Middle East

The Egyptian Ministry of Petroleum and Schlumberger have announced the launch of the Egypt Upstream Gateway, an innovative national project for the digitalisation of subsurface information and enable global access to the country's subsurface data. This unique digital initiative will be used to unlock the potential of Egypt's petroleum sector and promote the country for international investment in exploration and production projects.

“Egypt is in the process of launching the Egypt Upstream Gateway, a digital subsurface platform that will act as an up-to-date repository of the country’s subsurface data,” commented H.E. Tarek El-Molla, Minister of Petroleum and Mineral Resources for Egypt. “The Egypt Upstream Gateway will digitally promote Egypt’s oil and gas bid rounds through seamless online access to the sector’s data, as well as endorsing our exploration potential worldwide, it is a defining milestone in the country’s oil and gas digital transformation.”

The Egypt Upstream Gateway provides digital access to over 100 years' worth of accumulated national onshore and offshore seismic, non-seismic, well-log, production, and additional subsurface data under a single platform. This data, which empowers de-risked decisions through the ability to explore multiple basins and evergreen data, can be accessed virtually from anywhere using the platform’s online portal. In addition, the Egypt Upstream Gateway will host Egypt's upcoming bid round highlighting lease availability information to national and international investors.

Rajeev Sonthalia, President of Digital & Integration at Schlumberger, said, "The Egypt Upstream Gateway is the embodiment of the Egyptian Ministry of Petroleum's vision, leveraging digitisation to modernise the country's petroleum sector. With the launch of this industry-first platform, the Egyptian Ministry of Petroleum and its affiliates—EGPC, EGAS, GANOPE—can digitally showcase national assets to investors worldwide, in addition to leveraging the latest digital technology and solutions to accelerate discovery throughout the country."

Digitalisation has become a key issue for the offshore oil and gas industry (and indeed the entire energy sector). The importance of getting a firm grip on data and having the capacity to effectively use this is paramount and can lead to tangible benefits in areas such as production efficiency and lifetime of assets. This is clearly understood by the Egyptian Ministry of Petroleum with this announcement that marks a real sign of intent to get ahead of the curve. It is also noteworthy that the data will be opened up for international consideration with discussions on data sharing and partnerships around this intensifying in recent months. To read more on this subject as it was discussed at the UDT EU 2021 Conference, click here.

Deep Casing Tools (DCT), a technology development company for the global energy sector, has secured investment of UK£1.6mn from EV Private Equity and Scottish Enterprise enabling the company to develop and commercialise new innovations that will transform operations across well completion, well construction, well abandonment and slot recovery. In a bid to capitalise on this, the company has made a series of senior appointments and created a new role in its global team.

David Charles

Armed with extensive well and extended reach drilling (ERD) knowledge, derived from 34 years working in the energy sector, David Charles has been appointed as Well Engineer and has been identified as instrumental in helping DCT’s customers maximise return on investment. Prior to joining DCT, David was an ERD Drilling Engineer with ADNOC, delivering ERD wells on a world class projects before becoming a self-employed ERD well specialist consultant. The creation of David’s Well Engineer role demonstrates DCT’s dedication to project performance, with his involvement enabling the expert design, construction and maintenance of wells. Collaborating with well teams onsite, David will lead technical delivery to ensure optimal emissions savings, time savings and cost efficiencies.

Edward Kerr

Edward Kerr joins DCT as Global Sales Manager from Ardyne Technologies where he held the role of regional Vice President, leading Middle East and Asia Pacific operations and global business development activities. At DCT, Edward will focus on driving tool sales, including the firm’s well established TurboCaser and TurboRunner. He will lead business development activities across target international regions, which will increase awareness of the economic and environmental efficiency gains DCT’s suite of well life cycle tools can deliver to major operators.

Compared to conventional technologies, DCT’s TurboCaser and TurboRunner tools are 75% quicker by ensuring casings and completions reach target depth on the first attempt, saving around three days in even the most complex wells. In a typical offshore well, this time saving translates to a saving of around US$600,000. Edward will also introduce new innovations to global markets, such as the highly anticipated Casing Cement Breaker and recently patented MechLOK Drill Pipe Swivel, enabling industry to revolutionise well operations.

Kevin Robertson

Completing the set is Kevin Robertson, who has been appointed Middle East Regional Manager. Having acquired over 20 years’ industry experience, specifically within tubulars, drilling and completions, Kevin Robertson will focus on DCT’s strong presence in the Middle East, which has been a key market for the firm for over a decade. He will further develop current relationships in the region with partners and the world’s largest operators, and identify new opportunities for revenue growth.

Speaking on his appointment, Robertson said, “As a small but global independent company, Deep Casing Tools is very agile and allows its employees to have a creative say in the business, letting all voices be heard. I was excited by its fantastic portfolio of innovative tools that are helping industry achieve remarkable efficiencies and overcome the complex well challenges that drilling teams face today.”

Commenting on the new additions to DCT, David Stephenson, CEO of DCT, said, “We’re pleased to welcome Edward, Kevin and David to the Deep Casing Tools team, their expertise and experience adding a new dimension to our global offering. I am certain they will prove invaluable to client operations and projects, and will play a crucial role in our ambitious growth strategy for 2021 and beyond. Strengthening the expertise and experience within our team, coupled with the recent investment from EV Private Equity and Scottish Enterprise, will ensure we meet growing industry demand for our technologies, helping our customers optimise performance, increase efficiency and ultimately, reduce carbon footprint.”

Global energy company Eni has signed a concession agreement for the acquisition of a 70% stake in the Exploration Offshore Block 3, leading a consortium including a wholly owned subsidiary of Thailand’s PTT Exploration and Production Public Company Limited (PTTEP).

Under the terms of the agreements, Eni will operate the concession to explore for oil and gas and appraise the existing discoveries in the block, which covers an area of approximately 11,660 sq km. The exploration phase of the agreement has a maximum period of up to 9 years. Subject to successful exploration, an overall concession term will extend to 35 years, from commencement of the exploration phase, for development and production phases in which ADNOC has the option to hold a 60% stake.

3D seismic data has already been acquired for a part of the block, which is in close proximity to existing large oil and gas producing and under development fields, and that is estimated to have a promising potential.

His Excellency Sultan Ahmed Al Jaber, UAE Minister of Industry and Advanced Technology and ADNOC Group CEO, said, “This concession award reinforces ADNOC and Eni’s growing partnership across our value chain and deepens our relationship with Thailand’s PTTEP, one of the key markets for our crude oil and products. Despite volatile market conditions, we are making very good progress in delivering Abu Dhabi’s second competitive block bid round, underscoring our world-class resource potential and the UAE’s stable and reliable investment environment.”

Claudio Descalzi, Eni CEO, commented, “This award follows the one achieved by the same consortium in 2019 for offshore exploration Blocks 1 and 2 and represents a further important step towards the realisation of Eni’s strategy to become a leading actor in the development and production in Abu Dhabi. It also further strengthens our relationship with our valuable partner PTTEP. Offshore Block 3 represents a challenging opportunity that can unlock significant value thanks to exploration and appraisal of shallow and deep reservoirs.”

Eni has been present in Abu Dhabi since 2018 with a 10% stake in the Umm Shaif and Nasr Offshore concession plus a 5% stake in the Lower Zakum concession as well as 25% stake in Ghasha concession that is approaching final FID. Current equity production is around 50,000 bpd, in line with the current quotas agreed by OPEC+ members.

The acquisition of the Exploration Offshore Block 3 is the latest step in Eni’s 2017 strategy to geographically diversify its portfolio which has seen the company expand operations in several Middle Eastern countries with a focus on the Arabian Peninsula. This plan is aimed at strengthening the resilience of the business, and so far it appears to have paid off as the consolidated results from their Q3 2020 report reveal the company has exceeded market expectations. They have achieved production levels in line with predictions, maintained a steady cash flow of more than EU€5bn, and kept leverage below 30%.

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.

 

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?

Download Attachments: Download PDF