology for well intervention and how can operators help?
What are the key requirements operators need from service providers to ensure tendering time is kept to a minimum?
How does the increasing use of TOTEX (CAPEX+OPEX) evaluation during procurement enable the uptake in new technology adoption?
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?
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