Med Oil Gas summer 2019

MED OIL & GAS

Summer/Autumn Magazine 2019 1

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Content

Features Comments from HE Mohammad Sanusi Barkindo, Secretary General of OPEC....................................................................5 AnTech Ltd-Collaborative working enables valuable real-time CTD decision making...........................................................6 Wintershall Dea-Case Study- Reservoir delineation in terms of elastic properties, by applying a nonlinear full wave-field AVO technique.....................................................................................................................................10 DNV GL-Global Energy Transition Outlook for MENA oil and gas......................................................................................16 IHS Markit- Exploring ‘mature’ Petroleum Provinces.........................................................................................................20 SDS Ltd- A Simple, Safe and Cost Efficient Method of Installing Large Subsea Structures................................................24 Emerson Automation Solutions- Machine Learning Enriches the Data Available to Seismic Interpreters...........................29 The ICM Group- Overcoming Current Human Resource Challenges..................................................................................33 Wintershall Dea- VSP Measurements used as a Tool for Sub Salt Near Field Development................................................39

Conferences..........................................................................................................................................................13, 45, 47

Companies in the news: Inmarsat UAV pop-up lab for remote asset inspection.......................................................................................................36

Published by: OYOMEDIA18 Limited, (MED OIL & GAS MAGAZINE is a subsidiary of OYOMEDIA18 Limited), Malta & Dubai Printed & designed by: Rosendahls a/s Denmark Cover photo courtesy of AnTech Limited.

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Combating Market Volatility, Promoting Industry Stability extended in May 2017, for an additional nine months, effective July 1, 2017.

Comments from

HE Mohammad Sanusi Barkindo Secretary General of OPEC

This has proven to be successful thus far, and we are witnessing some positive developments in the market. Global stocks are coming down, world oil demand is stable, but the global economic outlook going forward is fragile.

A stable oil and gas market is a necessity for the industry to grow and continue to attract investment. All stakeholders must come together to halt the volatility that has hit the energy sector in recent years.

Though this process may be taking longer than originally anticipated, rebalancing a global oil market, with all of its inherent complexity, simply cannot happen overnight- it was bound to take time, along with a lot of hard work and perseverance.

First, let me point out that healthy industry growth can only be pursued in the context of a stable oil market. And stability goes to the core of what OPEC’s mission has been, since it was founded in 1960.

But the steadfast commitment of the 24 OPEC and non-OPEC producing countries participating in the Declaration of Cooperation is evident in conformity levels that have surpassed 100 percent recently.

Today, more than ever, OPEC is dedicated to helping to re-establish a balanced and stable global oil market. We have embarked on an unprecedented, historic cooperation with non-OPEC countries in an effort to rescue the oil market, which has experienced one of the worst downturns in the history of the industry due to an oversupplied market that sent the OPEC Reference Basket price plummeting by nearly 80% to $22 per barrel by January of 2016.

Commercial stocks across the Organisation for Economic Cooperation and Development (OECD), both onshore and offshore, are coming down; according to the most recent figures.

This event had a severe impact on the industry, resulting in hundreds of thousands of lost jobs, deferred or cancelled investments, and discontinued research and development projects.

In the wake of this crisis, OPEC realized it had to respond. And it did, by conducting extensive consultations during the second half of 2016, not only among OPEC Member Countries, but also between OPEC and nonOPEC nations, as well as with consumers and the wider international community.

The discussions concentrated on restoring a lasting stability to the market and culminated in the historic decisions leading to the landmark Declaration of Cooperation, which was signed on December 10, 2016, and was

At the beginning of 2017, the OECD stock overhang was at 338mb above the five-year average. This level has steadily dropped in recent years.

I believe dialogue and cooperation right across the industry is the only way to keep the industry heading in the right direction.

One thing we have learned from this cycle and all previous price cycle challenges is that extreme prices lead to boom and bust market conditions. These in turn have introduced high levels of volatility to the market.

Furthermore, this is simply bad news for producers, and bad news for consumers.

We must seek the middle ground and stay away from extremities-this is the only way to ensure a stable and sustainable future for the global oil market. Through dialogue and cooperation, we can hinder boom and bust cycles brought on by high volatility. This volatility not only contributes to instability in the market, it can also jeopardize future investment.

In addition, the importance of recent developments, specifically in terms of helping achieve market stability, and just as importantly, sustaining it, is clearly vital across all timeframes. While the focus for many is obviously on the short-term, we need to recall that in the short to medium- and long-terms are all interlinked. We cannot view any of them in isolation.

OPEC is focused on optimizing the path to a lasting stability in the global oil market.

Finally, we need to recognize the threat posed by climate change to our environment. Let me stress here that OPEC remains fully engaged and supportive of the Paris Agreement.

We firmly believe that a global consensus from the multilateral process remains the best and most inclusive way for all nations to collectively mitigate or adapt to the impacts of climate change based on the core principle of ‘common but differentiated responsibilities’ in a fair and equitable manner.

OPEC Member Countries recognize and support the development of renewables. Many of our countries have great sources of solar and wind, and significant investments are being made in these fields.

We need to continually look to develop, evolve and adopt cleaner energy technologies, as well as all-inclusive and non- discriminatory energy policies, that enable us to meet the expected future energy demand, in a sustainable manner.

Nonetheless, it is vital we appreciate just what each energy source provides today, and what they can provide in the decades ahead.

I think we all appreciate that the future is one laden with challenges and uncertainties, but also many opportunities. There will no doubt be areas where we may all agree, as well as areas where there will be divergences.

It is important for all stakeholders to look for shared and realistic solutions, where and when appropriate.

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Collaborative working enables valuable real-time CTD decision making A recent project in the Texas Panhandle shows how collaborative working enables real time decision making.

By Adam Miszewski, Global Operations Manager at AnTech Ltd

Underbalanced Coiled Tubing Drilling (UBCTD) offers operators a way to capture significant extra value out of known reserves. In fact, it has been comprehensively shown that, when applied correctly, the technology can deliver increased production rates at reduced cost when compared to traditional methods. It therefore makes maximising returns from declining fields a viable and attractive value proposition.

However, in a traditional site set up, the technology is still held back by traditional ways of working. There are typically four principal service companies involved in a UBCTD campaign: the directional downhole tools provider, the coiled tubing service company, the underbalanced drilling fluids package and the operator. Each company uses its own data acquisition system (DAS). Typically, this means an incomplete data picture is available to any party at any given time. Consequently, there are delays in decision making on-site while data from the other parties are requested, collated and analysed.

New proprietary technologies have come along that remove the delays inherent in these traditional ways of working. They enable real time decision making and take the productivity, operational and cost effectiveness of UBCTD together to the next level. As such, it opens up new opportunities for operators with declining fields.

An example of such technology is RockSense® that was demonstrated in a project led by AnTech in the Texas Panhandle. RockSense® is AnTech’s proprietary synthetic porosity algorithm. RockSense® has the ability to distinguish between difference formations by combining downhole and surface data in real time to give an at-bit qualitative measurement of porosity. It offers two considerable advantages over traditional geosteering techniques. Because wired telemetry has a high data rate, multiple measure6 | MED OIL & GAS | September 2019

ments can be made for every foot drilled and operators can gain inch-level resolution. And because the data delivered are representative of conditions at the bit – not 20-25ft behind it – the driller can deliver an optimally placed wellbore, with more feet drilled in the target zone.

To enable the use of technologies such as RockSense®, a complete real time data picture is required. This means all parties involved in a project have to share their data in real time. For this to be achieved – and for operators to be able to take advantage of the enhanced capabilities technologies such as RockSense® deliver – a different way of working that involves a very much more collaborative approach from the very earliest stages of a project needs to be embraced by the operator and the service companies.

It’s a way of working that was embraced by an operator in the Texas Panhandle. Specialist contractors were utilised for each major component of the project and tightly integrated from the earliest stages using project management best practices. Its success showed the value of collaborative working in combination with UBCTD and digital technologies.

Project background The project was a two well re-entry campaign in the Texas Panhandle. The wells were part of a wider campaign to revitalise a field that had been producing for many years. The overarching aim of the wider campaign was to intercept fractures and access untapped reserves to boost production.

The role of aggregating the data was taken on by AnTech, the directional service provider. AnTech also provided pre-job engineering, pre-job project management, downhole equipment and data aggregation. Halliburton provided CT unit and pumps. ADA provided the flow back package. Blade Energy Partners provided pre-job engineering and wellsite supervision/ project management on site. (See Figure 1.) To enable the CT unit to run e-coil, AnTech provided the conversion kit to convert the rig to e-line (slip ring collector, collector bulkhead), work that was done well in advance of arriving at the wellsite.

Figure 1: The interaction of service companies for the UBCTD campaign

for wellsite data acquisition, offsite support for data analysis and downhole sensors, by aggregating the data from all parties involved. By doing this, all parties would have a complete picture of what was happening on the wellsite and real time decision making would be improved.

In order to enable this way of working, a great deal of time and effort was given to the planning phase prior to work starting on site – considerably more than would be traditionally expected. However, the operator recognised that such detailed planning and preparation was critical to the success of the project and encouraged the approach, creating a fully ingtegrated and effective working culture and operation.

This collaborative way of working proved beneficial very early on in the project lifecycle.

Early planning and collaboration helps address challenges The principal challenge needing to be addressed early on in the project was cost. The critical requirement was to stay in AFE, with a related aim of showing that UBCTD could be carried out cost effectively in the US and generate a significant ROI. Wellbore stability in the build section and water were two areas considered to be of particular concern.In terms of wellbore stability in the build section, the candidate wells had to be evaluated for stability in the overburden immediately above the pay zone. In terms of water, assessment was required because wells in the area had a history of

Underbalanced drilling was considered the best way to increase production because .it is known that preventing a formation from becoming overbalanced at any time can have a significant impact on production. Indeed, the expectation was that the production would remain high for a prolonged time due to the benefits of drilling underbalanced.

UBCTD was chosen specifically because of the particular nature of the two wells. They were primarily gas producers, with condensate and water also being produced. UBCTD was seen as the best way to drill the reservoir underbalanced because it provided continuous stable underbalanced bottom hole pressure, as well as fast, safe and effective operation in two phase flow.

In the early stages of the project, the operator decided to use new digital technologies

Figure 2: Design of well one, before and after schematic 7

Figure 3 – The RockSense® log: Real-time at-bit porosity for geosteering

watering out, so there was a risk of hitting water, which would significantly harm ROI. The large amount of time and effort put into the planning work was critical in ensuring that the wells were drilled as planned, that there were no surprises and challenges could be mitigated. To assess these challenges, a Hazard Identification study (HAZID) and Drill Well On Paper (DWOP) exercise were carried out before starting work with all the major service companies attending in person during the planning phase. This work helped to identify the major risks and mitigations required to complete the project successfully.

The planning showed that only one candidate was able to be drilled underbalanced with an acceptable level of risk. All other wells had substantial amounts of shale interbedded with the limestone in the build section. There was therefore a high risk of shale instability. It was for this reason that the second well had an intermediate section drilled and cased by a conventional drilling rig.

The planning also resulted in several other important outputs. It enabled the creation of a detailed set of written procedures that outlined exactly how the project was to be carried out. It also enabled contingency planning to deal with wellbore stability in the build section and water in the horizontal to be carried out. These contingencies included an expandable liner being kept on standby as a contingency for the wellbore stability and inflatable plugs being available in case of hitting water. The planning demonstrated that such contingencies were a sensible investment.

Collaborative working in action for well one drilling phase execution Well one (Figure 2) was a vertical well. It had been producing gas but production had dropped off to uneconomical levels. It was planned to pull tubing from the well, insert a whipstock and mill a window using a workover unit, the most time- and cost-effective 8 | MED OIL & GAS | September 2019

Figure 4: Design of well two, before and after schematic

way to do this part of the operation. Once achieved, the UBCTD package would be mobilised and a horizontal wellbore would be drilled (build section and horizontal section drilled).

As planned, the original tubing was pulled, a cement plug was set to isolate the perforations and a casing exit carried out by a workover unit was created. The hole was left overbalanced with lease water in the hole and shut in on closed valves. The UBCTD package was then mobilised to the site and rigged up with the well treated as live.

The BHA was run to immediately above the window and the circulation valve in the BHA was opened. The well was displaced to nitrogen to underbalance the well. The circulation valve was a multi-action electrically operated valve and so it could be closed for drilling. In order to pass through the window, AnTech’s Acrobat gyro-directional sensor, which provides horizontal gyro-while-drilling capabilities, was used to take a survey and orient the bent housing motor to pass through the window. The technology is incorporated in the BHA so it can assist with passing through

windows without getting stuck and deal with inaccurate magnetic surveys when close to the existing casing.

There was difficulty in passing through the window due to a poor quality casing exit.

The drilling BHA was pulled out of hole after several unsuccessful attempts to pass. A milling BHA was made up of a lead mill and a string mill and was run beneath the 31/8” Dynomax motor to overcome the issue. The window was dressed using the milling assembly and on the subsequent run in hole with the drilling BHA there was no issue with passing through the window.

The build section was drilled with dogleg severities of between 25-30 degrees per 100ft.

After the build section was landed, AnTech’s Continuously Rotating Orienter ensured it was possible to continue drilling on the horizontal tangent section, even with the large motor bend setting.

The horizontal section was drilled with a hole size of 4½”. By combining RockSense® (Figure 3) and production data, several productive gas fractures were intersected. However,

water bearing fractures were also intersected.

Normally, an operator would need to complete the well to know if the well was productive and successful. However, the use of UBCTD and RockSense® meant it was possible to see exact production from the well in real time. This allowed decisions to be made on whether to carry on drilling, sidetrack or TD in real time as well, improving efficiency.

The use of UBCTD was also valuable when in depth analysis of production was required.

This was because the BHA could be pulled to the casing shoe and a more intensive well test could be carried out by applying different levels of draw down on the well. The BHA could be left in the hole providing downhole measurements at the same time as getting production measurements on surface.

Collaborative working in action for well two drilling phase execution Well two was a horizontal well (Figure 4).

Early stage planning showed that starting in the vertical section would have involved drilling through a shale section that would be unstable when the well was put underbalanced. A drilling rig was therefore specified to drill an intermediate section to the top of the reservoir which would then be cased and cemented. The casing shoe was at over 10,000ft and 74 degrees inclination.

On completion, the rig would be demobilised and the UBCTD package mobilised and rigged up. The UBCTD package would then drill out the casing shoe, land the well horizontally and drill a horizontal section.

Because the reservoir was very thick, control of vertical depth was not critical in order to stay in the payzone/target formation. There was a gamma marker above the reservoir which would be picked up using the gamma sensor on the drilling BHA. RockSense® would be used to identify when fractures and faults were drilled through.

Because of its short length, AnTech’s COLT BHA was specified for use on this element of the project and proved very valuable. It would allow a standard set up with the injector and lubricator suspended from a crane.

To ensure operational efficiency and safety during deployment and undeployment of the BHAs, two mouseholes would be drilled.

A back-up tool would be kept in one mousehole ready for deployment as required and the previous BHA would be undeployed in the other mousehole. Another advantage of the short BHA would be that it was short enough for a shooting boom forklift to be

used to lift the whole BHA fully made up into the mousehole. It meant there would be no need for a deployment tower or an additional crane, which lowered costs for the client.

As planned, well two had the tubing pulled and the existing perforations abandoned using a conventional drilling rig. A casing exit was performed and an intermediate 61/4” hole section added, which was cased off with a 4½” casing string. The rig was then demobilised and the UBCTD package mobilised.

The casing shoe was drilled out using lease water to minimise nitrogen costs. Once the casing shoe was drilled out and reamed through, the BHA was POOH to approximately 500ft. The circulation valve was opened and the well displaced to nitrogen as the BHA was slowly run back in hole. The openhole section was drilled utilising RockSense® in combination with the surface flow data to identify fractures and faults that were productive.

The well proved productive, with commercial quantities of dry gas being produced. However, a water bearing fracture was intercepted. The decision was made to stop drilling and run two inflatable plugs to seal off the water bearing fracture. RockSense® was used to identify the exact location of the fracture and the setting depths for the plugs which needed to be as close to the water bearing fracture as possible but within competent rock. Both plugs were set successfully using the e-coil on site. Once the plugs were set, the well was tested and the UBCTD package rigged down.

uses a drilling rig on a campaign drilling wells to just above the payzone and then moving in the UBCTD package to drill the payzone.

Conclusion The project delivered the production levels the operators had believed to be possible.

Furthermore, collaborative working, in combination with new digital technologies that are now available, enabled the production levels to be secured within AFE. It also validated the technology and provided a proof of concept to be taken forward to the operator’s next projects.

To be more specific, four key benefits can be seen in the approach of this project. It enabled the wells to be drilled according to planned trajectory. It enabled the use of RockSense®, which meant real time information on fractures and other features was available. It enabled real time data aggregation and therefore real time decision making.

It enabled live well testing, removing the delays inherent in gathering data and analysing it off site before proceeding.

However, it should be noted that successful execution of such advanced techniques relies on a greater degree of collaboration and integration than is typical. It was possible in this instance because of the operator’s clear understanding of the requirements of UBCTD based on successful projects in the past and the use of experienced service companies keen to explore new ways of working and the benefits of integrating operations more deeply.

The value of a whole project overview Aside from the benefits of collaborative working, this project was a good example of the importance of seeing a UBCTD campaign as a whole. By considering the overall picture, ROI could be maximised by using technologies where they were best suited.

For example, using a workover unit for the tubing pulling and casing exit reduced the cost of the operation and ensured the UBCTD package would only be deployed where it added greatest value. For well two there was a technical reason to use a drilling rig for the intermediate section. By planning to have the wellbore landed at 74 degrees just above the reservoir, the UBCTD was carried out solely in the payzone and the risk of drilling the build section in unstable formation was removed. Well two was similar in design to a “pre-set well” where an operator

Author

AdamIllustration Miszewski 3.CRISP-DM Model As Global Operations Manager at AnTech Ltd, Adam’s role is to deliver the company’s services safely and efficiently. Before joining AnTech, Adam worked as a lead drilling engineer for BP in Aberdeen and for a short period with Halliburton. Adam graduated from Imperial College London with a First Class Master’s degree in Mechanical Engineering.

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Reservoir delineation in terms of elastic properties, by applying a nonlinear full wave-field AVO technique A case study in the NW Khilala field INTRODUCTION Reliable reservoir characterisation from seismic data is a crucial step in the process of finding, developing and finally producing a hydrocarbon field.

The obtained elastic properties of the reservoir units are not only used for improved structural interpretation but also allow evaluation of reserves.

AVO techniques are widely applied in this context, with the objective to invert pre-stack seismic data for acoustic and shear impedances. These methods are generally based on the linearised Zoeppritz equations. In this paper we present a method that is fundamentally different to existing techniques on several accounts. First, the AVO technique discussed here acknowledges the true nonlinear relationship between seismic amplitudes and elastic properties. Internal multiple scattering, mode conversion and the true travel times over the target interval in the elastic medium are properly modelled and are hence turned from noise into useful information. Second, the full wave field inversion is carried out in an iterative way where progressively higher orders of internal multiple scattering are modelled and matched in the data. This scheme makes it much less likely that the nonlinear inversion gets trapped in local minima. In addition, the scheme solves directly for the elastic properties in terms of compressibility and shear compliance, which can be much more directly related to changes in the rock matrix and/or the pore fluid compared to the case in which impedances are inverted for. The technique will be demonstrated on a field dataset acquired in the Nile delta with the ultimate goal of delineating the reservoir sand by mapping a 3-D geobody based on the Possion’s ratio.

10 | MED OIL & GAS | September 2019

Geological Setting The onshore gas field is situated in the Nile Delta and was discovered and appraised by three wells. The target reservoirs are of Late Miocene (Messinian) and Pliocene age and are mainly formed by the Abu Maadi formation at depth ranges around 3000m.

The Abu Maadi formation was deposited in a low relief delta plain setting and is forming N to S and NE to SW trending distributary channels. Sand channels are laterally stacked and are separated by shale bodies.

Top seal of the whole system is formed

by Lower Pliocene shales. The field closes against a fault at the eastern margin where also the Lower Pliocene sales acts as seal.

Structural dipping and stratigraphic trapping barders the field to North, South and West. The sand bodies show an average porosity of 25%-30% and gross thicknesses of 8m to 25m for the lower two sands and up to 95m for the upper sand. Water saturation varies around 40-50%.

Nonlinear Full Waveform Inversion In a reservoir-oriented setup where the subsurface can locally (per CMP) assumed to be layered, nonlinear AVO techniques are still challenging from a computational

resources as well as a numerical stability point of view. We mitigate both problems by splitting up the nonlinear inversion process into alternating linear inversions followed by a forward modelling step to incorporate an increased order of scattering. Initially a linear inversion, based on propagation of wave fields in a very smooth background model, leads to a first estimate of the reservoir properties (compressibility and shear compliance). Since we know that the used linear assumption is not exact we only use the obtained properties to update our inversion kernel to account for first order multiple scattering. Note that we add a single order of scattering at each iteration.

We argue that there is no reason to solve for an exact solution of the wave-equation in a reservoir model which is known to be an approximation of the true model. With the updated inversion Kernel we repeat the inversion of the seismic data leading to improved reservoir properties, which will then be used to incorporate second order multiple scattering in the process. Note that multiple scattering in this context refers to a mathematical concept including true multiple scattering in the subsurface, mode conversions but also exact travel times in the inverted reservoir model. This iterative procedure of alternating linear inversions

Figure 1. Flow diagram for non-linear inversion. In every outer loop iteration the kernel for the linear inversion changes, based on the currently best estimate of the total field in the object. Tue total field update adding one higher order of scattering to the total field is based on the currently best estimate of the properties over the target interval.

and adding another order of nonlinearity to the inversion kernel is maintained until the reservoir properties and the inversion kernel do not change any more. The scheme is illustrated in Fig.1. The described algorithm has been successfully demonstrated on synthetic data (Gisolf et. al, 2012) and field data (Gisolf et. al, 2014).

Data input and pre-processing Input into the scheme are pre-stack seismic gathers, log data for calibration purposes and a horizon marking the top of the reservoir interval. A mild dip-filter (2500m/s in inline/crossline directions, 25000m/s in offset direction) is applied to the seismic data in three dimensions, to remove dipping noise from the migrated input data.

This procedure is justified because we do not expect severe structural dips in the current reservoir environment and the offset gathers are supposed to be flat in the migrated domain. Subsequent steps include offset to ray-parameter conversion and demigration (see next paragraph) of the seismic. Ray-parameter dependent wavelets were extracted by performing a seismic-to-well tie using synthetics modelled with the Kennett method (Kennett, 1983).

Kennett modelling provides exact synthetics (including internal scattering and mode conversions) and ensures that the obtained wavelets conform to the described nonlinear AVO technique. In a last step background models for the inversion are extracted from the well logs by severe smoothing (4Hz high­ cut filtering). These backgrounds will be hung of the target horizon but do not change laterally, thereby avoiding any interpretational bias in the initial background model. It should be noted that the logs are used to extract a wavelet and to provide the backgrounds but are not used in the actual inversion process.

Figure 2. Flow-chart for bringing the data down to a target location on the target boundary. At every location A the 2D r / p CMP data is inverted for a ID subsurface model. All locations are independently processed on a trace-by-trace basis.

trace mode ensures that the geological 3D dip is honoured by the data. Overburden transmission effects and the wavelets at the target boundary are extracted from seismic-to-well matches. When more wells are available, these wavelets can be interpolated between the wells.

taken into account when estimating the seismic wavelets. Despite this shift, the inversion recovered the elastic properties well and a more in depth well log study would be needed to explain this mismatch. Still, since we do not use the logs in the inversion process we can proceed with the inversion of the 3-D seismic volume.

Field data application Befare applying the nonlinear AVO technique to a 3-D seismic volume, we invert a single CMP gather at the well location. This allows us to compare the inverted compressibility and shear compliance with the logged properties. The results of the inversion process are shown in Fig.3. While a good match is obtained in the shallow part of the target, a mismatch can be observed in the deeper part. This mismatch was observed already in the seismic-to-well tie and is therefore also be expected to appear when comparing the logged properties with the inversion result.

The mismatch seems to be a bulk shift at the reservoir level and has been properly

To delineate the reservoir volume in terms of Poisson’s ratio, a seismic volume of 152x83 CMP gathers was inverted. This resulted in 3-D volumes of compressibility and shear compliance covering an area of approximately 8km2 (not shown in this abstract).

The target depth interval has a size of 500m being sampled on a 5m grid. Finally the obtained elastic properties were converted to Possion’s ratio according to Eq.1. The compressibility is denoted by Kand the shear compliance by M.

Target oriented inversion The inversion scheme is applied either to surface data that is redatumed to the target boundary, or to migrated data that is demigrated to the target boundary at the top of the target interval. A mapped seismic horizon can serve as a suitable boundary. The general workflow is shown in Fig.2.

In the present study the data-set at the top of the objective sequence is created by demigrating the migrated data over the target interval. This is possible when dealing with a plane wave r / p domain, assuming a layered medium immediately below the target location (A). Working in a trace-by-

Figure 3. From left to right: Logged (red) and inverted (blue) contrasts in compressibility; Logged (red) and inverted (blue) contrasts in shear compliance; Seismic input gather; Predicted synthetic gather based on inversion result; 11

Fig.4 shows a geobody extracted from the 3-D Poisson’s ratio volume based on an iso-value of 0.25. Clearly two separate reservoir sands could successfully be identified. While this paper is concerned with delineation of the reservoir, the obtained compressibility and shear compliance cubes could also be used for a detailed quantitative rock physics analysis. This could potentially provide details about the lithology of the extracted geobody, but this is outside of the scope of the present abstract.

Conclusions • An increased resolution was obtained for the upper two sands package.

• It was physically impossible to resolve

the lower sand and to distinguish individual stacked channels in the upper part.

• The inversion result was compared with a blind well and the test was positive.

• A good match between inverted and the corresponding logged properties has been achieved.

• The extracted geo-body showed good structural conformability

Acknowledgments This test application has been performed

by Delft Inversion subcontracted by Delphi Studio on behalf of DEA Deutsche Erdoel AG.

Figure 4. Geobody for Poisson’s ratio, constructed from κ and M predictions. The body is defined by the iso-surfacefor s = .25.

12 | MED OIL & GAS | September 2019

References A. Gisolf, R. Huis in’t Veld, P. Haffinger, C. Hanitzsch, P. Doulgeris, P.C.H. Veeken, Non-linear Full Wavefield Inversion Applied to Carboniferous Reservoirs in the Wingate Gas Field (SNS, Offshore UK). Extended abstract, 76t11 EAGE Conference and Exhibition, Amsterdam, 4p.

A. Gisolf, D. Tetyukhina, and S.M. Luthi: Full Elastic Inversion of Synthetic Seismic Data Based on an Outcrop Model, Extende abstract, 82n d SEG Annual meeting, Las Vegas, 4p.

B. L. N. Kennett: Seismic wave propagation in stratified media by, Cambridge University Press, 1983. No. of pages: 242

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15

Global Energy Transition Outlook predicts continuing demand growth for MENA oil and gas The world will need less energy from the 2030s onwards, but it will still require a significant amount of oil and gas in the lead-up to mid-century according to DNV GL’s 2018 Energy Transition Outlook.

DNV GL’S ENERGY TRANSITION OUTLOOK – IN BRIEF DNV GL’s recently released Energy Transition Outlook 2018, a global and regional forecast to 2050 is based on their annually updated Independent Model of the World’s Energy System produced by combining the expertise and experience of three of their Business Areas – Oil & Gas, Maritime and Energy.

The effort was coordinated by DNV GL’s Group Technology and Research unit and reviewed by a wide range of experts from both industry and academia.

Based on the model, DNV GL’s Energy Transition Outlook underpins a unique regional and global forecast covering 10 world regions and the energy trading between them.

Its goal is to assist energy supply chain stakeholders in developing their future business strategies and provides essential insights for any company operating internationally.

The Middle East & North Africa (MENA) region will remain the main global supplier of oil and gas for decades to come: • The energy transition will redefine oil and gas exploration and production activity in the lead-up to 2050 • Future production will favour a greater number of smaller reservoirs with shorter lifespans • Increased investment in digitally-enabled technologies is needed now to support faster, more cost-effective production in the coming decades • Gas will overtake oil as the world’s largest energy source by 2026 According to DNV GL’s 2018 Energy Transition Outlook, an independent forecast of the world energy mix in the lead-up to 2050, oil and gas demand will peak in 2023 and 2034, respectively. However, new oil fields will be needed until at least the 2040s, while new gas developments will be required beyond 2050. DNV GL’s Outlook predicts that operators will favor production from a greater number of smaller reservoirs with shorter lifespans, lower break-even costs and reduced social impact compared to those currently in operation.

16 | MED OIL & GAS | September 2019

“Most easy-to-produce, ‘elephant’ oil and gas fields have been found and are already in production. Smaller reservoirs will likely be harder to explore and develop commercially. Digitally-enabled technologies such as directional drilling and steerable drill bits, 4D seismic backed by advanced data analytics and steam flooding, will be crucial to ensure that exploration and production is economic and efficient,” says Liv A. Hovem, CEO, DNV GL – Oil & Gas. Following DNV GL’s Outlook existing technologies for decarbonization, such as car-

Figure 1. World primary energy supply

bon capture and storage (CCS) will need to be implemented at scale for the oil and gas sector to stay relevant in a rapidly decarbonizing energy mix. DNV GL forecasts CCS will capture only 1.5% of emissions related to energy and industrial processes in 2050.

Global warming will likely reach 2.6 degrees Celsius (°C) above pre-industrial levels in 2050, according to the Outlook. This is well above the 2°C target set out by the COP 21 Paris Agreement on climate change. By 2050, the Outlook predicts 972 gigatonnes of carbon will be emitted, overshooting the 810 gigatonne budget associated with the target.

“Our forecast reaffirms that the oil and gas industry has a vital role to play in the energy transition. It is our sector’s responsibility to maintain a sharp focus on decarbonization, sustainable production, cost management, and the need to embrace innovative technologies to secure long-term supply of sustainable and affordable energy,” adds Hovem.

Increasing investment supports gas to fuel the energy transition DNV GL’s Energy Transition Outlook predicts global upstream gas capital expenditure will grow from USD960 billion (bn) in

tripling of electricity demand between now and 2050.

Due to low-cost domestic gas reserves, the uptake of renewables starts later than in most other regions. In 2030, onshore wind starts to grow rapidly, followed by solar PV and offshore wind. By 2050, solar PV will be the main source of power, generating 39% of total supply. Onshore wind will then be second, with a share of 28%.

Figure 2. Middle East and North Africa (MENA) primary energy consumption by source

Figure 3. Middle East and North Africa electricity generation by power station type

2015 to a peak of USD1.13 trillion in 2025 to support the transition to the golden age of gas. Upstream gas operating expenditure is also set to rise from USD448bn in 2015 to USD582bn in 2035, when operational spending will be at its highest.

This cash injection will enable the 46% increase in the annual rate of additions to gas production capacity that the Outlook forecasts between 2018 and 2030. Conventional onshore and offshore gas production is forecast to decline from about 2030, while unconventional onshore gas is expected to rise to a peak in 2040.

Among its forecasts for 10 global regions, DNV GL’s Outlook sees North East Eurasia (including Russia) and the Middle East and North Africa (MENA) accounting for most onshore conventional gas production in the lead-up to 2050, while North America will continue to dominate unconventional gas production. In the offshore sector, the MENA region sees the highest annual rate

of new gas production capacity from now until at least 2050.

The forecast for the Middle East and North Africa (MENA) According to DNV GL’s 2018 Energy Transition Outlook, energy con¬sumption in the Middle East and North Africa will continue to grow moderately and increase 36% by 2050. Growth in energy use is driven by manu¬facturing, buildings, and transport up to 2040, the year when transport energy demand peaks and starts to decline.

The MENA region will remain the main global supplier of oil and gas. However, as the regional population grows, domestic energy demands will change and the use of electricity will grow rapidly. Today, 60% of electricity is gener¬ated from gas.

By mid-century, electricity will be primarily generated from variable renewables like wind and solar with increased support from hydropower and nuclear.

“Middle East nations are excited by what solar photovoltaic can do for them domestically,” says Jan Zschommler, Area Manager Middle East at DNV GL - Oil & Gas. “This is expanding to reduce oil imports (Egypt, Jordan), allow more oil exports (Iran, Iraq, Oman and UAE) and, to reduce the cost of generation by not having to invest in more expensive hydrocarbon production for domestic power (Saudi Arabia).”

Variable renewables alone will provide more than 65% of the electricity in the region by 2050. This means that even though oil and gas production will continue to play a significant role for decades to come, the shift to renewables will change the location of where energy is going to be produced, which in turn impacts on the region’s economies and politics.

Energy consumption is dominated by regional oil and gas resources. Oil is forecast to peak in 2035 at only slightly more than its current level. Natural gas, already the largest energy source, will see a further increase until it peaks in 2035, 30% above its current level. In the mid-2030s, oil for road transport will be increasingly challenged by the uptake of electric vehicles.

The growth in natural gas use is driven by a

Figure 4. Middle East and North Africa electricity generation in 2050 17

Figure 5. Conventional onshore oil production by region

Consequences for oil & gas production in the Middle East and North Africa DNV GL’s ETO forecasting model encompasses the global energy supply and demand and the use and exchange of energy within and between ten world regions, including MENA. “MENA nations are naturally interested in how much decarbonization reduces demand for their exported fossil fuels in the decades to come,” says Zschommler. “Our forecast shows that the region will remain the main global supplier of oil.”

As government and public pressure for cleaner energy solutions increases and the price of renewables decreases the production and exploration in challenging environments will shrink and, in some environments like the Arctic, cease altogether.

Operators outside the MENA region will choose to develop resources from smaller, more technically challenging reservoirs, with shorter lifespans, lower breakeven costs and reduced social impact. This may lead to a shortfall in world oil & gas supply favoring the MENA region where the cost of production has, historically, been lower and less technically challenging.

18 | MED OIL & GAS | September 2019

However, within the region the sector still faces the multifaceted challenges of adjusting production portfolios to favor gas, whilst reducing costs and bringing decarbonization of operations into full focus in order to maintain its social license to operate and help achieve international and national targets for climate change mitigation. Middle East energy companies are already investing heavily in energy efficiency and renewables while raising domestic consumer energy prices, which are widely expected to triple by 2023. The industry’s digital transformation will play a significant role in achieving this.

“The industry will need to invest in developing technologies supporting faster and leaner exploration and production. We experience that our customers are seeking more sustainable operations through digitally-enabled solutions, such as predictive emission monitoring for gas turbines and remote technologies to perform targeted inspection, to name just a few examples,’ says Zschommler. “DNV GL is supporting the industry with globally recognized riskbased approaches and domain expertise in combination with leading digital technologies, many of which are developed together with our customers through Joint Industry Projects (JIPs) and other collaborative initiatives.”

DNV GL’s suite of 2018 Energy Transition Outlook reports are available to download free of charge. The main ETO report covers the transition of the entire energy mix to 2050. It is accompanied by three supplements forecasting implications for the oil and gas, power supply, and maritime industries.

19

Exploring “mature” petroleum provinces – a review of activities in the Carpathian-Pannonian transect from S Poland to Hungary

ABSTRACT Petroleum provinces of the Carpathian-Pannonian domain have a long history of prolific hydrocarbon exploration. The region, believed to be a “mature” petroleum province, is still one of Europe’s main areas of hydrocarbon activity: over 200 exploratory wells were drilled in the area since 2013. A number of new discoveries was made in the process, reserves of several vintage fields augmented, and some new petroleum plays yielded encouraging results. There is a strong push to re-develop the zone - current plans of the explorers point to increased future activity.

Introduction The petroleum provinces within the Carpathian-Pannonian transect from S Poland across the Czech Republic, Slovakia to Hungary (Fig 1), have a long history of prolific hydrocarbon exploration. The Carpathian petroleum province - flysch series in Poland/ Ukraine/Romania explored for oil and gas since mid-19th century - is the world’s oldest producing thrust-and-fold system, with the Pannonian petroleum province actively explored since the early 20th century. The exploration efforts to date led to discovering approximately 700 oil and gas fields, with the volume of recoverable reserves exceeding 1.5 BBL of liquids and 20 Tcf of gas.

Although the Carpathian-Pannonian region is regarded to be a mature hydrocarbon province and most of the hydrocarbons in the shallow and geologically simple reservoirs are believed to have been discovered, the region remains to this day one of Europe’s main areas of hydrocarbon activity both for the domestic operators and some regional players. The interest in the area re20 | MED OIL & GAS | September 2019

Figure 1. General geological map of the Carpathian–Pannonian area after Schmid et al. (2008; from Gągała et al. (2012)).

mains high: over 200 exploratory wells were drilled in the region during 2013-18 (Fig. 2) and, despite low oil price prevailing since mid-2014 and the ensuing volatility on the markets, present plans of the explorers in the region point out to an increased future activity. The push to redevelop the area is a result of broad deployment of modern exploration techniques, primarily 3D reflection seismic and sophisticated signal modelling, arrival of new structural theories for the development of the area and the formation of reservoirs/ traps, as well as the use of new production techniques and careful management of the above ground aspects. The subsequent paragraphs reveal selected petroleum-related operations in S Poland, Czech Republic, Slovakia and Hungary during 2013-18, listing

several key successful operations.

Poland The Carpathian hydrocarbon province combines the Outer Carpathian fold-and-thrust system and the Miocene Carpathian foredeep with their respective basements. Almost the entire prospective acreage within the province is licensed to Poland’s two principal operators: Polskie Gornictwo Naftowe i Gazownictwo (PGNiG) and ORLEN Upstream (Fig. 3).

While the former company is active in the area since long, ORLEN Upstream entered the region in mid-2015 through a series of asset acquisitions – permits of DEA, acreage of Eurogas/San Leon Energy (to became

Figure 2. .Well drilling statistics for the countries along the Carpathia-Pannonian transect during 2013-18..

partner of PGNiG) – and the tender-related grants. Acting separately or as partners, these companies acquired since 2013 more than 2,000 sq km of 3D seismic, 800 km of 2D seismic and drilled over 100 new exploratory wells.

As a result, PGNiG discovered a number of new small- to medium-size hydrocarbon pools, especially within the Carpathian foredeep (e.g. Mielnik, Slotwinka). By acquiring large in scope 3D seismic programmes, the company was able to re-evaluate several vintage fields - e.g. Przemysl and Przeworsk - substantially augmenting the remaining gas reserves (0.7-1.0 Tcf). In addition, PGNiG is on the way to unlock, believed to be substantial, hydrocarbon potential of the Miocene-age tight mudstone-sandstone series below the frontal elements of the Outer Carpathian fold-and-thrust system. A 2013 discovery well was appraised in 2017/2018 with a fracture-tested well that delivered commercial quantities of gas. PGNiG is planning to drill further wells on the structure and on the nearby look-alike objects.

The company, pursuing new strategy in relation to the Carpathian province, is intending to spud up to 120 new wells until 2022, expecting to augment the gas production in the province by some 25%.

Similar exploration success within the Outer Carpathian fold-and-thrust system remains elusive still, owing primarily to poor seismic imaging of the flysch series at greater depths. Both ORLEN Upstream and the PGNiG/ORLEN Upstream group (Bieszczady area) acquired since 2016 new 3D seismic data, but three recently-drilled wells yielded mixed results: one positive well, two non-commercial discoveries. In late 2018, after a few years of hiatus, the PGNiG/OR-

Figure 3. Map of east-central Europe displaying the contractual situation in Poland, Czech Republic, Slovakia and Hungary on the background of the main basins of the Carpathian-Pannonian petroleum province.

LEN Upstream group spudded a well aiming targets at shallow to medium depths within the flysch series (Czarna Dolna), planning to drill also a deeper wildcat that should penetrate the entire Phanerozoic sequence. The only international player in the Polish Carpathians, San Leon Energy, divested assets in the western sector of the area to Horizon Petroleum (deal sanctioned by the authorities in late 2018) and the newcomer is preparing operations on a yet-to-be-produced Lachowice field.

In a bid to attract explorers to the remaining unlicensed acreage in the Carpathian area, the Ministry of Environment has prepared eight areas for licensing: Bestwina-Czechowice, Bochnia, Blazowa, Królówka, Proszowice W, Rudniki-Lipiny, Sucha Beskidzka-Wisniowa, Wetlina (Fig 3). Two of these blocks - Bochnia and Sucha Beskidzka-Wisniowa - were tendered during the May-August 2018 bid round. The next tender call is expected during 2019.

Czech Republic and Slovakia The prospective acreage is found within

both, tectonic elements of the Carpathian-Pannonian system - Carpathian thrust and fold- and Carpathian foreland-related successions - as well as in the Neogene strata of the Pannonian Basin with its lateral equivalents (Vienna Basin in Czech Republic/Slovakia, Danube Basin / East Slovak Sub-basin in Slovakia) (Fig. 3).

In the Czech Republic, where over 30 wells were drilled since 2013, MND is the principal explorer/producer active lately in the area of near-field exploration and seeking to preserve the country’s production levels (circa 2,000 bo/d and up to 20 Bcfg/d). In the process, MND discovered a series of new accumulations on the satellite structures to already producing fields (e.g. Borkovany, Hrusky, Mikulov). Green Gas DPB, active on the CBM arena (Upper Silesian Basin), producing also conventional assets located within the Outer Carpathian Foredeep / Carpathian Flysch Zone, continues gas output, optimising acreage portfolio.

In Slovakia, Nafta, the country’s principal explorer and producer was seeking a partner 21

on the prospectivity of the basin remains upbeat.

Conclusions

Figure 4. Maps of Hungary displaying acreage awarded as result of the tender calls organised during 2013-18 (red - new awards; yellow – areas earmarked for future licensing).

to re-start exploration in the Danube Basin, dormant for over three decades. Following a farm-in of Vermilion Energy, the new group acquired 2D/3D seismic in 2017 and, following interpretation, is planning a project to redevelop the Neogene series. Available information suggests that the group is planning to drill four wells in the Danube Basin in 2019. The activities in Slovakia’s Carpathian Flysch Zone area, where a consortium led by Alpine Oil & Gas is planning one (or more) exploratory wells targeting multiple reservoirs at shallow to medium depths, have been on hold lately as the operator has yet to secure all the drilling permits and access to land.

Hungary The Pannonian hydrocarbon province rests on the basement units of various tectonic provenience with the Precambrian-Mesozoic stratigraphy (AlCaPa/Tisza-Dacia), sealed along a ENE-WSW-trending mid-Hungarian fault zone. The province encompasses the Paleogene Basin and the Neogene Pannonian Basin formed as a result of back-arc extension within the Carpathian thrust-andfold mountain system. The Pannonian Basin itself includes several Neogene depocentres (e.g. Bekes, Drava sub-basins), each with a different rift history and complex pattern of rapidly changing sedimentary fill of considerable thickness, allowing for a rapid maturation of syn-depositional and older source rocks.

The Neogene basin fill is the traditional target of exploration in the Pannonian Basin in Hungary (and surrounding countries). Until recently, the basin was the main and exclusive exploration area of domestic Magyar Olaj- es Gazipari Rt (MOL) that discovered and produced the bulk of the hydrocarbons in the basin. With a few thousand wells 22 | MED OIL & GAS | September 2019

drilled and some 300 hydrocarbon pools discovered to date, the Neogene Pannonian Basin is understood to be well-explored.

To stimulate exploratory efforts and to attract investment, the country’s authorities are organizing, since 2013, tender calls (Fig. 4), offering up to 10 areas for licensing for hydrocarbon exploration and production each year. The procedure, adjusted for fiscal terms of the contracts, has proven vital for reviving petroleum-related activities in the basin. Some 30 contracts were granted this way during the period 2013-18 to Hungarian Horizon Energy (HHE), MOL, O&D Development, Panbridge and Vermilion Energy.

Further rounds are planned – the authorities have prepared approximately 35 open areas for future licensing – and the seventh bid round is expected to be launched in May/ June 2019, likely with another set of 8-9 blocks for hydrocarbon exploration (plus 1-2 areas for geothermal purposes).

As a result of the licensing efforts, operators active in the Pannonian Basin reprocessed a substantial volume of vintage seismic, acquired close to 3,000 sq km of modern 3D seismic and drilled over 100 new exploratory wells, discovering a number of new pools (e.g. Konyary, Mezotur, Pettend). Some of the discoveries, e.g. Mezohegyes Nyugat of Vermilion Energy, were swiftly brought to production due to the presence of a well-developed pipeline network.

The remaining hydrocarbon potential of the Pannonian Basin is seen within bypassed/”overlooked” plays, deeper (Miocene) sequences, syn-rift series, with the tight and/or HPHT reservoirs also being noteworthy. Further investment opportunities may include asset acquisition. As unlicensed acreage is still available, the view

The sedimentary series of the Carpathian-Pannonian hydrocarbon provinces, attracting substantial level of activity, are experiencing a revival of the exploration interest. Active operators in Poland, Czech Republic, Slovakia and Hungary procured new acreage, acquired large 2D/3D seismic projects and drilled over 250 exploratory wells during 2013-18. PGNiG of Poland discovered a number of new hydrocarbon pools and was able to redefine the remaining potential of some vintage fields (e.g.

Przemysl). The company is seeking to unlock hydrocarbon potential within the tight Miocene series. Exploration of the flysch series of the Outer Carpathian fold-and-thrust system remains challenging. Revision of legacy data, new chronostratigraphic framework and new models of the evolution of the tectonic system seem necessary to unlock the potential of this terrane.

Operators in the Czech Republic and Slovakia have successfully carried out near-field exploration that resulted with a few new discoveries. There are plans to restart exploration within areas which have long remained dormant.

New acreage made available through the bid rounds in Hungary has positively affected exploration efforts in the Pannonian Basin: the operators reprocessed substantial volume of vintage seismic data, acquired modern 3D seismic and drilled over 100 new wells, discovering a number of new hydrocarbon pools. As significant unlicensed acreage is still available, the prospect for the residual hydrocarbon potential of the Pannonian Basin, seen within bypassed plays, deeper (Miocene) sequences and syn-rift series, remains upbeat.

Author

Piotr Gawenda Technical Research Associate Director, IHS Markit

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A Simple, Safe and Cost Efficient Method of Installing Large Subsea Structures The Subsea Deployment System (SDS) enables even the smallest crane or anchor handling vessel to transport and install medium to large structures (100t to several 1000t) in water depths of 100m - 3000m, in hostile environments. It offers potential cost savings of 60% on multi-structure installations and up to 80% on single structure installations..

The subsea industry is increasingly developing more complex fields in deeper water. Typically, this involves the deployment of large structures in hostile environments which challenge the capabilities of most existing installation vessels. The limited availability of suitable vessels and the restricted operating windows in harsh environments can place significant constraints on the project schedule. The SDS is a cost effective alternative to a conventionally lifted installation that meets or exceeds the weight and depth capacities of existing vessels.

The system uses a fully submersible deployment vehicle (SDV), Figure 1, to support the subsea structure during transportation, positioning and installation. The vessel consists of a steel frame or hull which supports sufficient solid buoyancy modules to render the combined SDV and payload slightly positively buoyant.

The complete assembly is transported to site using a submerged tow which largely eliminates the effects of the surface environment and avoids the often critical phases of offshore over-boarding and lowering through the splash zone. Final positioning and set down is achieved by means of chains lowered into the SDV which behave as soft springs and minimize dynamic loading.

Once the structure is landed on the seabed, ballast is added to the SDV to compensate for the weight of the structure prior to disconnection. The ballast is deployed in batches to suit the capacity of the surface vessel, i.e. if the crane’s effective capacity is 100t and the structure is 400t, the ballast would be deployed in four batches.

The reduced weather sensitivity significantly 24 | MED OIL & GAS | September 2019

increases the operating window for hostile regions, offering greater schedule flexibility and in many cases the potential for year round operations. This is a distinct advantage in emergency response scenarios. The system is also particularly attractive for salvaging redundant structures due to the low dynamic loading and because it avoids the need to recover structures to deck offshore.

An affordable and readily available subsea heavy lift capability offers the potential to develop fields with fewer and larger structures avoiding costly inter-structure connections. It will also facilitate the development of more marginal fields. Although HLVs are frequently used for both the installation of heavy structures and pipe-lay, removing the need for an HLV offers the potential to adopt a cheaper pipe-lay vessel resulting in overall field development savings.

A typical installation will consist of, load-out, surface tow, submerged tow, positioning, set-down, ballasting and float-off.

The structure may be loaded-out into the Subsea Deployment Vehicle (SDV) by a variety of methods depending on the available equipment and draught including a direct lift, a submersible barge or a dry dock.

When the water depth is limited at the loadout location the side hulls are dry and the SDV and structure are towed in shallow draught surface tow mode until reaching a suitable inshore location for flooding the hulls. Once the hulls are flooded the amount of solid buoyancy is such that the SDV will float with only the castles and chain towers breaking the water surface. The tow wire and chain clump weight are then paid out causing the SDV to submerge fully for

the transit to site. The depth of the SDV is adjusted by varying the tow speed and the length of the tow wire.

On approaching the field, the vessel slows down and adjusts the tow wire while keeping the chain clump weight off the seabed until in a designated parking area. The vessel then pays out the tow wire until the clump weight rests on the seabed at which point the SDV and structure is safely “anchored” and floats above the seabed.

Ideally the length of tow wire between the clump weight and SDV will be marginally greater than the distance between the parking area and the final target location. This allows final set-down without the need to lift and re-position the tow chain clump weight.

The SDV is positioned by means of two control chains suspended from the installation vessel and lowered into the chain towers.

The height of the SDV is adjusted by lifting or lowering the control chains and the position and orientation of the SDV is adjusted by moving the installation vessel and / or the crane.

Once the SDV is in the correct position and orientation, the structure is landed by lowering the control chains until the structure rests on the seabed. The control chains are then fully lowered into the chain towers and temporarily disconnected. The weight of the control chains contributes to the initial on-bottom stability, i.e. prior to ballasting.

Ballast weights are added to the SDV ballast chain lockers by the surface vessel crane to balance the weight of the structure. Once all the ballast is added the SDV is slightly negatively buoyant and just rests on the struc-

A. Control Chains and Chain Towers The control chains are lowered into chain towers to control the SDV during installation. The weight of the chain supported by the SDV at the base of the chain towers is used to control the height of the SDV. The length (weight) of chain suspended within the chain towers provides lateral and rotational control of the SDV. B. Structure C. Longitudinal Pontoons The SDV consists of two longitudinal pontoons which have ballasting facilities. This enables the SDV c/w structure to operate at a shallow draught.

D. Castles The castles are positioned above the majority of the solid buoyancy and protrude above the waterline in the deep draught condition. This facilitates fine tuning of the trim.

E. Structure-SDV Interface Beam The structure-SDV interface beams are used to support the structure between the hulls of the SDV

G. Solid Buoyancy Modules Solid buoyancy modules (syntactic foam) rated to the installation water depth are located above the hulls.

F. Ballast Chain Lockers Ballast chain lockers are placed at each corner above the hulls. They are used to trim the SDV to suit the weight and centre of gravity of the structure prior to the tow. They are also used to hold the ballast weight which replaces the structure after installation of the structure

H. Ballasting Platform/System The flooding and vent valves are manually operated from workstations next to the control chain towers by means of mechanical linkage where necessary.

The SDV will be ballasted by means of gravity alone and all valves will remain open during the submerged tow.

ture. The SDV is now disconnected from the structure.

reduces the dynamic loading on the structure and installation vessel.

hood of failure and even if failure did occur it would not result in loss of the structure.

The installation vessel re-connects to the control chains and raises them until the SDV is neutrally buoyant and continues lifting the chains until the SDV floats clear of the structure. The control chains are then removed completely from the towers allowing the SDV to float above the seabed while remaining safely anchored by the clump weight before being towed back to shore.

During the final set down with a conventional installation there is a rapid change of tension in the hoist wire as the structure lands on the seabed. This can result in snatch loads in adverse sea states and consequently it is desirable to fully release the load as soon as the structure lands. This largely precludes the option to reposition the structure if it has been landed off target. The SDS differs from a conventional installation in that there is no significant change of tension in the control chain down lines when the structure touches the seabed. There is no possibility of snatch loading and the set down is unaffected by the surface environmental conditions. It is also possible to land the structure and reposition it if required.

When using the SDS, the structure and SDV are parked close to the seabed and consequently the time for lowering the structure to the seabed is short. This reduces the required weather window and any delays during the installation are less critical. In addition the lowering operation can be suspended at any time without risk to the structure or personnel. The control chains are simply withdrawn from the towers and the structure/SDV is safely anchored by the tow chain clump weight.

Apart from the cost and schedule advantages offered by the SDS it also has a number of safety advantages over a conventional lifted installation.

The most critical phases of a conventional lifted installation are considered to be over boarding, deployment through the splash zone and final set down. Once the over boarding has started it is generally not practical to suspend the operation before landing the structure on the seabed and a suitable weather window is required which covers the entire installation.

The SDS avoids offshore over boarding and deployment through the splash zone. Instead the SDV and structure are submerged at an inshore location where the environmental conditions are more benign. This significantly

If delays occur during a conventional installation in deteriorating weather conditions there is a risk of overloading the hoist wires and/or structure due to increased dynamic loading.

This could result in failure of the wire and catastrophic loss. The SDS largely eliminates the dynamic loading on control chains, the structure and its connection to the SDV thereby reducing the risk of a failure. The only hoist wires used in the SDS are associated with the control chains. These are subject to relatively low dynamic loading which reduces the likeli-

J. Tow Chain Clump Weight The tow chain clump weight is inserted into the tow wire to provide the necessary weight to submerge the SDV from the deep draught tow condition to the submerged tow condition. It also acts as an anchor for the SDV when parked on the seabed.

All the individual aspects of the SDS are developed from very basic principles and existing technology, but the combination has resulted in a potential “game changer� for the development, installation and decommissioning of subsea structures.

SDS is looking to align with an innovative partner to bring this concept to market.

Author

David Paul Engineering Manager, Subsea Deployment Systems Ltd

25

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Machine Learning Enriches the Data Available to Seismic Interpreters The interpretation of seismic data poses significant challenges as to the information we can reliably extract using the seismic method. Data quality, data complexity, and resolution can limit the value of seismic data in prospecting and field development.

Are we at the point where machine learning can play a significant role in enhancing the seismic interpretation process with these limitations? And are we closer to using machine learning as a component of the core interpretation process?

Geoscientists regularly face limitations in the interpretation process: Many of the tasks associated with interpretation are repetitive and time-consuming, requiring the dedication of a skilled geoscientist to ensure that the final interpretation is geologically-consistent. As the interpretation is dependent on data quality and on the capacity of the stacked seismic data to image and fully represent the subsurface, the interpretation can become more subjective and carry a higher degree of uncertainty. Adding auxiliary seismic data (e.g. seismic attributes, VSP data) and non-seismic data (e.g. electromagnetic, completions, engineering, well log data) can improve the interpretation process and reduce interpretational uncertainty; however, the integration of these data types into the processing and imaging sequence can be quite time-consuming.

Increases in computational power, expanded access to that power on the Cloud, and the availability of a wealth of Open Source machine learning engines have empowered developers to create new applications to automate, integrate, and transform the interpretation process. Machine learning workflows are being adapted to work through large volumes of seismic data in shorter periods of time, to transform seismic data to other value-added attributes that better describe the depositional and stratigraphic processes of the subsurface, and to recog-

nize patterns in the data image volume corresponding to specific subsurface features (low energy faults, small faults, edges, discontinuities, reefs, salts, diffractions, channels, etc.).

Machine learning is not new to Emerson.

With a twenty-five-year history of applying Machine Learning to improve different seismic processing, imaging, and interpretation technologies, we have established a base of experience that includes the underlying physics model and appropriate data input preparation. In this article, we focus on two emerging solutions – the use of deep learning to classify pre-stack depth image gathers to deliver more informative volumes to the interpreter, and a classification methodology which uses well data and multi-dimensional seismic data to predict facies away from the well bore.

In the last ten years, the exploration community has benefited from the acquisition of high-density and rich-azimuth seismic data surveys. These data-rich surface acquisitions sample the subsurface, resulting in different wavefields associated with different subsurface features. These wavefields carry signatures related to fractures, faults, edges, points, and other structural discontinuities.

When isolated, these wavefields can be used to produce feature-targeted images of the subsurface.

Unfortunately, traditional seismic processing and imaging procedures impose many averaging operations before the final interpreted image is generated, preventing the isolation and recovery of the wavefields. Consequently, seismic interpreters routinely work with “composite� wavefield images of the subsurface of high signal-to-noise quality, but low seismic image resolution.

Concurrently, a new generation of machine learning methods has become available, enabling geophysicists to develop applications that better automate, classify, transform, analyze, and identify features in high-density seismic datasets. Deep learning is a specific type of machine learning technology used to classify features or objects. It is carried out with a convolutional neural network, a network consisting of many layers, neurons and connectors, where each layer of the neural network detects a certain characteristic of the input data that permits a comprehensive classification. To become efficient at seismic feature classification, thousands of data records (or models) are required to train the network.

However, for the reasons referenced above, the separation of the wavefields associated with all the subsurface and near surface features cannot be solved with deep learning methods alone. A sophisticated data preparation process must be run to allow

29

the image capture of wavefields prior to the generation and application of deep learning filters. This problem is solved by using a full azimuth pre-stack depth imaging procedure carried out in the local angle domain (Emerson’s EarthStudy 360™) where full-azimuth directional angle gathers are created. Each directional angle gather consists of thousands of traces (directions) illuminating each subsurface point from a rich spectrum of angles. This makes it possible to isolate and extract targeted wavefield energy associated with subsurface features, such as faults, stratigraphic edges, channels, and reefs. The separation of continuous (specular) energy associated with dominant reflectors and discontinuous (diffraction) energy creates the opportunity to generate feature-targeted images using wavefield separation.

For example, the diffraction energy from a fault spreads throughout all dips but keeps a specific orientation, the azimuth of the interface between the fault and the reflectors.

The diffraction energy is usually only 1-10% of the strength of the reflections. This makes diffractions hard to see in a post-stack image, as they are masked by the more dominant reflection energy. That is why it’s important that this wavefield separation be performed in the pre-stack domain. If we create small sub-volumes in the pre-stack domain, we can create ‘images’ which can be passed to neural network technology to automate the recognition and classification process.

Deep learning is an advanced methodology within the broader machine learning portfolio. It adopts a more sophisticated approach involving multiple layers of neural networks which learn to solve problems of higher complexity. In the deep learning classification workflow, we use a Convolutional Neural Network consisting of 18 layers. Each layer applies a convolutional operation to the input, passing the result to the next layer, with the layers gradually detecting more and more complex features and structures. The training of the neural network is carried out with many overlapping images or tiles constructed from the principle directivities of the directional angle gather derived from Principle Component Analysis.

This methodology delivers post-stack volumes in which the energy relating to each type of structural feature has been isolated.

Thus, we obtain a volume containing only primary reflections, a volume containing only faults, or even a volume containing a specific source of noise, etc. (Figure 1). The separa30 | MED OIL & GAS | September 2019

Figure 1. Deep learning applied to full-azimuth gathers to isolate signal and noise patterns.

Figure 2: Coherency, diffraction weighted stack and deep learning results

tion of these features significantly enhances the resolution of each volume: In the fault volume we see faults which are missing in a conventional full stack, as they are masked by stronger energies.

If we can deliver these structural features as independent volumes to the interpreter, they can respond better to other forms of automated machine learning processes for map and model creation.

Techniques aimed at enhancing fault energy are not uncommon, from post-stack discontinuity methodologies to more modern diffraction imaging workflows. So how do the results of deep learning compare with more conventional approaches? Figure 2 shows a comparison between a post-stack coherency attribute, a diffraction-weighted stack image, and the deep learning result, where the fault detail and definition are clearly superior.

The second of the emerging technologies is a tool for predicting rock type distribution in the reservoir The Emerson Rock Type Classification methodology uses a machine learning algorithm called Democratic Neural Network Association (DNNA), an ensemble of naïve neural networks which propagate probabilities with each predicted rock type. The steps used in Rock Type Classification are conventional ma-

chine learning steps – definition of the training set, training, classification, and ultimately a validation stage before propagation of the classification (Figure 3). The deliverables are a volume of most probable facies with a volume of maximum probability, and a probability volume for each facies.

DNNA can be divided into two parts: The first is Associative Neural Networks, where several independent networks work alongside each other within a single layer. This has the effect of debiasing the result that may occur from the use of a single neural network. This step is used to train the neural network, making use of seismic data and electrofacies derived from wireline data calibrated with core data. The next stage is the ‘Democratic’ part – where the networks effectively vote on unlabelled data comprised of seismic data sampled away from the well bore. If all networks agree, then a label is added, enriching the training set for further learning. If they do not agree, the data is rejected.

Figure 3: The core steps of machine learning algorithms

Once the training is complete, the classification is performed. We obtain the classification volumes mentioned above by exposing the data to the neural network. Results can be validated through 3D visualization of the volumes, blind well tests, and through the use of QC diagnostics related to the separation of the classifications.

We can illustrate this methodology using a case study from North Texas, the Eastern shelf of the Permian Basin, where the study area is a mixed siliciclastic shelf. The goal was to predict rock type/fluid content distribution through the reservoir to capture lateral and vertical heterogeneities and to constrain the reservoir models away from the wells, in order to validate the drilling strategy. Time was short and longer turnaround inversion workflows could not be accommodated.

The available data consisted of a small, high-resolution, good-quality seismic survey with pre-stack data and attributes, but with only three wells within the survey area. From the electrofacies logs it is observed that the oil-filled packstone layers were thin, so the challenge was to use the limited well data and select the highest resolution and most relevant seismic data to provide the best prediction possible.

Figure 4 shows the high-resolution facies result obtained, clearly better than the individual seismic volumes used as input. This is a benefit of using multiple pre- and post-

Figure 4: 3D semi-opaque voxel cloud view of the oil-filled packstone probability cloud We include an acknowledgement to Halliburton Operating Company for permission to show this data.

stack volumes in the input stage, as they help to enhance the resolution. As a result of this study, the well found a good pay facies at correct depth, with double the pay zone thickness and an increase in porosity from 10% to 17%.

These are just two of the ways in which Emerson continues to find innovative ways to use machine learning to deliver improved data and better results to the interpreter, in a variety of geological settings. The capacity to automate repetitive tasks to handle very large volumes of data makes these technologies a must in today’s exploration and production environments. As part of our mission to deliver high-quality, innovative software and services designed to tackle the most challenging geoscience problems, we at Emerson see machine learning as an essential technology whose value will only continue to increase.

Author

Sandra Allwork Director of Technical Services at Emerson E&P Software in Europe.

For more than 20 years in the oil and gas E&P industry, she has helped customers optimize their velocity model building and imaging workflows, incorporating the latest advances in anisotropy and full-azimuth analysis. Sandra holds a BSc in Geology & Geophysics from the University of Durham in the UK.

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Overcoming Current Human resource Challenges It is imperative that organizations find a balance between long and short-term investments whilst maintaining a robust balance sheet to fund their way through the upturn.

Crucial to this can be decreased in recruitment, local manpower, HSE training, technical coaching, logistics and other cost reductions applied over the last couple of years.

The ICM Group add value to its clients by becoming an “exclusive partner” using the “Turn Key” services and benefiting reliable cost savings.

Whether a company’s strategy is based on organic growth, alliance and JV, or M&A, the ICM Group provides its clients with tailored manpower, manning and training core competencies. Invaluable and uniquely sustainable human capital structures translate into a tangible competitive advantage in the industry. As such, it is of utmost importance to continuously monitor the need for future human capital demand, structure business continuance and contingency plans accordingly.

By 2018, 1.2 million people were employed within the oil, natural gas and petrochemical industries, the industry lost nearly 270,000 jobs during the downturn. Only three-quarters of the laid-off employees, however, are expected to return, according to a recent study by the ICM Group, a leading-edge consultancy specializing in fully integrated training and human resource solutions.

Moreover, an estimate of 140,000 to 170,000 employees will be needed by 2021.

The “Great Crew Change”, as this phenomenon is referred to in the industry, reflects the inevitable retirement of thousands of older generation workers. It brings with it the necessity and opportunity of training younger employees to fill the gap. This can lead to a motivated work environment, strong work ethic and even encourage the older generation to work slightly past the retirement age.

This shift within drilling companies forces a rethinking of traditional approaches towards human resources in an attempt to keep hard-to-replace, well trained, and thoroughly experienced employees. It also brings the opportunity of renewing processes and systems to create long-lasting, sustainable models which allow organizations to attract and maintain top-level competence and expertise.

All those involved in recruitment need to be equipped with the appropriate knowledge and skills for a company to succeed. By providing our expertise and a unique model in the industry, we can help your company stand out from the crowd.

The ICM Group can help companies successfully fair this shift by providing a one tun key human resources, training and competence services, or by strengthening the different part of functions that will make them successful.

How The ICM Group Can Help You Successfully Fair this Shift HUMAN RESOURCES

Manning:

Agility and flexibility to select the right people for jobs are critical to avoid high turnover in the recruitment cycle. Our thorough selection process is conducted through our database of over 20,000 competent candidates, performance evaluations and competence assessments, personality tests, reviews, evaluations of attitudes and behaviors, interviews and ability tests.

Seadrill is one of the main partners who decided to take the ICM Group as their recruitment partner with a high level of satisfaction.

Choosing the right candidates will, in turn, reduce turnover and ultimately training and competence costs.

Some developing countries are ready to step up their level of expertise and ICM has

been successful in providing such candidates from Brazil, South Africa, western Europe, Asia and many more…

Ad-Hoc: The single-most influential factor behind outsourcing is a significant cost reduction. It allows Rig and Project Managers to supplement their core team with local or specialized expertise. Those come with the added advantage of flexibility and adaptability adjusted to an organization and its teams’ changing circumstances and needs.

Green hat outsourcing: The ICM Group is providing a unique proposition to tackle all pros and cons of outsourcing, including a well-recognized three-hitches outsourcing program. It allows an employer to easily identify the potential of possible employees without wasting unnecessary turnover resources, time and contractual engagements.

Local manpower and contracts: With offices on every continent, we strive to be represented in every oil and gas exploring country in order to represent a unique local partner with a unique global offer for our clients worldwide.

The provision of complimentary regulatory training and competence development, being part of our core services, brings our offer to an noncompetitive quality and pricing level of expectations.

TRAINING & COMPETENCE

HSE, Maritime, Crane and Forklift Onboard Training All our experts and trainers come with specific, practical local knowledge. We strive to 33

Rig Manager Class for all levels. This course covers the following core competencies: • Finance & Accounting, • Maintenance & Assets, HR, • Training & Development, Safety, • Health & Environment, Clients, • Suppliers & Legal and more. be recognized as the most global most innovative and cost-effective onboard training provider.

Our classes follow international standards such as OPITO, IMO, API, etc. and DIT accredited.

CFST (Crew Familiarization System Training) Particularly in a recovering industry, equipment adaptability, as well as having the capacity to move employees from different rig types, is of great advantage.

Crew Familiarization System Training is used on the different rig units, usually to new crewmembers. Even qualified and experienced, employees newly assigned to a vessel may have never worked on the specific equipment they will use or become responsible for.

The objective of the program is to provide them with familiarization, layout, and a general overview of the various equipment and systems. This assists the crew in understanding the unit systems and allow them to develop their own routines more accurately.

The crewmember can gain in a short period of time: • Invaluable knowledge • Experience • Exposure to equipment and system • Ability to work independently and efficiently As the CFST documentation remains on the unit, they can also be used on a daily basis as a guideline by the supervisor for training purpose of the newly hired or promoted personnel.

CFST’s can also be integrated through our E-learning system.

Cyber base/drilling/Technical coaching and OJT (On the job training) Mentoring and coaching employees is an essential part of the employee development process, external training is essential but not sufficient for an employee to understand its local environment and be developed through hands on training.

Our expert trainers are all trained and certified to provide such training and bring real added value to the employee environ34 | MED OIL & GAS | September 2019

ment and bring him to its optimal skills.

Management feedback on candidates is an integrated part of our coaching program, allowing the client to receive a status of the employee level and progress.

Competence Management System: The ICM Group combines knowledge and experience to develop leading edge competence management systems, including customized competence programs, competence assessments, on-site training and system auditing.

Furthermore, subcontractors are also starting to request certain competencies.

SSE is one of them and commented, “The ICM Group have many years of experience assessing the capabilities of professionals in the oil and gas industry and have been chosen by SSE as the ‘way to go’ to achieve our goal – to ensure we have a benchmark for the assessment of our team of professionals and ensure we are able to offer a reliable and trustworthy level of technical competency with technical, financial and safety advantages as major considerations.”

Proven Methods How the ICM Group’s unique and proven methods can help you achieve long-term success is listed below.

Fast Tracking has been the key to the expanding success of drilling contractors and this is where we recommend our clients invest in. As a leading training organization, we regard it our responsibility to assure the selected candidates absolutely satisfy the operational level expected of them. We provide them with the ability to operate relevant equipment confidently and safely, while progressing through the organization and filling the skills and competence gaps.

E-learning is crucial in reducing training costs. We specialize in developing interactive and effective programs, customized to clients’ needs.

Rig Manager: In today’s innovative environment, rig managers are having to deal with multi-tasking, additional responsibilities and less on-site functional support than ever before. The ICM Group has developed the first

Our People, Your Success The ICM Group recognizes that the industry will continue to face demanding challenges in the future. Our services and expertise strive to add human capital value to organizations in a timely and cost-efficient manner.

Our team of highly skilled experts is able to provide fully integrated solutions tailored to meet each client’s specific needs.

Combining technical and managerial expertise, the ICM Group is committed to deliver leading edge consulting services bound to create competitive advantages and sustainable business operations over the longterm.

Pierre Brunet was appointed CEO upon the foundation of ICM People and became Chairman of the group in 2018. He previously had overseen different managerial training projects and divisions of O&G, as well as mining and drilling contractors such as Ensco (formerly Pride International) and Boart Longyear. Mr Brunet brings more than 13 years of leadership, financial skills, industry-specific expertise and offshore experience to the industry and enjoys a close, approachable and continuous relationship with all of his clients.

About the Author

Pierre Brunet was appointed CEO upon the foundation of ICM People and became Chairman of the group in 2018. He previously had overseen different managerial training projects and divisions of O&G, as well as mining and drilling contractors such as Ensco (formerly Pride International) and Boart Longyear. Mr Brunet brings more than 13 years of leadership, financial skills, industry-specific expertise and offshore experience to the industry and enjoys a close, approachable and continuous relationship with all of his clients.

Klausdorfer Weg 163 | 24148 Kiel | Germany Tel. +49 (0) 431 6 6111-0 | Fax -28 info@podszuck.eu | www.podszuck.eu 35

Inmarsat UAV Pop-up lab to showcase progress on remote asset inspection Leading global mobile satellite service provider demonstrates how its ‘UAV Pop-up lab’ is helping commercial drone companies develop remote inspection services to support offshore assets.

The ability of Unmanned Aerial Vehicles (UAVs) to operate in hard to reach spaces has seen class societies making good use of the technology in close-up ship inspections, but satellite connectivity supports ‘beyond line of sight’ applications offshore that is rapidly coming to include predictive maintenance.

36 | MED OIL & GAS | September 2019

The application is a key objective for global mobile satellite service Inmarsat as it unveils its ‘UAV Pop-up lab’ to work with commercial drone companies in demonstrating the role of L-band connectivity in delivering real time UAV control for long range missions worldwide.

Formally launched in February, the UAV Pop-up lab sees Inmarsat providing satellite connectivity and live mission testing to a partnership with terminal hardware provider Cobham and technology accelerator Starburst, alongside seven commercial drone companies.

in the Pop-up lab initiative, UAVs use Cobham’s lightweight but resilient AVIATOR 200 terminal to communicate in ‘beyond line of sight’ (BLOS) missions via Inmarsat’s global network, where L-band is especially robust for remote area operations.

According to Andrew Legg, Regional Sales Director at Cobham: “While many UAVs will rely on terrestrial based connectivity solutions, they often operate beyond line of sight of point to point digital data links and out of coverage of ground networks. Many of these airframes are compromised by connectivity shortcomings and the addition of a high reliability, light footprint satcom solution enables a broader theatre of operation.”

Many countries have yet to introduce legal frameworks to regulate UAV flight operations and manufacturing, meaning that most UAV flights today have to be within radio line of sight or require special exemptions.

However, market forces are in play that suggest change is inevitable, according to Francois Chopard, CEO of Starburst Accelerator.

“The UAV market is very exciting due to the bottom-up emergence of start-ups focused on making UAVs economically accessible to users outside of the military domain,” he says. “The UAV Pop-up Lab is a fantastic way to work with these start-ups to develop propositions that will bring this market to maturity as regulatory certainty improves.”

“The UAV Pop-up lab programme is a grass roots innovation programme that seeks to explore the full scope of benefits available using satellite communication in the commercial UAV market,” says Jordan Picard, Digital Incubation Lead, Inmarsat Product Group.

Applications include search and rescue, ground-mapping, forest firefighting and vaccine drops.

According to PwC* research, the UAV industry in the UK alone will be generating £42bn in incremental GDP by 2030 - just a small fraction of the anticipated global market opportunity.

Inmarsat and its partners believe the use of UAVs will provide a decisive advantage for those operating in remote parts of the globe that will be immediately recognisable. With-

Picard expresses similar confidence. “Even at this early stage, our expectation is that the commercial UAV market will grow exponentially in the next five to 10 years, with satellite playing a crucial role in remote areas,” he says. “This aligns with Inmarsat’s role as the leading provider of global, resilient satellite communications for mobile assets. It also links nicely to the emerging digital economy of tomorrow.”

The offshore sector is just beginning to shake off a five year dip in fortunes and put assets back to work, and is once more prioritising data analytics and diagnostics technology to optimise performance, condition monitoring and remote diagnostics of subsea assets.

Subsea, ROVs and AUVs have provided critical gains through standardizing operations and centralizing project management, with video streaming providing operators on the surface with the ‘eyes’ to get the job done.

The same safety benefits apply in the case of airborne drones, where remote inspection techniques are already covered in International Association of Classification Societies

(IACS) Unified Requirements, which took effect in January 2019. Lloyd’s Register recently offered new guidance notes on UAV inspections based on a pilot flare tip and boom inspection for the ENI offshore installation Liverpool Bay, and a ‘Test and learn’ project for a Maersk Drilling rig. LR is also working with Oil Spill Response Ltd (OSRL) drone-based inspection service provider Sky-Futures to trial a surveillance/reconnaissance application.

Fly-by inspections negate the need for humans risk of scaling structures, while Picard also points out that drones are faster to mobilise than field inspectors, don’t mind antisocial hours or need accommodation.

On another level, floating rigs need to be taken out of operation for essential maintenance checks every five years, and getting the schedule wrong can involve losing earnings of $300,000 to 400,000 per day perhaps for up to three weeks. Picard says that the tests carried out to date are showing the way routine remote inspections allow actionable decisions to be made on a predictive basis so that repairs can be planned at the budgeting stage. “This type of budgetary control is a key reason why, despite higher upfront investment, UAVs will cost less than traditional manual inspection.”

Picard adds that the UAVs are delivering high quality data for specialist analysis in real-time and that inspections can be reviewed by competent personnel, yielding integrity assessments for areas of concern, while captured images can be subjected to closer inspection, monitoring continued to evaluate degradation rates.

“In a nutshell, we’re learning that UAVs deliver real value when it comes to obtaining critical data in hard-to-reach places where terrestrial networks are spotty,” Picard says.

“This can mean the difference between life and death for emergency response, and of course there is a straightforward safety gain when inspectors are not exposed to high risk activities. However, UAVs should also be recognized for the way they can help companies with heavy operational footprints in remote areas to save millions. That’s where the global satcom solution using L-band becomes a massive enabler.”

*https://www.pwc.co.uk/intelligent-digital/drones/Drones-impact-on-the-UKeconomy-FINAL.pdf 37

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VSP Measurements used as a Tool for Sub Salt Near Field Development Introduction The field example presented is located onshore Northem Germany. The field has been in production for 20 years and development currently plans for two wells per year on average. The reservoir is a relatively low permeable, deep Rotliegend dry gas field. Despite numerous wells and a comprehensive data set collected over the years, mapping of faults and understanding of dynamic compartmentalisation remains the key challenge for further drilling and field development.

The main reason for this is that the available surface seismic data set is strongly reduced in quality at reservoir level over the majority of the field, mostly due to intense salt tectonism in the overburden and unfortunate acquisition parameters. The available 3D data set from 1993/94 was acquired using the “Northem German Grid” survey design which was default for each 3D acquisition in the 90’s. This grid is basically oriented North-South and is not optimised to the geological setting. This causes problems in illuminating structures undemeath the salt bodies. Consequently, only prominent faults with throws of more than 50m can be interpreted in parts of the field. Even then is the orientation of those faults often ambiguous.

Production experience furthermore suggests that also faults well below seismic resolution have a significant baffling influence affecting reservoir communication.

Additionally, due to poor seismic resolution, distinguishing ‘true’ fault structures from

seismic processing artefacts is a very difficult task in many places of the field.

part of the well, velocity information (time -depth curves) is of minor interest.

This is particularly illustrated with attempts to reconcile production data from wells and compartmentalisation seen in seismic. In various places those data do contradict each other significantly.

The processing of the VSP is therefore optimized for creation of a VSP image which retains small structures and can be incorporated into the surface cube to fill the data gaps of the 3D data set. Down-wave separation was simplified by using polarisation techniques as described by Ahmed [1986].

Up-wave separation was model-based and applied to each source and receiver pair in turn. The imaging was based on Dillon 1984 but used a 3D model to guide the location of the migration ellipses.

Due to permitting restrictions and public resistance the acquisition of new 3D data is not possible. DEA is therefore using VSP measurements as a central field development tool. In the last five years DEA have started to record VSPs in deviated outstep wells to image the section below the well path for fault detection in the reservoir. The results have shown to be crucial not only for improving the understanding of the reservoir structure but even more so to de-risk a potential sidetrack location . Thus early VSP results after drilling represent critical data to reduce the overall project risk of development wells and are therefore now included in the decision process of every project.

Method and Theory Based on the relationship between the well path and the salt dorne, a spread of different VSP record geometries (far offset, zero offset, walk above) is used in every single well to make sure that at least one of the VSP images illuminates subsalt structural features. To achieve this, the VSP geometry is planned using 2 D ray path models minimizing the travel time through the salt.

The focus of the measurement is purely on the seismic image underneath the deviated

The interpretation of the final VSP image is discussed within an interdisciplinary team of geophysicists, geologists and reservoir engineers. The VSP delivers structural information that has to be implemented in the overall geological model which is based on seismic and well data (core, FMI, logging, production data etc.).

Examples The VSP measurements re of far better quality than the vintage surface seismic.

They provide detailed information of faulting (fault density, throw, etc.) and have a higher vertical resolution that allows separation of different reservoir sands (thickness estimation, pinch­outs, etc.).

Operational experience also showed that VSP results were usually available two weeks after acquisition. Thus the results could already be included together with 39

Figure 1: Comparison of 3D seismic (left) and VSP image along a deviated well path (right). Tue VSP image proves the continuity of the lead horizon underneath the salt dorne

Figure 2: p/Z plot confirms VSP results that all wells are in cornmunication and cannot be separated by a fault as seen in the 3D surface seisrnic.

40 | MED OIL & GAS | September 2019

Figure 3: Tue 3D seisrnic image (left) suffers from migration artefacts a continuous interpretation of the lead horizon is impossible. Tue VSP image along a deviated well path (right) shows the extension of the lead horizon and a fault probably covered by a thin salt pillow above.

well testing and logging results. This timing is of huge benefit in case a technical or geological side track is required as an immediate follow up.

Figure 1 shows an example of a VSP recorded with a combination of near and far offset source geometries in a well which has a target directly underneath a salt dorne structure. The comparison of the surface seismic with the VSP image shows an immense difference. The image of the surface seismic can be easily misinterpreted resolving a fault structure in the reservoir. The image of the VSP shows a continuous reflection from the major surface seismic horizon at top of reservoir. The former assumption of a north and south compartment separated by the fault shown in the 3D surface seismic is rebutted by the VSP result and matches the production data (see Figure 2).

The example in Figure 3 shows a normal fault with a throw of 70 to 100 meters underneath the edge of a salt diaper not resolved in the 3D surface cube. Based on this result a geological side track is planned and de-risked.

The example in Figure 3 shows a normal fault with a throw of 70 to 100 meters undemeath the edge of a salt diaper not resolved in the 3D surface cube. Based on this result a geological side track is planned and de-risked.

Conclusions The results so far clearly show that reservoir understanding greatly improves from VSP data in many parts of the field. By means of the VSP results, it is possible to fill local gaps in the 3D which cube obtains a better control of the reservoir and the fault polygons. By discussing these results in an interdisciplinary team the results of the 2D measurement are implemented into the field development model used for well development. Thus the VSP reduces the risk of economical failure in parts of the field where the classical approach of well planning based on 3D seismic interpretation does not work due to limited resolution in the data set.

Consequently the improved reservoir illumination puts the VSP on the critical path for drilling projects. Particularly for step out wells, VSPs are a central part of the decision process in the event that a geological side track is needed.

Another important advantage especially onshore Germany shows the economical comparison of a new 3D acquisition and a VSP. A VSP is cheaper and faster to acquire. It minimizes costs and impact for the local population. Especially the minimization of the impact is important due to public resistance against the gas production in that area.

Authors

Thomas Bartels, Manuel Gelhaus DEA Deutsche Erdoel AG and

Mary Humphries VSProwess

References Ahmed, H., Dillon, P.B., Johnstad, S.E. and Johnston, C.D., 1986. Northern Viking Graben multilevel three-component walkaway VSPs- A case history: First Break Vol 4, No 10, October 1986.

Dillon, P.B. and Thompson , R.C., 1984.

Offse t source VSP surveys and their image reconstruction. Geophysical Prospecting 32, 790-811.

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PRESS RELEASE

Large-scale conversion project on offshore platform Molikpaq operated by Sakhalin Energy • First of two offshore cranes has already been replaced • Modernisation of a third, already existing crane has been finished • Total pro Rostock, February 2019 – Liebherr’s maritime customer service is carrying out an extraordinary modernisation project on Sakhalin Energy’s Molikpaq offshore platform off the Russian island of Sakhalin. Two ram luffing offshore cranes, type RL 1500 are going to be completely renewed. An existing crane, type BOS 1900 will be upgraded with the same generation control system as the RL 1500.

Molikpaq operated by Sakhalin Energy was the first Russian offshore oil production platform. Commercial oil production from the platform was launched in 1999. Since December 2008 oil from the platform streams through the trans-Sakhalin pipeline system to the oil export terminal of the Prigorodnoye production complex. After two decades of continuous operation, the existing three Liebherr offshore cranes now need to be renewed. Liebherr accepts this challenge and will completely replace two of the offshore cranes while the third device will be modernised for further operation. In terms of planning, logistics, technology and craftsmanship, this is an extraordinarily demanding conversion project. Several Liebherr companies cooperate with each other to implement the project. The contract drafting and signing were carried out by Liebherr-Russia OOO (Russia). LiebherrMCCtec Rostock Gmbh (Germany) is responsible for the operational refurbishment of the platform. Liebherr-Werk Biberach GmbH (Germany) participates in the conversion with a tower crane which is used as a support crane for lifting large components. Since the start of the project in 2016, over 6,000 planning hours have already been invested in the project.

The replacement of the first crane (Liebherr BOS) with a brandnew Liebherr RL 1500 has already been executed from spring to autumn 2018. 24 Liebherr employees of various nationalities were involved in the realisation of the first stage of the project. In order to be able to move large parts on the platform, Liebherr installed

a tower crane of the type 230 HC-L 8/16 Litronic to be used as a support crane. In addition, a special sliding system was designed and built by Liebherr´s customer service team to move particularly heavy components and modules over the platform. The extreme weather conditions and limited space on the platform demanded full concentration and professionalism from the involved Liebherr staff.

The entire conversion project is planned to be completed by the end of 2020.

The second phase, the modernisation of the existing BOS 1900, has also already been finished. The main reasons which triggered this modernisation was to have the same software and handling for the crane operators as the two new RL 1500. A further reason is to use as far as possible the same control system components in the modernisation as used for the new RL 1500. This increases the spare parts interchangeability and availability. Additionally it reduces the spare parts storage costs. The third phase will include the installation of the second ram luffing crane until the end of 2019. Both RL 1500 cranes are characterized by a cylinder luffing box boom design and a diesel-hydraulic driven main engine. Considering the project specifics, the cranes can handle loads up to 65 tonnes. That means 25 tonnes more than the standard lifting capacity of Liebherr RL 1500. This customized solution has been ensured by providing a three fall reeving. Equipped with a main and an auxiliary hoist the RL cranes have a maximum outreach of 42,6 meters. This makes them an ideal solution for general purpose applications such as maintenance work or lifting supply.

In order to take the environmental conditions into account, the cranes are equipped with an arctic temperature package which allows operation down to -36°C. Another feature of these ram luffing cranes is the large and comfortable cabin. Upon customer request a mid-sized cabin with 10 m³ is installed.

To both avoid heavy loads and thereby ensure easy handling of components onsite, the box boom has been split into two pieces.

After mounting the pivot piece to the column, the second boom section has been assembled via bolted connections.

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48 | MED OIL & GAS | September 2019

PRESS RELEASE

CIMC Raffles Yantai ordered Liebherr Board Offshore Crane for oil and gas activity in Africa.

• BOS 2600 will be used in the BP Greater Tortue Ahmeyim Field off the coast of Mauritania and Senegal • The maximum lifting capacity is 30 tonnes • In 2020 Liebherr will deliver the crane from its production site in Rostock, Germany to the shipyard CIMC Raffles in Yantai, China who are performing the engineering, procurement and fabrication of the Jack Up accommodation platform.

requirements for the crane are IECEx certification requirements for outside-assembled parts. The BOS 2600 has a lattice boom with a maximum working outreach of 54,5 metres and is equipped with Liebherr Litronic, the company’s in-house developed control system which is the centrepiece for precise crane operations.

Rostock (Germany), August 2019 – Liebherr-MCCtec Rostock GmbH together with CIMC Raffles signed a contract concerning the delivery of a board offshore crane, type BOS 2600. The company BP will use the crane for supply and maintenance tasks on its Jack Up accommodation platform next to the African west coast.

The BOS 2600 is a compact and function-orientated crane design within the well-known Liebherr Offshore crane series and therefore the ideal solutions for platforms where space on deck is limited.

“Because of the particular requirements of this project, we are pleased that CIMC Raffles awarded us the contract for the project. With our product we have passed this challenge and fulfilled all contractual agreed specifications”, says Stefan Schneider, Area Sales Manager for Offshore Cranes. Further

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Demand from Asia is set to power the growth of the global gas industry over the next five years After another record year, global demand for natural gas is set to keep growing over the next five years, driven by strong consumption in fast-growing Asian economies and supported by the continued development of the international gas trade.

Demand for natural gas grew 4.6% in 2018, its fastest annual pace since 2010, according to the IEA’s latest annual market report, Gas 2019. Gas accounted for almost half the increase in primary energy consumption worldwide. Demand is expected to rise by more than 10% over the next five years, reaching more than 4.3 trillion cubic metres (tcm) in 2024.

“Natural gas helped to reduce air pollution and limit the rise in energy-related CO2 emissions by displacing coal and oil in power generation, heating and industrial uses,” said Dr Fatih Birol, the IEA’s Executive Director. “Natural gas can contribute to a cleaner global energy system. But it faces its own challenges, including remaining price competitive in emerging markets and reducing methane emissions along the natural gas supply chain.”

China is expected to account for more than 40% of global gas demand growth to 2024, propelled by the government’s goal of improving air quality by shifting away from coal.

Chinese natural gas consumption grew 18% in 2018 but is expected to slow to an average annual rate of 8% to 2024 as a result of slower economic growth.

2018 was another golden year for natural gas, driven

by China’s battle against air pollution (Photograph: Shutterstock)

consumer of natural gas, in spite of slower growth due to strong competition from renewables and coal.

Gas 2019 also focuses on the role of liquefied natural gas (LNG) at sea, which is set to emerge as a fast-growing alternative fuel because of stricter rules on sulphur content that take effect in January 2020.

Supplies to meet growing global demand for natural gas will come from both new domestic production in fast-growing economies but also increasingly from major exporting countries, led by the development of abundant shale gas resources in the United States.

The IEA also sees strong growth in gas consumption in other Asian countries, particularly in South Asia. In Bangladesh, India and Pakistan, the industrial sector is the main contributor to growth, especially for fertilisers to meet the needs of growing populations.

The strong growth in LNG export capacity will enable international trade to play a growing role in the development of natural gas markets as they move towards greater globalisation.

Industrial use of natural gas, both as a fuel and a feedstock, is set to expand at an average annual rate of 3% and account for almost half of the rise in global consumption to 2024. Power generation remains the largest

Investment in LNG projects have rebounded in 2018 after several years of decline, and the large number of projects due to take final investment decision in 2019 is likely to further support trade and market expansion.

50 | MED OIL & GAS | September 2019

However, more investment will be needed in the future.

The recent convergence in market prices in major regions gives an indication of the increasing globalisation of the natural gas trade. Establishing market-driven pricing mechanisms in fast-growing economies remains a challenge, however. Recent reforms in major markets are sending encouraging signals, but more will be required to ensure the sustainable market-driven development of natural gas in these economies.

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