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The Welltesting Network

HOT TOPIC MEETING #14

Welltesting in Harsh Environments

18th September 2002

Hosted By Alistair Stenhouse Of Aberdeen

This report contains the meeting presentations and group discussions. It is a reference document, with 2 levels of detail plus a contents list and index to help locate items of interest.

Abstracts of the contents are loaded onto the ABDAB database enabling keyword searching. All presentation image downloads are provided in a Presentation Gallery on WTNISS. Information is provided in this report in good faith for the benefit of WTNISS members. However, the information may be incomplete, inaccurate, out of date or incorrect. Before taking any action which references information obtained from the report, it is essential that you verify the information with the original source. Win Cubed Limited and all WTNISS participants make it a condition, in allowing you access to this report, that you accept that they will not be liable for any action you take in reliance on the information contained within.

John Curley 19th January 2004

John Curley Win Cubed Tel : (44) 1494 673339 [email protected]

WIN CUBED LIMITED

John Curley

WTN HTM#14 - Welltesting in Harsh Environments - 18th September, 2002 ____________________________________________________________________

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CONTENTS CONTENTS ............................................................................................................................................2

INTRODUCTION ..................................................................................................................................3

PRESENTATION GALLERY ..............................................................................................................4

SUMMARY.............................................................................................................................................5

ATTENDEES..........................................................................................................................................7 CONTACT LIST......................................................................................................................................7

ROUND THE TABLE INTRODUCTIONS.........................................................................................7

END OF MEETING REMARKS..........................................................................................................8

PRESENTATIONS...............................................................................................................................15 1. DP RIG OPERABILITY STUDY FOR WINTER TESTING OFF THE FAROE ISLANDS - ALISTAIR STENHOUSE, AMERADA HESS .................................................................................15 2.. WEATHER AND DOWNTIME SIMULATIONS - ADRIAN ADAMS, AMERADA HESS.....30 3. DEEPWATER CLOSED CHAMBER DST - GEOFF GILL, AMERADA HESS ........................40 4. OVERVIEW OF ORMEN LANGE GAS TEST IN DEEPWATER WITH A DP RIG - MARK COOPER, NORSK HYDRO .............................................................................................................50 5. MARATHON HARSH OFFSHORE ENVIRONMENT WELLTEST ISSUES AND CONCERNS - GREG STIMATZ, MARATHON....................................................................................................64 6. GOOD PRACTICE IN HARSH ENVIRONMENT TESTING - ALAN CHRISTIE, SCHLUMBERGER ...........................................................................................................................69 7. HARSH ENVIRONMENTS - A SERVICE COMPANY PERSPECTIVE - BEN STEWART, HALLIBURTON...............................................................................................................................77 8. SERVICE COMPANY ENGINEERING DEVELOPMENT STRATEGY FOR HARSH ENVIRONMENTS - BRIAN IMRIE, SCHLUMBERGER...............................................................87

INDEX ...................................................................................................................................................97


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INTRODUCTION • The Welltesting Network Hot Topic Meeting#14 on WELLTESTING IN HARSH

ENVIRONMENTS was held on 18th September 2002, in Aberdeen, to discuss the technical issues surrounding harsh environment welltesting.

• Harsh environments refers to the location, for example a hostile marine environment, as distinct from well conditions, ie it was not about HPHT welltesting.

• The meeting was predominantly attended by experienced engineers who presented planning case histories and descriptions of good practice. It was mixed with discussion about related “real world” issues.

• Pushing aside the technical discussion to an extent, a shared concern surfaced that the industry is rapidly losing its capability to conduct this sort of operation properly. Attendees at the meeting had their individual observations and opinions validated by hearing that people in other companies had reached the same conclusion. The group was big enough, international enough and balanced enough to be representative. Their key assertions were that :

• 1. The service industry is rapidly losing its capacity to conduct high quality tests in challenging harsh environments. This is a response to declining operator demand. There is also now low or zero new investment in the technology. The capability remains, but not off the shelf – each job is a special project now. When jobs do go ahead there is said to be a greater incidence of problems than there used to be (due to lack of experience and practice).

• 2. Harsh environment welltesting is a niche which seldom makes money for service companies. Cost are high, but revenue is low. Considerable investment is needed to build the equipment, yet usage is limited and uncertain. Traditional operating company-service company contracts do not remunerate the service companies sufficiently to carry on – ie, the way risk, and regret costs are handled.

• 3. Value added by welltesting is not appreciated enough to make it happen. Dynamic test data from hydrocarbon offtake during a welltest generally has a unique value in reducing oil and gas field development risk. Welltest engineers typically react with disbelief when this is not intuitively obvious to subsurface staff or decision makers, but the “battle” is being lost. Cost and environmental concerns seem to be defeating the value creation argument.

• 4. The industry is changing; the chances of arresting the decline are low. The meeting provided a “wake up call”, however an industry reaction does not seem likely; the current trend is likely to continue. Positive changes - to break the trend - could be made by the service companies, but not without engagement and confidence-building by the operating companies.

• 5. New investment, innovation and therefore better equipment would help - to reduce rig time during harsh environment testing. A convergence of underbalanced drilling technology, testing while drilling and closed chamber testing might be the key. However, as above, lack of confidence in the future will undermine the chance of such investments being made.

• An Open Letter to attract management attention was drafted - which got support from several attendees, but rather more attendees preferred silence and it was hence withdrawn.

• Instead a questionnaire was created and sent out to WTN members. There were 20 replies to the questionnaire plus 3 views expressed in the lead up to issuing the questionnaire. These split down as 15 replies from operators and 8 replies from service companies. A couple of people sent in earlier comments. Consequently, when we add in the HTM attendees themselves, a sample of about 35 WTN members contributed to the report.


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• The replies were consolidated and summarised in : “Harsh Environment Welltesting Capability Decline Report and Questionnaire Results” in November 2002, which can be found at : http://www.wincubed.co.uk/wtn/wtniss/reportd/declinan.doc.

• Comments from both service company and operating company staff mesh together. It is hard to avoid the conclusion that they illuminate “two sides the same coin” – that the industry harsh environment welltesting capability is declining in all the service providers in response to light operator demand.

• The Decline Report serves to: 1. Provide a historical document which shows how a cross section of WTN members

view this matter at this point in time. 2. To provide a basis for conversations on these matters between interested

managers in the operating companies and the service companies. • The Decline Report records the words people actually used, although all responses

are anonimised. Effort has gone into summarising the issues fairly, hopefully neither over-dramatising or under-stating.

PRESENTATION GALLERY The Presentation Gallery for HTM#14 can be found at http://www.wincubed.co.uk/wtn/wtniss/reportd/hostgall.html

Presentation Download

• Talk 1 : Alistair Stenhouse, Amerada Hess Aberdeen : DP rig operability study for winter testing off the Faroe Islands.

• http://www.wincubed.co.uk/wtn/wtniss/reportd/hostgall/astenhouse.ppt

• Talk 2 : Adrian Adams, Amerada Hess Aberdeen : Weather and downtime simulations.

• http://www.wincubed.co.uk/wtn/wtniss/reportd/hostgall/aadams.ppt

• Talk 3 : Geoff Gill, Amerada Hess Aberdeen : Use of: Closed Chamber DST design, Subsea Test Tree run in a "Locked Open" mode without any hydraulic umbilicals and use of acoustic telemetry system for realtime SRO.

• http://www.wincubed.co.uk/wtn/wtniss/reportd/hostgall/ggill horiz.ppt

• http://www.wincubed.co.uk/wtn/wtniss/reportd/hostgall/ggill vertical.ppt

• Talk 4: Mark Cooper Norsk Hydro Bergen : Overview of Hydro's recent Ormen Lange Gas test in deepwater with a DP rig.

• http://www.wincubed.co.uk/wtn/wtniss/reportd/hostgall/mcooper.pdf

• Talk 5: Greg Stimatz, Marathon Houston, Talk from the Seat : Marathon harsh offshore environment during the summer of 2003 - issues/concerns.

• No presentation materials.

• Talk 6: Alan Christie, Schlumberger Houston: Pre job engineering, equipment qualification, operational interfaces and management of deepwater testing safety systems.

• http://www.wincubed.co.uk/wtn/wtniss/reportd/hostgall/achristie.pdf

• Talk 7: Ben Stewart, Halliburton: Harsh Environments - A Service Company Perspective.

• http://www.wincubed.co.uk/wtn/wtniss/reportd/hostgall/bstewart.ppt

• Talk 8: Brian Imrie, Schlumberger Stavanger, Talk from the Seat : Service company engineering development strategy for harsh environments.

• No presentation materials.

http://www.wincubed.co.uk/wtn/wtniss/reportd/declinan.doc

http://www.wincubed.co.uk/wtn/wtniss/reportd/hostgall/astenhouse.ppt

http://www.wincubed.co.uk/wtn/wtniss/reportd/hostgall/astenhouse.ppt

http://www.wincubed.co.uk/wtn/wtniss/reportd/hostgall/aadams.ppt

http://www.wincubed.co.uk/wtn/wtniss/reportd/hostgall/aadams.ppt

http://www.wincubed.co.uk/wtn/wtniss/reportd/hostgall/ggill vertical.ppt

http://www.wincubed.co.uk/wtn/wtniss/reportd/hostgall/ggill vertical.ppt

http://www.wincubed.co.uk/wtn/wtniss/reportd/hostgall/mcooper.pdf

http://www.wincubed.co.uk/wtn/wtniss/reportd/hostgall/mcooper.pdf

http://www.wincubed.co.uk/wtn/wtniss/reportd/hostgall/achristie.pdf

http://www.wincubed.co.uk/wtn/wtniss/reportd/hostgall/achristie.pdf

http://www.wincubed.co.uk/wtn/wtniss/reportd/hostgall/bstewart.ppt

http://www.wincubed.co.uk/wtn/wtniss/reportd/hostgall/bstewart.ppt


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SUMMARY

1. Hit List - To Draw Management Attention To Concerns About Harsh Environment Welltesting. This Hot Topic Meeting was called to discuss the technical issues surrounding harsh environment welltesting. Pushing aside the technical discussion to an extent, a shared concern surfaced that the industry is rapidly losing its capability to conduct this sort of operation well. It was agreed to use the meeting outcome to address these concerns to management - in both the operating companies and service companies. An Open Letter to attract management attention was drafted - which got support from several attendees, but rather more attendees preferred silence and it was hence withdrawn. Instead a questionnaire was created and sent out to WTN members, which in turn led to a report.

2. Dwindling Industry Welltesting Capability Attendees from both service companies and operating companies referred to concerns about the dwindling industry capacity - in terms of equipment and people - to conduct high quality tests in a wide range of harsh environments (not just harsh marine).

3. Future Technology Developments in Harsh Environment Welltesting Harsh environment technology development needs to be in directions which can reduce rig time on the job. This was seen to be in convergence with underbalanced drilling technology - moves towards testing while drilling and closed chamber testing techniques.

4. Contracting Strategy - To Support A Future Testing Infrastructure Harsh environment welltesting is a niche which seldom makes any money for service companies due to the considerable investment needed but limited and uncertain usage. Looking for ways forward, there were suggestions to review the traditional operating company-service company contracts which are part of the problem. They tend to skew more of the risk onto the service companies and mis-align the financial interests of the parties.

5. The Value Of Dynamic Test Data To Development Risk Reduction Dynamic test data from hydrocarbon offtake during a welltest generally has a unique value in reducing oil and gas field development risk. Welltest engineers typically react with disbelief when this is not intuitively obvious to subsurface staff or decision makers. Cost and environmental concerns seem to be defeating the value creation


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argument. There are parts of the world where the geology and fluids are so well known that dynamic data may be a luxury, but many more where it is essential. High cost marginal deepwater areas are a case in point. Incorrect exploration data can significantly reduce development economic viability in the longer term.

6. Harsh Environment Testing - A Project Not An Operation Preparation for a harsh environment welltest requires a well-led, significant, multidisciplinary effort, spread over a long time frame; often several months to a year. It is consequently better regarded as a project than merely a commodity or routine operation. This implies the need for familiar project management tools and techniques to be used throughout.

7. Harsh Environment Testing - Planning and Preparation The particular requirements need identifying for each test, in order to set crystal clear objectives. Only then can the right tool be chosen and tailored for the test. That is a general truth, but the ramifications are magnified in harsh environments. For example, if you do not have to flow to surface to meet your objectives then do not flow to surface. A significant amount of effort and cost needs to go into the preparation. It is important to show management the options, costs and risks early on in the planning process. It is also important to have time for discussion to get the subsurface people off “dead centre” (ie their desire for perfect data) without considering the cost, safety or operational aspects of gathering it.

8. Harsh Environment Testing - Wider Thinking To Cut Down On Rig Use The punitive cost driver in harsh environment testing is the rig cost, rather than the testing service costs or capital costs for purchase of equipment. Wider thinking is needed on methods and technology to help minimise the amount of rig time which is needed, while still gathering acceptable quality data. Hence the long preparation times.

9. Harsh Environment Testing - Managed Process Of Reduced Data Acquisition The need for a managed process of reduced data acquisition is part of minimising rig time during testing. This might mean less data (taken in less time) or lower quality data if that can be obtained faster. The point is about balancing the time spent with the quality of the data obtained - so it remains both “cost effective” and “fit for purpose”.


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ATTENDEES

Contact List Name Company Phone No internet

1. Adrian Adams Amerada Hess Aberdeen (44) 1224 243083 [email protected] 2. Ashley Brammer Amerada Hess Aberdeen (44) 1224 243025 [email protected] 3. Geoff Gill Amerada Hess Aberdeen (Blackwatch) (44) 1467 643082 [email protected] 4. Alistair Stenhouse Amerada Hess Aberdeen (Integra) (44) 1224 243588 [email protected] 5. Dermot McCollum Expro Aberdeen (44) 1224 214961 [email protected]. Sandy Forbes Expro Aberdeen (44) 1224 225982 [email protected] 7. Ben Stewart Halliburton Aberdeen (44) 1224 776277 [email protected] 8. Brian Nutley Halliburton Aberdeen (44) 1224 776130 [email protected] 9. Ray Bullock Halliburton London (44) 1372 866801 [email protected] 10. Arild Fosså Halliburton Norway (47) 51 83 71 70 Arild.Fosså@halliburton.com 11. Greg Stimatz Marathon Houston (1) 713 296 2220 [email protected] 12. Mark Cooper Norsk Hydro Bergen (47) 55 99 54 65 [email protected] 13. Alan Christie Schlumberger Houston (1) 713 715 2108 [email protected] 14. Brian Imrie Independent (was Schlumberger Stavanger) (44) 1337 828516 [email protected] 15. Øystein Jensen Smedvig Aberdeen (47) 51 50 97 99 Ø[email protected] 16. John Curley Win Cubed London (44) 1494 673339 [email protected]

ROUND THE TABLE INTRODUCTIONS Ben Stewart: I’m in Halliburton’s Business Development Group in Aberdeen. I’m interested in the dialogue here today - to get a feel for where people think we are as an industry - in terms of deciding to test in the environments we’re moving into. Alistair Stenhouse: I work for Amerada Hess. We’re currently preparing for two deepwater wells in the Faroes. I was involved with the same DP rig last year for two wells which didn’t test. It was quite a challenge to look at testing in the autumn on a DP vessel in deepwater. Ashley Brammer: I’m the supervisor of the trees and wellheads group for Amerada Hess. I’m here more on the harsh environments side than the welltesting side. Øystein Jensen: I’m with Smedvig. I’m a drilling section leader on the West Navion. I start as the rig leader in the Operations group next week. I’m interested in the discussions today. Arild Fosså: I’m a technical advisor in the business development group for Halliburton. I’m mainly here to see what people consider to be “Harsh Environments”. Mark Cooper: I’m a consultant working for Norsk Hydro in Bergen in the completions department - dealing mostly with welltesting. I’ve come to hear about hazardous environments and to talk about the planning for tests we recently did in the North Sea offshore Norway. Sandy Forbes: I work in the business development group for Expro North Sea. I’m interested in the problems associated with DP vessels. Dermot McCollum: I’m the processing engineering team leader for Expro in Aberdeen. I’m primarily involved in surface equipment and I’m here to learn and pick up as much as I can. Greg Stimatz: I work in Marathon’s deepwater and completions organisation in Houston. Marathon is preparing for drillstem tests off Nova Scotia - next year or perhaps the year after. I’m here to learn what I can about harsh environments. Brian Imrie: I work for Schlumberger in Norway. I’m here today to figure out what we as service companies should be developing for these harsh environments. I think we’re wasting an awful lot of money on kit that’s never used and it’s getting left on the shelf. Alan Christie: I’m the Schlumberger subsea business development manager based in Houston. I look after subsea well control systems. Today I’d like to find out where the business is going and see what technology development and people training is needed.. Ray Bullock: I work for Halliburton in Leatherhead. My interest today is to listen to our client’s views on harsh environment operations and the challenges they face. Brian Nutley: I’m UK sales manager with the business development group in Halliburton Aberdeen. Like many folks here, I have a major concern over the amount of kit we have on the shelf and the amount of money we’re making from it. Geoff Gill: I work for Blackwatch Petroleum Services and am currently working with Alistair in Hess preparing the two tests on the West Navion.


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END OF MEETING REMARKS

Hit List - To Draw Management Attention To Concerns About Harsh Environment Welltesting • Øystein Jensen : There were good presentations here today. I heard concerns from

service companies today and it was disappointing we only had representatives from 3 oil companies. What is the process after this meeting - will the thoughts get presented to management in any way?

• John Curley : Where we agree there is a message to send out, we do it. The first thing is to get some wording which is worthy of sending out and then we release it. There are past examples on improving HPHT pressure gauges and the famous list of “51 issues” which was about preparing for deepwater testing in DP mode in Northern Norway. The first delivery in this case is the Quick Report which takes a week to prepare.

• Alistair Stenhouse : It can contain a “hit list” of our concerns to pass up to our respective managements.

• Greg Stimatz : It’s up to us collectively as WTN members to make sure that gets into the hands of our managements. They will not visit the website or read a lengthy report but it’s up to us to try and get them to read such a hit list paragraph.

Dwindling Industry Welltesting Capability • Alistair Stenhouse : Looking around the table and thinking about what has been

discussed, the expertise and equipment levels -i.e. the capability - is leaving our industry. That will limit our ability to perform a welltest unless we get the message over to upper management on all sides that we need to change things.

• Ray Bullock : It was also good to see the concern is shared over service delivery. As an industry we are losing the ability to deliver high quality service as a routine. We used to deliver it routinely. Problem jobs were a rarity. Now they are becoming more and more common.

• Mark Cooper : We as operators need to get together with the service companies to come up with some solution to the dying out of the expertise and find ways to manage that. I’m not sure if anything can be done - perhaps more can be made of the “flying squad” approach - where there are small teams of experts who work globally.

• Alan Christie : That’s basically one of the avenues we can go down. We can take the expertise, put it in one place and then do some planning with the clients so we have a place where we can keep an eye on the needs of all the clients. It’s not common - in the sense that testing in harsh environments is not happening 3-4 times a week. There are only certain rigs which can do it, and only a certain number of people, and only a certain number of clients who can do it. And there is only a certain amount of equipment within each service company. So it is a case of planning and addressing resources to meet the demand, keeping it all together, so we can deploy those resources.

• Mark Cooper : I’ve seen the same thing with well test interpretation. Somebody who has never done it before doing an interpretation which becomes a basis for a whole development project. Both Schlumberger and Halliburton have what could be called “Flying Squads” of people with expertise who are constantly doing their specialist testing jobs. They keep up their experience level this way, but at the moment they are only brought in when you cannot be supported using the local people.

• Ray Bullock : They are used to fill in the high points of activity, rather than to be the nucleus of the expertise.

• Alan Christie : And maybe this is what needs to change.


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• Mark Cooper : The Flying Squad people tend to be real experts. They are always welcome on my jobs.

• Sandy Forbes : Welltest demand is decreasing. When the demand for traditional welltesting resources decreases, the resources must decrease too. We will have to consolidate the resources. The key question is how we consolidate the resources - it can be into geographical pools of experts or by simply pulling out of certain activities and working elsewhere. That may be a problem, both for the client and ourselves. The client needs to consider whether he wants to keep competition alive within the industry, or just have one very large company.

Future Technology Developments in Harsh Environment Welltesting • Alistair Stenhouse : To survive, the DST needs to be nearer to the drilling

process. Whether this means closed chamber, modified closed chamber, SILD or whatever, we need to reduce costs and complexity. The main cost driver is rig time - rather than the cost of the services themselves.

• Geoff Gill : I have attended one other WTN meeting before this. I’m struck that so many of the conversations seem to be about how the welltesting industry as a whole is decreasing, and that people are worrying away at how that can be rectified. It seems to be a similar conversation that we had today. I do not have a solution to offer to reverse that, but someone, somewhere, will need to hatch a bright idea to use the skills that people have got in a novel way - to at least keep them in the industry. Otherwise they will disappear. I suspect we need something which is used in place of the wireline fluid sampler.

• Alistair Stenhouse : I do not think that is far away. • John Curley : Geoff, you are talking about something which is beyond the wireline fluid

sampler, going in the direction of closed chamber testing or beyond it? • Geoff Gill : Yes. • Brian Imrie : That brings to mind the cased hole MDT. We have now got it working. It

can shoot a hole in the casing and plug it after taking a sample. With that kind of track record on innovation, we should be able to get more. The cased hole MDT has taken 10 years to develop, but hopefully we will see new things in a shorter timeframe.

Contracting Strategy - To Support A Future Testing Infrastructure • Ben Stewart : I valued the recognition, by everyone in the room - both operator

and service company staff - that we really must take a hard look at how we price and buy services. The way we are doing it now will not support a future infrastructure. Basically we as a service company want to sell the operator a better welltest result. For us, that might mean a better price margin, but it also reduces the risk to the operator. We need to do more to align the financial interests of the buyer and the provider.

• Alan Christie : It was good to hear that there is a shared concern over our ability to deliver services today, and the way that it is done. This is dear to me at the moment because I am trying to change things. I’d value any help I can get from other people. That was key for me today, because it is an issue. It seems like I am


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hearing of cases almost every day where some form of specialist service gets delivered badly - because of problems with the organisation and structure which is delivering it. I am pleased to know from today that I am not on my own in believing this. There is also a concern from the client’s side.

• Ray Bullock : It was good to see the shared concern on contracting strategy - within the room at least.

The Value Of Dynamic Test Data To Development Risk Reduction • Brian Imrie : There is a challenge for the service companies to try and help the oil

companies take more risk, and to show and explain the value of the dynamic data you go out to acquire. They should also explain that to their colleagues who are working on development projects - since they have a much bigger budget. We need to get the production and development engineers involved in this early stage. It would be excellent to get these engineers in the room with us.

• Alistair Stenhouse : There is maybe something in the background. More and more of the management staff in the oil companies are non-technical, for example accountants rather than petroleum engineers or drilling engineers. They often do not know or see the value of the data intuitively. They gain an appreciation when they are told about it.

• Brian Imrie : I have made a note of the company MERIC. This is a small company Schlumberger acquired recently. They help the “bean counters” make decisions such as going ahead with a development. I should ask them to modify the software to somehow tie-in the value of dynamic data, to reduce the risk.

• Alistair Stenhouse : Twenty years ago we did not need to explain why we needed to do a test. The managers in those days knew it. But now we do.

• Ben Stewart : Using the example from earlier today - about cement plugging the screens run on the DST - a holistic solution is very important. Involving the well construction team is essential to achieving the desired result. If the cement job design is not compatible with the DST, the test is a disaster. The risk to data quality is high. Poor isolation can result in cross-flow between zones, etc. All the pieces in a harsh environment well have to fit together if you want to manage cost, recover high quality data, and achieve results. The critical thing is not planning in isolation. Working alone increases the risk of failure.

• Arild Fosså : I would like to second Brian Imrie’s comment. Halliburton’s Landmark company are already working on something similar to what he wants MERIC to look at. However, the tools available to the Asset Managers are not detailed enough to quite get as close to things as Brian wants - at least not from what I have seen in these programs. Personally I think the only way forward is to be able to demonstrate value of any data gathering exercise in a Net Present Value term. If not, we will just see the industry dwindle and die. There are some promising ideas out there; I think we will start to see the benefits from them in the next few years.

• Another point I picked up recently from our APC company in Aberdeen is that they more frequently run across reservoir simulation models in the oil companies that do not match the production history. I wonder why? Basically what we are seeing is that the core decision basis tool in the reservoir management process is, if not breaking down, at least showing worrying symptoms of inaccuracy. This is probably the long term effect of gradually entering poorer and poorer data into the geological model, during appraisal and exploration of a prospect.


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Harsh Environment Testing - A Project Not An Operation • Alistair Stenhouse : The contractors have made it clear that they should be

involved earlier in the planning process. I believe in that, but I am not sure if the rest of the industry does. The test preparation, especially for harsh environments and other challenging tests, needs to be regarded as a project. It is something we try to do here with minuted weekly progress meetings.

• Ashley Brammer : I have a different perspective, not being a welltester. But we all see the same need for good, strong, well-led project management from early on. It is about getting objectives clear, communication, keeping track of what everyone is doing and keeping everyone in the loop.

• Dermot McCollum : We tend to run our unusual jobs in line with the “bread and butter” jobs. So the same people are doing them, the same supervisors - they are already very busy. Alistair brought up earlier the importance of having one principal contact for a job - it smooths the way to help get the job done. We did a recent HPHT job and put a project manager on it - and the client was delighted. We can do that more for unusual jobs. The oil companies and service companies need to agree what the definition of an unusual job is. But it is distinct from the “bread and butter” welltest where the equipment is the standard suite and everyone knows what they are doing. The odd job comes along which is just not like that. The whole job runs better if one person is nominated to pick up all the correspondence and chase up the equipment deliveries, to make sure everything happens on time and to flag up anything which going wrong.

• Alistair Stenhouse : The only potential downside to this might be that - I doubt Amerada Hess, for example, would pay for more than one point of contact. We would not pay for such a point of contact in every single service company.

• Dermot McCollum : On this job that I have in mind, it was a 10 week job and Expro and the Operator both contributed to paying for the project manager, who was from Expro. Expro saved money as a result and because the job went so well, the operator saved money too. It needs buy-in from both sides. But the end results are generally worth it.

• Alistair Stenhouse : Something out of the ordinary like say an extended welltest I would agree 100%. On a common welltest we expect just to have a point of contact. It doesn’t have to be the technical expert in every time - he may be just a point of contact; a mailbox as it were.

• Alan Christie : “Common or garden” welltests are getting less common. This is the issue - they are all becoming special.

• Ashley Brammer : It’s the result of more creativity - there are different objectives every time.

• Greg Stimatz : This point about project management is important to me - it is important to look at harsh environment tests as a project rather than an operation.

Harsh Environment Testing - Planning and Preparation • Greg Stimatz : This came to light through the 2 tests that Amerada Hess are

planning - they are so different - because they are different applications. You need to look at the specific of the particular requirements for each test. What are your objectives ? You need to choose the right tool in the toolbox and tailor the tool to be suitable for your test. That is especially true in the harsh environments because if you do not need to take particular risks to meet your objectives then you should not take them. It’s true for all cases, but the ramifications are magnified in harsh environments. For example on Geoff’s test - if you do not have to flow to surface


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to meet your objectives then do not flow to surface. We knew this already, but now I really am a true believer - to get the objectives crystal clear. It is about hearing the amount of effort and cost which needs to go into the preparation - something to take to management as an example and something to help get the reservoir people off “dead centre” (ie desire for perfect data without considering the cost, safety or operational aspects) early on in the planning process.

Harsh Environment Testing - Wider Thinking To Cut Down On Rig Use • Ashley Brammer : Think more widely. I saw two colleagues from my own

company present different ways of doing something. We all have different drivers, but we have to ask the question : how can we do this differently? What could sell it to the company? It is about rig rates. It is the same in my end of the business - in subsea engineering. It is about cutting down on time installing things. There are pushes regarding the capital costs of equipment, such as 1£million for the capital cost of a tree. But we push down on the price of a tree and then find we get “hammered” later on - because it takes twice as long to intervene on it. It appears nobody thinks about that at the time, and we can’t put that into the contracts unless somebody has “sold” the idea upfront. Looking at the bigger picture will help us.

• Alistair Stenhouse : I’m not sure if there is a bigger picture. That’s perhaps the problem. • Ashley Brammer : It’s bringing everything that we’re all considering together in one

place. • Alistair Stenhouse : As an industry, I don’t think we have any long term view at all. • Brian Imrie : The challenge for us is to explain the value of the dynamic data we can get

from a DST. For example that it can help make your subsea tree design smarter. That’s what we’re talking about. It’s the future and long term value of doing a proper dynamic test.

• Alan Christie : What will you use the data for? Do you have a data management plan? Have we said what we are going to do with it?

• Ashley Brammer : What is the value from it? How can you get the same value for less cost or less risk?

• Alistair Stenhouse : As an industry we do seem to be becoming more risk averse in the North Sea.

• Many voices : Yes.

Harsh Environment Testing - Managed Process Of Reduced Data Acquisition • Ray Bullock : I’m surprised at what hasn’t been mentioned or discussed in more

detail. This would include issues such as : do you test/not test/do an alternative test in a harsh environment. Looking at the alternative means to reduce objectives and decrease exposure in harsh environments. We hardly touched on that. Amerada Hess mentioned it with their closed chamber testing and Greg mentioned it too - about establishing the objectives, especially in harsh environments, being the “number 1 task”. If you do not know what you are trying to achieve, you can’t develop any of the rest of the procedures to go along with it.

• Alistair Stenhouse : And that is true of any project.


_____________________________________________________________________ 13

• John Curley : Ray, you are talking about a managed process of reduced data acquisition? • Ray Bullock : Yes. I expected to hear a lot more discussion about the use of wireline

formation testers and using that to replace conventional testing in harsh environments - because you reduce equipment mobilisation and need fewer people on the rig. But of course this is at a cost in terms of data quality. Also the closed chamber testing which offers some middle ground. And there are other alternatives too, which have had no airing at all.

• Alistair Stenhouse : It would not take any more people to run a closed chamber test than a wireline log.

• John Curley : So we are spending more time talking about things which are getting in the way of delivering quality, and our concern over how services are delivered? And we are spending less time on the straight technical issues that we used to spend all our time discussing?

• Ray Bullock : Yes.

Knowledge Management Systems • Ben Stewart : There are magnificent knowledge management systems in place that

can help testing success if we give them the chance. However we seem to go in the opposite direction, in the sense that we do not use the tools that we have available. It’s not clear whether this is a challenge to training, planning, or both.

• Alan Christie : I was also struck by the data management issues. It always amazes me that we have so much data and yet we do not do anything with it. We need some form of data management - a chain, a process that seems to make one logical connection to the next one. You drill a well, you get some shows, you log it, you test it. It sometimes appears that nowhere along the line do we use that information to improve what we are trying to do. I do not see the connections being made. Within our company, people are sometimes surprised to hear about a big development taking place somewhere, say offshore Africa. Yet it was us who drilled and logged the well. We have to do something about improving how that is done.

• John Curley : Alan, to sense check what you’re saying : you’re really talking about the industry, not a single company? It’s the processes between companies that you’re talking about. We seem to lack a feedback loop between companies - we do not seem to have good enough processes to use the information that we gather as we go along conducting operations? We don’t do that well enough to improve what we do?

• Alan Christie : Yes. There are maybe valid reasons for it, but I find it surprising. It does not all seem to connect together.

Feedback on Planned Test Design • Geoff Gill : It was interesting for me to get feedback on our upcoming welltesting

plans. It seems to be acceptable to those in the room.

Rig Selection Which Takes Testing Into Account • Mark Cooper : Rig selection - there needs to be more focus from the drilling

department on testing. If you are planning on testing then that should be taken into account when the rig is selected. Otherwise, you end up having to do


_____________________________________________________________________ 14

something that you do not want to do, when you test - because of the way the rig is configured.

Novel Use Of Existing Technology • Brian Imrie : Some very interesting use of existing technology has been

demonstrated today - to use the technology to meet the goals. It was interesting to see the tools being used differently, in a novel way. Some experience and some thought was put into it.

Separate AFE For Testing • Brian Imrie : I was delighted to hear that Amerada Hess had a separate AFE and

budget allocated for testing. • Alistair Stenhouse : That’s normal. It always has been done that way here. We have a dry

hole budget and a testing budget. In the success case budget, we put all the additional wireline logs for the success case, the casing and cementing goes in there, plus the testing costs themselves.

• Brian Imrie : That practice needs to be spread to other operators. It is a message to other operators.


_____________________________________________________________________ 15

PRESENTATIONS

1. DP RIG OPERABILITY STUDY FOR WINTER TESTING OFF THE FAROE ISLANDS - ALISTAIR STENHOUSE, AMERADA HESS

• Alistair Stenhouse: We would ideally like to test in May or June when conditions are milder. However, we often actually end up testing in October, November or December. In some areas we just have to plan for the possibility of welltesting in harsh environments,

• We are preparing for two very different wells. The first is an appraisal well, which is a conventional well test in 915m of water. The second well is a rank exploration well in about 1100m of water. It

should take place around end 2002.

Testing on a DP Drillship • Alistair Stenhouse: The vessel we will use is the West Navion. It’s a large

drillship : 252m long, weight about 100,000 tonnes and a 42m beam. It’s very big. From the welltest area to the rig floor is about 80m.

• The West Navion has already been used in Nova Scotia in January/February 2002, when the temperature was minus 18 degrees C and the waves were up to 24m. They would not have been testing in those conditions, but even so, they severe weather conditions to cope with.

• The challenges of testing on a DP drillship are quite different from testing on a semisubmersible rig - especially in Autumn. The differences include :

Managing the coiled tubing lift frame and Coflexips in the Ram Rig while the vessel is moving. The vessel will heave more and you have to manage that.

Limit man riding to a minimum. If at any time you had a DP failure, the vessel would basically ‘walk off’ location. If anybody happened to be up there in a riding belt on a tugger, it wouldn’t be very nice. During the unlatch, the marine riser will recoil quite a few metres.

• Øystein Jensen: Yes, but that won’t influence the rig floor. • Alistair Stenhouse: No. But I wouldn’t want anybody up in the coiled tubing lift

frame when you unlatched. It would be exciting, to say the least. Vessel weather-vaning is another challenge - because the vessel is basically

rotating around a central point - the flowhead has to be able to rotate under tension in both directions. It needs to be proved. It’s not good enough to assume that the swivel will work. That’s not good enough. It has to be able to rotate,

Alistair Stenhouse (44) 1224 243025 [email protected]

30th July 2002 1Faroes Extension Welltest

Challenges – Testing on a DP Drillship in the Faroes Trough in the Autumn

DP Drillship Vessel Aspects

Drillship has different responses than a semisubmersible

Managing CTLF & Coflexips in the Ram Rig during vessel movement.

Limiting manriding to an absolute minimum.

Vessel weather vaning

Flowhead needs to be able to rotate under tension in both directions

Umbilicals need careful management

Managing Weather Windows

Weather critical test operations need to be understood

Needs continuous assessment with break points identified

STOP operations as necessary.

Faroes Extension Welltest


_____________________________________________________________________ 16

because it can rotate right and it can rotate left - and when it rotates left - well, you know what can happen.

Because we’re going to have four umbilicals running into the well, we need to manage them carefully as we’re rotating 180 degrees either way.

• Alistair Stenhouse: Probably the main crux of this is managing within the weather window. We can’t change the weather – we will get what we get - but we can manage within it. So we need to look at the critical test operations. We need to understand what they are, and what we can do about it. We need continuous assessment - with break points identified in the programme - so that we are able to stop operations as necessary.

Mean Heave Comparisons • Alistair Stenhouse: This work was done for BP for the Faroes area - comparing

the heave response of different rigs in the month of November. • The Jack Bates, which is a moored

semi, would have a typical mean heave response of 0.81m. It’s better than any other vessel by a good margin. I’m not exactly sure why, but it relates to its configuration.

• The Transocean Leader is 1.53m. • The West Navion heading straight

into the prevailing weather is at 1.65m. If it’s lying off the weather slightly, it will be slightly greater.

• This is for November and December; it will only get worse at the height of Winter. There’s about 1m difference in heave between the Jack Bates and West Navion. When the sea gets really rough, the ship’s heave actually starts becoming better than the semi-sub. But at that point you wouldn’t be testing.

• Ray Bullock: Are there any pitch and roll considerations also? • Alistair Stenhouse: Yes, lots. We’ve concentrated on heave because heave has

the main impact on what happens in the drilling centre. But obviously pitch and roll has a big impact on lifting equipment, getting equipment up to the drillfloor - it will have an big impact on surface welltesting processing. We don’t know what the limit of the actual welltesting equipment is going to be – you will get free surface effects inside the processing vessels. So yes, it will have an effect.

• Ray Bullock: What are the pitch and roll characteristics? • Øystein Jensen: Depending on the wave period, there’s not so much roll - it’s

mainly pitch. • Alistair Stenhouse: Assuming it’s head in to weather. • Øystein Jensen: Which we are. We are always head to weather during operations. • Alistair Stenhouse: I guess if you had very strong wind in one direction and swell

in the other side then you’d be in the worst conditions. • Øystein Jensen: Yes indeed. But we haven’t seen that much roll, it’s mostly

pitch, and it’s not creating too many problems.


Mean Heave Responses (m) November only November & December

Jack Bates 0.81m 0.94m

Transocean Leader 1.53m 1.79m

Stena Dee 1.43m 1.66m

West Navion (0 Degrees) 1.65m 1.90m

West Navion (30 Degrees) 1.88m 2.18m

Notes – figure are theoretical Mean Responses based on vessel RAO’s and winch data 1990 to 1999, computed by Global Maritime.



_____________________________________________________________________ 17

• You’re right Ray - there’s heave, pitch and roll. There’s also riser angle which Adrian will probably talk about. It doesn’t really have much impact on testing as such though.

West Navion Heave • Alistair Stenhouse: This is some real data taken last year for BP on the West

Navion. • The plot shows the basic

Significant Sea Height – this is not the maximum wave, it’s the “technical” wave you experience. The maximum wave may be 80% more than that.

• Here we’ve got 4m, nearly 5m back down to 2m. This is real weather from September/October 2001. This is the vessel response - it more or less follows the heave - but it does depend on the period of the weather coming towards you.

• To try and simplify that - the rig heave is initially all between 1m and 2m, with a little excursion. Then on 26th September it goes off the scale.

• We can take that data and put it into a cross-plot of significant sea height vs. heave for the West Navion. Based on this we can look at the operations we can do in any particular sea conditions.

• For a significant sea height of 2m, we’ll have about 1m heave on the West Navion. If the Significant Sea Height goes up to 4m, we’ll have about 1.75m heave.

• We think the practical limit for welltesting will be around 2m heave and worsening. So once the weather gets to about 4.50m significant sea height, we’re going to look at curtailing operations or even unlatching the subsea test tree.

• Brian Imrie: Do you have a drilling performance plot during that period, when they were drilling?

• Alistair Stenhouse: Drilling is completely different. • Brian Imrie: I know. But I’m just interested to know if you did a comparison

against the drilling performance – to find out if the amount of heave was affecting the metres they were making?

• Alistair Stenhouse: No. Because they’ve got active heave compensation on the rig. So really drilling is not impacted by heave. You can drill in up to 5m heave.


W est N av io n S ig S ea H eig h t an d H e ave

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Cross plot of Sig Sea Height vs Heave

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_____________________________________________________________________ 18

• Øystein Jensen: We have actually been drilling with 7.50m heave. They had stopped working on a semi, but we were still able to carry on.

• Alistair Stenhouse: To put that into context, if you’re drilling with 7.50m heave (my scale only goes to 5m), you’re talking about significant sea heights of 9-10m. That’s getting rough, by any standard.

Wave Period • Mark Cooper: On semis, the wave period is a really significant factor. Is that not

so important with a ship? • Alistair Stenhouse: It is, but there are two factors with a semi. Generally they’re

anchored, so that adds some stability. Also, as the period gets longer, the semi response (and the Navion response), would tend to follow the period of the wave.

• So I think at the “top end” of the scale for heave, the performance of a semi and the Navion would be much closer than they are at the “bottom end” of the scale. But of course, we’re interested in the bottom end for testing.

• Ashley Brammer: Alistair, on that graph you’re picking a position for a nominal limit for your significant sea height. But there are very large error bars on that graph, so that’s just a guideline isn’t it?

• Alistair Stenhouse: Well spotted. There’s a lot of distribution on this data. That’s the ‘best fit’ line. But the performance also depends on the period and the direction. This is just an average. We’ve never tested on the West Navion before - nobody’s done it.

Heave Limit • Greg Stimatz: Did I understand correctly that you’re setting your nominal heave

limit at 2m? • Alistair Stenhouse: It depends on what we’re doing – but that’s an excellent

question; it leads me on to the next slide. • These are the proposed limits that

we have for the operations. I say they’re proposed, because we don’t know - we’ve never done it.

• This is based on experience and working on other vessels. I actually believe it may be slightly better because of the vessel characteristics and the active heave compensation and the fact that the Smedvig crew are used to working in much worse conditions.

• These are the limits we’ve set, but they would be reviewed on an operational basis offshore. The decision has to be made offshore.

So, for example - testing your BOP, check space-out calculations for subsea test tree - we’d probably only be able to work on those up to a maximum of 2 metres heave. In other words, about 4.50 metres of significant sea height. That’s about Force 6, so that’s getting a little rough.

Run bit and scraper, condition mud, test casing, 5 metres - it’s a drilling operation.



0 1 2 3 4 5 6

Test BOP & check spaceout calculations for SSTT

Run bit & scraper, condition mud, test casing

Run Junk Basket/Gauge Ring/CBL

Pick-up TCP guns and DST Tools

RIH 3-1/2” tubing, pressure test and space-out

Space-out, install f luted hanger, SSTT, Gauge Mandrel etc

RIH landing string

Land out in Fluted Hanger, Install CTLF, Flow head & Coflexips

Circulate in cushion and perforate

Perform DST # 1

Perform DST # 2

Kill Well

Rig dow n Flow head and CT Lift frame

POOH and breakout assemblies

Heave (m)

Heave Limit

PROPOSED WELLTEST HEAVE LIMITS


_____________________________________________________________________ 19

• Ray Bullock: How many days of >4metres significant waves can you expect in that area in November?

• Alistair Stenhouse: That’s the next slide. • Mark Cooper: Alistair, how big is the compensator? • Alistair Stenhouse: What’s the stroke of the compensator? Maybe Øystein can

tell us. • Øystein Jensen: Depending on the loads. We have different modes, but we can

actually use the whole piston length; it’s integrated in the ram rig. • Alistair Stenhouse: It’s very different from a conventional rig. • Mark Cooper: So up to 10 metres or more? • Øystein Jensen: Yes. • Alistair Stenhouse: Unlatch conditions for your main riser are about 8metres

heave, yes? • Øystein Jensen: Yes. • Alistair Stenhouse: You’re talking about rough weather to get 8 metre heave.

⇒ For a drilling operation we’re quite confident that we can do drilling operations in 5m heave.

⇒ Run junk basket and gauge ring, CBL - wireline operations, probably about 2.50m, maybe 3m. We’ve set the limit at 2m.

⇒ Pick up TCP guns and DST tools - 4m - on the rig floor. ⇒ Run in tubing, pressure test, space out - 5m. We think we can get away with 5m.

It’s getting rough, but we can still do it. ⇒ Space out, install fluted hanger, subsea test tree gauge mandrel - probably 3m

because we’ve got active heave compensation. ⇒ RIH with the landing string - then it gets a bit more complicated - because we’ve

got all these umbilicals and centralisers - 4m. ⇒ Then this is the crux - Land out in the fluted hanger, install the coiled tubing lift

frame, flowhead and coflexips - we think 1m. This rig has never picked up a coiled tubing lift frame before, nor a flowhead, nor coflexips. So, it will be a challenge. It’s going to take at least 24hrs. I think we’ve got 32 or 36 hours total in the programme to do this.

⇒ Then once we get on to testing we think that 2m and worsening is the limit, so basically right through the test the limit is 2m.

⇒ Then POH is 5m.

Weather Impact On Test Duration – BP Method • Alistair Stenhouse: So these are

the kind of limits we’re setting ourselves - to be reviewed on site. The question was asked how much of that kind of weather we’re going to get. Well, if you could predict the weather it would be a miracle. There are two approaches to this:

• This is the BP approach, which was used last year. This plot is basically showing significant sea height of 3m for 24hrs. Those are about the conditions we need to pick up the


Hs 3m for 24 hours



_____________________________________________________________________ 20

coiled tubing lift frame. These are the months of the year and these are the years from 1955 to 1995.

• Remember “white is good, black is bad” in the plot. In the summer you can expect lots of these weather windows. Towards winter-time the weather windows become fewer and fewer.

• How many of these periods will occur? Again, this is from BP’s statistics - if you’re looking for 3m for 24hrs, you’ll get an average of 9.3 such days during November.

• The minimum you’ll get is zero -in other words you’ll never see that sea state during November; the maximum is 19.4. So you could be 20 days waiting to do that operation. It’s unlikely that the 20 days would be in one run.

• If you were needing heave below 4 metres for 72hrs - basically the test period – on average you will only see 4.3 periods of 3 days - so that’s 12, 13 days in the month you’d be able to test. Again, the minimum is zero - you might never be able to test. The maximum is 8.3 periods of this duration.

• BP and Global Maritime looked at the test they were going to do last year for the BP Faroes well. The expected test time was about 290 hours. Global Maritime plotted the test duration depending on the different start dates.

• If you started the test on 15th October, it would be from 290 to 320 hours. If your start date was mid November, your 290 hours now becomes 380 hours - so 100 hours of weather down-time. That’s the BP method of doing it.

Weather Impact On Test Duration – Amerada Hess Method • Alistair Stenhouse: Adrian Adams

has taken a different approach – I would say it is more mathematical.

• Our timing for our test is 13.13 days trouble-free time. Adrian has taken the trouble-free time for each operation, and then put in some mechanical NPT, put in the rig heave limits, the expected significant wave heights and for each month worked out the time for each operation, based on weather statistics, which he’ll probably go into.

• It basically says that if we test in June, we would expect rather than 13.13 days for it to take 16 days. In October, that will become 19 days. In November it would be 20 days. What it doesn’t say is what happens if we have bad weather and have to



Example - Frequency of specific weather windows in November based on 40 years data

Window 3m / 24 hours 4m / 72 hours

Average 9.3 4.3

Minimum 0 0

Maximum 19.4 8.3

W est Nav ion - A ssynt W e ll Tes tAv erag e Te st D uratio n (Oc tob er & No vem b er S tart Da te s)

Ba sed on 1 989 -1 999 W IN C H W e ather Da ta

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Scheduled D uration


Faroes Extension: estimated duration of well test operationsAFE timing: 13.13 days TFT, 15.43 days inclusive of NPT and WOW at 17.5%Last edited by AJA 30/7/02

Operating limits Operating limitsOperation Trouble- Time Max rig Signif. Surface Deep Estimated duration (days)

free including heave wave current currenttimemech NPT (note 1) height speed speed

(days) (days) (m) (m) (m/s) (m/s) Jan Feb Mar April May June July August Sep Oct Nov Dec

Test BOP and check space-out 0.500 0.575 2 4 0.75 0.4 0.95 0.72 0.74 0.62 0.60 0.60 0.59 0.59 0.62 0.69 0.75 0.80Run bit and scraper, test casing 1.083 1.246 5 4 0.75 0.4 1.47 1.43 1.43 1.33 1.31 1.29 1.27 1.27 1.31 1.35 1.38 1.41Run junk basket, gauge ring, CBL 0.417 0.479 2.5 4 0.75 0.4 0.63 0.55 0.55 0.51 0.50 0.50 0.49 0.49 0.50 0.52 0.56 0.56Pick up TCP guns and DST tools 0.833 0.958 4 4 0.75 0.4 1.13 1.10 1.10 1.02 1.01 1.00 0.98 0.98 1.01 1.04 1.06 1.09RIH tubing, presure test 0.625 0.719 5 4 0.75 0.4 0.85 0.83 0.82 0.77 0.76 0.75 0.73 0.73 0.76 0.78 0.79 0.81Space out, install hanger, SSTT 0.375 0.431 3 4 0.75 0.4 0.51 0.50 0.49 0.46 0.45 0.45 0.44 0.44 0.45 0.47 0.48 0.49RIH landing string 1.000 1.150 4 4 0.75 0.4 1.36 1.32 1.32 1.23 1.21 1.19 1.17 1.17 1.21 1.25 1.27 1.30Land out in hanger, install CTLF 1.375 1.581 1 4 0.75 0.4 6.39 3.87 3.84 2.49 2.01 1.80 1.76 1.81 2.40 3.40 3.80 5.44Perforate, perform DSTs, kill well 4.917 5.654 2 4 0.75 0.4 9.36 7.09 7.25 6.14 5.94 5.87 5.76 5.77 6.14 6.83 7.36 7.91Rig down flowhead and CTLF 1.000 1.150 2 4 0.75 0.4 1.90 1.44 1.47 1.25 1.21 1.19 1.17 1.17 1.25 1.39 1.50 1.61POOH and break out assemblies 1.000 1.150 5 4 0.75 0.4 1.36 1.32 1.32 1.23 1.21 1.19 1.17 1.17 1.21 1.25 1.27 1.30

Total 13.13 15.09 25.92 20.18 20.33 17.05 16.20 15.83 15.54 15.59 16.87 18.99 20.21 22.74Increase wrt time inc mechanical NPT (%) 72 34 35 13 7 5 3 3 12 26 34 51

Notes1) Double amplitude, regular wave2) Allowance for mechanical NPT 15 %3) Maximum LFJ angle = 2 deg. This applies to both the RIH/POOH and static pipe cases, because of the requirement not to pinch the control lines4) Proportion of time during which LFJ anglecan be managed by repositioning rig 80 %

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_____________________________________________________________________ 21

unlatch. The chances of unlatching in one place are much greater than they are in another - you get a distribution of test time.

Predicted Test Duration • Alistair Stenhouse: Taking all that into account, we worked out what we thought

was going to be the test time for the Faroes extension wells. That’s assuming we’ve got one unlatch and we get back on within about 3 days, which is a typical weather cycle.

In mid July, our 13 day test plus 3 days for wiper trip, cement, liner preparation would take us about 18½ days.

By mid September that becomes 20 days.

In October it will become 26 days.

If we leave it to November that becomes 27 days.

By December we’re at 30 days.

• Alistair Stenhouse: These are the times we’re looking at to do a 13 day test.

• Ashley Brammer: Are they planned times or projected times? • Alistair Stenhouse: These are projected times. • Ashley Brammer: Did you do any sensitivity studies on how far it could go either

way? You’re saying 25 days, but what’s the likelihood of it being 30 days? • Alistair Stenhouse: Let me come back to that. • So, how do we manage this? We can’t just go out there blithely to do the test - and

then just sit and wait on weather - our management would not be pleased with that. So we’ve broken the test down into what we call ‘traffic lights’. These are for the basic operations : the heave sensitivity and the time they take.

• Test BOP and check spaceout calculations for SSTT - we give that a green. In other words, activity can be stopped and started as required.

• Some activities will only start if you’ve got 6 hours of decent weather - for example run junk basket/gauge ring/CBL. We think that’s going to take us about 10 hours. But we wouldn’t start it unless we’ve got a +6 hours weather window available. So if there was no window we’d just have to sit and wait.

• There are other key activities - the red ones - which we won’t start unless we’ve got full confidence in the period we’ve got available.

• So for space out, we need 9 hours of no more than 3m heave.


Faroes Extension Test Duration (days)

0.00

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UnlatchWOWNPT (15%)Trouble Free WelltestWiper trip, Liner & CMT




Activity Hold Points while Welltesting Faroes Extension Rev -1Description Heave(m) Other Time (hrs)

Test BOP & check spaceout calculations for SSTT G 2.0 12Run bit & scraper, condition mud, test casing G 5.0 26Run Junk Basket/Gauge Ring/CBL A 2.5 10Pick-up TCP guns and DST Tools G 4.0 20RIH 3-1/2” tubing, pressure test G 5.0 15Space-out, install fluted hanger, SSTT, Gauge Mandrel etc R 3.0 9RIH landing string G 4.0 24Land out in Fluted Hanger, Install CTLF, Flowhead & Coflexips R 1.0 Wind < 30 knots, P & R < 1.0deg 33Circulate in cushion and perforate R 2.0 3Perform DST # 1 A 2.0 Possible unlatch for main PBU 55Perform DST # 2 A 2.0 Possible unlatch for main PBU 52Kill Well G 2.0 8Rig down Flowhead and CT Lift frame R 2.0 Wind < 30 knots, P & R < 1.0deg 24POOH and breakout assemblies G 5.0 24

Total 315

R Activity not started until full confidence in period availableA Activity started only if 6+ hours availableG Activity can be stopped/started as required

Traffic Lights


_____________________________________________________________________ 22

• For landing out in the fluted hanger, which is the most critical, we need no more than 1 metre heave for 33 hours.

• You mentioned the pitch and roll - yes, wind less than 30 knots, pitch and roll less than 1 degree. So these are the limits we’ve set and we will follow this.

• Brian Nutley: What contingency factor did you use for operations? • Alistair Stenhouse: In what respect? • Brian Nutley: In chance of failure. Have you assumed that everything will go

right within those numbers? • Alistair Stenhouse: Be mechanically correct do you mean? • Brian Nutley: Yes, have you allowed a contingency for mechanical problems? • Alistair Stenhouse: There’s 15% in there for mechanical NPT, but it doesn’t

include major train wrecks if something really went wrong. • Brian Nutley: Did you look at the sensitivity of the thing if you did have a major

train wreck? • Alistair Stenhouse: No. You don’t want to do that! • Geoff Gill: It’s taken us a long time just to work out the weather dependency. As

someone said, there’s an error band; we’ve put in P90 and P10 cases. You can give a good feel for how long the test will take - with no weather problems - then a flavour as to how much weather downtime you can expect to have. To get into any greater detail you just spend the whole time looking a meteorological data and not planning the test. Where do you draw the line?

Hold Points • Alistair Stenhouse: We’ll get what we get. We have to be prepared - to be able to

manage it as it comes at us. We can’t change the weather. • But what we can do is have some “hold” points. There are certain operations

where we can hold the operation. For example, running the test string. If we’re running just test tubing and we had a

problem, we could just run the hang off tool and wait on weather. We can leave the DST string in there and hang off and come off it. Running the landing string - it depends on how deep you are. If you’re near surface you’d POH. Or if you were deep, you’d just RIH and land out.

Picking up the lift frame - that’s

a key operation. We may get to that point and not see the weather window. So we could land it out with tubing and just sit there, latched in the elevators, and wait for the weather window to pick it up. Just sit there and wait - why not? We’re not going to flow the well.

Prior to perforating we would remain latched, or at worst we could come off it, if we really wanted, and then re-spot the cushion.

For flow periods we need a weather window with less than 4 metres significant wave height.

For main pressure build ups - in theory you can unlatch at the subsea test tree but there are complications about killing the well and what impact you would have.



HOLDPOINTSOperation Mitigation

RIH Test string Run hang-off tool and WOWRIH Landing String Depends on depth, either POOH or RIH.Picking up CTLF Land out SSTT using tubing and wait for

weather window to pick up CTLF/Flowhead.Prior to perforating Remain latched at SSTT OR unlatch if

heave >2m and weather worseningFlow Periods Need windows of <4m HsMain PBU’s Unlatch at SSTT is possibleWell kill Window of < 4m HsPOOH Remain latched at SSTT for window to R/D

CTLF and Flowhead.Pulling tubing Run hang-off tool and WOW


_____________________________________________________________________ 23

Well kill - basically 2 metres heave. POH is very similar to RIH and pulling tubing is the same.

• We will have these hold points and we will have the traffic lights. The only thing I would say is that we haven’t done it yet. Maybe in a year’s time we can come back and explain how good a job we did.

Hydrate Risk Management • Brian Imrie: What would you need the coiled tubing for, Alistair? • Alistair Stenhouse: Well, the plan is that we don’t need coiled tubing. However,

there is a very high risk of hydrates on this well. Not so long ago, a test was performed west of the UK with no coiled tubing lift frame. They had a hydrates plug - they had no vacuum insulated tubing either - and it took them three weeks to ‘get out of jail’ as it were. It’s a contingency - we’re putting a coiled tubing lift frame out there. It’s not ideal - far from it - but it does gives us the contingency to do anything if there is a problem.

• We are looking at other contingencies. There’s a hydrate melting tool on the market that I think Norsk Hydro paid for. The service company involved is looking at maybe procuring one of these. That’s a much better contingency than running coil, much better.

• Mark Cooper: We still had to use a lift frame for that, but I can talk about that later.

• Alistair Stenhouse: Yes, you need a lift frame to do any wireline or anything else. We don’t have any wireline planned at all. We’ve got one man-riding operation planned - in basically a two-zone test. No coiled tubing planned, no slickline planned.

Conclusions • Alistair Stenhouse: So, conclusions.

⇒ Testing on a DP Drillship is feasible in the Autumn. ⇒ Amerada Hess calculated that a 13 day test would take 26 days in October. BP

calculated that a 12 day test would take 26 days in the Autumn. So we use different methods but get similar numbers.

⇒ These times do not include major “train wrecks”. A major train wreck could add a day, or it could add on two weeks - we just don’t know. For example, hydrates. We’re doing lots to prevent hydrates, but there are no guarantees.

⇒ It includes the average weather, not the worst. • Brian Imrie: Where were the hydrates forming in that previous well? • Alistair Stenhouse: I can’t remember, I think it was in the landing string. • Geoff Gill: An SPE paper was written about it, which we read. It sounded like a

horrible experience. They were flowing the well and they saw a decrease in the wellhead flowing pressure. That is consistent with a plug forming, but I think they thought it was a wax problem. They tried to solve the perceived wax problem, but it just made the hydrate even worse. They ended up getting a plug - I can’t remember if it was over the tree, but it was certainly in the landing string. It consumed three weeks before they ended the test.

• Arild Fosså: There is another thing that can happen. Sometimes you go through the ice point before you go through the hydrate point. You can start to glaze over the internal wall of the pipe with ice - so the effective ID starts shrinking. That


_____________________________________________________________________ 24

effectively creates a long venturi, which gives you a pressure drop, which then pulls you through the hydrate point. That can happen.

• On Sleipner, some years ago, we did the production cleanups using the West Epsilon rig. In the process simulations that we did for that particular rig, we predicted going through the ice point before we went through the hydrate point. We had cut-off points and detectors to avoid the risk of getting glazing up inside the pipe - to avoid excessive pressure drops. It’s just another point that can add to the difficulties, especially if you have seabed pressures that are sub zero.

• Alistair Stenhouse: Yes. At our location we predict -2 deg C. • Arild Fosså: It might not be a problem, but you have to look at a process

simulation to detect it. • Alistair Stenhouse: The trouble is, when it becomes a problem, it is a real

problem. So we’re doing everything to prevent it. Absolutely everything. • Our hydrate point is about 700-800 metres below the seabed. We will be injecting

methanol almost continuously 600-700 metres below the seabed. We will have gauges at the BOP stack to monitor the temperature, but it will be -2 deg C when we start. The surface temperature won’t be much better than 12 deg C. Prevention is better than cure - by far.

• Alistair Stenhouse: So, just to wrap this up. This includes the average weather, not the worst - so the duration could be much longer than this. Weather windows can be managed into segments, we just have to manage it. #

• So the main implication is cost. It’s not a safety issue. We will not start an operation if it’s not safe. That’s it. Any questions?

Hydrate Risk Management • Ben Stewart: If hydrates have formed, and you’re trying to get rid of the plug, how

would you bring the ice back to surface? • Alistair Stenhouse: With coil? • Ben Stewart: No, when you are flowing back. Brian was talking to me about

some experiences offshore long ago. In that case, hydrates had formed at two points. When the hydrates started coming back they came back as a solid plug - a dynamic ‘bullet’ as it were. The contingencies weren’t really there, and we ended up having to go straight to the choke. This wasn’t very effective, because when it hit, you could see the whole thing take the shock load.

• So I just wondered about contingencies for things like that. In that case we spent just over four days trying to get rid of the plug. When it came loose, it took about six hours to clear the system. They had methanol and glycol - they had initially planned to prevent the hydrate with glycol, and then switch to the methanol. Then we were literally pouring it in the top to get rid of the other plug. It seems to be one of the biggest contingencies. That gave the crew their biggest problem - when the ice came back. It was like a clay or a shale coming through.

• Alistair Stenhouse: It’s obviously dangerous to have too much differential across it.

• Ben Stewart: It’s actually how you would bring it back. • Alistair Stenhouse: I think that’s a decision you’d have to make on site. I don’t

think that’s something we could plan for, as such.


_____________________________________________________________________ 25

• Mark Cooper: We actually did start to get a hydrate plug on the Ormen Lange test. The contingency plan we followed was to shut in the tester valve and bleed off the tubing - to take the pressure outside the hydrate envelope. And it worked; we did get rid of the hydrate plug. We never saw any evidence - apart from pressure - that we actually had a hydrate. Once we bled off, it did melt.

• Alistair Stenhouse: We will have surface readout just above the tester valve. We’ll have it at the subsea test tree and we’ll obviously have it at surface too. From these three parameters, we should be able to monitor what we’re doing. That’s the reason we have so many umbilicals in there. You have to manage it as you go along.

• Geoff Gill: It depends on the formation performance as well. It’s appraisal – there are so many unknowns in the reservoir. We’ve thought about using vacuum insulated tubing, but in the end, we’re not going to use it. A great deal of “head scratching and soul searching” went into making that decision.

• We took the view that a lot of the temperature drop could due to the Joule-Thompson effect. Obviously, that’s directly related to the PI of the formation. You don’t know that ahead of time - it’s the reason you’re testing the well. So you can “go round in a circle” quite a lot.

• A lot of it will be “suck it and see”. We’ll have hydrate curves offshore. We’ll be scrutinising them at regular intervals, and we’ll be pumping methanol into the system the whole time.

• Arild Fosså: If you have the reservoir fluid composition, I would plug that into a process simulation programme like ISIS.

• Alistair Stenhouse: Yes, that’s done. • Arild Fosså: That actually reveals a lot about hydrate risk - you can get those

points straight out of the simulation. • Geoff Gill: Yes. We’ve done that.

Hydrate Prevention Chemicals • Brian Imrie: I believe that on Clair, BP were checking the performance of their

new chemicals to prevent the formation of hydrates. How successful was that? • Alistair Stenhouse: I don’t know. • Brian Imrie: We were creating pressure differentials at surface and then pumping

BP’s new fluid in, to evaluate its performance. Did you get any feedback on that? • Alistair Stenhouse: No, I didn’t. Shell also seem to be developing hydrate

prevention chemicals – they are using some quite radical ones in the Southern North Sea.

• Arild Fosså: Probably the best place to be going to search is Sintef in Trondheim. Take have a look at the work they are doing on hydrates - at least that is semi-open information.

• With hydrates, everybody thinks that methanol is the solution. But I’ve also done quite a lot of simulations - and it turns out that good old fashioned low rate line pack or MEG (Monoethylene Glycol) is actually more efficient than anything else. There are two reasons for trying methanol :

Firstly, it’s pumpable; you don’t have viscosity problems with it. If you have an umbilical full of glycol and then you want to switch - what are you going to do then? You have an umbilical full of glycol that you can’t get rid of - you can’t pump it against the plug.


_____________________________________________________________________ 26

Secondly, our rule of thumb calculations on how much it depresses the hydrate point of methanol. That’s easy to calculate - that’s actually why people tend to prefer using lots of methanol - because you can actually calculate it. If you go to glycol you have to do a full process simulation - that’s the only way you can actually predict the effect.

• Brian Imrie: And you need crude to do that. • Arild Fosså: Yes, you need crude. • Alistair Stenhouse: We’re using a diesel cushion. Everyone says ‘oh, diesel!’, but

we’ve gone back to using diesel cushions because: it burns quite easily, it’s cheap and it doesn’t have a hydrate issue. We’re injecting methanol downhole as fast as we can, basically. You’re right about glycol - it’s difficult to pump. Especially when your umbilical is going to be about 8,000ft.

• Geoff Gill: An 1,800m injection line! • Alan Christie: How much can you get through it? • Geoff Gill: One of the comfort factors is that it’s predicted that there will be very

little water production. The hydrate production says that if you can get methanol to 800m below mud line, it doesn’t really matter what quantity. As long as you get some there, you’ll hopefully solve your hydrate problem. Even so, we will pump it as fast as we can.

• Mark Cooper: Is it a gas well or an oil well? • Geoff Gill: Most likely a light oil, but there’s a fair error band on that! • Arild Fosså: This is a Faroe Isle extension well? • Alistair Stenhouse: Yes. It’s tight hole. • Greg Stimatz: Do you have a generic wellbore schematic that you can show, or the

test set-up? • Alistair Stenhouse: I don’t have it with me, but I can get you one. • Greg Stimatz: I respect the confidentiality of the well. • Alistair Stenhouse: The test string is not confidential - I can give you that easily.

No Worst Case Scenario • Brian Nutley: The service companies sit at the other end of this whole process. I

have had to explain to my senior management in Houston why we didn’t make the testing revenue and profit in any particular month, year or quarter.

• Partly, it is the consequence of not taking the worst weather conditions, wave height, oil gravity, presence of water etc etc into account.

• If you do test, we make great money out of it. Lots of equipment rental, lots of people. But what has happened, predominantly in the North Sea, is that we do not calculate on the worst possible case scenario. As an old fraccing hand, who did a lot of blow out work, we always calculated upon the worst possible case scenario - it could only get better from there.

• Much of the North Sea testing in particular is not calculated on the worst case scenario. The end result is that welltesting is dying slowly - because the eventual costs that you do build up, in the real case, are so much higher.

• When you actually go out there and do this test, it isn’t really 13 days that runs to 26 to do this, sometimes it’s 13 days that turns to a month and a half, or two months, or possibly even worse if things go critically wrong.


_____________________________________________________________________ 27

• It worries me when people don’t use the worst case scenario. It smacks of planning that can go wrong - as opposed to planning that can go right from the worst possible scenario.

Testing Budget Contingencies • Alistair Stenhouse: It just depends on your philosophy - how you manage your

budget. Here we take a P60 case for budget. I don’t know why P60 rather than P50, but it is basically the expected time.

• We don’t use P90 as such. We will calculate the time, but in this case it’s going to be very difficult to calculate a P90 time - because you really don’t know what you’re going to get. In theory it could be zero weather for three months. You wouldn’t get the budget; management would not even think about it.

• Brian Nutley: Your time estimate was interesting. We’ve been looking at another 14 day test - working off a platform in a harsh environment. When we did the critical analysis and the potential contingencies, we actually turned the 14 day test, with contingencies, into 22 days, with minor train wrecks.

• Here you are talking about working off a floater in 960m of water. To me, that scenario seems more prone to going wrong than working off a platform in harsh environments. And yet you’re looking at a very similar contingency factor to ours for this other test.

• Brian Imrie: What percentage of your overall budget have you set aside for testing?

• Alistair Stenhouse: I can tell you in currency – about £5.4-6.0mm. • Brian Imrie: What’s that as a percentage of the overall drilling programme? If

you start having drilling problems, will that start digging into your £6mm? • Alistair Stenhouse: The drilling budget is about £12.2 mm. Testing is on a

separate budget. There’s a dry hole budget and a testing budget. That includes the rig rate of course.

• Brian Nutley: So the test budget is roughly one third of the total. • Brian Imrie: That’s good to hear. Normally, it’s miniscule - for all the other “rope,

soap and dope” tests they’re doing. So that’s a big change for the industry to be able to do that.

• Arild Fosså: Actually, Amerada Hess are, to an extent, going back to the old way of doing things. They are setting aside a certain budget. Most companies don't do that. The Drilling Manager usually controls the entire money budget. So the testing budget might get spent on drilling problems. When you come to the main reason for drilling the hole, there can be no money left.

Testing Being Priced Out of Business • Alistair Stenhouse: Here, the Drilling Manager doesn’t control the testing budget

nor the well evaluation budget. • It’s maybe a broader subject, but a couple of years ago I did some presentations on

the cost of testing. I’m concerned that we’re actually pricing ourselves out of the business in testing.

• Brian Imrie: No. The drillers price us out of the business. • Alistair Stenhouse: No, I think we price ourselves out of the business. A typical

welltest on a typical North Sea well costs about £1.3-1.5m.


_____________________________________________________________________ 28

• Arild Fosså: Here’s a good example to keep at the back of your mind. Many people think that any wireline-deployed formation testing systems are automatically cheaper – but not necessarily so. A company operating on the Gulf Coast of the USA ended up with a tab of $3m for a wireline formation tester in 2001.

Planning Costs • Greg Stimatz: Alistair, the subject of budget is near and dear to our hearts too.

We’re looking at two separate budgets. One is to actually do the test. The other is to plan for the test. We’ve been asked how much it will cost to plan for it. Obviously you have been planning for some time, and you have more planning to do. Does your £6m number include your planning work?

• Alistair Stenhouse: Yes, that’s the total. I don’t have the budget details here in front of me, but I think £5.4m is the actual number. That’s going to be reviewed next week - because that was based on testing in July. There are some sensitivities in there, there are some other issues in there, but somewhere between £5.5m and £6m.

• Greg Stimatz: Do you have any feel for what the planning portion was? - When I say “planning” I mean consultant’s time, operator’s time, service company time etc. And any early mobilisation costs – for mobilising some equipment in advance.

• Alistair Stenhouse: What you’re looking at are what we would call the planning costs and the regret costs. Off the top of my head, I’d say £350,000-400,000. That’s the regret cost - to have the equipment available, to make things, time for planning and engineering.

• Geoff Gill: I’ve been in Amerada Hess since March 2002. I’ve spent a lot of that time convincing the reservoir engineers not to do a PLT, and not to do an acid frac, and not to do a water injection test at the end of the welltest. That’s not exactly direct planning.

• Greg Stimatz: No. But it’s something we go through every time - pretty much. • Alistair Stenhouse: We eliminated that very quickly. The thought of doing a water

based acid frac and flowing it back in November in a high hydrate risk well!

Test Location • Mark Cooper: A lot depends on where you’re doing it. We planned a test in

Angola and that cost us double what it cost to plan in Norway. We expected it to be cheaper and it actually cost more.

• Greg Stimatz: That includes equipment mobilisation? • Mark Cooper: Yes. • Greg Stimatz: We’re looking at Nova Scotia. I don’t think there’s a lot of

equipment up there right now. So we would be in a similar situation. Alistair Stenhouse: There are certain items you must focus on early. For example,

if you want vacuum insulated tubing, you’re going to have to secure that. In BP we spent probably £600,000-700,000 securing tubing that we ultimately didn’t use.

• Greg Stimatz: We planned for a test in Tranch 37 here a couple of years back. We figured that it cost us between £200,000-300,000 to plan for that test – and it never happened either.


_____________________________________________________________________ 29

Mannesman String • Ben Stewart: The cost you quoted (for the last well planned in Ireland that didn’t

test) was pretty accurate. In fact the regret cost was actually higher. Do you see any cost advantage in going back to strings like the Mannesman string - where the drillstring was the test string? Initially the Mannesman string was a big handful, but it can reduce costs.

• Alistair Stenhouse: Was this the drillpipe with the seals on it? • Ben Stewart: Yes, with the Teflon seals. • Alistair Stenhouse: Well, we’re going to use PH6 - which plus or minus is similar

same stuff to handle. You’re not suggesting we go back to using drillpipe? • Ben Stewart: No. It’s just that when you do this, you’re mobilising it - and a big

part of your regret cost will be having the tubing available. • Alistair Stenhouse: The tubing is actually a very small part of the whole thing -

for normal tubing at least. Vacuum insulated tubing is very expensive. • Ray Bullock: Are you using vacuum insulated as your landing string? • Alistair Stenhouse: No. • Geoff Gill: There’s been an awful lot of soul searching to make that decision. The

easy way is to spend the money and get the vacuum insulated tubing. Obviously you want to be as efficient as you can be. But at the same time you don’t want to open yourself up for enormous problems. The planning just to make that decision was quite extensive.

• Arild Fosså: It needs to be remembered that if you use vacuum insulated tubing, it works both ways, as it were. On an offshore job we did for Hydro many years back. Somebody decided to pressure test a lubricator valve with water. It caused a hydrate plug - and we took about a week trying to get rid of it. We had to puncture the thermal tubing in the end in order to melt it.

• Mark Cooper Yes. That’s the problem. If you’ve got thermal tubing you can’t melt the hydrate plug.

• Alistair Stenhouse: Yes. That was one of our conclusions too. • John Curley : OK, thanks Alistair.


_____________________________________________________________________ 30

2.. WEATHER AND DOWNTIME SIMULATIONS - ADRIAN ADAMS, AMERADA HESS

• Adrian Adams: This follows on from Alistair’s talk, even though the work itself preceded it.

• As you know, we intend to test late in year. That exposed us, as a company, to certain economic risks.

Not to mention an additional safety risk. • We did a deal of “soul searching” to try to predict the levels of both risks, and to

see whether the prize involved justified the risks we were taking. • As a result, we did quite a lot of “waiting on weather” prediction. This is often

done rather badly. We wanted to at least put our methods on the table, and share them with you - not in any sense that we have arrived at “the answer” - but merely to say that we hope we’ve engaged with, and avoided, most of the common pitfalls. If you yourselves see any more that we have accidentally fallen into, then please shout out!

Waiting On Weather Prediction • Adrian Adams: I’ll cover four main areas :

Analysis methods, Common pitfalls, Results and Comparison with historical data.

• Let’s start by asking where our operation limits for welltests come from? They’re derived from two main conditions.

• The first is that we have to satisfy the motion limits of the vessel. These derive in turn from both mechanical limitations - of heave compensators, cranes and so on - and personnel safety issues.

• The second, and it’s one which is often forgotten, is that we have to satisfy riser angle and stress limits - because for the main part we will be working inside drilling riser.

• There are two rather different analyses in each case. One is rather better known - we start off with some wave data, preferably by month, and some vessel motion characteristics. We carry them through to a vessel response. We then compare that response to the motion limits - for a given wave height and period. Because we know the relative incidence of that height period box, we can sum over all the height period boxes and calculate operability - ie that proportion of the time we expect to be able to proceed with that operation.

• The riser limits are the same, except you are working with current. It’s also a much more expensive analysis because you have to go away and do a riser analysis, which is generally done by a contractor.

Adrian Adams (44) 1224 243083 [email protected]

18th Sept 2002 3

Analysis methodsAnalysis methods

Vessel motion limits

• Wave data

• Vessel RAOs

• Vessel response

• Vessel motion limits

• Availability

Riser angle and stress limits

• Current data

• Vessel RAOs

• Riser response

• Riser angle and stress limits

• Availability


_____________________________________________________________________ 31

Response Amplitude Operator • Adrian Adams: Here’s one common pitfall - to forget about the effect of wave

period. • There is a measurement called an RAO (Response Amplitude Operator) that

describes a vessel’s response to different wave heights and wave period combinations. All this information is listed in the RAO data set unique to the vessel. For each wave period, the data set gives the vessel’s RAO in terms of surge, heave and pitch. It also gives the RAO phase lag in degrees for each wave period, i.e. how many degrees in the wave cycle after the wave peak does the vessel surge, heave or roll.

• Here is the vessel heave response, captured as an RAO, expressed as : vessel motion per unit wave height. For a given wave period, you go in here, you read off the value for your given vessel, you multiply that value by the wave height and you get a predicted vessel motion.

• On this plot, the semis are in black and the drillships are in red. All the semis behave similarly. The drillships, for which there are rather fewer data, again behave similarly to each other.

• Note that that the response, particularly for semis, is very sensitive to wave period. There is a region of virtually nil response, ie the wave just “whips past” the vessel. It’s a short wave – there is no time to accelerate the vessel - so it’s almost untouched. There is also a zone of “quasi-static” response where the wave period is so long that the vessel is carried up with it and falls again with the wave. The dynamic effects are most evident in the middle.

• Brian Nutley: What is the difference in length between those two drillships? • Adrian Adams: The Navis Explorer? As memory serves, it’s about ¾ the length

of the West Navion, but that’s a memory figure. The Navion is the larger of the two. (JC : Adrian was right - actually it’s 200m long cf the West Navion’s 252m length)

• So to summarise on this point - the response is tremendously sensitive to wave period - and this is often left out. What you get as a result is pretty fair nonsense.

Measured Heave Response • Adrian Adams: This is an illustration - I’m grateful to Alistair for this slide,which

again is from the BP work. I table it - not to cast doubt on the BP work, nor indeed ours - but just to illustrate that we avoided this pitfall.

18th Sept 2002 4

Typical vessel RAOsTypical vessel RAOs

Heave

0.0

0.4

0.8

1.2

1.6

2.0

0 10 20 30

Period (s)

RA

O (m

/m)

Transocean Leader

Sovereign ExplorerOcean Alliance

Jack Bates

Scarabeo 5Navis Explorer 1

West Navion


_____________________________________________________________________ 32

• This is significant wave height in metres and this is vessel heave response, again in metres. You can see this tremendous scatter about the mean line. To my mind, this is almost predominantly due to a wave period effect. These wave heights have a range of different periods and because the vessel response is very sensitive to period, you get a range of responses. If you look at the breadth of that range, it’s probably plus or minus 100% - which is not the sort of error you’d like to be making on a daily basis. Particularly not when you’re trying to derive a good quality cost estimate from it.

• So do remember about the periodicity of the wave. It means you have to use a scatter diagram of course. We don’t normally have scatter diagram data by month, so the best we could do was to get the wave data by month, and assume that the period distribution was the same as in the year-round scatter diagram. That’s an approximation, but probably a reasonable one.

Riser Limits • Adrian Adams: Another common pitfall is to forget about the riser limits. We

may end up caught by those as well. I’ll say more on this shortly. • This is typical of what comes out

of the riser analysis. It’s an operating envelope that gives the safe working limits for the riser in any given combination of water depth (%) and surface current (m/s from -1 to +1). There are two boundaries here. The first is for a low-ish surface current, 0.21m/second. The second offset, in red, is for a higher deep current of 0.4m/second.

• So according to your surface current, your deep current and your water depth, you can look at plots like this and determine whether or not you are inside the riser operating limits.

• Of course, much of the time you can monitor riser angles directly. So if you were merely working with angle limits, then you’re rather better off than this. But if for whatever reason your riser limits derive from stress limitations - be it the riser body or flange strengths - then you pretty much have to believe these simulations -because you’re not measuring the bolt loads in the flange.

• So we did this, and we got some quite severe limits, and we wondered why this was. Then it dawned upon us that normally we move the vessel if we start to have riser angle problems. If your low riser angle is over here, you move the vessel

18th Sept 2002 5

Cross plot of Sig Sea Height vs Heave

0

1

2

3

4

5

0 1 2 3 4 5 6 7

Significant Sea Height, m

Hea

ve, m

West Navion: measured heave responseWest Navion: measured heave response

18th Sept 2002 6

Tyical riser operating limitsTyical riser operating limits

-1

-0.75

-0.5

-0.25

0

0.25

0.5

0.75

1

-15 -10 -5 0 5 10 15

Vessel offset (% of water depth)

Surf

ace

curr

ent (

m/s

)

LFJ Absolute Mean Angle -Deep Water Current 0.206 m/s

UFJ Relative Extreme Angle -Deep Water Current 0.206 m/s

LFJ Absolute Mean Angle -Deep Water Current 0.41 m/s

UFJ Relative Extreme Angle -Deep Water Current 0.41 m/s

Notes:1. Water depth 1112m.2. 890 kips top tension.3. 1.3 SG mud weight.4. Hs = 4.0 m, Tz = 9.6 s.5. A positive vessel offset or a positive surface current is in the same direction as the deep water current. A negative vessel offset or a negative surface current opposes the deep water current.


_____________________________________________________________________ 33

back, it straightens the riser out. Fine - riser angle problem corrected - and we go about our business.

• So we looked at that and we said, ‘Well, how much of the time do we believe we can control the riser angle by moving the vessel about?’ We consulted our own experience and we consulted Smedvig (to whom our thanks), and we came up with figures at around the 90-95% mark.

• We then decided to look at a variety of possibilities to see what that gave us in terms of predicted down-time.

• You can see a family of curves here. This is the predicted duration of the Faroes extension welltest.

• There is our summer estimate - 13 days. This is month : 1 is January, 12 is December.

• We see here a variety of positions on riser management. 0% means that we will never be able to manage riser angle by moving the vessel. 100% means we will always be able to control riser angle by moving the vessel.

• What we got was quite interesting. If we were ineffective, we were coming up with very high predicted durations of welltest. But reasonable effectiveness - in the 80-100% mark - gave us very little change in predicted duration. So the message we got from that is that certainly for our riser, and water depth, and current profiles - both in velocity and incidence - is that we really didn’t have to worry about riser limits too much.

• We might have to be prepared to move the vessel round a little, but this is quite commonly done. Seeing as we were on DP we didn’t mind that much anyway. It’s a little more trouble to do if you have a conventionally moored vessel, but it’s still not too bad. So that was an interesting sideline.

• Brian Nutley: When you did those studies, did you do those based on sea state and wind velocity?

• Adrian Adams: Sea state only. We don’t often end up taking much downtime due to wind. I’d have liked to have put it in, but our belief is that if you leave it out, you still get reasonable figures. If you challenged us it would be a deal of work to prove that however!

Vessel and Riser Limits For Various Operations • Adrian Adams: We went through that sort of exercise - vessel and riser limits -

for every one of the vessel operations. Here they are, you’ve already seen them. • We worked through them, the various times. We made 5% allowance for

mechanical NPT. I checked these figures last night and we’re currently running at 17%, which is not pleasing. My case rests, I say no more!

18th Sept 2002 7

Effect of riser managementEffect of riser management

Well test (Faroes Extension): effect of riser management

0

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1 2 3 4 5 6 7 8 9 10 11 12

Month (1 = Jan, 12 = Dec)

Pred

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ays)

0%20%40%60%80%100%

of the time inkeeping LFJangle withinrequired limits

Risermanagementeffective for


_____________________________________________________________________ 34

• Alistair Stenhouse: It’s not 5% is it? • Adrian Adams: Yes it’s 5%. • Alistair Stenhouse: In there? • Adrian Adams: Yes. The additional 12.5% being the weather allowance. • Mark Cooper: So do you

actually plan for weather allowance on the time budgets all the time?

• Adrian Adams: Yes. I’ll cut directly to the chase. The sort of allowances we’re used to putting in - like 12.5% - Hess allows 17.5% for mechanical NPT and WOW (waiting on weather) both taken together. Those sorts of allowances are good for summer, but they start to be under-estimates in September/October. They become severe under-estimates at the height of the winter. And then they become reasonable again in late April.

• Brian Nutley: The other half of that is do you have those estimates for operations that you consider ‘normal and standard’ - as opposed to operations which are ‘unusual or new’ to the operations group?

• Adrian Adams: I’m glad you mentioned that. I will be dealing with it in a slide in a minute, if you’ll bear with me.

• So, various limits. You see that some operations are particularly sensitive. Land-out in the hanger is only 1m heave. Others are rather more generous, giving you motion limits that are more typical of drilling.

• Our riser limits are over here. These are wave heights, surface and deep current speed - you need to consider all three. Do be aware of that in your riser analysis.

• Having worked at this some years, we find that we need to consider the surface and deep current separately for deepwater. There are two reasons for that. The first is oceanographical - they are normally quite separate currents. Most deepwater sites have a shallow current which overlays a deeper current - normally an Arctic current for us. So they are physically separate things. And secondarily, if you do treat them as the same, at the analysis stage, you end up with nonsense - “garbage in, garbage out” - simple as that. So you have to allow for their independence and analyse for it.

• Alistair Stenhouse: I think it’s fair to say that the deep current affects the riser, the surface current affects the vessel somewhat more?

• Adrian Adams: Yes, I think up to a point.

Predicted Test Duration • Adrian Adams: I will pass on directly to what we got. Alistair has already been

through this, so I won’t repeat his points. • I merely observe that our trouble free estimate was 13 days but we got 2-3 days

extra, even in the summer. That was driven largely by the weather sensitivity of the more vulnerable operations like landing out the subsea tree. Secondly, we

18th Sept 2002 8

Typical operating limits vs. operationTypical operating limits vs. operation

Operating limits Operating limitsOperation Trouble- Time Max rig Signif. Surface Deep

f ree inc luding heave wave current currenttime ech NPT (note 1) height speed speed

(days) (days) (m) (m ) (m /s) (m/s)

Test BOP and check space-out 0.500 0.575 2 4 0.75 0.4Run bit and scraper, test casing 1.083 1.246 5 4 0.75 0.4Run junk basket, gauge ring, CBL 0.417 0.479 2.5 4 0.75 0.4Pick up TCP guns and DST tools 0.833 0.958 4 4 0.75 0.4RIH tubing, presure tes t 0.625 0.719 5 4 0.75 0.4Space out, instal l hanger, SSTT 0.375 0.431 3 4 0.75 0.4RIH landing st ring 1.000 1.150 4 4 0.75 0.4Land out in hanger, instal l CTLF 1.375 1.581 1 4 0.75 0.4Perforate, perform DSTs, k ill well 4.917 5.654 2 4 0.75 0.4Rig down f lowhead and CTLF 1.000 1.150 2 4 0.75 0.4POO H and break out assemblies 1.000 1.150 5 4 0.75 0.4

Total 13.13 15.09


_____________________________________________________________________ 35

predicted maybe double the 13 day duration in the depths of winter, say in January.

• There you see it, that’s what we had including our 17.5%, roughly. So we’re okay in September (just), maybe OK in April, certainly OK in May. And then you start to build up predicted additional costs, with the emphasis on prediction. We will see how well these predictions compare with reality in a moment.

Probability Of WOW In Any Given Operation • Adrian Adams: To come back to Brian’s question; this overhead neatly answers

it. It’s a similar idea, only this time you have the probability of Waiting on Weather (WOW) in any given operation, rather than time.

• The various operations are listed. You see this dramatic drop - very low probabilities in the summer, very high probabilities in the winter.

• Also the WOW risk varies hugely by operation. The most vulnerable operations being : firstly supply boats, secondly landing the BOP or subsea tree and then a big step - running riser is much better. Once you’ve got the riser on, you’re pretty problem free.

• So that slide merely illustrates what we’ve long known in practice - which is that the open water operations and equipment landing - are by far the most vulnerable of the various operations. Is that a fair answer Brian?

• Brian Nutley: Yes.

Time-Shifting Operations • Alistair Stenhouse: An interesting point - the probability of WOW for the supply

boats is very high - although practically it’s never happened. That is because you can manage when you take the equipment out; you can manage the situation. If you just left it to chance, it would be a high probability. I don’t think there’s actually ever been a problem on the Navion with unloading or waiting on boats.

• Adrian Adams: So this raises an interesting point on how to interpret the results of these analyses. This probability assumes that you need to carry out that operation, at the given instant, and you cannot delay or reschedule it to suit your weather forecast. If you can reschedule or delay without cost effect, you are better off. Alistair has already looked at the issues of scheduling or waiting operations.

18th Sept 2002 9

Typical results: predicted durationTypical results: predicted duration

0

10

20

30

40

50

60

Jan

Feb MarApri

lMay

June Ju

ly

Augus

tSep Oct

Nov Dec

Pred

icte

d du

ratio

n (d

ays)

18th Sept 2002 10

Typical results:Typical results: predictedpredicted WOW by operation WOW by operation

Predicted W OW due to wave action(W est Navion, W oS wellsites)

0

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Jan Feb Mar Apr May June July Aug Sep Oct Nov D ec

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OW

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) O ffload supply boatsLand BOP/SSTTRun riserDS T, operatingDrilling


_____________________________________________________________________ 36

• Alistair Stenhouse: Just as an example, I don’t know if this has actually happened, but we were talking yesterday about sending out the large heavy lifts for the next well surface section – for the conductor – later this week. That is because the weather’s good; let’s get it on the vessel, there’s plenty of storage. So that would solve the problem.

• Adrian Adams: In fact we looked at it, but we couldn’t find “a corner” to store the conductor. Our extension joint is 73ft long, so that did give us a problem.

Comparison Of Analysis With Historical Data • Adrian Adams: So the last question is how all these analyses compare with our

observed experience? Any prediction is precisely that - it’s a prediction, no more, no less.

• So you see here the historical WOW experience of the West Navion for all the wells drilled to date. I thank Smedvig for this data. It lists the various wells, time spent waiting on BOP, drilling, everything else - and the total as a percent of well time.

• Adrian Adams: Several interesting things there. Many wells, even towards winter, had no WOW at all. At worst, the WOW was 9-10% of the total well time.

• Now of course, most drilling operations are not as weather sensitive as those for welltesting. Both experience and prediction indicate that welltests have rather higher WOW risk than drilling itself.

• So when looking at these figures, we have to keep in mind that they will be under-estimates for welltests on their own. So we might roughly double this - maybe even consider a factor of three.

Comparison Of Semis With Drillships For Testing • Brian Imrie: You’ve no statistics here for testing – and that’s because they’ve

never done any testing on the rig. So this is another prediction, right? • Adrian Adams: Right. This is all the experience we can bring to the table. We

wish it were better, we wish we had specific experience of welltests, but as we don’t, the best I can put before you is drilling.

• Brian Imrie: Or a semi from something else? Or are you only relating it to the one vessel?

• Adrian Adams: It would be interesting to see specific welltest experience for semis. Yes.

• Alistair Stenhouse: The problem is that we don’t believe the semi experience is strictly reliable. If you look back at the period curve - at the bottom end the semi is better - but as it gets rougher, the drillship gets better. So using a semi will not give you the answer. It will give you an indication. That’s why we’ve set the limit to 2m.

18th Sept 2002 11

West NavionWest Navion: historicalhistorical WOWWOW

Operator Location Period BOP Drilling Other Total %

Statoil 6608/10-006 26.02.00 - 14.05.00 132 34 166 9.0

Statoil 6507/5-3 14.05.00 - 25.06.00 0 0

Statoil 6507/8-12 25.06.00 - 29.06.00 0 0

Statoil 6354/4-1 08.07.00 - 25.09.07 29.5 30 59.5 3.2

Statoil 6710/10 04.10.00 - 26.10.00 0 0

Statoil 6608/11-2 27.10.00 - 23.11.00 7.5 7.5 1.2

Statoil 6608/10-6R 24.11.00 - 03.12.00 0 0

Shell Egypt-Shorock 20.12.00 - 24.01.01 0 0

Shell Egypt-Leil 25.01.01 - 09.03.01 0 0

Enterprise Errigal 20.03.01 - 27.04.01 16 16 1.8

Conoco Tranche 01.05.01 - 08.06.01 0 0

Conoco Nave 09.06.01 - 19.07.01 0 0

BP Svinøy 22.07.01 - 09.10.01 0 0

BP Assynt (1) 10.10.01 - 10.12.01 118 28.5 146.5 10.2

Marathon Nova Scotia 24.12.01 - 08.01.02 11.5 11.5 3.4

Marathon Nova Scotia 08.01.02 - 14.03.02 7.5 7.5 0.5

Marathon Nova Scotia (2) 14.03.02 - 19.08.02 0 0

1) Special operations due to helicopter accident included

2) Repairs to the rig over the whole period


_____________________________________________________________________ 37

• Adrian Adams: They are really “two different beasts”; one should not uncritically transfer semi experience to drillships. It’s interesting for an “over the shoulder” comparison, but I wouldn’t like to “bet my house” on what came out of the end of it.

Summary • Adrian Adams: So let’s summarise what we can say about WOW prediction for

welltests as well as drilling: There are lots of places where one can go wrong. We hope we’ve avoided at least

the more common errors. Given that the results are uncertain, and contain an error band, is it worth doing the

exercise at all? We believe yes. At least it gives you an internally consistent set of trends across the year. You may not believe that the exact weather risk in November is an additional 30% on cost. But you can, with some certainty, compare it with October and say ‘well, if November is twice as bad as October I’m prepared to believe the proportion, if not the absolute value’.

Lastly, the limited historical data we have available tends to suggest that the best models we can build at this time are probably on the conservative side.

• With that, I end my remarks and thank you for your time.

Ideal Vessel For Completions • Brian Imrie: Let’s assume it’s 10 years from now. Assume that Amerada Hess

have been successful in finding the deepwater, hostile environment reservoir they’re looking for. Assume that you’re now going to develop this field, and you’re going to develop it subsea. What type of vessel would you specify for year-round operations? What kind of system do we need to engineer to help you complete and produce the wells - as opposed to just carrying out a simple DST?

• Because that’s the future. We can do a simple DST on the West Navion. But if you’re going develop the field, how are we going to develop it? What kind of vessel do we need? What type of operation will it be?

• The equipment we’re using inside an 18¾ inch riser is now at its limit. We need to come up with more and better ways of doing a simple welltest, or a simple cleanup of your completions – to improve your effectiveness.

• That’s what we should be looking at from this experience. It is very interesting. I would say that the West Navion would not be the vessel to do your completions from. Can you imagine trying to run a completion on it?

• Ashley Brammer : It’s hard to say. It may be the vessel of choice. • Adrian Adams: That’s a hard question. I’m not sure I’d have an easy answer to it.

I’m not sure that there even is an easy answer. The only two points I would offer are :

I would suspect that you’re going to need large vessels. That’s for two reasons; first they’re hydro-dynamically more stable (since you’re talking about year-round operations) and the second is the question of supply. We will need vessels with large Variable Deck Loads (VDLs) - because winter supply West of Shetland is difficult, both from the standpoint of boats and helicopter operations. Last year on the Marjun well, we lost 30-40% of our helicopter trips due to fog, not weather. So large vessels - both because of motions and supply issues.

The second point concerns riser fatigue – which is near to my heart. As an industry, we need to create riser systems which are less vulnerable to vortex-induced vibration driven fatigue.


_____________________________________________________________________ 38

• Brian Imrie: Andrew Moseley is the person I’ve been in contact with for riser analysis. There are significant limitations on what we’re looking to do. In certain instances, it would be good if we could modify an open water drill stem test operation and make it closer to a drilling procedure. Or, if we could take away the riser and complete it with something else - you’re in a safer mode and reducing your downtime. We need to start thinking differently.

• Adrian Adams: It’s not only a riser issue. Even if we took away the riser, or made it twice as thick, or made it of some material that didn’t suffer fatigue damage, we would still have to consider the stresses through the wellhead and conductor system.

• The key critical point of the drilling riser system is normally the first conductor connector below mudline. So how do you get around that?

• Even if you put on a flexible system, which I think is the sensible answer for production, you still somehow have to engineer a template, or template-like system, which has a low fatigue damage rate. And that’s a very difficult issue.

• Ashley Brammer: There are other concepts to go about testing this well. You can complete it conventionally. Then you can disconnect, reconnect, etc., but you buy yourself a lot more guaranteed extra time in the welltest. So looking at proven systems, and trying to reduce the risk, or have a better understanding of the risk. I’ve found this work quite valuable. You can transfer the methodology back to another vessel, and onto another riser system - and that will make whatever we do better understood in the future.

• Brian Imrie: For HPHT and deepwater - I know that Statoil have now gone completely away from doing their completions traditionally through the drilling riser. They’re looking at a completely different option.

Riser Within Riser Operations • Alan Christie: Just a question here Alistair - you talk about the drilling riser

analysis here, but you actually have two risers in operation when you’re completing a well.

• Alistair Stenhouse: Yes, you have the landing string too. • Alan Christie: Yes, the landing string too. Did you look at “riser within riser”

operations? Especially since you’ve got a lot of umbilicals in there. Also especially when you’re looking at the bigger equipment – when you’re not talking about horizontal tree completions and flowbacks. This is not particular to what you’re doing just now, but we’ve recently started to understand more about that. And it’s starting to be an issue. I don’t know if anybody’s doing any work on it.

• Alistair Stenhouse: We looked at the effective shortening of the landing string if the rig moves off centre - obviously it moves closer to the rig floor. The other thing was the protection of the umbilicals – deciding whether to put centralisers in there - in fact the umbilicals are going to be taped on the outside the landing string. We haven’t done any more than that.

Vessel Selection For Other Than Drilling • Mark Cooper: The other aspect of vessel selection is that the rig is designed for

drilling principally and testing’s always an afterthought. Recently I was on the Deepwater Discovery drillship in Angola - and we couldn’t run our tubing on it


_____________________________________________________________________ 39

because it couldn’t handle 3½ inch tubing in the derrick - it would just fall out. The automatic system just couldn’t handle it. So we had to go to much bigger pipe - even though we didn’t want to. It had a really nice burner system and separators and tanks built into the ship - which was great - but when it came to doing the well operation, it had not been thought through.

• Alistair Stenhouse: It’s a fair point. The Navion is designed as a drilling vessel primarily - and it’s a very effective drilling vessel. But the idea of running a conventional completion on there would be a “nightmare”.

• It’s interesting to note that, in terms of weather, BP have stopped doing winter completions on Schiehallion. They had one completion that took them about three months - and since then they’ve not gone back. They’re looking at going back, but I would say that if you’re going to do a development in deep water West of Shetland, you would do it in the summer. The rig you would choose would depend on the functionality you need. If you’ve got everything in one drilling cluster you’d probably have a moored semi. If you’re doing it sporadically, all over the field, with subsea tiebacks, you’d probably have a DP drillship.

• Arild Fosså: In the Norwegian Sector these days, at least in the Åsgard area, we basically see the lower specification rigs dedicated to do drilling only. Then we have a couple of higher specification rigs doing batch completions. That is typical of the way that everything are moving.

• Brian Imrie: FMC have designed mudline suspension systems so that they can just “knock” the conductors in and then move on to using a different vessel for the drilling. They’re looking at performing the operation with different vessels at different times - changing vessels out.

• Ashley Brammer: We’ve done a half-way house to that - with batch drilling on Scott. We just rig up to run the conductors and we’ll put 4 or 5 in the ground. Then we swap round - do all the rest of the drilling - and then swap round and do all the completions. It’s case-by-case.

• Arild Fosså: It is. What we’re talking about here – in a welltesting mode - really applies to production tubing too - because it’s exactly the same equipment. The only thing that’s different really is how many shut-ins we do.

• Brian Imrie: We just call it “welltesting” nowadays to keep it easy for the industry to understand what we’re talking about. We perhaps should just call it “production testing”.

• John Curley: Okay, let’s break there.


_____________________________________________________________________ 40

3. DEEPWATER CLOSED CHAMBER DST - GEOFF GILL, AMERADA HESS

• Geoff Gill: We are planning this deepwater closed chamber DST using a ‘locked open’ SSTT. We do not plan to use hydraulic umbilicals. We will utilise acoustic realtime surface readout (SRO).

• This is the second well planned for the West Navion - it will probably be drilled in late October if we’re successful on the Faroes extension. So it will not be a great time of year to test - if we actually get to test. This obviously wasn’t how it was planned at the start,

but the actual method we’ll use for testing the well isn’t really changed. • This is an exploration prospect, so there’s the usual low chance of doing any

testing. Wireline fluid sampling will be tried first as the preferred option. The chance of that working is limited by the unconsolidated sand we envisage. Of course, this is guesswork because of the nature of the well.

• The reservoir is thought to be about 2,000m TVD, but it’s in a water depth of 1,000m. So effectively half the well will be in water. The prospect is thought to contain heavy oil. A heavy oil, deepwater welltest is something of a challenge at Christmas time, in the West of Shetlands.

• The well objectives are to: Conduct operations safely with little or

no environmental impact Determine near well bore parameters Obtain PVT quality samples Obtain a bulk sample of some volume

(undefined) Perform all operations within +/- 5%

of the budget.

Deepwater Closed Chamber Testing Challenges • Geoff Gill: The initial thought was

to go straight to planning a standard DST. That was carried forward for quite a long time. The challenges were obviously the deep water - it’s 1000-1100m deep.

• It’s an exploration well, so although you’re given a range of reservoir parameters that they’re expecting to find, you really don’t know.

• It could be gas, although the most likely fluid is heavy oil. Nobody knows. Timing - it didn’t start out being October/November, but that’s where it’s

Geoff Gill (44) 1467 643082 [email protected]

September 2002 1Deepwater Closed Chamber Testing

Deepwater Closed Chamber Testing

Well Objectives

• Conduct all operations safely and with no environmental impact

• Determine near well bore parameters

• Obtain PVT Quality fluids samples

• Obtain a limited bulk fluid sample for flow assurance

• Perform all operations within +/- 5% of budget



Challenges

• Deepwater +/- 1000m

• Exploration well No reservoir info for planning

• Timing October / November

• Shallow formation Potential for sand production

Potentially heavy oil

• Cooling leading to high viscosity

• Managing Costs Limiting regret costs


_____________________________________________________________________ 41

ended up. It’s a shallow formation, so the potential for sanding - unconsolidated sand - is there. Because it’s deepwater there’s a lot of cooling - bringing fluids back up the marine riser. Added to that, the formation temperature is low to start off with - it’s about 90 deg F.

• Because of the very low chance of testing, we want to keep the regret costs to a minimum – to minimise the “bits and pieces” we spend money on upfront. So there are quite a few things to juggle.

DST Options • Geoff Gill: In the initial planning for a standard DST, a few things really stood

out: • The hydrate risk, which is always there because it’s deepwater. • Potentially a heavy oil. You’ve got to imagine the worst case - flowing to surface

through that length of marine riser. It will cool down and potentially create a kilometre long “candle” within the landing string. How do you deal with that? Or how do you stop it happening in the first place?

• Standard heavy oil jobs often need artificial lift. The traditional way of doing that is to install an ESP. I did not like the thought of having a wet-connect 1000m down in a deepwater landing string. You can’t have a deepwater subsea test tree with a wet-connect (we couldn’t at the time anyway) just added to the difficulty of that scenario. So to my mind, an ESP fell out of the equation almost immediately.

• To carry on with the planning for a ‘standard’ DST - and using an artificial lift method - meant we had to do some fairly novel thinking. We came up with 2 methods for getting round it – either to put a gas lift valve or using a jet pump.

• You would need to install a gas lift valve somewhere deep within the landing string to gas lift the well from a deep point. You’re then trying to use the 1000 metre water depth to your advantage.

• The alternative to that was to use a jet pump - getting the jet pump down just above the subsea test tree - as far down as we can get - and using diesel as a power fluid. This would help to get around the viscosity problems and lift in the well simultaneously.

• If we used a gas lift valve, we’d be using nitrogen as the lift fluid. We’d also have to add in chemicals to reduce the viscosity of the fluid coming back up.

• As studies were conducted on the various methods, the cost estimates went up. We looked at the umbilical that you’d run down the outside of the landing string to pump diesel or nitrogen down there. There would potentially be problems with collapse. It would have to have a fairly significant bore and would have to withstand a fair collapse pressure. It became more and more problematic.

• Some simulation model runs predicted that the reservoir fluid would stall on its way uphole - even before it got to the mud line. A jet pump or gas lift valve at



Use of ‘Standard’ Testing Options Discounted

• Reliance on natural flow to surface unacceptable due to:-

Unknown crude, wax & hydrate risks

• Artificial lift contingency considered to be a necessity however:-

ESP not feasible – no SSTT quick connect

GLV considered – difficult to design effectively

Jet pump considered – difficult to design effectively

• Unknown fluids reduce chance of successful lift technique

• Complex lift contingencies increase regret costs and leadtime


_____________________________________________________________________ 42

1000 metres then would not help - because nothing would physically reach that point. So we were coming up against hurdles and not finding many solutions.

• Our thoughts became crystalised. We could spend all this money and buy all of this equipment, but it’s all for an exploration well. Even after spending all of this money, there’s still only a small chance of success. Complex lift contingencies were increasing the regret costs and adding to the lead time, but not increasing the chances of a successful test at the end of the day.

Closed Chamber DST String • Geoff Gill: So we looked at the alternatives. This is the DST string that we

eventually came up with.: There would be PURE

TCP guns at the bottom. We’re planning to use the Schlumberger PURE dynamic underbalanced perforating to optimise the underbalance and reduce the skin - while not pulling in too much sand.

The initial flow is into the surge chamber at the bottom, which is just empty standard gun casings. The empty gun string is run below the perforated interval, and the volume inside it is used as a chamber to take the rat hole volume plus a little flow to clean out the perforation tunnels.

There is a choke at the top, as a further mitigation against sanding – to give some means of flow control.

It is a standard packer. Above it, there is an annulus transfer sub to get annulus pressure to the firing system.

Above that, there are standard jars and safety joint. Next the bottom hole sampling DST carrier, a Metrol acoustic gauge carrier which will send signals up through the drillpipe rather than using wireline to give surface readout.

There is a lower SHORT sub to give contingency, a choke sub as a further means of regulating flow rates during the test.

There is a lower IRDV - which is a Schlumberger tester valve - run in the closed position. Another SHORT sampling chamber, another drain sub, an upper IRDV which will be run in the open position - that’s just used to capture the bulk sample at the end of the job.

Then there will be another SHORT and an RA sub, purely as contingency. The MAP transmitters are the acoustic system for transmitting data to surface. Then there are slip joints, tubulars, fluted hanger with adjuster sub, slip joint, subsea

test tree - slightly modified -which I’ll talk about later. Then the landing string. So that’s the string.

Long Bails from Topdrive

Flowhead with productions and Kill CoflexipsFlowhead Swivel

4-1/2” Ph4 Tubing with centralisersEncapsulated umbilical

Upper MAP TransmitterShear SubSubsea Test Tree (LOCKED OPEN)SlickJointFluted hanger and adjuster sub

4-1/2” PH4 Tubing c/w MAP relays every 1000FtSlip Joints (2)MAP Transmitter on 3-1/2” PH6 pup4 stands of DrillcollarsMAP transmitter3 stands of DrillcollarsMAP transmitter on 3-1/2” PH6 PupRA SubSHORT Valve - 3500Psi nominalUpper IRDV valve - 1100 then 200 to 500Psi nominalDrain subSampling Chamber - 5-1/2” 20# VAM Top HC tubingSHORT drain SubLower IRDV valve - 1100 then 200 to 500Psi nominalAcoustic Gauge Carrier and MAP transmitterChoke SubLower SHORT valve – 4250Psi nominalAcoustic gauge carrierSCAR-B Bottomhole Samplers (8) – 2750Psi nominal

Jars and safety JointAnnulus Transfer SubPositrieve Packer (9-5/8” with 7” contingent)Ported sub and CTR

5’ TCP gun system – 2000Psi nominal 5Ft PURE GunChoke Sub

Surge Chamber Rev 3By ASTDate 19/8/02

Shear Rams

MPR

Seabed +/- 1089m

CL

Cambo Closed Chamber DST String

Surface MeasurementsP, t, Q gas, Q liquidRKB

Packer @2170m

Long Bails from Topdrive

Flowhead with productions and Kill CoflexipsFlowhead Swivel

4-1/2” Ph4 Tubing with centralisersEncapsulated umbilical

Upper MAP TransmitterShear SubSubsea Test Tree (LOCKED OPEN)SlickJointFluted hanger and adjuster sub

4-1/2” PH4 Tubing c/w MAP relays every 1000FtSlip Joints (2)MAP Transmitter on 3-1/2” PH6 pup4 stands of DrillcollarsMAP transmitter3 stands of DrillcollarsMAP transmitter on 3-1/2” PH6 PupRA SubSHORT Valve - 3500Psi nominalUpper IRDV valve - 1100 then 200 to 500Psi nominalDrain subSampling Chamber - 5-1/2” 20# VAM Top HC tubingSHORT drain SubLower IRDV valve - 1100 then 200 to 500Psi nominalAcoustic Gauge Carrier and MAP transmitterChoke SubLower SHORT valve – 4250Psi nominalAcoustic gauge carrierSCAR-B Bottomhole Samplers (8) – 2750Psi nominal

Jars and safety JointAnnulus Transfer SubPositrieve Packer (9-5/8” with 7” contingent)Ported sub and CTR

5’ TCP gun system – 2000Psi nominal 5Ft PURE GunChoke Sub

Surge Chamber Rev 3By ASTDate 19/8/02

Shear Rams

MPR

Seabed +/- 1089m

CLCL

Cambo Closed Chamber DST String

Surface MeasurementsP, t, Q gas, Q liquidRKB

Packer @2170m


_____________________________________________________________________ 43

• Mark Cooper: Are you using acoustic technology all the way, or do you have a cable from the top MAP to surface ?

• Geoff Gill: Yes we have a cable. We drove hard to eliminate umbilicals of any sort, but we did relent. There will be a cable up the outside of the landing string for the acoustic system. Because it’s fairly small, we don’t envisage that it will take long to clamp on to the outside; it shouldn’t really impact on the string running time.

• Alistair Stenhouse: It’s neutrally buoyant, so it doesn’t have to be supported.

Riser Sealing Mandrel • Greg Stimatz: I notice that you’re not using a riser sealing mandrel. How are you

planning to close the diverter packer? • Alistair Stenhouse: The problem with that is handling it and putting it in there.

It’s the same with a slick joint through the rotary. We looked at that when I was in BP. We had a “nightmare” handling it on a well in West Africa. It’s just so long that we discounted it.

• Greg Stimatz: We used one on our completions recently - off a DP vessel in the Gulf of Mexico - and the handling was challenging. There have been improvements - I think a lot of the BP lessons were taken into account. The design we used was actually built by Cameron.

• Alistair Stenhouse: Feeding umbilicals through, and things like that are difficult. • Greg Stimatz: It was workable, but it was a challenge.

Closed Chamber DST Advantages and Disadvantages • Geoff Gill: The advantages and disadvantages of a closed chamber test for our

application are : Advantages:

⇒ No flow of hydrocarbons above the mud line. You can potentially get rid of all your hydrate problems - certainly viscosity problems are reduced.

⇒ Overall test duration is very short. With the potential for weather problems, that’s an advantage.

⇒ Limited equipment. The DST string is more complicated, but at surface it’s simpler - just a flowhead, bales, no coiled tubing lift frame, a choke and a tank. That’s it. There’s no massive production spread.

⇒ Lead time and regret costs are small. Beneficial financial impact. Disadvantages

⇒ Limited flow volume and radius of investigation. ⇒ More potential for sample contamination because the cleanup’s hardly ideal -

only a small volume to flow into. ⇒ Not a standard technique – more planning and programme detail to explain to

everyone else. ⇒ Complex DST/TCP string - frightening number of “bits and pieces” in there. ⇒ Operational flexibility is limited - once the string’s in the hole, you must follow

the programme. Any strange occurrences mean closing in the well, pulling everything out, changing something and running back in again. A standard DST string allows more tailoring of flow periods and shut ins to suit unpredicted situations.

• Alistair Stenhouse: It should be understood that this test will only happen if the RCI sampling doesn’t work. If hydrocarbons are there, and we’re able to take


_____________________________________________________________________ 44

wireline samples, it’s very unlikely that we’ll do this test. So it’s really replacing wireline sampling.

• Geoff Gill: Yes.

Test Sequence • Geoff Gill: The sequence of operations with the string are :

Run everything in, set it on depth, set the packer, pressure test etc. Pressure up on the annulus to fire the guns. That opens the port on the top of the

junk chamber. Flow the rathole volume, plus a little more, into the junk chamber to clean out the perforation tunnels.

Conduct a build up against the lower IRDV. We should be seeing all of this in real time using the acoustic SRO system.

Wait a certain amount of time then open the lower IRDV. We should then get pressure to surface.

We should have a diesel cushion up to the subsea test tree. Above that it’s just run empty.

The diesel cushion does two things. It enables us to pressure test the string up to the subsea test tree - which is fairly important to give a degree of confidence. Secondly, the volumes in question mean that when the diesel cushion reaches surface we will know that the formation fluids are just below the mudline. This is a major contingency and a major mitigation for the fact that we’re using a modified subsea test tree.

Once that is complete, we will do another build-up. This will be used as the main flow/PBU period for the test.

Then we will bullhead everything back in to the formation – to the point where the formation fluids are just above the upper IRDV.

We will then close the upper IRDV, trapping a sample. We can circulate out above the IRDV to kill that portion of the well.

Then we can open the circulating ports in the lower IRDV and bullhead into the formation.

We then pull the string. • That’s it. We have lots of other components in the string for contingencies. • Arild Fosså: The only thing making the string complex is the acoustic system. If

you ran it without the acoustics, it would actually be simpler than a normal string. • Geoff Gill: Basically if you took out the extra guns and the upper IRDV, you’ve

got a standard DST string. Nothing much more than that. • Alistair Stenhouse: That’s where it limits the regret costs - because we’re using

standard equipment.

Wireline Fluid Sampler Advantage • Brian Imrie: Do you have partners in this asset, or is it 100% Amerada Hess? • Alistair Stenhouse: We have partners. • Brian Imrie: Do you have to drill this one; is it a Commitment Well? • Alistair Stenhouse: Yes.



DST/TCP String

• Junk Chamber: Well ‘clean up’ to minimise sample contamination

• Limited perf interval 5ft, PURE modelled dynamic underbalance

• Junk chamber choke Modelled to limit drawdown and sand

• Below packer weak point Sanding contingency

• Dual IRDV Permits flow & catches bulk sample

• PVT BHS DST carrier Annulus pressure triggered

• Acoustic P&T SRO Facilitates test management

• Cushion Volume manages flow below seabed


_____________________________________________________________________ 45

• Brian Imrie: So you have to do something with it. • Alistair Stenhouse: Yes. It’s a potentially a big prospect, but ranked as a wildcat. • Brian Imrie: Are all the partners happy with the amount of money you’re

spending – basically just to get a wireline sample? I wouldn’t have thought just getting a wireline sample should be your first objective.

• Alistair Stenhouse: It’s the advantage of doing the wireline sample over this. I would have more faith in this, in the conditions.

• However, remember that you have to run casing, cement it and clean it out. You’ve got 3-4 days additional rig time to do this on top of the testing itself. Whereas for the wireline fluid sampling, they’re out there doing wireline logging anyway. They’ll go in and try the wireline sampler. If it doesn’t work, they’ll probably try another run, and then we’ll move on to this.

Cased Hole MDT • Alistair Stenhouse: There’s an alternative, intermediate step - it was proposed

yesterday at a partner meeting. This was to perforate the casing and try to test it with inflate packers inside the casing. I don’t think that’s going to do it.

• (Many sounds of disapproval) • Alistair Stenhouse: Hess have done that before - made holes and tested with an

MDT inside casing - that’s been done. It doesn’t however get over the sanding problem with the MDT. It does actually increase your risk of getting stuck with the MDT if you do produce some sand in. It also leaves a hole in the casing. If you want to do a test, you have to be sure where you leave the hole because it could influence what you do there. So it has to be thought out.

• Brian Nutley: Have you considered an open hole, closed chamber test? • Alistair Stenhouse: No. Though we did look at a barefoot test. • Geoff Gill: Yes. The thought is that if we do find something - we do this test – so

that we get a decent reservoir fluid sample. Then when we come back and do the next well, we’d have so many more ‘knowns’. We could then actually plan a proper test around that, if that’s required.

• When we started to plan a conventional test on this well, we just didn’t know where to start. There is such a huge range of fluids that we could be presented with, what do you do? So the idea was to do this – and while it’s not ideal by any stretch of the imagination – it will give us a certain amount of information. This in turn will enable future tests, if required, to be far better. A lot more detailed engineering can be justified for future work.

• Alistair Stenhouse: It wouldn’t preclude future testing, it would enhance it. • Brian Nutley: Certainly open hole testing was one of the major benefits of closed

chamber testing - in its original format and concept. You could do the closed chamber test in open hole without spending money on the additional rig time or for casing or preparation.

• Alistair Stenhouse: It’s pretty hard to have a long open hole section with inflate packers on a semi or a drillship. People actually tried open hole testing about 25 years ago in the North Sea on a semi - and it was totally unsuccessful from what I hear - for good reason.


_____________________________________________________________________ 46

• Geoff Gill: So to summarise: There’s a junk chamber and a limited perforation interval to match the size of the junk chamber. There is a choke in the chamber and a weak point below the packer as a standard contingency, there are two tester valves and PVT bottom hole sample chambers within a carrier. We have acoustic pressure and temperature surface readout and a cushion.

Locked Open SSTT • Geoff Gill: Once you’ve decided to go for a closed chamber test, you look at the

amount of time it’s going to take. You soon realise that the amount time on bottom is really small. The time it takes to run it and pull it back out is enormous, as summarised here:

With a standard test tree, your time on bottom doing something useful is 15 hours. We estimate potentially two days to run the landing string, another half a day for the major string, pulling the landing string is a day and a half, and pulling the major string will be about 8 hours.

• The landing string takes so long to run because of all the umbilicals and attaching the hoses to the outside of the landing string etc.

• If you can replace all those hoses with standard pipe, the amount of time to run that part will be enormously reduced. One suggestion was put forward to just forget the subsea test tree completely - but that was considered a little too radical.

• As a “halfway house” of sorts, we thought about a modified subsea test tree. It would still be there - but locked open by modifying the deepwater vent pack downhole accumulator. This can provide a nitrogen charge - so that the subsea test tree ball valves are hydraulically locked open.

• The umbilicals can then be removed and the running time to pull the string is dramatically reduced. The test duration is thus reduced from about 5 days to about 2¼ days. When multiplied by the rig cost, that’s a lot of money.

• Alistair Stenhouse: The other main aspect is the weather manageability. It’s really hard to get a 5 day weather window; it’s quite easy to get a 2¼ day window.

• Geoff Gill: With a conventional subsea test tree, the overall test time is dominated by running and pulling the landing string. A modified test tree with locked open valves and no umbilical saves time – and this is the main driver.

• There are also further arguments to put forward. The conventional test tree only gives an advantage over this modified tree when you physically land it out – but that will only be for about 15 hours.



Sub Sea and Landing String

• With conventional SSTT, overall test time is dominated by running & pullinglanding string.

• Plan to run modified SSTT with locked open valves & no umbilical:

Standard SSTT Modified SSTT

Run major string 12 hrs 12 hrs

Run landing string 48 hrs 12 hrs

Perform test 15 hrs 15 hrs

POOH landing string 36 hrs 8 hrs

POOH major string 8 hrs 8 hrs

Total 119 hrs 55 hrs

c.5 days c. 2 ¼ days


_____________________________________________________________________ 47

• The conventional tree increases operational risks when running and pulling. That is because people are working close to the rotary table in potentially bad weather. There is more handling going on, with hoses and clamps and reels reaching up to the rig floor.

• If you were using a standard test tree, (same philosophy as the Faroes extension well) and you have an emergency unlatch, you’re just going to shear the pipe. You’re not going to try and disconnect. You would just let the Driller close the shear rams and get off the well.

• So the only advantage that the conventional test tree gives you is if you’ve got bad weather - you’d be able to unlatch in a controlled manner. But only being on depth for 15 hours is such a short amount of time - you can predict the weather in that period – so the advantage is therefore minimal.

• Mark Cooper: Also, many people forget that one of the heave limit criteria is because you’ve got those subsea tree umbilicals in there.

• Several voices : Yes. • Mark Cooper: If you take out those umbilicals - then you’ve actually got a bigger

time window to carry on testing in. • Geoff Gill: So you’ve modified the tree because your overall test time is shorter.

This has a cost impact, but it also has a large impact on coping with the weather.

Shear Rather Than Unlatch • Arild Fosså: You made the point that in an emergency unlatch situation you

would just shear anyway. I think it is equipment specific. • Several Voices : No. • Arild Fosså: That’s because the BOP shear ram does not activate that quickly. If

you have the right equipment, the SSTT will be off and pulled back much quicker than the BOP shear ram can activate. We can discuss that, but I think that’s an equipment specific point.

• Alistair Stenhouse: Both BP and ourselves came to the same conclusion. Even with an electro-hydraulic subsea test tree, we would still shear if the DP failed.

• Arild Fosså: Yes, but if you activate the shear ram at the same time, and hook the two systems together, the subsea test tree will be off and pulled back before the shear ram has physically moved downhole.

• Alistair Stenhouse: Two things there. You said ‘if’, for a start - if you connect them together. We would never envisage connecting a subsea test tree hydraulic system to the rig ESD system - because the rig ESD is extremely complicated.

• The unlatch sequence happens immediately, so you would need to have absolutely parallel operation. Depending on the set up, in anything between 32 and 72



Sub Sea and Landing String

• Conventional SSTT only gives an advantage when landed out

• Conventional SSTT increases operational risks when running & pulling string

• Unlatch not planned during DP event even with standard SSTT

Summary

Plan to use modified SSTT because:

• Shorter test time means easier management of weather windows

• Shorter test time means lower operational and financial risks

• Modified SSTT will close on shear

• Safety not compromised as hydrocarbons not brought above mud line


_____________________________________________________________________ 48

seconds it will be off the well. • At any time between 0 and 32 seconds, things are happening down there, things are

closing. And we would not want the subsea test tree caught across the rams. • Arild Fosså: I think we’ll have to discuss this offline afterwards, because I

disagree pretty strongly. • Mark Cooper: Hydro feel the same way. Hydro’s philosophy is to shear. That is

because if you initiate the unlatch, and then the automatic system cuts in, it can’t cut the latch head. And then you’re in really big trouble.

• Alistair Stenhouse: The confidence is not there that the subsea test tree will be clear by the time the rig system activates.

• Mark Cooper: Because the rig system is automatic. • Arild Fosså: Yes, but I still maintain that that is equipment-specific and not a

general statement. • Geoff Gill: The Navion blind shear rams start closing 5 seconds after the Driller

hits the button. So it’s not a 35 second disconnect that you’re worried about, it’s 5 seconds. So you’ve got have an electro-hydraulic system that can get clear of the blind/shear rams 5 seconds after the Driller hits the button...

• Alistair Stenhouse: No, actually before 5 seconds. And guaranteed. • Geoff Gill: Yes. Otherwise, you’ve got to start changing the rig’s Safety Case - so

that the Emergency Disconnect package is changed. I wouldn’t want to start going through that body of work, not for a one-off DST.

• Alan Christie: How often do you test the 5 second response time? And how do you test it?

• Øystein Jensen: Prior to running the BOP. • Alan Christie: Prior to running it, so it’s not on bottom? • Øystein Jensen: No. This is the disconnect sequence of the West Navion. The

LMRP is disconnected after 35 seconds. • Alan Christie: And you don’t test that either? • Øystein Jensen: No.

Closed Chamber vs DST Comparison • Brian Nutley: What’s the difference in cost to do a short test closed chamber vs. a

three day DST. From the point you start thinking of running a DST, to the point you end it. Just the ratio of costs is fine.

• Alistair Stenhouse: About 3:1 as a rough number. You would have 6 days of rig time for this test, including running casing and all the pressure tests - about £2million. So this would be about 25-30% of the cost of a conventional welltest. And with much less weather risk – because you wouldn’t have the same overrun. Even if you doubled the three days and had to wait six days, your overrun is small.

• Brian Nutley: And in terms of quality of reservoir information? • Alistair Stenhouse: Limited. • Brian Nutley: Are you talking about half the quality, a third of the quality, 20%? • Geoff Gill: That’s a call. It’s a gut feel.


_____________________________________________________________________ 49

• We’ve made it very obvious to all the people making the decisions that the data won’t be as good as that from a standard DST.

• Brian Nutley: You don’t have a good handle on the quality - one versus the other? • Alistair Stenhouse: Not until you do it. No.

• Geoff Gill: The common view is that it’s equivalent quality to a Wireline Fluid Sampler (WFS) sample.

• Alistair Stenhouse: I think it’s better than a WFS sample because of the volume. • Arild Fosså: The biggest difference I believe with these closed chamber tests is

that the pressure data actually gets used. I’ve checked for instance with Statoil – and asked what they really do with probability numbers from WFTs. Their “guru” on pressure transient analysis said that he can seldom use it. He uses the pressure points and the fluid samples and that’s it.

• The data quality is a “far cry” from a DST. I fully agree on that. But at least you get a radial flow permeability value. You can debate how accurate it is, but generally it’s not far off – at least from what we’ve seen on a couple jobs on the Gulf Coast. It’s fairly close - typically 10-15% off the “official” DST figures if you compare them. And that’s not half bad, actually.

• Alistair Stenhouse: I remember from a test validation course – that if you get on to the steady state condition line - even if you use the wrong model etc to interpret it – you’re still within 10-15% for your skin and kh. It’s an approximation.

• We wouldn’t get any real welltest results at all. We wouldn’t be allowed to do it. • Brian Imrie: Did you get any opinions on the quality of the samples? • Alistair Stenhouse: No. We’ll take what we can get. • Brian Nutley: Interestingly enough, if you look at the way we calculate WFS data,

there’s a lot of extrapolations, a lot of manipulation of data. If you extrapolate from a closed chamber test, you’re dealing with more reality. You’re not dealing with the short end of the curve, as it were, which can vary considerably.

• Alistair Stenhouse: Yes. You’re extending it a little. • Brian Nutley: But take it back to what we did in the USA as an industry with open

hole testing, even before closed chamber. The old rule was “in hole and on bottom in no more than 6 hours”. And then we got out of the hole. Just about the whole of the US industry was developed with that kind of duration for downhole data. Very rarely did we do any extrapolation of that downhole data.

• I think there’s a huge difference between WFS and closed chamber, but I don’t think there’s a very big difference between closed chamber and the longer term flow capabilities in the DST.

• Alistair Stenhouse: Yes, it’s less. • John Curley: Okay, thanks Geoff.


_____________________________________________________________________ 50

4. OVERVIEW OF ORMEN LANGE GAS TEST IN DEEPWATER WITH A DP RIG - MARK COOPER, NORSK HYDRO

• Mark Cooper: In this talk I’ve focused mainly on the weather and environmental aspects of a deepwater test from a DP rig.

• There were two key environmental elements we had to deal with: one was the weather and the other was the seabed temperature. The North Atlantic Deepwater Current starts near here and spills over and flows right through here. It gives us seabed temperatures of about -1.8 degC – and that was a major consideration.

• The partners in Ormen Lange are : BP, Shell, Statoil and Hydro. This is the fifth well on the structure, so we already had gas composition analysis and a lot other information about the reservoir.

• The green plot shows the well location in yellow, sitting in a fault block of the Ormen Lange field. The whole reservoir is full of faults - there are thousands of faults. We weren’t sure whether these were sealing faults, or partially sealing, or whether gas could flow right though the faults.

• The field will be developed regardless of whether they are sealing or not, but we would possibly have clusters of wells at each end of the reservoir, or maybe scattered wells all the way, depending on whether these wells were sealing or not.

Test Objectives • Mark Cooper: The purpose of this test was to find an area bounded by 4 faults

and try to deplete it - to see if they were sealing. • This location is on the flank of the reservoir. The initial location was going to be a

much bigger “box”. But we found that we would have to flow the well for about 8 days at 4million sm3/day - we looked at the risks and the pipe size and decided that there was no way we were going to do it. So we moved the well location to the flank of the reservoir - where the faults were much closer together.

• We had a lot of problems during the test - a lot of equipment failures. But luckily we had a successful test at the end of the day - we got the data we needed from one of the build-ups. We were able to see that although two of the faults are sealing, the other two are probably open. That means we will be able to cluster the wells in satellites rather than having them more spread out.

Weather Conditions

Mark Cooper (47) 55 99 54 65 [email protected]


_____________________________________________________________________ 51

• Mark Cooper: Weather conditions - the water depth was 1,025m and we planned to start the test in January 2002. There’s a lot of wind and wave data for this area - and so we expected to have a lot of problems. BP also did a lot of work for us on this - we took a lot of information from them.

• The rig we were using, Scarabeo 5, is a DP rig. It’s been working the North Sea for 6-7 years. This slide shows the environmental conditions that they’ve experienced over the last 6 years.

• The big ‘blobs’ are showing, in hours, where they’ve been waiting on weather. You can see that during every winter it gets pretty bad.

• When BP put all this data into their Monte Carlo simulator, they came to the conclusion that we actually only had a 15-18% chance of having to wait on weather during a test. The likelihood was that we would complete the test without having to wait on weather.

• As it turned out, we did the job in May 2002, so we didn’t have to wait on weather at all.

RAO (Response Amplitude Operator) • Mark Cooper: Hydro use RAOs a lot. We have many subsea developments and

we’ve got 4 rigs which we use for all the subsea interventions. We can tie this in very accurately with weather data. We can take the wave periods - which we get from the weather forecast - what the wave period will be 24hrs in advance. The rig’s movement actually ties in very closely with this chart. So we can predict what the heave’s going to be. We do that on every job.

• We use a 25% increase on the time budget for winter and 20% for summer. But that’s overall, for all down time - operational and weather. We don’t single it out as being only weather-related.

W OW data for scarabeo 5

0

5

10

15

20

25

30

35

40

12-95

03-96

06-96

08-96

11-96

03-97

05-97

08-9 7

11-97

02-98

05-98

08-98

11-98

02-99

05-99

08-99

11-99

02-00

05-00

08-00

11-00

02-01

05-01

Date & Time

WO

W h

ours

0

2.5

5

7.5

10

12.5

15

W OW hours/day Wind, m/s Heave W ave


_____________________________________________________________________ 52

• I think Hydro tried to separate out the downtime due to weather-only a few years ago. But we found that since we only did 1-2 welltests in a year, we couldn’t really apply these statistics to those events, If we were doing 20 tests a year then we probably could apply it.

• So we don’t have a budget for waiting on weather - we just don’t do it. We just take the overall downtime. We do a lot of subsea operations that aren’t testing – completions, well interventions and cleanups - and we’ve found that all falls into the 20-25% rule of thumb for the budget overall.

• This is the first time I’ve been involved when we’ve looked so closely at the waiting on weather statistics. But we ended up not including it in the budget anyway!

Riser Management • Mark Cooper: I’ll just briefly touch on the riser - the deflection of the riser and

riser management. • The Scarabeo 5 has a Riser Management System which cuts the electrical supply.

Traditionally, we’d have a planned offset from the well before we’d disconnect or shut in the well - based on the water depth and how far the riser is deflected etc. But the Scarabeo 5 has actually got it integrated into their thruster system.

• The Watch Circle is not actually a circle; it’s a constantly changing shape - depending on current and wind and how much power is sent to each thruster. We originally started out with just the traditional Watch Circles but now we go by what the control operator tells us - whether the status is green or red. He actually has to tell us what the status is.

• On this particular job, one of the criteria for shutting in the well and disconnecting was if we went over 50% power consumption from the rig generators. One of the generators actually went down - they got water in the fuel and it shut down - and so we had to do an emergency disconnect. Even though it was flat calm and was in May, we ended up doing it!

• The other aspect of riser management related to the different currents. The North Atlantic Deepwater Current comes from the north and the surface current is going to the north - so we get an ‘S’ shaped riser.

Packer Choice • Mark Cooper: We discussed the consequences – for example, whether we would

use a retrievable test packer or a permanent test packer. If we had a retrievable packer, we’d have to rotate the string.

• So we ended up deciding to use a permanent test packer - so we wouldn’t have to rotate and possibly snap off clamps or twist the hose or whatever. Also the subsea tree is sensitive to rotation.

• Shortly before the test, we decided to use the new Schlumberger “HiPack” packer - which is like a test packer but it also has the advantages of a permanent packer. It worked extremely well.

• Geoff Gill: We’re using another Schlumberger product – “Sliplock” - which is a rupture disc module you can put on the bottom of a Positrieve Packer.

• Mark Cooper: This is a completely different thing. • Geoff Gill: Yes, I know it’s a different packer.


_____________________________________________________________________ 53

• Alistair Stenhouse: But we’re only using that because we can’t get the HiPack Packer. We want to avoid rotation too.

• Brian Imrie: That’s because it’s limited. We only built so many. • Mark Cooper: We were going to use a Sliplock, that was discussed. But then we

weren’t sure about it - because we couldn’t find a good track record on it. Then this came along and it was ideal for the job.

DST Sand Screens Plugged With Cement • Mark Cooper: Although it’s the fifth well on the structure, we’ve only done one

test on it before. The first one was drilled by BP and they ran screens on their test. The structure is fairly shallow and it’s not a strong sandstone. They were worried about producing sand during the test.

• In the end, we ran screens on the bottom of the DST string, just like BP. But it did cause problems. The partners were actively involved in the planning and there was a range of opinion about the sanding potential. Our geologists were more confident that we would not produce sand on test. Eventually in future we would expect to produce sand when we started getting water coning.

• So we ended up running these screens on the bottom and they plugged with cement debris from the perforations. The screens were completely full of crushed cement particles - which was a real surprise. We don’t know if it was because of a bad cement job, or whether that happens every time you flow such a well. We’ve never done this before - perforated a well and then run screens in it.

• Alistair Stenhouse: That’s been done quite a few times. But it’s the first time I’ve heard of it plugging with cement.

• Mark Cooper: The CBL was very good. It showed good cement, although they did have some problems during the cement job - they didn’t “bump the plug”. Analysis confirmed that the screen was completely full of cement particles. We didn’t see any sand at all, so on balance, I don’t think the screens were needed.

• When the screens plugged up, the differential pressure eventually caused them to partially collapse and holes were eroded in them. We just cut a hole through the screens and eventually produced the well as if there were no screens. That happened very early on in the clean up, due to the high gas velocity. I think it caused other problems too - a temperature drop through the small orifice that was created.

• Brian Imrie: How long did you flow for? • Mark Cooper: About 23hours. The plan was to flow for longer than that, but we

didn’t complete the test plan.

Test String • Mark Cooper: I’ll just briefly run through the test string. We had the TCP guns,

hydraulic firing heads, and spacer. We had downhole gauges which could be retrieved on wireline, but we didn’t really plan to do it that way. It was a last resort. Some people wanted to be able to retrieve these gauges by wireline, even though we’d said we wouldn’t run wireline. Then there were the screens, HiPack packer and gauge carriers. We then ran two IRDV’s - one immediately above the other - as part of our strategy for handling hydrates.

• Alistair Stenhouse: Why was that, Mark?


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• Mark Cooper: To avoid hydrates. When the well was flowing, the temperature was high enough to prevent hydrates forming. But if we did a conventional shut-in downhole, and then bled off some pressure and shut in at surface, then we’d go inside the hydrate forming envelope. We originally planned to have an IRDV valve close to the seabed - so that we could bleed off the riser during the shut-in – to avoid being in the hydrate-forming envelope.

• So the original plan was to have a big bore IRDV just below the seabed, maybe 100m below the seabed. But after doing a HAZOP, we decided instead to have strong enough tubing that we could bleed off the whole string from the bottom.

• That is how we did it, but if we got a leak in the tester valve, we would have had very big problems - it would have been a disaster. So we decided to run another tester valve as a back-up. So we ran two.

• Alistair Stenhouse: Did you not consider using a subsea test tree for shut-in for the hydrates? Or didn’t you want to use it?

• Mark Cooper: No. We considered it briefly, but it’s a safety device, so we decided against that. Also, the hydrate could actually form below that depth because of the environment we had. We measured -1.8deg at the seabed before we ran the DST string.

• Alistair Stenhouse: I guess you could have put in a downhole safety valve operated by a control line?

• Mark Cooper: Yes, we looked at that too. We looked at various different options, but we ended up going with this; it seemed to be the simplest way.

• Then above that is standard. Reversing valves and so on. Tubing up to the seabed and then we had the deepwater SenTree3 subsea test tree. We also had a riser sealing mandrel in the rotary table - so that if we had an emergency disconnect we could close the diverter on the riser sealing mandrel - to divert any gas out to the flare boom rather than come up on the rig floor. That took a long time to rig up - 12 hours - feeding the hoses through.

Ram Rigs, Derricks And Lift Frames • Mark Cooper: We had a lift frame on top - in case we had to run wireline through

in an emergency. This assembly was quite difficult. It was 36.5m long and we ended up being right on the limit of the alarms for the derrick. We had to switch off one of the 3 alarms to get it installed.

• Alistair Stenhouse: On the West Navion, when we pick up the coiled tubing lift frame, and we have the flowhead all spaced out. We did a subsea test tree unlatch - we would have a clearance of 30cm – about 1 foot - on top of the Ram Rig. That’s how close we are - for working to get the subsea test tree above the ball joint. Our crossovers have to be an exact length.


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• Mark Cooper: We had about one metre clearance. It’s really tight. But we had really nice weather and it went quite smoothly, actually installing everything.

• Alistair Stenhouse: I was going to say that if anybody’s planning a test using a Ram Rig – be aware that it’s different from a derrick. They have different height limitations. It means you don’t have this extra length for the blocks to travel up – with the Crown-O-Matic etc.

Acoustic Data Telemetry System • Mark Cooper: Geoff mentioned Metrol’s MAP acoustic surface readout system.

We planned to run it here, but we had a problem with lots of pup joints that had to go in there, and it was just impractical. We were going to have multiple sized pipe all the way up the hole. Or, we could have made special clamps. But then the clearance between the clamps and the casing was small – so that when we did the HAZOP we decided it just wasn’t worth the risk. It had also not been run before at that time, although I think it has now.

• Alistair Stenhouse: It’s been run in the Far East I think, but not in deepwater yet. • Mark Cooper: So we didn’t run it. I really wanted to run it, because it would

have been valuable to know what was going on downhole. We did have gauges installed in the subsea tree – but the cables got broken when we were installing the tree. It was going to take 8 hours to repair it, so we decided to run without the gauges. So we didn’t have any seabed temperature and pressure data at all during the test.

Subsea Test Tree • Mark Cooper: We had a hard time getting

the electro-hydraulic SenTree 3 subsea test tree to go through the rotary table. We couldn’t grab hold of it with the pipe handling system because it was too fragile. It just kept hanging up because the shoulders are too sharp to get through the rotary easily. I believe that Schlumberger are addressing this - they’re adding centralisers so that it won’t happen again.

Hydrates • Mark Cooper: Because it was an appraisal well, we had accurate information on

the gas composition. The hydrate envelope for the Ormen Lange gas shows that hydrates will form unless there is chemical injection.

• If you add glycol, then you lower the hydrate formation temperature to below zero deg C. But if you don’t add any chemicals at all, within the pressure range from say 0-160 bar, then hydrates could form at up to +20 degC. By adding the glycol, the hydrate formation temperature is brought down to minus 10 degC.


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• In this particular gas, methanol is more effective than glycol. You can reduce the hydrate formation temperature down to minus 25-30 degC - so you wouldn’t get any hydrates or ice.

• The main hydrate prevention method was to pump lots of methanol. We were pumping 5 litres/minute and it worked, to a point.

• Greg Stimatz: Where was the entry point for the methanol?

• Mark Cooper: At the subsea test tree. After we shut in downhole, we carried on pumping for 20 minutes. Then, before we started the flow again, we pumped more, just to make sure that everything was full of methanol.

• We had to pump at 5 litres/minute because of the water saturation of the gas. As the gas is decompressing, even though there’s no free water being produced, you get water condensing. We worked out that 5 litres/minute was just enough to cover all the water that was in the gas if we bled off to zero. That was the highest rate that we could get down the hose too - 5 litres/minute. Everything was going “flat out” and that was with the methanol. We looked at using glycol, but it wouldn’t have gone down the hose. We would have got a back pressure of something like 5,000psi. The hose had a ¼ inch ID.

• Alistair Stenhouse: We’re going to do a test on that next week - the actual line and the umbilical will be pumped through at the surface with water (we don’t need to use methanol at surface) to ascertain the rate we can obtain.

• Ray Bullock: We’ve been running hoses up to 1 inch in deepwater West Africa to get the volumes of methanol that are needed.

• Arild Fosså: Yes, but those hoses are spliced - you do get some leakage. The biggest size that you can get in long seamless lengths is the one that Mark was using. All the others need connectors. You could instead run a “spaghetti” coil on the side.

• Mark Cooper: We looked at running an additional line on the chemical injection sub, but we found that we could get enough down that hose. But we did have a back pressure of about 110bar (1,500psi) at that rate with methanol.

• Ray Bullock: Did you make any provisions for possible collapse of that line? • Mark Cooper: It was built into the hose. • Ray Bullock: It’s collapse-resistant then? • Mark Cooper: That particular hose is, yes. But when I was planning the job in

Angola, the hoses there weren’t collapse resistant. We had to have a back pressure valve on it, so that you always had enough pressure in the hose. You need to pressurise the hose up before you run in.

Thermal Properties of Riser • Mark Cooper: So we did actually get hydrates. We did do temperature modelling

- the scientists in Oslo did all the modelling and we believed that everything was


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going to be fine. But when we actually flowed the well, we didn’t get anywhere near the temperatures we expected.

• It was much cooler, and we couldn’t figure out what it was. Then we realised that one of the reasons was down to the thermal properties of the riser and the landing string. The buoyancy elements on the riser are good thermal insulators and so that was used in the calculations. We expected to have about 40degC in the landing string when we were flowing. But in actual fact we had about 25degC.

• We then discovered that the bottom six joints of riser had been run without any buoyancy elements on them. Even though we had planned to run them all the way down, someone forgot to put them on the bottom six joints - which is the worst place. So that was a big lack of communication and it made a big difference.

NPT Fitting Leaks • Mark Cooper: We also had problems with the subsea system. First of all, there

are NPT fittings in that system and they had a leak which was not rectified. Nor was any compensation made for it, so we simply ran out of hydraulic fluid and the subsea tree started to close on us.

• Initially, we didn’t know this was happening at all. The only information we had was on the real time readouts. Everything was going fine during the flow period. We had a pressure sensor in the flowhead, upstream of the surface safety valve and we were also monitoring the choke pressure. The pressure suddenly dropped and we were trying to figure out what was happening. We found out afterwards that the subsea tree valve had started to close.

• So we got a big pressure drop, and we also got a huge temperature drop, and that’s when we got the hydrate forming. There was a “thump” and the hydrate moved up, either from the flowhead or the landing string somewhere, to the flowline - between the flowhead and the choke manifold.

• So we started getting a build up of pressure on the flowhead, while the choke pressure dropped. We were trying to figure this out as it was happening. We weren’t really sure what was going on, but we thought it was probably a hydrate. So we shut in the IRDV and bled off the landing string. It took us about twenty minutes to bleed it all off, but it worked. Having started, we decided to carry on with the build up.

• When we shut the IRDV, we had some differential pressure across this valve downhole in an empty string. So before we opened the well again, we filled the string up with diesel for the main flow. That helped avoid having a big differential across the valve when we opened it.

• Dermot McCollum: So Mark, did you in effect have no chemical injection at the surface?

• Mark Cooper: No. All the pumps were “going like crazy”, it was very noisy. But when we realised there was probably a hydrate, we checked all the pumps anyway. We were flowing just under 2mmscm/day - just short of 80mmscf/d - so it was very noisy from that too.

• The noise was one of the reasons that we didn’t spot the leak in the hydraulic system on the tree in the first place - it was so noisy that nobody could hear anything. We shut everything down, and started switching off all the chemical pumps, and only then did we hear the hydraulic pump going on the subsea system.


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Hydrate Melting Tool • Mark Cooper: Because of our concern with hydrates, we got together with

Schlumberger and we had this tool built – it is based on the PatchFlex casing patch tool.

• It circulates hot fluids - basically it’s a wireline logging cable with a downhole pump and a heating element.

• I think one or two of the cables are used for the low volume pump and the other cables are used to power up a twenty kilowatt heating element.

• We did a lot of tests onshore with it and we’ve melted through 3 metre long water-ice blocks at -30degC. The rate through that was about 1.7 metres/hour and that was just using ten kilowatts - we couldn’t heat it up over 100degC. We couldn’t get it as hot as if we had it downhole. It’s designed to run at 240degC at pressure. There are two sets of this equipment.

• Mark Cooper: We looked at coiled tubing for removing hydrates. We talked to all the coiled tubing companies and to Diamond Offshore who have done a great deal of CT work on DP ships. Apparently, nobody has done a detailed HAZID of running coiled tubing on a DP vessel.

• When we started looking at it, we talked to Smedvig about working the derrick. They were not prepared to consider it. In fact, the legislation in Norway is a maximum of 2 metres peak heave for personnel working the derrick. We often can’t do even slickline or wireline operations offshore for this reason alone. With a peak heave of 2 metres, the actual average heave is about 1.3 metres.

• The issue with coiled tubing is the rig up time for the injector. In Norway we’re looking at 12 hours to rig up the injector - with 3-4 people up in the derrick on man-riders. There’s a big problem straight away because most rigs have only got 2-3 man-riders. Someone has to disconnect the man rider and connect it to the unit itself, so it’s a really dangerous operation - if we have to do an emergency disconnect.

• So when we did a HAZID, we decided we just couldn’t use coiled tubing and that was it. We couldn’t do it, so we’d have to do something else. That’s why we started looking into building these heaters and got two of them built. They’re 2.75 inches OD.

• Alistair Stenhouse: To me, this is a much better contingency than any coil, for the reasons you describe. Coil would be a “nightmare”.

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• Mark Cooper: That’s the coiled tubing lift frame we’ve got. It’s owned by Hydro and is built to their specs. I don’t know what Transocean’s etc are like nowadays. The last time I did a coiled tubing job with the sort that Transocean supply, it was just a big box.

• Brian Imrie: I think it’s JMC now. • Mark Cooper: And are they still just big

boxes? • Brian Imrie: No, JMC have got a new

design now. • Mark Cooper: This has got “fancy” gadgets on it – whicxh make it great to use.

The bottom swivels - it’s got hydraulic rams on it - so that you can turn it through 90 degrees to connect the flowhead. There’s a hydraulic collector inside - you just press a button and it just grabs hold. You don’t have cables and elevators to “mess around” with.

• Alistair Stenhouse: I think we’ve got the basic version of that! It’s got the swivelling bottom sub, but it doesn’t have the hydraulic collector – which is neat.

• Mark Cooper: Yes, they have to do a lot of coiled tubing work.

• The only downside is that it’s complicated to operate it. But people don’t have to get their hands in - you’ve got all hands-free operation.

• Here’s another photograph of it. This is the bottom end of the lift frame, there are two decks on it. The bottom deck takes the BOPs etc - wireline BOPs, while coiled tubing BOPs would go in here. They space out, so this is actually a complete work space here on top, on either side of the top of the BOPs. People can therefore disconnect from the riding belts, walk around and work safely up there - there are handrails. We said that if we did do an emergency disconnect, those people would ride with it up the derrick. You do have to plan for it. We just made sure there was nothing protruding that would catch on the lift frame when it went up. We positioned it so that it had completely free travel.

• Alistair Stenhouse: The most dangerous scenario would be if there was someone half-and half on a riding belt and trying to get on to that when it disconnected. They could get tangled up. Do you know how long it is?

• Mark Cooper: It’s 13.5 metres long. • Brian Imrie: They’re continually refining the design of it. • Brian Nutley: This is with the alarm disconnected, with a 1 metre clearance and 2

men riding? • Mark Cooper: Yes, but once it’s installed, the alarm’s back on again. It’s just to

actually make up one connection. The heave is not a big issue when we’re making this up because we’re not landed out. We’re quite high up off the landing point.

• At 13.5 metres, it’s just long enough for what we wanted to do with the wireline tools. That’s the big cable, and we’ve got pressure as well - we had to have weights to get the tool in the hole.

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• Sandy Forbes: That’s the other issue with that hydrate melting tool - you need big cables for the pressure control.

• Mark Cooper: But there is pressure control equipment for it. • Sandy Forbes: Yes, 5,000psi? • Mark Cooper: Yes.

Reconnecting the SSTT • Mark Cooper: The other big problem we had with the subsea tree was

reconnecting it. It took 6½ hours to relatch. We just couldn’t get it centralised. We could see the bullseye - that we were over - but it could have been because the riser was ‘S’-shaped. We’re looking at getting better centralisation on the latch head itself. Schlumberger are working on that.

Sandscreen Damage • Mark Cooper: That’s a photo

of the sandscreen afterwards. It’s a Baker mesh screen and all the brown material in here is cement. There was lots of it.

• Brian Imrie: What condition was the reservoir in when you perforated?

• Mark Cooper: It was underbalanced by 48 bar, about 1,500 psi.

• There’s one of the holes that was eroded on the outside of the screen. I think there were six holes like that in the screen when we pulled it back out.

IRDV Valve Failure • Mark Cooper: One of the IRDV valves stopped working. The cause was a paint

brush hair across the ‘O’ rings - so the tool pressure tested and functioned fine - and then downhole either the hydraulics leaked into the air chamber, or visa-versa, but gradually it stopped working.

• Mark Cooper: So that was the end of the test - we couldn’t figure out what was going on. First of all we had a leaky subsea tree, and then we started getting a leaky IRIS.

• There were two completely different causes, but at the time we thought there might be a link, and there was something going on with the well that we didn’t understand.

• We decided that we probably had enough data, and that it wasn’t safe to carry on. So we pulled everything out of the hole, with the contingency to run back in and do a re-test if the gauge data was no good. But we did a quick analysis on the rig and it was good enough - we could see the boundaries.

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Ambient Noise • Mark Cooper: The final thing,

which caused us a big “headache” as it were, was noise.

• There’s new legislation in Norway for noise - the air compressors and the flare. We’re now supposed to endeavour to keep the noise below 83 decibels in any working area.

• However, you can’t do it with these compressors. We did tests onshore in open air and the noise was 110 decibels all around it. We placed containers around it to see if that helped - which it did.

• This approach may not be an issue anywhere else, perhaps just in Norway. Basically, ear protection will reduce the noise you hear to below 83 decibels. But what they’re saying now is that your body shouldn’t be exposed to anything higher than 83 decibels either - there’s a vibration on your body. We are supposed to try and reduce that to 83 decibels or less.

• We were substantially over on that test - getting 110-120 decibels at the side of the burner booms from the gas flare. We’ve now installed silencers on the gas flares on one of the rigs and we’re waiting to see how they perform.

Welltests Are Projects Nowadays • Mark Cooper: In summary, all of these problems were really caused by what I

think is an industry problem with testing now. We don’t have a test team based in Norway who can do the whole job and who do it ten times a year. Instead we have people coming in from different places and we’ve got inexperienced people. We’ve got test supervisors who are only maybe doing one test a year or even one test every two years. It’s a big problem - these systems are so complex now. I don’t know what the solution is.

• Alistair Stenhouse: It applies to service companies and to operating companies. There’s just not the experience - there’s not the number of jobs being done.

• Brian Imrie: We were looking at having a project-based approach to testing – to involve these people in a specific project team. Because for something like this now, it’s actually a project.

• Many voices : Yes. It has to be considered as a project. It’s not just another operation.

• Brian Imrie: I think the tenders that get sent out have to be changed to reflect that it is a project. At the moment the operators are still giving us the same tenders as you’ve done for years - and you expect the same service. And then it’s a hassle over the “rope, soap and dope” issues. I think that’s where you need to look at it.

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Compressor

Container

Container

Container Container

4 m

3 m

10 m

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8 m

13 m

10 m

13 m

1 m

Container

90dB

80dB

1 m1 m

90dB

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75dB

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75dB

75dB

Sound metering of Airpower NH-50, using LUTRON SL 4001 sound level meter.The test was performed under full power at 2000.RPM.Yellow area 90dB and upBlue area between 80dB and 90 dBGrey area between 74dB and 79 dB70dB was measured 22 meters from the surrounding containers, normally talk in this area showed76 dB!

75dB

80dB

80dB

80dB

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• Alistair Stenhouse: We’re running this as a project. And we’ve been having project meetings throughout.

• Alan Christie: It’s a valid point and I’m glad you brought it up Mark. It’s an issue I’m trying to raise with management. Really, the only people they’re going to listen to is you people from the operating companies. So if you want specialist teams to be set up to handle this business, you’re going to have to tell the management of companies like Halliburton, Expro and Schlumberger that it is what you want.

• Right now, they’ve geared up the business to doing things in a certain way. If you want it to change, you’ll have to tell them. I’ve made recommendations like this in several different areas - this is not just applicable to welltesting. But every time I get to someone who could make the decision, I’m told that that is not what the industry wants.

• So if you need it, and you want it, you’re going to have to ask for it. And you’ll have to ask at the correct level in the companies so people will listen. That way it will happen. You will get specialist teams set up.

• It’s a problem in Norway, but it’s a even bigger problem in West Africa. I’ll touch on some of the issues we’ve got there.

• To me it’s a change in the way we approach the business. It’s not about technology - we’ve got all the technology – it’s “coming out of our ears”, but we can’t run it. We don’t have people who have spent enough time on the equipment to make it a high competence. It’s the way we run the business – it’s a business approach, it’s a contracting approach. The push has come from the operators to the service company managers to make things change. We need that kind of help to make the changes.

• Ben Stewart: More importantly, if you take Brian’s meeting objective - about looking to the future - to identify what technology is needed, we should be thinking right now about the skill sets needed.

• Look at the things that are going to be critical – for example, if everything is going to be driven by cost - then it means you’re going to have to do it earlier, ie before casing is run, and more efficiently. Yet how much open hole skill do we have left in the industry? That’s probably the biggest issue about making testing a viable, reliable function in a well programme.

• Alistair Stenhouse: Another thing is the “greying” of the community. Brian asked ‘what’s going to happen in ten years?’ By then, a good percentage of the people here today will be retired, or dead, or whatever. But they won’t be here.

• Brian Nutley: I could go beyond what you’re saying - in terms of talking to our managements about it. I don’t think our management are interested in listening to the talk anymore, even.

• They want to hear you say ‘here’s the money up front to do this project’ . That’s because of what we’re finding with our testing packages - quite sincerely - we’re financing a very high proportion of the risk on extreme well conditions. And at the end of the day, we get a note saying, ‘Dear Sir, Sorry we’re not going to test’. We’ve talked a lot about regret costs today.

• Alistair Stenhouse: It always used to be like that. But in those days, you had much more activity – so you could peak shave it.

• Brian Nutley: You probably didn’t have subsea trees and all the rest of the expensive high technology equipment though.


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• Brian Imrie: If you audit your testing equipment assets, they’re costing you something every month, whether they are working or not. So you get rid of the people or you get rid of the assets, or do both. That’s what’s happening. We’re getting rid of both the experience and the assets. But keep on with that good new technology – because we might use it; but there again, we might not. Then let’s transfer it somewhere else.

• Brian Nutley: That’s what we did in the North Sea. We took all our people, and all our equipment, and we moved it somewhere else - where it’s making money.

• That was because we couldn’t get the support from the customers to help us make money. And we’re here to make money no differently from the operators. Ours is a shorter term time-span, but we could no longer afford to be here, supporting the operations with the complexity of today’s welltest picture.

END


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5. MARATHON HARSH OFFSHORE ENVIRONMENT WELLTEST ISSUES AND CONCERNS - GREG STIMATZ, MARATHON

• Greg Stimatz: I’ll give you an overview of what we’re planning in Nova Scotia. As a preface to that, I’ll give you a little information about the governmental requirements too - they tend to drive a test there as much as the operator’s desires or requirements.

• In Canada, each province has its own Regulatory Board. They have national representation too, I think it’s 50/50 national/provincial representation. So for example, Nova Scotia may have different

rules from Newfoundland. • We’re preparing for work here, particularly in Nova Scotia. They have a shallow

water, Shelf-type industry developed. They took the rules developed for the Shelf and brought them directly to deepwater, with essentially no changes that I’m aware of - at least with regard to welltests.

• Within those regulations, there’s a requirement to flow test any hydrocarbon zone thicker than 5 metres in a 10 metre gross interval, which is not a very thick zone. You can actually hit a number of those zones outside your primary target. That’s a pretty onerous burden to put upon the operators.

• We drilled a well here at the beginning of 2002, until just recently the rig was released to Amerada Hess - it was the West Navion.

Not Testing The First Well • Greg Stimatz: We got permission from the Nova Scotian Board to defer a test on

this first well. It was a rank wildcat well, so they allowed us to do that. • Marathon’s philosophy is generally not to plan a DST on the first well on an

exploration prospect. Sometimes there’s a lot of internal pressure to do it and so we go ahead. But it’s certainly our preference to get away from that - for obvious reasons that you’re all familiar with.

• For the 2nd, 3rd or 4th well, you hopefully have some fluid samples available to you and you have some ideas of the zone thickness, etc, etc. So it’s much easier to plan a test for a subsequent well. It maybe not even be the second well – it may be the third or the fourth, depending on the project size. We got permission from the government to do that.

• Next year we’ll be going back to Nova Scotia to drill, and we’re looking at a couple of wells next year. We’re probably looking at gas prospects - dry gas, which works in our favour. Fairly high pressure. Water depth is about 1700 metres – fairly deepwater. One is an exploration prospect near to the one we’ve just drilled. The other well would potentially be an offset or delineation well to the prospect we just drilled.

• We believe that we can get another dispensation to not test the new exploration prospect. It would be along the same lines as we did on our first well.

Greg Stimatz (1) 713 296 2220 [email protected]


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• If we go back for a delineation well, we’re not so certain about that. The government may require us to test that well. At this point we’re taking the position that we have to be prepared to test in Nova Scotia. I say next summer, but it may run later than that.

• I don’t have any weather information to show you here - wave data, etc., but it’s very similar to what Amerada were showing us earlier. So it is very like the northern North Sea, where you really have about a four month window from June through to September. And then it really starts to get rough in a hurry.

• If we do get another deferral from the government, it’s just a matter of time before we will test, possibly driven by our own needs as opposed to the government’s, but it’ll probably be a combination of both.

Planning A Deepwater Welltest As A Project • Greg Stimatz: I’ve already picked up a good deal of information on aspects of the

planning. I will continue to pick up more input from both the operators and the service companies about what we should be doing right now, the high level points, to test next summer in 2003.

• We’ve got some idea of some of the issues. We’ve gone through planning for a test West of Scotland in Tranche 37 – but that test was never done. So we’ve gone through this before. But in that case, there was infrastructure nearby in Scotland. In Nova Scotia I don’t know what is up there, what’s available to us. I’m trying to get some idea on that and what we will need to do.

• We don’t have a rig chosen yet. I know that’s a big issue because probably some rig modifications will be needed. I’d like to get some input from you for that.

• That’s pretty much it - I’d like to hear some feedback from you and I’ll answer any questions that you have.

• Alistair Stenhouse: How deep is the prospect itself? • Greg Stimatz: Probably about 5500 metres. Fairly high pressure. I think we will

need about 14.5 ppg mud. • Mark Cooper: You’ve got a problem right there! • Alistair Stenhouse : It’s about 14,000 psi. • Greg Stimatz: Yes, it’s high. Certainly higher than we had expected to encounter. • Ray Bullock: That’s typical of the area. • Greg Stimatz: Is it? We’re actually quite a way distant from anything else that’s

been drilled up there. • Ray Bullock: Almost everything we did up there was in that range. • Greg Stimatz: I don’t know the background - I don’t know why the pressure was

higher than we expected, but it certainly was.

Rig and Testing Equipment Procurement • Arild Fosså: I would talk to Miles Winter who is up in Halifax now, I believe,

with ExxonMobil. You might be able to share equipment - because there’s not much equipment in Canada. A lot of it is tied up on contractual work, but I believe there is some under the Exxon contract. If you’re lucky, you can tie into that. That’s based out of Halifax; that’s the closest.

• Arild Fosså: Basically Halliburton and Schlumberger have a presence up there. I think that Schlumberger has one package up there and we have about the same.


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• Brian Imrie: I think a rig and a rig contract need to come first! • Greg Stimatz: Yes. That’s in the works. • Alistair Stenhouse: You need to know the rig at least 3 months before you even

think you want to use it. Based on my experience last year, and rigs coming late this year, you do need to know the rig up front. In BP the rig kept changing - and it’s a “nightmare” trying to plan something like that.

• Greg Stimatz: I feel for you there, because we’ve had that happen to us too. Fortunately, I think our Drilling Manager has been able to press that point upon management and they’re in the process of trying to secure a rig now.

• Arild Fosså: You might want to consider approaching the other operators up there - to see if it’s possible to share a rig. Some of the projects are experiencing delay after delay, so it might be worth checking with ExxonMobil first.

• Greg Stimatz: Again, I’m not tuned in directly to our efforts to secure the rig. But I do know that we have several partners in our well. I know that Norsk Hydro is part of it, EnCana and I think it’s Murphy. Each of those companies also have their own operated properties up there. They’re planning to drill too and we’ve been looking at sharing with them. I don’t know if we’ve gone outside that. I would have thought that we would, but I’ll take your point back and make sure.

• Arild Fosså: It helps knock the rig rates down, the longer the contract duration. • Alistair Stenhouse: The only problem is that you probably won’t get the rig at the

optimum weather time. They will get the optimum time and you’ll get what’s left. • Geoff Gill: Does Marathon have any urge to test these wells? Or is it purely

external forces driving it? • Greg Stimatz: I think that because of the remote nature of these wells, and the

cost of a potential development, that we probably would want to test. • In the Gulf of Mexico - we have no real inclination to do so - we’re very

comfortable with the geology there. If we can get good fluid samples, decent core and good log data – we can feel comfortable predicting well productivity and long term behaviour - and so go forward with development.

• In a frontier area like this, I would be surprised if we would go forward with billion dollar-type developments without testing the well. Even if the government doesn’t drive it, we would probably have a desire to do so.

• Alistair Stenhouse: How far offshore is it? • Greg Stimatz: About 150 miles. • Alistair Stenhouse: Subsea? • Greg Stimatz: Almost certainly. But that’s still a big question mark at this point.

Right now, we’re trying to explore in a large enough area to find enough fields to string together to justify putting in some shared infrastructure.

Testing By Choice Or Government Requirement • Geoff Gill: If you do a test, you’d want to do a proper, full package DST? • Greg Stimatz: It could go either way. I’m thinking that if we’re “forced”, as it

were, by the government, to test under conditions where we normally wouldn’t, it might be more of a closed chamber-type test. They only require a ‘flow test’; they are not more specific. On the other hand, if it’s something that we feel is going to really help our development decision, if we’re going to all that trouble, we’d probably design a more rigorous test.


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• Geoff Gill: If it were me personally, I’d try and figure that out. A simplistic test means that you can fly in lots of the kit at the last minute. Obviously, you’re not going to fly in your choke and your surge tank on an aeroplane, but DST tools can be put on an aeroplane quite easily. So your regret costs will be low.

• But if you want to do a full pitch DST, you do want to be pretty sure that you’re really going to be doing something - before you do all that planning and commit to spending all that money and getting all the right kit into the area as well.

Depletion To Reduce Development Infrastructure Cost • Brian Imrie: It depends on how you counter-balance your regret costs. If you’re

getting serious about developing the discoveries, then depletion is important. An oil company might try to deplete the reservoir quite quickly – so that the infrastructure might get down to 10k rather than the far more expensive 15k psi.

• The perfect example of that is ConocoPhillips with Embla across in Norway. They took it to the minimum. Their shut-in wellhead pressures were 9,800psi when they started. They knew it would deplete and they were safe.

• This is why doing drillstem testing need not have regret costs. You’ve got to actually spend the money - to get the data - to plan your field development. Don’t even bother getting a drilling unit if you’re not going to get the right data to help the development decision. If you can get the correct information you can then take it on to a development and save money.

• I think Embla is a good example and perhaps Shearwater is a good contrast. Shearwater was completed with 15k kit throughout, which cost a fortune. I would have argued for a different approach to drilling and completion – to find a way to deplete the field more simply to the point where they would have had a 10k psi surface pressure.

• The harsh environment is always a special challenge, so you do need to know what you’re drilling into. It’s essential.

Testing By Choice Or Government Requirement • Geoff Gill: Brian, my point really was to clarify whether testing would be due to

government requirement or operator choice. That really drives the approach. • Greg Stimatz: I think that eventually we will test because we want to. But there’s

that wild card out there. One other component of the government regulations are the way they’re written.

• At some point in time, when you decide that you have significant discovery, or you convince them of that, they issue what’s called a Significant Discovery Licence. This assigns the acreage to you for ever. You can go “hunting” for other fields and work out a long-term plan.

• The Canadians have yet to issue a Significant Discovery Licence without a test having taken place. So that will come in to play, at some point, when we’re looking at our other exploration prospects in the area. We’ll probably go back and test the well. If we do it on our own terms we’ll probably have different objectives than if we do it purely for governmental reasons.

• Arild Fosså: Based on what I’ve heard, perhaps the Nova Scotia Petroleum Board is less strict than in Newfoundland.


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• Greg Stimatz: It’s interesting. Their regulations are actually written into law - so to change a regulation requires a change in the law. Obviously they have a little leeway – in that they can grant a deferral.

• ChevronTexaco just drilled a well up there in the last several months. Through the grape-vine I’d heard that they had been given a deferral from the government to test within a 3 year period, not necessarily straight away.

• So there’s a little leeway, but the bottom line is that eventually we’re going to have to test. So there’s hope for you service companies yet!

• Arild Fosså: The first thing I’d do is check with the authorities is if they would accept a closed chamber test as a substitute for a DST.

• Greg Stimatz: All of that is being worked right now. • Arild Fosså: I’ve seen it go both ways. In most cases they consider a closed

chamber DST in the same way as a normal DST, but there have been exceptions to it. The biggest argument for a closed chamber DST is actually environmental, because you’re not doing any flaring. That might “swing” it.

Planning A Deepwater Welltest As A Project • Greg Stimatz: I have picked up on the comments from Brian earlier, which were

seconded by others, to plan this as a project and not just an operation. I think that is a good approach.

• Alistair Stenhouse: Yes. Setting clear objectives for what you want right up-front. If you don’t do that you’ll have fuzzy results.

• And having limits for what you want. So that you don’t say well, we can flow 10,000 bbls/day and then somebody phones you up and says we want 15,000 bbls/day - you can’t do that! We used to do that, but we don’t do that any more.

• Greg Stimatz: At this point, we’re probably “planning our planning” as it were - so I’m trying to take all this into account.

• Alistair Stenhouse: The other thing I’d say is involve the service companies - because a lot of the experience is in the service companies.

• Greg Stimatz: That’s all I had. I’ll continue to talk to you all in the breaks and exchange some contact information.

• John Curley: Okay, thanks Greg.


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6. GOOD PRACTICE IN HARSH ENVIRONMENT TESTING - ALAN CHRISTIE, SCHLUMBERGER

• Alan Christie: This will be a very short presentation - simply because everything I’ve got to say has already been said in one form or another.

• I can tell you some stories, not related to east coast of Canada or the North Sea, but some other remote locations - things to be aware of.

Pre Job Engineering - Objectives and Procedures

• Alan Christie: This is based on my experience both in Shell and in Schlumberger. By pre-job engineering I particularly mean objectives and procedures. Objectives - make sure you know what you want to do. Procedures - make sure you know how you’re going to do it.

• Make sure that all the client requirements are understood. This is what I try to do, from the subsea test tree point of view, mainly with the SenTree7. Make sure that all the barrier philosophies are understood, the test objectives, the kill procedures. Look at the rig interfaces, the BOP capabilities, space-out, annular capacity to close round slip joints.

• The weather has already been touched on, so I’m not going to do it, but I will say something about riser operating capability (heave, pitch, roll, wind speed, visibility).

• I’ll bring up riser-in-riser operations because that’s an issue - how does one riser react to the other?

• Disconnect philosophy - recover or hang off? Basically do you want to disconnect and recover all the way to surface so that you can check everything out before you re-run it? Or do you just recover and hang and relatch? That’s both for BOP and inner riser and also what applies to production equipment - LRPs etc.

• Also the reconnect philosophy - integrity testing and what do you want to do when you reconnect?

Writing Disconnect Procedures • Alan Christie: So it is important to make sure that all of the above is well

understood. I looked up some of the disconnect procedures that I wrote for Shell for subsea completions. The hardest task was taking so much data and turning it into something that people on the rig can use.

• There’s a lot of data there. But you need to give them something that is easy-to-use - basic guidelines. As Alistair said, quite rightly, the final decision will be made on the rig – but they need some guidelines. Don’t make it too complicated and don’t make it too simplistic. It’s a fine balance.

Equipment

Alan Christie (1) 713 715 2108 [email protected]


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• Alan Christie: Then looking at the equipment - is it standard or is it customised? If so, how is it customised? Is it a new widget or is it a new system - a new way of using widgets? This might for example be about closed chamber testing. Is it an off-the-shelf service or is it specialist? Is it something you can pick up?

• We touched on this with Mark - we have so few pockets of people around the world now who know how to do this, should we have them all in one place? This is something the industry needs to work out. From the service companies perspective, we need some help from the clients on that.

• Are there some new operating parameters for the standard equipment? Are you trying to push equipment to the limit? Was it designed for that?

• We’re actually using for instance, some test tree systems in open water to do interventions in the Gulf of Mexico for clients. So we’re pushing the limits. We’re actually well within the limits of the equipment itself, but we’re using it for a completely new application from a non-drilling rig vessel. We’re doing coiled tubing and wireline interventions into subsea wells without having a big LRP system. There are some restrictions on that, it’s not universal, but we’re using it from a DP vessel.

• Customised - do you need some customised equipment? Do you really understand what you need and do you have the lead time to do it? For example, high bending loads can give you changes in some parameters. Is some of the customised equipment rig-driven or buyer-driven or intervention method driven?

• Do you want to run different types of coiled tubing in the well? • These are all issues, but I guess you’re already asking all these questions, so I’m

going to speed through them because they’ve mostly been covered.

Logistics • Alan Christie: Logistics is a major issue for all remote locations. Emergency

response - flying time - how far is it from the rig to the nearest heliport? How far is it from the nearest heliport to the nearest hospital?

• Transportation. We’ve had some instances where the best approach is to load the equipment on to the rig while it’s in port and then sail everything out to the location on the rig. It’s happening this way for some locations on the west coast of Africa. For instance, there are some prospects in Mauritania, where the job’s being run from Perth, Australia. Support logistics have to be considered carefully - there’s no boat, no easy airports, you’re a long way from a hospital.

3

Pre job engineer ing

• Equipm ent

– St andard or Cust om

– St andard

• Of f t he shelf or Specialist service

• New operat ing param et ers

– Cust om

• Tailor m ade t o suit condit ions (High bending loads)

• Rig dr iven, bar r ier dr iven, int ervent ion m et hod dr iven


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• Contracting strategy. Are you just going to wait until you’re ready and then say ‘now can I have somebody?’.

• We have had instances where somebody has said they don’t like a particular person and have wanted him off the rig, and out of the country. But the flight off the rig isn’t until the following week. And the chopper flight doesn’t match with the only commercial airline flight either. So not only could we not get the individual off the rig quickly, but we couldn’t get somebody else in there quickly to replace him.

• So be very well aware that these things can exist – it is not like the North Sea! That includes equipment too - don’t forget your crossovers because if you do, you’re going to be in deep trouble!

Customs and Immigration • Alan Christie: Import Regulations. Here is an example from Brazil. We’d

imported a whole SenTree system and used it for Petrobras. Shell wanted to use it. We had to export it and re-import it again, rather than pay a huge amount of duty, which nobody wants to do. In many countries the import/export regulations are not very flexible. Even if you have equipment in the country, you can’t use it for somebody else without paying horrendously high fees.

• Visas: It’s very difficult to get visas for some of these places. Equatorial Guinea, for instance - not easy to get.

Health Issues • Alan Christie: Health. There

are health issues down there and other remote parts of the world. Malaria is a very prominent problem. Some of the problems are even caused by the medication too - Larium for instance. We’ve had two Schlumberger people die with cerebral malaria as a result of trips to Equatorial Guinea. Yellow fever too - it takes 10 days from having the injection to being allowed in the country. Something else to think about.

Flights

5

Pre Job Preparat ion

– Im por t regulat ions

• Fees, t im e eqt allow ed in count ry, only allow ed t o be

im por t ed f or one operat or m ust be re-im por t ed f or anot her .

– Visas

– Healt h ie Malar ia, Yellow Fever

– Flight s

• Passenger & t ranspor t aircraf t

4

Pre Job Preparation• Logistics

– Emergency response

• Flying time, distance of heliport to nearest hospital, etc etc

– Transportation

• Transit deck load, support logistics

– Contracting strategy

• People and Equipment


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• Alan Christie: Flights. Both passenger and transport. In some of these remote places there are not a lot of passenger flights in and out. Often there’s nowhere to land a big transport aircraft. So again, issues on job preparation.

• Alistair Stenhouse: Just a slight aside, it’s something about helicopters which I picked up yesterday in a partner meeting. I never knew this before - I thought a helicopter was a helicopter. The West Navion had an incident last year when a helicopter fell over on its deck with the rotors going. They hit the co-pilot who was badly hurt.

• It was a Super-Puma - apparently a Super-Puma can tolerate only a very low angle of tilt before it falls over. It can only stand a one metre heave. One metre of heave is not a lot on a DP drillship anywhere in the northern hemisphere. Some other helicopters, like the ones we’re using now, can stand 4 metres of heave – equivalent to some thirty-odd degrees of tilt. So don’t just assume that a helicopter is a helicopter on a DP Drillship. There can be a huge difference in safety.

• Øystein Jensen : Not only a drillship of course, but also production vessels. • Alistair Stenhouse: Yes. Production vessels, DSV’s etc. • Brian Imrie: I think production vessels have special helipads to keep helicopters

on board - just as a contingency they’re having to do that in some of the really harsh environments.

• Alan Christie: Yes. It is instructive to consider the service company’s role in all of this. Schlumberger, Halliburton and Expro all have to look after these issues for our people. This is a cost; it doesn’t come for nothing. You don’t just turn up and get this done. There is a lot of administration and a lot of investment in people. So we do have a cost in here that has to be recognised.

• Often in some of these remote locations, we are more familiar than some of the operators. That is simply because we’ve often been there longer. So we’ve got a valuable role to play in preparation for the job, because we know the local conditions.

Qualification Testing • Alan Christie: Qualification Testing for Equipment. Client funded testing – for

example, if you want something special, if you want to take some equipment to beyond where it normally operates. Or, perhaps you just want to test it for your particular application. In all such cases, you’re going to have to fund it.

• We’ve got limited resources and we cannot afford to pay for these extra tests ourselves. We do normal product development qualification testing - within the normal bounds of what the equipment is designed for. If you want anything beyond that, then you have to

6

Qualif icat ion Test ing

• Client Funded

– Deepw at er – eg Norw ay

• Replicat e operat ing environm ent

– Hyper bar ic t est ing of syst em s

• Qualif icat ion t est ing –

– Prot ot ype or not ???

– Third Par t y Cert if icat ion


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fund it. For example, the deepwater system in Norway was funded by 4 clients. • Replicating the operating environment. We do a lot of that, like everybody else.

We do hyperbaric tests of subsea test trees for example, put them in a chamber, pressure them up and test them. The investment in that alone is $1.5-2 million dollars - just for the test chamber.

• Qualification testing: For something new - do we build a prototype or not? We actually run “Serial #001” equipment now because our engineering process allows us to do that. But you have to be aware of that.

• Third party certification. This is another area where we get quite a few different opinions. Sometimes that’s forced upon us by clients. We have to consider how we go ahead on that.

• Brian Imrie: Another issue is political. The deepwater system development in Norway was partly to be able to give the government a “feelgood” factor about the industry’s capability to do the job. The operators had to demonstrate to the NPD (Norwegian Petroleum Directorate) that they could actually do such testing in a safe manner. There’s a big political issue. Everybody was behind it, and it was great to have the support.

New Equipment Development • Alan Christie: New equipment. We’ve got investment engineering lead time to

consider. These things don’t just materialize, although sometimes it might look that way. A concept for SenTree 3 coiled tubing cutting only took 6 weeks to make, qualify, build and ship. But we had it on the drawing board for 2-3 years - people dabbling with it, on and off. For these reasons, we don’t really know exactly how much it cost. To get the money back we had to order 6. But there’s not that many people using this system – simply because there’s not much coiled tubing run on exploration welltesting. We usually use this in open water applications.

• Mark Cooper: One problem we have in Hydro is that everything is project-driven. So for example, the Ormen Lange team had to pay the whole cost for the hydrate heating tool. We couldn’t fund it through a Hydro development budget, it had to be a project expense. For any new equipment like this, we have a “nightmare” trying to get any money to fund it.

• Alan Christie: You’re not alone. • Brian Imrie: Some of the oil companies try to get equipment development funded

by a specific asset production development budget – the place where the technology is destined to be used. I can think of heavy oil testing examples.

• Mark Cooper: Yes, but it can take time. The deepwater heater took about 2 years within Hydro before it was agreed to spend the money on it.

7

New Equipm ent–Cut s CT

–16.00 OD

– 3 .0” ID

– 15 ,000 psi

• Investment in Engineering Lead time

• Eg – 12 months concept[t to mfg drg

• No prototype

• Mfg & Testing 6 weeks

• Min order 6


_____________________________________________________________________ 74

• Brian Imrie: It depends on who you can lobby. If you can get some of the people who are going to do the developments involved - and they can see the benefits of it - and not just in one area – then they can see that knowledge being transferred. It’s about being able to sell the concept and the tool to many different departments.

Operational Interfaces • Alan Christie: Operational Interfaces. In Shell, we used to spend plenty of time

on the operating procedures between Shell and the rig. Bridging documents and the like. If you’re putting someone on a new facility, then bridging documents need to work between the vessel, the operator and the facility. It might not even be your facility- for instance if you’re tying back to somebody else’s platform or somebody else’s pipeline. All these things have to be considered.

Project Management • Alan Christie: I look after subsea completion trees. We’re working in 7,200ft of

water today with this kind of system. Lots of operational interest. It’s a significant challenge and this is why it’s managed as a project.

• This is more about horizontal trees; it’s not really welltesting, it’s cleanup. There are lots of interfaces with all the tree manufacturers and they’ve all got different running tools. There are different tree spaceouts, different shearing capacities, different response times etc…. I could go on, but basically the point is that it’s project management. You need somebody to look at it - you can’t just turn up on the day.

• There’s a lot of work done and there are processes in place. I’m sure Expro and Halliburton are the same. The point is that operators need to engage us earlier in the process to get this done properly. I think it paid off on Canyon Express. We didn’t have any problems at all - because we were engaged early.

Management Of Deepwater Harsh Environment Safety Systems. • Alan Christie: Selection. Do you need a subsea completion test tree? There’s an

emotive debate. You’d probably have to assess it on a case by case basis. • Controls options. It depends again

on your HAZOPs and your FMEA/FMECA [Failure Mode Effect (Criticality) Analysis] - whether you need no controls, or feel you can’t run umbilicals.

• Electro-hydraulic, fast response - what does that do for you? Do you want to go for something completely different with multiplexing where all your hydraulics go down to the wellhead and you send electronic signals. All these systems bring you different things.

15

Com m ander Telem et ry


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• There’s a lot of equipment. This picture shows BP’s scope of supply for the SenTree7 and commander controls. There’s a lot of equipment there, so think about that when you’re taking it offshore - where are you going to put it? The reel is very small, but the rest of it can take up a lot of space. You’ve got surface control units, hydraulic power units and umbilical reels.

• This is what it looks like offshore - handling the thing - Marathon, TFE and BP used a dual derrick rig because of the logistics of handling all this equipment. The pipe handling system runs well, but it needs managing. It takes a lot of preparation to get it to work.

Proper Planning and Preparation Prevents Poor Performance • Alan Christie: Finally : Pretty

Poor Planning makes Pretty Poor Performance (or words to that effect). If you don’t have clear objectives and you don’t have clear roles and responsibilities, if you don’t know who’s doing what, if you don’t set up your project correctlyor if you don’t have a clear contracting strategy, how can you engage your contractors? These factors will all give you problems.

Early Involvement • Alan Christie: Getting early engagement with the client is really the key. We do

it this way with SenTree 7 and we’ve got a pretty good track record. We don’t do it so well with SenTree 3 and I think we’ve had some problems; we do it in a different manner.

• It takes a culture change, especially in welltesting. It’s now a project-based business and these are one-off projects. But if we’re not involved early then it limits the value we can bring and the client gets limited benefit.

• We may be doing a good job in some parts of the world, we’re engaging people early. But in some areas we’re not. And you’re driven by government regulations. In Angola we’d love to do all these good things, but the government might not let you. Or in Nigeria, or Brazil or in Canada they’ll force you to do things and not let you do other things. We can have the philosophies, but there are some things you’re just not allowed to do. .

Change Control Management • Alan Christie: Change control management. I don’t think we’re very good at this.

Changing your mind somewhere through the project and not letting everybody know what the change is, and how it impacts them. There’s no point in just telling the people on the rig if everybody else doesn’t know. I think a lot of the other aspects are in place, but I could spend hours talking about change control issues and how it has impacted the performance of a project.

16

And f inally … … … ….

• PPP = PPP• Clear ob ject ives• Clear Ro les and Resp onsib ilit ies• Clear con t ract st rat egy• Change con t ro l m anagem ent


_____________________________________________________________________ 76

• Greg Stimatz: The management of change is important. I think we’ve taken note of that, and hopefully become better. But it still crops up from time to time - where not everyone knows what’s going on.

• Alistair Stenhouse: I must admit, we’ve had it for our 2 wells, back and forth. People have got confused. They think that they’re two deepwater wells, so they must be the same. But they are totally different; totally different wells and totally different equipment. Some of the suppliers have been scratching their heads keeping up with us, but I think we’ve just about got there now.

• Alan Christie: It’s difficult. If it was easy, it wouldn’t be on that list, would it? It’s a very difficult thing to do, to manage that process. It takes time and it takes people. That’s often the two things that we just don’t have - and it does impact on performance - big time.

• John Curley: Okay, thanks very much Alan.


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7. HARSH ENVIRONMENTS - A SERVICE COMPANY PERSPECTIVE - BEN STEWART, HALLIBURTON

• Ben Stewart: I had 3 different presentations to chose from for today – but this is the shortest of the 3. We chose this one because this is one of the rare instances where we have gathered a lot of experienced testing people together in one place. The typical things that you might get up to present therefore aren’t applicable - most of the people in the room recognise good practice.

• One talk was similar to Alan’s. As Alan said, if you’re really going to have a successful test, you

need to get engaged early. To get to a good result, Alan has outlined what really is the process that you have to go through. The sooner you start doing it, the better off you are.

Mitigating Risk, Cost Management, Data Quality • Ben Stewart: Let’s look at the challenge of this meeting - testing in a harsh

environment. A clearly defined, harsh environment. The service company deliverables include being tasked with mitigating the risk. Within this risk modelling, the service provider is tasked with balancing the cost management and the data quality. It’s our job to deliver to the operators the best system for achieving their objectives.

• That’s what today has been about. Whenever I’ve attended these meetings I’ve thought that it would be better to come in here with a blank sheet of paper and then build a presentation around the topic to take out to the industry.

• Greg’s challenge is really what we’re in business to do - to supply him with the guidelines for achieving his well objectives.

• This is what we have to think about when we do it. How does the service provider manage the risk in testing in a harsh environment while at the same time delivering cost management and quality data?

• So to repeat what Brian and Alan said - the sooner you engage the service industry, and the sooner you can tell us what you want to achieve with your well or with the field, the better.

• The more isolated the location, the more important it is that we know what this well could do. If you don’t want to test the first well, but you do want to test the second well, we need to know. We need enough information from the first test to design the second test.

Ben Stewart (44) 1224 776277 [email protected]

Meeting Challenge

• How do you mitigate risk in the environment defined by the scope ofthe meeting. In this risk model the service providers are challenged tobalance cost management and data quality– Weather– non well aspects– remoteness– terrain– sea conditions


_____________________________________________________________________ 78

• The second aspect is the well environment - the sea states. If you’re in the Gulf of Mexico in deepwater, you’ve got a high frequency wave action, which is different from elsewhere. There’s a different kind of risk associated with working there compared with a place that has a very long slow frequency to the wave action. Two different things. The vessels will move differently. The sea states are different. There are many different things that you have to understand.

• And that’s our job. If we understand the environment, then we can do a better job when we evaluate what we can do. We can give you a better set of options than if we aren’t engaged and we don’t understand where we’re going to be.

• Thirdly, it’s up to us to define what we can achieve. We have to be able to tell the operator what we can do in the different options. And when we come up with this, it’s supposed to be interactive. For example, a lot of different things can impact on what Greg wants to do when he goes out to test in Nova Scotia.

Understanding The Objectives • Ben Stewart: The important start point is understanding the well objectives -

that’s paramount. I have an anecdote for you to illustrate. We met with an operator, talked to him about a well and went through all the planning process. We then accidentally came across a presentation that had been given to the partners. The well objectives in the partner presentation were different from the ones we were working on! They had a longer-term objective than we knew about. They knew what they wanted to do. The structure was positioned in a very strategic area. They had to do a certain amount of work to evaluate what they were going to do with it. As a result, we had to go back and redefine what we were doing.

• Arild Fosså: One good idea as regards objectives is to have a “Plan B”. You may have decided upfront that you need some geology data and some pressure gradients and a fluid sample. You may plan to stick to that, but it’s good to have a “Plan B”.

• It seems quite common that the deepwater areas often tend to have soft and unconsolidated sands. And a disproportionately high percentage of the wells seem to find heavy oil, not gas. The normal wireline-deployed tools might not work in these soft formations. You can get stuck and have to fish it out of the ground. If that happens, you may end up having a well that cost $60mm dollars to drill - and potentially not have anything to show for it. This begins to suggest the merit in having a “Plan B” - a “What Happens If” plan.

• An example of this happened in south east Asia just recently. The client has tested about 5-6 wells in deepwater, but so far they haven’t managed to take a single fluid sample. They don’t have anything to show on the fluids side, so they can’t design the process facilities yet.

How does a Service Provider managethis risk

• Understanding the client’s objectives• Understanding the risks associated with the well environment• Defining what can be achieved


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Collaborative Team Environment • Ben Stewart: Alan mentioned change control already – and that is founded on

having “a concern for impact” on other members of the team – it is about working in a collaborative environment. If we don’t work as a team collaboratively, our test results will be exactly what you’d expect from working disjointedly.

• There are 3 things up here on this slide, but there are many more that could be added. We just wanted to limit it to 3.

• The first thing is: identify the people you’re going to be working with and then most importantly - make sure they’re talking to each other. For success on a test in a harsh environment - where there’s so many things that can affect the outcome - it’s really important that the people talk.

• Alistair Stenhouse: Can I make an observation here? One of the things we’ve noticed is that the service company key focal points change every week. It’s almost impossible to keep up with all the changes.

• Brian Imrie: Get us involved with the project, give us a day rate for the person and he’ll be available!

• Alistair Stenhouse: Maybe. • Alan Christie: That is, until you hire him! We all know that can happen. • Ben Stewart: The second point is that if you look at the people typically now

involved in testing, very few of them have actually been on more than one or two tests. So it’s really important at the outset that you define the accountability, responsibility and authority associated with each person in each position.

• Because no matter who is in that job, they need to know what they’re accountable for, what they’re responsible for, and how much authority they have. Because if you have to make a decision, you want to be able to make a decision. If the person is there, and he can’t do the job, this is where you’re going to find out wheter or not you can work with him long term. That is because you’ve defined what his deliverables are - his KPI’s (Key Performance Indicators).

Document Control Systems • Ben Stewart: Thirdly, control of the projects. We recognise that when you’re

working on testing, it’s really important that you control the documents going back and forth. It is most important to make sure that everyone is working from the same version of a specific document.

• So we have created a website where we can manage a project. I think that this is probably one of the more important tools. I’m sure that Schlumberger and Expro have their own equivalents.

• Halliburton has created the myhalliburton.com site (https://www.myhalliburton.com). It’s secure - the only people that will have access are the people that you let in. All the documents should reside there,

Creating Collaborative Environment

• Identify key focal points and they have to talk to each other• Define accountability/responsibility/authority• Project communication network - myhalliburton.com


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there’s a common calendar, there’s a collaboration tool where you can assign tasks and know that they are deliverable. You can link different bodies together.

• Alan Christie: Yes. Schlumberger are starting to use the same thing – ours is called project.net (http://project.net/index.jsp). It’s the same sort of thing - it does the same things and offers chat rooms, etc. It saves sending e-mails back and forward and having to remember e-mail addresses. Everybody logs in, there’s an update every day as to what’s been changed on each document. To change a document you have to log it out, change it and then log it back in, so everybody knows you’ve been working on it. It’s a good tool. But it’s like all the other computer-based tools - people actually have to use it.

• Mark Cooper: Exactly. Ormen Lange was done like that. The whole project, from beginning to end on this well, was done on the Internet. We’d all log on and get a daily e-mail and we’d have to update this and that.

• Well, I don’t like it. I don’t know how other systems work, but on this one, you had to navigate through a lot of different links to get to where you needed to be; wait for downloads etc. Maybe it is getting better, I hope so. It is actually one of the reasons we didn’t get the riser insulators on – the person who was responsible didn’t read his section - to see that he had to do it!

• Ben Stewart: That’s why it is so important to have somebody who is accountable and responsible - who has the authority. That’s his project - he has to manage it. He should see every time somebody goes in there. If you check a document out and modify it and then save it back, it doesn’t over-write the original document. S so you can take a look at the process of change. When something goes wrong, or when something goes right, you can actually understand how you got to that point. When you’re going forward with a project, those are the important things. It has to be collaborative, and you’ve got to have control.

• Alistair Stenhouse: That’s all control, but it’s not actually engineering. I’m just concerned that we’re spending an awful lot of our time sitting looking at computer screens filling in boxes instead of doing real engineering.

• Alan Christie: This is only a tool to help you manage the process. • Alistair Stenhouse: I realise that. • Ashley Brammer : You should still be doing the same things as you’d do anyway

– it’s just making it visible to everybody. • Ben Stewart: It reduces miscellaneous e-mails. It also makes sure that when you

actually do the engineering, that everybody knows about it. • Brian Imrie: I was very sceptical about it at first. But what I enjoy about it most

Alistair, is that you can control the process. There’s a hierarchy. It means that you’re responsible and controlling the whole process. There are other people down the line responsible for their part of the process. That’s the best thing I got from it. Granted, there are points about how effectively people use the system.

• Alistair Stenhouse: Was this for Ormen Lange? • Brian Imrie: No. It was another project. • Alistair Stenhouse: It’s interesting that the only feedback we’ve had is not very

positive about this as a means of running a project. • Brian Imrie: What were you using Mark? • Mark Cooper: This wasn’t the Halliburton or Schlumberger systems. This was

another system being tried out by Hydro - from Datalink ( http://www.datalink.com/). It’s based on ‘living’ documents. If you go in and


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make a change on a document, say concerned with the riser management system, then everyone else knows who went in and changed it. But it needs someone “policing” it really hard - someone who is dedicated to policing it. People otherwise just don’t do what they’re supposed to do; they send you an e-mail instead, or as well as.

• Ben Stewart: These are actually pretty good document control systems – whether it is ours, Schlumberger’s or one of the independent systems. We can show you the value - if you use this system the way it’s designed to be used.

Understanding The Risk • Ben Stewart: There is also a challenge to understand the risk associated with a

well environment. We’ve already talked about understanding the state of the seas, but actually the two most important things you depend on are having a Management System and the right experience. A process map can help drive your success - because you have a way of auditing and QA-ing as you go through the work.

• The major service companies all have management systems. Inside the system they’ve got clear cut guidelines - processes for designing the service that they have to deliver - so that you can audit the path to get to the result.

• They all have logistical control mechanisms. Alan was talking about the case in Equatorial Guinea, where the equipment was sent from Australia. We had a test in the Seychelles and the equipment was loaded out from Singapore, Oman and the UK. We went back through the process, evaluated it and actually everything got to the rig at the right time, with nothing missing. But it was one of the few cases where we actually used the management system - because it was otherwise extremely hard for people to visualise what was coming. It was pretty impressive. The well didn’t test in the end, but everything got there on time.

• Alan Christie: We had a similar case and we used the same sort of system for a job in Sarawak in Malasia. We had equipment coming from the States, some sent by ship from Houston, some from Los Angeles, some from the Far East, some from Aberdeen and it all got to Sarawak as planned. It all went on the rig, and went together as planned. We used the tools and there was discipline. If people didn’t naturally use the tools, the discipline was there to force them to make use.

• Ben Stewart: It’s about having the control mechanisms – they all reside in the processes. When you go in to test in a harsh environment – due to remoteness or the terrain - those are the key issues.

• The second point is about the global and local knowledge resources. There’s a tremendous amount of information out there that you can draw on – for analogue data to help you make decisions.

Understanding the risks associated with thewell environment

• Management System (HMS)– Design of Service– logistical control mechanism– Verification

• Global and Regional Knowledge Resources– Correction, Prevention, Improvement Databases– Safety and Environment Statistics


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• All the major service companies are essentially the same in this regard. You can go back into the database and look up what was done to correct something. In other words, there was a past problem. What lesson was learned to help prevent a repeat in future? And what improvement was made? It tells you a lot. It’s probably the best history of what’s happened on a job or while preparing for a job. Those resources are there for people to use.

• So if you’re going to test in a harsh environment, and if the service company is going to deliver the cost management and control the quality of the results, those are the most important things. They relate back to each one of the earlier slides in a logical order. And when you do this, it drives success.

• Brian Imrie: I got a surprise when I first started to use this tool. The contract we had received from the Norwegian operator mentioned all the documents that we were supposed to be working towards. I set out to load all the documents that were referred to in the contract. But at first the operator couldn’t even find all the documents they were referring to. Nobody was using the system - not at all. Once we eventually got the documents loaded some people were seeing them for the first time. It was quite amazing.

• Arild Fosså: A lot of that is due to cut and paste out of the original NORSOK standards. There are certain parts that people use and certain parts that they don’t.

Evaluate The Options • Ben Stewart: The next logical

step - for us to be able to deliver what’s expected of us - is that we’ve got to evaluate the options. It’s important that you trust us - that we’re actually going to do it. And you can audit the process that we go through.

• For us internally, we’ve got to define the options. It’s our responsibility to go through, and take a look at what can be done in the situation. There are a lot of ways to do it. Each of the service companies has their own database - tools that allow you to rank the fitness of a solution to a task.

• Mobil actually paid for system called PTTS - where we took a look at all their completions equipment. It didn’t matter who owned the equipment, because the same people ran all the equipment. It involved people from Guiberson, Baker, Otis etc - lots of different equipment - and the database allowed him to take a look at what the best solution would be in each case. In the first year that they used it, the savings were tremendous - because it was a system that they could audit.

• Ben Stewart: So it’s our responsibility internally to make the decision about what we’re going to propose to you

Evaluate the Options

• Define the options• Rank the risk associated with each option• Make a Decision on what to propose to the client• Evaluate decision and decision making criteria with client

– this is an iterative process


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as the best solution. We should also be able to explain the alternatives. As Arild said - always have a backup and always have options. Options are your best friend when there’s nobody around to help you.

• Lastly, evaluate the decision making criteria with the client. Talk to each other. We’ve got to be able to sit down and go through things. It’s an iterative process. It’s not going to end with the first time through the process.

• The real trick whenever you evaluate your options is to go back to basics. A simple Boston Square analysis can help. You can identify things that you can do, but they could be pretty risky. There are other things that aren’t so bad - these are the things that you could consider first off.

• You can take these, and match them with the client’s objectives, with the risk associated with the environment, and the risk associated with each of the solutions. You can then come up with the options.

• That’s how you build success when you’re testing. If the challenge for us is to deliver cost management and quality data, this process is mandatory on our part. And it’s mandatory that we talk to each other as we build the solution.

Testing ToolBox • Ben Stewart: Let’s first look at closed chamber testing - a conventional test -

what we did in the 1970’s whenever the well wouldn’t flow to surface - when it was important to understand a particular zone. There are a lot of examples in the Central North Sea, especially around the Claymore area, where the operator knew that zone wasn’t going to flow to surface. But it was mandatory that he had some kind of fluid sample, or some kind of pressure data - because it was critical to the main reservoir evaluation. There are a lot of instances of this. Those wells flowed just a few litres of fluid, so they had to design a welltest to get what they needed.

• Secondly, advanced closed chamber testing is what’s being developed now. Everyone is working on something. If we look at our systems - you’re actually talking to it while the test is happening. Our FasTest is in cased hole and SILD is in open hole - they’re two different systems. With the advances, you’ve got a lot of control. With the FasTest system you can actually have three flow periods if you want. There are a lot of things that you can do. We should be able to bring options to the table and explain the value and the risk.

• Advanced telemetry system. I think Alistair and Geoff both showed that you’re always better off when you have technology that you can apply correctly. But if you apply it incorrectly, or if it’s not applicable, it can cause you “grief” - because it raises expectations.

• SeaLink is our ocean floor connect/disconnect package. It’s a hydro-electric system with a fast response. The

Halliburton Tool Box

• Conventional Closed Chamber Testing (Shoot & Pull style)• Advanced Closed Chamber Testing (using conventional tools)• FasTest – tailor made CCDST system• SILD – future CCDST Open Hole system• Advanced Telemetry System• SeaLink Ocean Floor Package• FasQ – Non-Nuclear Multiphase Meter• Real Time Operations• myhalliburton.com• Standard Testing Services and Equipment• Research and Development Capabilities


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dialogue about decision making shows that you need to understand the value of being able to unlatch in 5 seconds or 30 seconds. It relates to whether your concerns are drift off rather than drive off. The human element has to be considered. You have to decide what you would really do in a given situation.

• You need to evaluate all your options when you’re testing in a remote location. In fact that applies anywhere, I think, as the technology develops. FasQ is a multiphase metering system, but FasQ doesn’t have a radio-active source. If you’re going to fly it somewhere, you don’t have to worry about a live source.

• Real time operations pull all the expertise together. Let’s say Alistair’s two wells both came up at the same time. He can only be in one place at one time, but now the technology exists where Alistair could apply his expertise to both his wells at the same time. It can reduce exposure. Some people can work remotely where the logistics make it awkward to get to the rig quickly or where there are health issues, as Alan mentioned earlier.

• Our experience with myhalliburton.com has been really good. It’s not so much that it’s a tool that you put everything in, but it’s a place where you manage the communication, and that’s great.

• Standard testing services and equipment are the “bread and butter”. There are times when that’s probably the best solution for what you’re trying to achieve.

Integration • Ben Stewart: Every company

has a toolbox, and it’s our job to bring that toolbox to you. That is the way that we can together manage your costs, our costs and the data quality. Everybody is in business to make money, but when it all comes together, we get an integrated result which is good for everyone.

• Here’s an example which underscores what a good outcome looks like. It doesn’t matter where the well is - whether it’s in the Mediterranean, in deepwater or whatever. The real prize here was when the first well was drilled and tested and there was money left over. In fact, there was enough left in the AFE to drill and test a second well.

• Alistair Stenhouse: Fair enough, but it must have been a bulky AFE at the start. • Ben Stewart: Yes, but we’d need to look into how different operating companies

establish AFEs. • The key point is that the challenge for the service industry is to :

• Achieve cost management and • Deliver fit for purpose data and • Mitigate risk in a harsh environment.

• It’s actually pretty straightforward - going back to certain basics, using the tools in place, and talking to each other.

• John Curley: Okay, thanks very much Ben. Any questions for Ben?


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Dropping The Process When Under Stress • Ben Stewart: One thing that I take forward is to suggest that when we go into the

next session, it would be interesting to take Greg’s question and take a real stab at that – to pull things together. I would certainly find that useful. Today has been useful to bring together a lot of expertise. That is always a pretty solid foundation for achieving results.

• Alistair Stenhouse: Yes. I think the key is to have a process and follow it. The process will then identify the key issues. Then for example when people want to cut 2 months out of the schedule we can look at the process and identify what the consequences are. We probably can’t achieve all the objectives if we do that. We can cut the two months out, but we would have to cut back on the objectives, too.

• Alan Christie: That’s an interesting point. When we’ve done that in some cases, the client has said to us that they will find someone else to do the job. We may point out that we’re following the process and it is an agreed process and that if the client wants all the work done to the correct quality it will take, say 6 months. They don’t like it!

• Alistair Stenhouse: That is being shortsighted, though. • Alan Christie: Yes. But that is what predominates in the industry, Alistair. That’s

the norm, not the exception. • Mark Cooper: That’s not the norm in Norway, I wouldn’t say. • Alistair Stenhouse: It’s not the norm here in the UK, either. We have our own

planning process and we endeavour to follow that as best we can. • Alan Christie: OK, let me re-phrase the remark. There are several occasions

when we’ve been asked that question, and we have put forward answer in the sort of format that we are talking about here, and the client does not like the answer.

Coping With Limited Experience • Arild Fosså: There’s another thing that might be worth considering. I’ve sat down

with the clients on a few occasions and we’ve set the objectives for the well together. In many oil companies these days the reservoir engineers are awfully young and inexperienced. They don’t have any “stroke” and they don’t really know how to actually set these objectives. They may “cut and paste” from previous work and hope that it applies in this case.

• Sometimes you simply need to sit down with them and give them some “off the record” guidance to put them on the right track. It has been interesting to do those kinds of things. I would hope that the operating companies aren’t afraid of doing things that way – they can learn things from their service companies.

• Alistair Stenhouse: I used to look after the training of petroleum engineers in Amerada Hess at one point. It’s really quite difficult to find them appropriate training - to get them on jobs and to get them out on welltests. They happen so rarely and there are constraints on Personnel On Board (POB) and other things, that you just can’t get the people offshore to do it. They get just a little bit of everything - they don’t get an in-depth knowledge of very much.

• Ben Stewart: Most of the big service companies now have software now so that they can simulate a testing environment from the reservoir face and the perforations all the way to the burner. You can in effect do the test before you go out. Once again, this is about using the tools that you have available.


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• In Halliburton it’s called Cyber-tool. You build the test string, the reservoir, the burner, you’re able to operate the surface package. For inexperienced people that’s really what you want. You want to sit them down and go through the process of actually doing it so they come to understand. You can put pressure, temperature, torque, tension on the string and simulate what’s going to happen. There’s a tool that allows you simulate different problems. There are lots of things that you can do to reduce the risk by using the tools available.

• It would be nice for us if I thought that we were the only company who had that tool. But I happen to know that all the big service companies have these tools or that they use an independent package from the market – such as the package built by 2 ex-Schlumberger people.

• Brian Imrie: It’s a simulator. You can draw an analogy with the Eclipse reservoir simulator. It can be a real problem to get a history match with the real production world. They add on so many bits to get a match that the model can end up unrelated to reality.

• Arild Fosså: One good reason for not being able to history match is simply that they haven’t tested enough! I have made this remark to asset managers before. They’re using point values from logging and trying to history match. They don’t have flow data to go on.

• Brian Imrie: There are gaps in the experience. I’ve been involved in the designing of intelligent completions and sizing of downhole chokes. I asked if they’d checked critical condition through the whole flow path right to the line? They didn’t know what critical condition was. As gets said quite often, a simulator is only as good as the input.

• John Curley: Let’s take a break there.


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8. SERVICE COMPANY ENGINEERING DEVELOPMENT STRATEGY FOR HARSH ENVIRONMENTS - BRIAN IMRIE, SCHLUMBERGER

• Brian Imrie: My talk is about what we should be developing for harsh environment testing.

• The big thing about the Welltesting Network, and what everybody has alluded to, is to get the reservoir data.

• We have now got reliable pressure gauges. But we’re thinking about taking them a step further ahead because of the types of testing they’re looking at doing.

Technology Developments – Active and Shelved • We’ve got new testing ideas such as harmonic testing from Dr Alain Gringarten at

Imperial – for which we’re trying to improve the resolution of the existing pressure gauges. We are trying to create harmonics within a wellbore - to get better reservoir measurements without flowing anything. Of course this would be ideal to try and get measurements back within a harsh environment. Dr Gringarten has even brought PhD musicians into the frame because the process involves trying to create harmonics within the reservoir.

• On the PVT analysis front, we’ve been developing an on-site PVT analysis system for about 6-8 years. However, wave motions on a floater can play havoc with doing the PVT analysis, so there has been investment in trying to keep the system stable and balanced during the measurements.

• Alistair Stenhouse: Do we need it? • Brian Imrie: I would say no. This is the question. A lot of these things have

been stopped, Alistair. • The packer that Mark mentioned during his talk - it took us 6 years on the drawing

board. We’ve got one, or perhaps two - and we’ve used it once. • Alistair Stenhouse: The concept goes back about 20 years. • Mark Cooper: We’ve been asking for it for years and years. • Brian Imrie: Also acoustic telemetry - the deepwater IRIS control safety system. • We’ve been looking at “fancy” coiled tubing cutting kit. • We’ve got “smart” separators. Has anyone seen the smart separator with the

movable weir? We’re trying to improve the reservoir measurements. A separator typically provides flowrate readings which are ±15%, compared with the stock tank. You may get slightly better accuracy in Norway because you take lots of stock tank measurements.

• The issue is to compare that with fiscal metering, to actually tie that back. Everybody is trying to make more use of smart 3-phase meters. The dilemma is that we are spending a fortune on being able to make all these measurements - but we don’t test. We never use anything. They’re all lying in a yard somewhere. If we’re not going to use them, let’s stop bothering to develop them.

Brian Imrie (44) 1337 828516 [email protected]


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• It is also interesting on the environmental side - what we should be doing to keep up with noise pollution legislation.

• These are a few of the things that I know we put money into - either from our engineering budgets - or some of the others are items that we put in our more scientific R&D budgets. I’m not convinced that this is what we should be spending our money on - for this particular part of the business. We can make good justifications, as we try to do every year, to keep the budgets there. It’s exciting to go and look at harmonic wave forms and invest say $0.5mm in it. But if they come back with nothing, there is a big loss. We need to keep a sense of reality somehow.

Technology Development Drivers • Alistair Stenhouse: If I could just step in there - I said this earlier on, but it’s

appropriate to repeat it now - most of the big reservoirs in the North Sea (and in other areas) could be developed with Amerada gauges, right?

• I personally don’t think we need more accurate or better resolution memory gauges in 99% of the jobs that we’ll ever do. The only situation in which I’ve ever seen the need for better gauge resolution was during the site investigations for Sellafield - which was a very different thing altogether.

• In contrast, what we do need to do is to reduce the costs - the regret costs and the preparation time and the speed of the tests that we’re doing.

• It now takes Amerada Hess about 10 days to do a DST and £1½ mm - as opposed to 20 years ago when we could probably do the same thing in 3 days for a cost of say £½ mm in today’s money. I think we’re pricing ourselves out of the business.

Mark Cooper: High resolution gauges can help. For example, with the SILD - by producing 15 barrels into a closed chamber and monitoring the pressures with these high resolution gauges - we can get the same data in 6 hours as we got flowing the well for a week with the Amerada gauges.

Alistair Stenhouse: OK. If there’s a benefit, then fine. • Mark Cooper: It’s viable. We’re getting the same data as we did with low

resolution gauges from 10 years ago. • Alistair Stenhouse: In Sellafield, we did tests where we were essentially

deliberately testing ‘tombstone’. It was taking us 30 hours with an open hole DST to get a result. We got the same result in 6 minutes with an MDT and twin packers. Exactly the same result. So you could see a benefit from running MDTs.

• If it’s just a scientific benefit, it’s not going to “fly” - it has to offer a real benefit - in money or other terms - to the operating companies.

• Greg Stimatz: It could be a risk reduction benefit. • Alistair Stenhouse: Yes. Or a risk reduction - a safety improvement. • Brian Imrie: Or environmental. • Alistair Stenhouse: Yes. Environmental, Safety and Cost are all drivers. • Greg Stimatz: I like the idea of telemetry for the gauges - where you get away

from running electric line or slickline. • Ashley Brammer: It can help improve reliability and avoid downtime. • Greg Stimatz: It costs a little money and it adds a little to the price of the job but

it can be worthwhile. • Ashley Brammer: Geoff’s example of avoiding umbilicals - that avoids a failure.


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• Brian Imrie: Yes. We’ve talked for years about the IRIS control - to get rid of all the umbilicals and put all our modules downhole. It’s on the drawing board. It’s half-way there, because we’ve done it with the IRIS. That is one I’ll push - definitely. I can go back and say it was agreed here that it’s a good idea.

• Alistair Stenhouse: You can see it straight away - that it will save 2 day’s rig time. You can sell that to anyone. Just don’t charge 3 days rig time to run it, or it won’t work! That’s the bottomline.

Contracts – For Value Adding Services Or Minimum Cost Commodities? • Ben Stewart: But Alistair, one of the factors we have to consider is the way we

contract for services right now. That is driving some of the cost scenarios. • We could triple the price of the equipment, and yet still do a better job, because

we’d hugely reduce the time it took to achieve the objectives. But there’s a disconnect between the way we contract the services, and the drivers that are evaluated, and what you’re going to take out to location. I think that’s probably the biggest task ahead.

• We have a patent for an ultra-sonically operated acoustical tree. But when we went out and talked to the operators. We said ‘you do this, there are no cables at all. Everything is remote. This is what it would cost to build the tree, it is expensive because you’d have to have so much redundancy in the electronics package’. They wouldn’t accept the cost.

• Even something as simple as the OMNI illustrates the point. We learned lessons from the HPHT ones that were built out of Inconel. When we designed them, we introduced enhancements to reduce the risk of failure – but it would add significantly to the cost of the tool. We offered to go back and retrofit the enhancements to every one of our tools, and almost completely eliminate the potential for one mode of failure. But the increased cost wasn’t accepted by contracts people. It would have added about £200-300/day vs the average downtime in a test while you wait on a decision – say about 12 hours at £6,000/hr.

• Alistair Stenhouse: I guess, frankly, that you didn’t get the benefits over to these people. If they had seen the benefits....

• Alan Christie: No. I think it’s a big problem Alistair. • Ben Stewart: I think every one of the service companies has that problem. • Many voices : Yes. • Ashley Brammer: You get a contract for a single piece of equipment - it is priced

on the specifications. If 2 pieces of equipment can both do the same job on paper, and one is cheaper than the other, then the cheapest one always gets chosen.

• Alan Christie: Yes. They’re not interested in the benefit. • Brian Imrie: We’re treated as if we are providing commodities, rather than value

adding services. We’re contracted as commodities, not contracted as a package, or part of the project.

• Statoil gave us a FEED study for one of their HPHT field developments - one of their first subsea fields. We proved to them that big bore ball valves would deform at the high pressures and high temperatures they were talking about - this was purely from a mechanical point of view. We put engineers onto that project – and they essentially proved that you shouldn’t use the tools we’d developed.


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• It might sound strange, but that, to me, was a useful exercise. We were taking the equipment past the limit of what it could do within an 18¾ inch stack. If you had a bigger stack, and gave us more space, we could design different tools. But when you are limited as we were, there is a mechanical limit. So we actually “sold” ourselves out of that business. That doesn’t matter. In the end, we now know that you can’t do it that way - no matter what “fancy” material you’re using.

• That is what we should be looking at for harsh environments because we might have to change. They have to complete the wells differently. They can’t use a drilling rig in that mode, with a drilling riser, to complete the well. It’s not safe. We need to start thinking about new methodologies. We have to take a look and see what else we could do to help.

• It’s great that we’re repackaging some of the kits to give you what you’re looking for. That’s about you looking in the toolbox. I’m trying to look at what we’ve got on the drawing board to put in the toolbox? What is going to be more effective for us to sell, to get the data and samples you’re looking for?

Equipment Development Costs • Brian Imrie: The sums we put into development are not small. You’ve seen

some of the new kit we’ve got – for example the MUX system technology. It is brilliant equipment, but it is a challenge to do the fault finding and tie everything in together. We need a dedicated crew to work it all the time.

• Alan Christie: That’s how we’ve got to run it. • Brian Imrie: Ben, I’m sure Halliburton have the same challenges? You’ll have kit

on the drawing board that might never see the light of day? • Ben Stewart: Yes. That’s the biggest problem. For example, developing extreme

tools for 520 degrees F BHT. It’s a different environment, but the same story. • Everything was done to prepare, and then we had to tell the operators there was a

cost associated with actually delivering this equipment. There was this cost for the operators to be able to evaluate their structures in the basin concerned.

• And that’s where it fell down. Because the mentality is to do a cost effect analysis rather than a cost benefit analysis. We’re one of the few industries that doesn’t seem to do that any more.

• Brian Imrie: I was involved a while ago in a Win Cubed audioconference in one of the other networks (the Subsea network, NESSE). BP were trying to take existing 10K subsea trees and stretch them to a near 15K rating. At the end of the day, they decided not to do it that way, and instead to develop 15k subsea trees.

• On that occasion you could see there was a wider market - that enables you to go and develop equipment appropriately. But in testing – what do we do?

• Alistair Stenhouse: Our market is too sporadic. • Brian Imrie: Yes. It’s sporadic. So what do we do next? • Alan Christie: One of the challenges is to figure out how the testing business

dovetails with the development business. I don’t think you can have testing and development as separate activities any more. They have to come together in some form or another. Maybe that needs to be in the methodologies we apply, or some of the technologies we deploy, or whatever.


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• In loose terms, a DST is a completion, and so is a development completion – although different tools are used. Maybe we should be looking along those lines on how to move it forward. I have no instant right answers at this stage though.

• You can no longer justify technology development on just testing alone. That is “dead” - believe me, I’ve tried! It’s gone. I have put proposals to our management for the last 2 years. We believe we have a good case, but it gets turned down.

• It is all about choices and competition for the investment. It is about looking at the return you could expect from different competing investments. It is not so much about keeping the operator or service company testing business alive. So you need to start looking at what volume of business you can create out of the “testing and development” business – to enable technology development.

• Ben Stewart: The operators and service companies would need to enter into a different relationship on the cost/benefit aspects to achieve that however.

• Brian Imrie: I don’t know how much money the oil companies are now putting into investment in this part of the business. Generally zero, I’d say.

• Alistair Stenhouse: Yes, quite possibly. • Mark Cooper: I don’t think that’s true for Norsk Hydro. • Brian Imrie: Yes. You have something taking place in Trondheim I believe. • Alistair Stenhouse: I think it’s different in Norway. Norway has a different

approach to new technology – generally keen to give it try - whereas in other places the concern is more with the track record to date.

• Mark Cooper: Norsk Hydro has often been prepared to spend money on developing new techniques and equipment. Right now, Hydro funding several different projects for open hole test systems - SILD and FasTest, etc.

• Alistair Stenhouse: In the last 6-7 years I’ve only been approached once to ask if the company I worked for wanted to participate in a technology development.

• Mark Cooper: We gave up partners for the PatchFlex system hydrate melting system. We tried to get several other companies involved, and at the end of the day, it was just stopping it from happening. So we decided just to do it ourselves. Now, if someone else uses the tool, Hydro gets some money back from it.

Harsh Environment Welltests – Activity Level • Greg Stimatz: This may be a question for the service companies - how many

other harsh environment welltests are being planned right now? I mean ones that have a reasonable chance of going ahead.

• Ray Bullock: They’re going on in West Africa all the time. • Alan Christie: Also Khazakstan, Australia. • Ray Bullock: And in the Far East - although the weather conditions are quite

benign - there’s deepwater work going on there all the time. • Geoff Gill: I think Brazil is doing the most deepwater work. In Brazil though,

they use fairly mundane standard procedures and kit because of the environment. • Greg Stimatz: I mean harsh marine environment. • Geoff Gill: That would really just be North Sea, Norway and Canada. • Mark Cooper: In Angola, with these big drillships they still have very similar

problems to ours. They’ve got 2 metre heave. They’re so long that the whole thing is going up and down 2 metres. That falls outside the operating limits for


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some operations right there. Even though the sea is “glassy” and there’s not a puff of wind, the thing’s going up and down 2 metres, so there are a lot of similarities.

• Ben Stewart: Also in some of the areas in the Mediterranean, some of the currents change direction and speed at surprisingly regular intervals. If you’re testing in deepwater, it’s the drift off that you have to worry about. Even if you’ve got the best tree in the world, no-one wants to rely on the unlatch - they’re going to cut.

Vessel Design For Drilling and Completing • Brian Imrie: Unless we can think ‘out of the box’ somehow Ben. Maybe we need

to say ‘He can drill at any time throughout the whole year because he’s licked drilling in 8 metres of heave. We need to be able to test, linking to that 8 eight metres capability somehow’. That, to me, is how we should be thinking.

• Forget the riser - how else can we hook on to the vessel? But it has to be customised within a project - dedicated to that vessel. For a harsh environment it has to be project-specific; it has to be done through a deal between the vessel owner, the oil company and the service company. It’s not like, say, gauges - that we can run anywhere. It will only work if we change the contract strategy.

• Alistair Stenhouse: That will only work if you’ve got multiple wells to do from the same vessel.

• Brian Imrie: Or if you’ve got multi-partners. • Alistair Stenhouse: That makes it more difficult! • Brian Imrie: Or it makes it easier if you can sell it like that. • Øystein Jensen: You have to have a contract today. They’re not building any new

vessels without a contract. So if you have 3-4 years work under a contract - you can go into a deal with that.

• Alistair Stenhouse: The West Future 2 was an example. The end result might not have been where everybody thought it was going, but that build was based on multiple wells and one location.

• Brian Imrie: Few oil companies are prepared to do that. • Arild Fosså: True, but we had the same sort of deal for the West Navion with

Statoil. However, they did pull out. • Ben Stewart: Thinking outside the box - one of the things that has to improve is

the communication around rig design and build. Drilling contractors need to communicate their strategies for vessels in the future, whatever it may be - whether it’s rigless vessels, or triple derricks or whatever. Because right now the direction that technology takes is very uncoordinated.

• You still need the innovations and the options, but unless we’re all more aware of the directions, we’re never going to come up with the right equipment. The risk is that it’s going to be so tailored and so specific to a particular installation that you’ll never make the business case.

Testing While Drilling • Sandy Forbes: What about testing right behind the drill bit? • Ben Stewart: That’s what Brian has been talking about. • Sandy Forbes: That’s where it has to go.


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• Ben Stewart: It goes back to what was tried in the 1950’s. The reason it failed then was due to material failures and rig rates. At the time the industry was in a down-turn and it couldn’t afford the cost of the equipment.

• We actually found a retired engineer who had worked on a project in 1954. We talked with him about the thought processes that they went through.

• When it gets down to it, the industry has to align its visions. Not that you want the same vision - you still want 3 or 4 different ways to ‘skin the cat’ - but we need to know, just like we did for Ramrig - what Generation 2 and 3 will be able to do?

• For example, if you go to a rigless vessel for drilling - it’s no secret we looked at Anaconda and composite risers for vessels. Swift was built in the Central North Sea in about 1982. Even back then we recognised that you didn’t want to do your interventions on the rigs - because of the rates. Even at that time vessels were £7-8k/day. The fact is, no-one wanted to buy into it and it really didn’t align with what the rigs were doing.

• Brian Imrie: It’s good that we’re taking it outwith the testing arena and moving it on somewhere else with this. I think that’s what we need to take to the industry.

• Ray Bullock: Underbalanced drilling - a big move towards testing while drilling. • Brian Imrie: Yes. You get more fluids back, and we now have better separation

processes and onsite PVT analysis capability. Some of the tools we’re looking at can give us good information.

• Alistair Stenhouse: From my experience, a lot of the drillers don’t have an appreciation of what’s involved in underbalanced drilling.

• Ray Bullock: I agree. • Alistair Stenhouse: When I was in BP, I got involved in some testing work there.

They wanted to take the kit out to the rig just 5 days before we needed it. I had to tell them they couldn’t do that. They thought they could get a welder out onto the rig and have it take a couple of days - but it’s a lot of kit. There was no appreciation of what’s really involved. There’s a mis-alignment there.

• Alan Christie: Yes. It’s an education problem. • Geoff Gill : It’s been about education and communication all the way along.

Vessel Design For Drilling and Completing • Alan Christie: There are instances where you have a rig contracted to do the

drilling and then you find that you can’t run the completion with it, without ripping it apart.

• The Ocean Nomad was a classic case in point in Shell. We couldn’t lift the tree off the boat, we couldn’t get the tree in the moonpool, we couldn’t get the coiled tubing on the catwalk.

• There was a long list of things we couldn’t do. Yet they’d already spent money putting the top drive in and upgrading to active heave, etc. They just hadn’t considered running a completion from the ship.

• Øystein Jensen: The West Navion was built to run completions on the Åsgard field for Statoil.

• Alan Christie: But others aren’t though. Many aren’t. • Ben Stewart: It would be interesting if the industry does go to testing behind the

bit. I guess we all have projects going ahead. Some of the kit coming out of Anadril and Sperry are works of art - the machining is pretty impressive. You’re


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really going to have to sit down and ensure that the rig is as you said – set up for running completions.

More Dialogue About Technology Directions • Ben Stewart: We really need a different way of talking to each other. That will be

the basic driver for any new technology that’s taken into the field, and for decisions by oil companies to take risks drilling and evaluating a well.

• Somehow, everybody has to know what directions the technology is moving in. You’re not going to be able to tell everybody what you’re doing specifically, but you need to know what directions you believe are right, and you need to understand the drivers which favour going that way.

• That will allow us in the service companies to prioritise where we spend our money and what technologies we take into the field.

• On the oil company side, the engineer will then be able to make a simpler case for drilling the well, and gathering the data. He will know what the options are.

• Getting funding is hard. If you can’t test or evaluate the well in a way the company thinks is cost beneficial, you will never get the money to do it in the first place.

• Alistair Stenhouse: That’s right - absolutely right.

Dealing With Old Data • Ben Stewart: Look at the amount of “stranded assets” around – assets that

haven’t been developed because the information from the first well was not encouraging. It was non-existent in a lot of cases. I can think of an example from the biggest undeveloped asset in the North Sea. The first DST produced erroneous data, for various technical reasons. Once they had left the location they realised that the data was erroneous. So they went back and had to do a second test.

• Brian Imrie: We got a call in Aberdeen recently from somebody who was developing a field discovered long ago. They were asking us for the old temperature, pressure and PVT data to use for the pipeline design.

• Alistair Stenhouse: For their field development? • Brian Imrie: Yes. For the field they were now planning to develop. We don’t

even have the computers from the period when we first gathered that data. There’s a hard copy and you can go and type it in yourself.

• It just shows how long the time gap can be from first discovery to development. Obviously the oil companies are going to develop the biggest and easiest fields first and leave all the other ones until later. It’s just common sense.

• Ben Stewart: About 5 years ago we got a request to re-read a mechanical gauge for a well drilled in 1972. It was one of the old BT RPG gauges and luckily we still had the calibration data in our library. So we went back and read the gauge.

• It was really amazing – we quickly realised that the AOF for the well was 25mmscf/d. It’s now on production. Today’s automated chart reader makes life easier. The application of the technology and what people do with it is critical – little things got missed and operators walked away from discoveries. What’s the impact of that well sitting undeveloped?

• Alistair Stenhouse: I got a call from Schlumberger Aberdeen asking if I could read a J200 DST gauge from BP Algeria. Nobody in Aberdeen could read it. They


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were considering a development or acquiring acreage based on this. No calibration - but I managed to give them something based on the mud weight.

Openhole Closed Chamber Testing Offshore • Brian Imrie: This is just a conversation here, there are lots of ideas. But as an

industry, we do need to think differently. I just gave a quick summary of our toolbox; it is more or less the same as Halliburton’s.

• Alistair Stenhouse: I agree with what Ben said - understand the drivers. Understand the objectives and add value. If you can do all that, you’ll do good business without any problems.

• I think a lot of the industry is driven by technologists who don’t really understand what we want as an industry. I’m sure you’ve seen plenty of examples.

• Mark Cooper: There is a pressing need now for something which sits between wireline testing and a full DST - because the cost is so big. On a lot of projects, when managers look at the full cost of the DST, they say ‘Well, OK then. We’ll just go with the MDT data, even though it’s not what we really want right now’.

• Ray Bullock: Don’t you think it’s there now with closed chamber, though? • Mark Cooper: I think we’re close to being able to do something. We’ve got

reliable acoustic telemetry now. We’ve got the tools that operate acoustically, accurate gauges etc. I don’t think it’s a big jump to build a tool and do it.

• Ray Bullock: Ah. You’re talking open hole now? • Mark Cooper: Yes. Open hole. Because cased hole is where a lot of the big costs

occur – liner costs for example - so let’s get rid of them. In Hydro we’re doing a HAZID on the SILD openhole. We’ve already done an informal one and the drilling people have already accepted doing the job in the North Sea, open hole. So it’s a matter of going through the detail, and the risks of how we deal with a kick, for example. I think it will come soon, whichever service company does it.

• Alistair Stenhouse: The idea is not new. As soon as IRIS came out you could immediately see combining that with inflate technology.

Vertical Versus Horizontal Well Testing • Brian Imrie: It still surprises me that DSTs are still mostly in vertical wells. As

soon as we go to production, development wells are drilled at every deviation. Information from an MDT in a vertical well often relates poorly to a horizontal well. You have to drill that first well in same manner as you will drill it in production. It can look like a completely different type of reservoir with just a different type of perforation technique.

• Alistair Stenhouse: You wouldn’t drill your “fancy” development well at all, unless you’d done a DST first.

• Brian Imrie: It depends on the cost. Maybe we should be pushing towards testing in wells that resemble development wells.

Evaluation of Single Well Penetrations • Ben Stewart: Specific to the UKCS, most of what we drill will only support a

single well penetration for appraisal. How do we go about evaluating such wells?


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I sometimes have a problem when we call it “testing”. When we evaluate that well, what are the economic drivers for doing that?

• As soon as you invest say £9mm, or whatever the cost of the well is, that money is lost if you can’t get enough data to make the decision to put in more investment. The £20-30mm for the pipeline and to put the wellhead into place to produce the well. We really shoot ourselves in the foot.

• What Mark is saying is that there are some “in-between steps” to evaluation. It takes an investment in technology – not cheap when you look at the day rate - but it adds so much value. You need to look at what it’s going to save you, it will help you to qualify the value of the data that you’re gathering. That’s going to be a big driver in doing this. Take Beaulieu and Perth for example – how long were they sitting around undeveloped – they are classic examples.

• Ashley Brammer: There’s a definite advantage there. Hess at the moment are averse to the thought of a single well development because of the risk. I think that will become increasingly true. If you can reduce the risk in that initial well - the exploration well turns into a development well. If you can find out more at that point, and the risks go down, there is a chance that we might take it on.

• Alistair Stenhouse: We should say that just applies to the UK North Sea. • Ashley Brammer: Yes, in the UK North Sea. • Brian Imrie: In Norway, the NPD have got a superb explanatory

exploration/appraisal/development process chart. They show the information being gathered, and then they show the PDO (formal Development Plan) being submitted. This is where the operator has decided to go one particular way. As the development wells are drilled, they start getting more and more information, but they now have little flexibility. As soon as you have decided to put a floater on, or you decide to go subsea, you’re “stuck”, as it were. You’re stuck with that style of development. But you base all of that commitment on very little dynamic data. It is not a good process.

• John Curley: OK, we’ve run long having that wide ranging discussion, but we should really now move on. Thanks very much Brian.

THE END


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INDEX A

Appraisal Strategy Evaluation of Single Well Penetrations ... 96 Not Testing The First Well ...................... 64 Vertical Versus Horizontal Well Testing. 95

C

Closed Chamber DST Advantages and Disadvantages................ 43 Comparison With Traditional DST.......... 48 Deepwater Challenges.............................. 40 Openhole Testing Offshore...................... 95 String ....................................................... 42

Contracts – For Value Adding Services Or Minimum Cost Commodities? ................. 89

D

Development Dealing With Old Data ............................ 94 Depletion To Reduce Development

Infrastructure Cost............................... 67

E

Equipment Acoustic Data Telemetry System............. 55 DST Sand Screens Plugged With Cement 53 IRDV Valve Failure................................. 60 Locked Open SSTT ................................. 46 Mannesman String ................................... 29 Packer Choice .......................................... 52 Ram Rigs, Derricks and Lift Frames........ 54 Reconnecting the SSTT ........................... 60 Rig and Testing Equipment Procurement 65 Sandscreen Damage ................................. 60 Subsea Test Tree...................................... 55

H

Harsh Environment Management Of Deepwater Safety Systems.

............................................................ 74 Welltest Activity Level ............................ 91

Hydrates........................................................ 55 Melting Tool ............................................ 58 NPT Fitting Leaks.................................... 57 Prevention Chemicals .............................. 25 Risk Management .............................. 23, 24 Thermal Properties of Riser ..................... 56

P

Planning And Preparation Change Control Management .................. 76 Collaborative Team Environment ............ 79 Coping With Limited Experience ............ 85 Customs and Immigration ........................ 71 Document Control Systems...................... 79

Dropping The Process When Under Stress.............................................................85

DST Options ............................................41 Early Involvement ....................................75 Equipment ................................................70 Evaluate The Options ...............................82 Flights.......................................................72 Health Issues ............................................71 Hold Points...............................................22 Integration ................................................84 Logistics ...................................................70 Mitigating Risk, Cost Management, Data

Quality.................................................77 Operational Interfaces ..............................74 Planning Costs..........................................28 Pre Job Engineering .................................69 Project Management.................................74 Proper Planning and Preparation Prevents

Poor Performance ................................75 Qualification Testing................................72 Understanding The Objectives .................78 Understanding The Risk...........................81 Welltest As A Project.........................65, 68 Welltests Are Projects Nowadays ............61 Writing Disconnect Procedures................69

R

Rigs Heave Limit..............................................18 Ideal Vessel For Completions ..................37 Mean Heave Comparisons........................16 Measured Heave Response.......................31 RAO (Response Amplitude Operator) .....51 Response Amplitude Operator .................31 Vessel and Riser Limits............................33 Vessel Design For Drilling and Completing

.......................................................92, 93 Vessel Selection For Other Than Drilling 39 Wave Period.............................................18 West Navion Heave..................................17

Riser Limits .......................................................32 Management .............................................52 Riser Within Riser Operations .................38 Sealing Mandrel .......................................43

Risk No Worst Case Scenario ..........................26 Testing Budget Contingencies..................27

T

Technology Development Active and Shelved...................................87 Drivers......................................................88 Equipment Development Costs ................90 More Dialogue About Technology

Directions ............................................94 New Equipment........................................73


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Test Location ................................................... 28 Objectives ................................................ 50 Sequence .................................................. 44 String ....................................................... 53

Testing Ambient Noise ......................................... 61 Being Priced Out of Business .................. 27 By Choice Or Government Requirement 66,

67 In Autumn ................................................ 23 On A DP Drillship ................................... 15 Shear Rather Than Unlatch...................... 47 ToolBox................................................... 83 While Drilling.......................................... 93

W

Weather

Comparison Of Analysis With Historical Data .....................................................36

Comparison Of Semis With Drillships For Testing.................................................36

Conditions ................................................50 Impact On Test Duration, Amerada Hess.20 Impact On Test Duration, BP...................19 Predicted Test Duration......................21, 34 Probability Of WOW In Any Given

Operation.............................................35 Time-Shifting Operations.........................35 WOW Prediction Analysis Methods ........30 WOW Prediction Summary......................37

Wireline Fluid Sampling Advantage ................................................44 Cased Hole MDT .....................................45

the welltesting network · about harsh environment welltesting. this hot topic meeting was called...

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