Multi-Well ConductorProspectus...cultural and drilling practices. In 1998 project and procurement managers recommended application of CRINE to FPSO, subsea and deepwater. The LOGIC

Conductor Sharing New Technology (multiple wells through single conductor/wellhead)

Improving the Economics of Stranded Hydrocarbon Reservoir Tie-backs

for Wet or Dry Trees

Multi-Well ConductorProspectus

2

New Method of Adapting Proven Technology

| www.oilfieldinnovations.com

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Oilfield Innovations Limited, July2017

PROSPECTUS |

New Conductor Sharing Technology for Improving Economics of Stranded Reserves

by Clint Smitha and Bruce Tungetb

Figure 1 - Magnus Conductor Sharing (Hicks, 2009)

Abstract: To understand why competitive markets, proven technologies and conventional practices do not develop stranded offshore hydrocar-bons deposits of 3 to 15 million barrels oil equivalent (OGA, 2016)21, it is important to understand that “Controllable Cost” is the primary driver preventing said development. In a world where hydrocarbon prices are set by onshore fracking, the price is unlikely to increase in the near fu-ture and, thus, controllable cost reduction is required. Stranded offshore hydrocarbons deposits of 3-15 million barrels oil equivalent will continue to be uneconomic until the development “cost” is substantially reduced. Obvious technologies, like subsea tie-backs, have already been included within previous uneconomic development proposals. Marginally reducing cost by tweaking various components of subsea tie-backs is unlikely to make stranded hydrocarbons economic. As Einstein said, insanity is doing the same thing over and over again and expecting a different result. If you ignore the jargon, subsea infrastructure is not necessarily complex but it is always expensive and, thus, forms part of the problem. Developing strand-ed hydrocarbons requires new technology that can access multiple stranded hydrocarbon discoveries while reducing subsea infrastructure to a single wellhead, pipeline, riser and control umbilical. Amalgamating multiple laterally separated stranded hydrocarbon pools to single point-A-to-point-B pipeline, riser and control umbilical not only decreases subsea infrastruc-ture cost but can also increase reserves associated with the investment. With the above terms of reference in mind, Oilfield Innovations proposes the new technology of integrating proven wellhead splitting and sharing technology (see Figure 1) into a single subsea conductor used to batch-drill and batch-complete multiple well bores concurrently. Extended reach wells

may be drilled to multiple stranded hydrocarbon pools from a from a single wellhead. Additionally, Oilfield Innovations propose that a subterranean high pressure separator, used for water disposal at the wellhead, can be added to substantially reduce water disposal costs and increase reserves for multiple stranded reservoirs. Oilfield Innovations have initially iden-tified 100 opportunities in the UK North Sea where two (2) or more small pools (i.e. more than 200 stranded discoveries) can be tied-back with such new technology.

Introduction

Uneconomic “small” offshore hydrocarbon discoveries are substantially larger than economic onshore discoveries, wherein “small” refers to discoveries of 3 million to 15+ mil-lion barrels oil equivalent in the North Sea (OGA, 2016)21.

When a stranded pool of hydrocarbons is discovered, sub-sea development and tie-back to existing infrastructure is evaluated, but the small economic size does not justify the subsea infrastructure cost, tariffs, waste water disposal, well count and drilling costs.

To address the issue the UK North Sea has been working on standardization for twenty years, initially through CRINE and now through the trade association Oil and Gas UK. While plug-and-play standardization of existing subsea infra-

structure can reduce costs, it is unlikely to make small pools of hydrocarbons economic in an industry driven by onshore fracking.

Fracking has existed since the 1940’s and is nothing new. Many tried to make shale fracking work and failed, but in recent years new fracking technologies have been able to in-crease shale productivity to the level that is it displacing off-shore oil and gas.

World Oil reported in March 2017, “Exxon Mobile is diverting about one-third of its drilling budget this year to (onshore) shale fields that will deliver cash flow in as little as three years, said Chairman and CEO Darren Woods”27.

Efforts to standardise and lock in existing technology to create marginal cost reductions are unlikely to make offshore

4

Terms of Reference

www.oilfieldinnovations.com

Threshold of Pain(uneconomic)

Establish HighestValue Option afterRisking

CONVENTIONAL GATED PROCESS FOR STRANDED OFFSHORE HYDROCARBONS

EvaluationFrame

Appraise

Select DefineGivens

Universe ofConventionalOpportunities

Evaluation of SubseaTie-back of Small Pools

to Existing Infrastructure

Figure 2 - Small Pools and Conventional Gated Process (Hopper, 2016)18

oil and gas more competitive.

To survive current prices, offshore oil and gas needs to develop new technologies that can be competitive with new fracking technologies used in shale plays.

Subsea infrastructure may need standardisation, but oil and gas drilling represents at least half of the development costs and has used plug-and-play standardization for decades.

Various sized connections and tubular sizes for drilling and completion equipment have plug-and-play standardisation through API and ISO, wherein vendors wishing to sell tooling or equipment ensure compatibility with those standards.

This prospectus explains how proven technologies, like Figure 1 Conductor Sharing, can be adapted and combined with proven Extended Reach Drilling (ERD) technology to provide a step change in the cost of developing stranded off-shore hydrocarbons.

Changing the paradigm of uneconomic stranded offshore hydrocarbons discoveries requires a step-change in cost that can only occur with “new technology” that minimises subsea infrastructure, waste water disposal, well count and drilling costs.

Accordingly, to understand how new technology can be implemented it is important to understand past and present industry processes and initiatives.

Conventional Development Process

The oil and gas industry uses a linear gated decision mak-ing process shown in Figure 2, wherein the appraisal phase specifies the givens and defines a frame that bounds field proven solutions. A universe of established opportunities is generated that lies within the frame and rigorous step wise process is used to establish the highest value option during

the select phase (Hopper, 2016)18.

Every undeveloped stranded hydrocarbon discovery will have been subjected to the Figure 2 process one or more times after its discovery.

The rigorous linear nature of industry’s gated process does not consider new technologies and cannot easily accommo-date new information so, commonly, when change is neces-sary the project either presses on regardless or goes into a major recycle, which significantly increases the risk of cost and schedule overruns (Hopper, 2016)18.

Ernst & Young (2014)18 evaluated 365 mega projects and concluded that 78% of European upstream projects faced de-lays and 65% faced cost overruns, with the average overrun of 53%. Nandurdikar (2014)18 in a presentation to IPA, came to a similar conclusion and found that E&P megaprojects had a success rate of 22% compared with a success rate of 52% in other industries. The inflexible and rigid approach adopted by industry to the project management is one of the causes of these project failures (Hopper, 2016)18.

Accordingly, cost overruns have come to be expected to the extent that every conventional aspect of hydrocarbon de-velopment is risked until stranded pools of hydrocarbon ap-pear uneconomic due to risk multiplication factors associated with the gated process and deficiencies of existing offshore technology.

Risk reduced recoverable hydrocarbon forecasts are mul-tiplied by stagnate free market price forecasts, limited by West Texas fracking, to calculate a discounted (reduced) net present value. The net present value is compared to risked (inflated) controllable development costs that use the limita-tions of existing technology and assume cost overruns and schedule delays to determine whether, or not, development of

5

Terms of Reference

July 2017 - PROSPECTUS |

Figure 3 - Previous Initiatives (Duthie, 2016)25

Previous Initiatives

1994 – CRINE

Same themes highlighted by CRINE such as standardisation, simplification & collaboration….

1998 Follow On CRINE report

Original report 1994 on back of dramatic decrease in oil price to $15 (62% drop from 1990 to 1994).CRINE Network established 1994 – 1999 supported by the industry on a part time basis and Operator driven.1994 report made 6 recommendations (Codes, Standards and Specifications/ Technical Standardisation/CommercialStandardisation/ Regulatory/ Cultural Change/ Drilling Practices Committee).

Large report but deemed high level, mixed feedback on the success of CRINE.No evidence or legacy of CRINE today except Terms and Conditions which were adopted by LOGIC.

Other Initiatives

Around Oil price drop from $25 to $12 (52%).Project and Procurement Managers Conference report, 1998:Applying the philosophy of CRINE to FPSO, Subsea and Deep-water.

Industry sponsored event.Focus on Functional Specifications, but never adopted by industry.

Conclusion: No visibility of long term solutions being implemented and adopted

Majority of other initiatives such as:Oil & Gas Industry Task Force commenced 1999 till 2001.LOGIC commenced 2000 – now part of Oil and Gas UK (2007).PILOT commenced 2000 - now part of MER (OGA 2015).

Similar trend followed where work groups never really followed through to provide detailed solutions and adopt alonger term approach.Only provided high level recommendations.

Previous UK North Sea Initiatives

Figure 3, which is taken directly from an Oil and Gas UK presentation, shows that each price cycle since 1994 has caused a number of North Sea initiatives, from which Duth-ie25 (2016) states that no visible long term solutions were ei-ther implemented or adopted.

With regard to the present price cycle, it is important to recognise that important structural changes are taking place in, for example, US reliance on energy imports where shale plays and new fracking technological advancements are dis-placing offshore hydrocarbons (Dale, 2015)26.

After a complete oil price collapse in 1986, oil rebounded and cycled around $20 per barrel for about 20 years.

Structural changes caused by fracking of shale plays have the realistic possibility of causing oil price to cycle around $40 per barrel for decades.

Accordingly, it is important to remember that significant changes may be necessary for the offshore oil and gas to com-

pete with onshore shale and, therefore, previous and present initiatives to reduce cost are critical to the survival of the offshore oil and gas industry.

The 1994 CRINE report made six recommendations to standardise specifications, technical, commercial, regulatory, cultural and drilling practices.

In 1998 project and procurement managers recommended application of CRINE to FPSO, subsea and deepwater.

The LOGIC and PILOT projects and various industry task forces have occurred after the turn of the century.

Now, more than twenty years after it conception, Figure 4 describes how Oil and Gas UK are presently attempting to reduce subsea infrastructure costs and risks using standardi-sation.

The previous efforts were obviously worthwhile because they are being continued in present initiative that will be im-portant in the development of stranded pools of hydrocar-bons, but it is important to recognise that present initiatives are not addressing all factors preventing development of stranded hydrocarbon discoveries.

a stranded pool of hydrocarbons is economic.

Recognising the inherent problems of a rigorously linear process and an inability to develop small pools of North Sea hydrocarbons, the Figure 3 initiatives attempted to rectify some of the issues.

6

Terms of Reference


Figure 4 - Oil and Gas UK Subsea Standardisation (Plug-and-Play) Theme (Duthie, 2016)25

Less is Better Documentation Requirements Review Cycles Inspection Reporting Interface Management Methodology (Concept to Detailed Design) Industry Performa Documents Risk Review Profile Standard Process

Apply to Design, Manufacture, Installation Hot Taps to host pipeline EPS with minimal SURF Schedule optimisation, Vessel sharing and cluster development strategy (Mass Centralisation).

Fit for Purpose Establish Reference/Base Case UKCS Minimum Standards/Guiding Principles Functional/Performance Requirements Pre-qualification Industry Standards today (i.e. API) are considered above a Fit for Purpose

Literature Review Findings: Standardisation Themes

(Inc. TLB Hackathon)

Catalogue of Components Re-Use of Equipment Envelope for Design Components Standard Classifications Interchangeability (Mix & Match) Plug and Play Modularised and building block approach Standard Interfaces Standard Classifications for pressure, bore.

Literature Review

FindingsStandardisation

Projects

Codes,Standards

andSpecifications

AlternativeMethods andTechnologies

HardwareProcess

DOESNOT

INCLUDEDRILLING COSTS

DOESNOT

INCLUDEO&G TREATMENT

HYDROCARBON TREATEMENT AND PRODUCED WATER

DISPOSAL

WELLCONSTRUCTION

SUBSEAINFRASTRUCTURE

SMALL POOLSICEBERG

OtherFactors

An “Iceberg” of Other Factors

Standardisation is important, but stranded offshore hydro-carbon development may require reducing various portions of subsea infrastructure to an absolute minimum quantity of standardized lower cost piping, hoses and valves.

Figure 4 depicts Oil and Gas UK’s efforts to addresses many important aspects of subsea infrastructure that are crit-ical to stranded hydrocarbon tie-back, but it does not include the costs of drilling or oil and gas treatment.

As shown in Figure 3, previous industry efforts began with standardisation, whereby standardising the piping, hoses and valves of subsea infrastructure is a good place to start, but it is only the tip of the iceberg and, unfortunately, it is the hidden part of an iceberg that sinks ships or, in this case, stranded hydrocarbon developments.

Half, or more, of small pool development costs and risks are associated with connecting the reservoir to subsea in-frastructure through the wing valve of the production tree, which is not considered by the Figure 4 standardisation plan.

Like the tail-wagging-the-dog, subsea infrastructure engi-neers have included subsea trees in Figure 4 because they want to select the subsea production tree to fit their piping and hose connections without considering the substantial ef-fect on well construction costs.

Standardising subsea production trees may actually in-crease development costs by locking in current technology and preventing, for example, conductor sharing technology used on production platforms. Also, regardless of whether new or conventional technology is used, the subsea produc-tion tree comprises critical drilling and completion equip-ment that can favourably or adversely affect half, or more, of the project costs, wherein selection of the most economic subsea tree requires competence in drilling and completion.

The other half, or less, of costs and risks are subsea in-frastructure and hydrocarbon treatment and/or water disposal equipment. Subsea infrastructure is important but hydrocar-bon treatment and/or water disposal are more likely to pre-vent the development of stranded hydrocarbon pools.

Hydrocarbon treatment will depend upon the composition of oil and/or gas in place with any tie-back and commingling of fluids with existing infrastructure production being either viable or unviable.

Disposal of produced water is a variable that limits a stranded hydrocarbon discovery’s production life and its re-coverable reserves.

Accordingly, the hidden parts of the iceberg preventing stranded offshore hydrocarbon development are typically well construction costs, hydrocarbon treatment and water dis-posal, which are substantially more important than standard-ising and locking-in established but old subsea technology.

7

Terms of Reference


Figure 5 - Conventional Tie-back versus ERD to Common Tie-back Point

Old versus New Technology

The left of Figure 5 shows established older technology that can be standardised to lock-in both its benefits and de-ficiencies, using conventional subsea development ties-back of multiple small pools or a compartmentalised reservoir with multiple wells connected to a production manifold that com-mingles flow through a pipeline to a host facility. The host facility can be a platform or a floating production, storage and off-loading (FPSO) facility.

Controlling a conventional manifold and multiple subsea production trees can involve a complex system of umbilical lines with numerous bundles and complex interconnections that can be very expensive.

Conventional tie-backs to a central manifold are typically considered with respect to the need for more than one well to fully develop a compartmentalised reservoir or multiple small pool reservoirs separated by kilometres.

Such evaluations will have already been considered at least once after discovery of a stranded hydrocarbon pool.

The first step in any development effort is to seek cost re-ductions and/or efficiency increases from service companies, manufacturers and/or contractors and, thus, it is likely that cost reductions comparable to those associated with standard-isation may have already have been factored into previous economic analysis.

Accordingly, standardisation can reduce risk and improve the economics of stranded offshore hydrocarbons, but stan-dardizing established older technologies is unlikely to cause previously uneconomic discoveries to be developed.

Alternatively, the right of Figure 5 illustrates that a new technology can comprise adapting and combining standards and field proven technologies like conductor sharing well-heads and extended reach drilling to create a new standard that can be adapted and combined by a qualified vendor and/or service provider.

Oil and gas can learn from others industries. For example, computing and software industries are extremely competitive, yet Microsoft® has released the source code to an open-source operating system, based on Debian GNU/Linux, that runs on network switches (Williams, 2016)28. If Microsoft® can dump its proprietary software in favour of open source Linux, an oil and gas service provider can use the same philosophy to facilitate deployment of its new technology.

Accordingly, as is explained on the following pages, to-tal development cost of the right side of Figure 5 could be +/-30% less than that of the left side of Figure 5, wherein a Service Provider who manufactures the new technology could open source the connection interfaces to allow standardisation of the new technology to quickly establish its prominence and widespread usage within the oil and gas industry.

Subsea TreeSingle Well

Kilometers of Pipeline & Umbilical

Host Platform or FPSO

Conventional SubseaInfrastructure Option

Subsea TreeSingle Well

PLET

ManifoldJumper Hoses or Kilometersof Tie-back Pipelines & Umbilicals

Subsea TreeSingle Well Conductor

SharingSubsea Tree

Kilometers of Pipeline & Umbilical

Extended Reach Wellwith kilometers of horizontal offset

ExtendedReach Wells

Host Platform or FPSO

Minimal SubseaInfrastructure Option

Pipe Line End Termination (PLET)

Technology ExistsMay still beuneconomic

New Technology

CompetitivelyLower Costs

Small Pools

Economically Viable

Collaboration

DECISION TREE Conductor Sharing Wellhead & Tree Manifoldsharing umbilical functions and more

efficient Batch Drilled Extended Reachwells tied back to Host Facility

Multiple Small Pools or Multiple Reservoir Compartments Multiple Small Pools or Multiple Reservoir Compartments

Conventional Subsea Wells Connectedby Pipelines or Jumper Hoses to a Manifold

tied back to Host Facility

OilfieldInnovations

PatentedTechnology

Competent andQualified Service

Company DevelopingTechnology

IndustryStandardisation

Initiatives

ProprietaryService Companyor Manufacturer

or Contractor

Plug & PlayStandardisationw/ ProprietaryChallenges

Standardisation ofNew Technology

for EconomicStranded

Development

8

Terms of Reference


Table 1 - Small Pools withi a 5km Extended Reach Drilling Radius (see Appendix A for UK North Sea)

Figure 6 - Examples of Small Pools withi a 5km Extended Reach Drilling Radius (OGA,2016)21

SNS Northern North Sea

Moray Firth Central North Sea

Total

18 17 27 38 100

Pooling Stranded Discoveries

Reducing risk and increasing net present value can require increasing recoverable reserves by amalgamating or pooling stranded discoveries using commingled flow and a single tie-back to existing infrastructure.

Figure 6 shows groups of two or more small pools within a 5 kilometre radius, wherein looking at the entire UK North Sea, at least 100 such instances can be found, as shown in Table 1.

The Figure 6 excerpt of the OGA21 map in Figures 24-27, of the appendix, show that a 5 kilometre extended reach well can access two or more small pools from a single location, wherein a conductor sharing wellhead could produce laterally separated reservoirs to a single pipeline with a single control

umbilical to reduce cost.

The Central and Moray Firth portions of the UK North Sea have the most opportunities for connecting multiple small pools with a commingled single tie-back to existing infra-structure.

Using extended reach drilling, a single subsea wellhead above a conductor sharing arrangement can access multiple small pools to at least double the recoverable reserves as-sociated with the economics and, thus, can reduce risk and increase net present value.

9

Terms of Reference


True

ver

tical

dep

th, f

tTrue vertical depth, m

Horizontal departure

ft.

ft.

m.

Worldwide Extended-Reach Drilling0

5,000 1,525

1,525

0

0

3,050

3,050

4,575

4,575

6,100

6,100

7,620

7,620

9,150

9,150

10,670

True vertical depth, m

1,525

0

3,050

4,575

6,100

10,670 12,020

m.1,5250 3,050 4,575 6,100 7,620 9,150 10,670 12,020

10,000

15,000

20,000

25,000

30,000

35,000

40,00040,00035,00030,00025,00020,00015,00010,0000 5,000

True

ver

tical

dep

th, f

t

Horizontal departure

0

5,000

10,000

15,000

20,00040,00035,00030,00025,00020,00015,00010,0000 5,000

Up to 1975Up to 1980Up to 1985Up to 1990Up to 1995Up to 2000Up to 2005Up to 2010

Low reachMedium reachExtended reachUltraextended reachERD well

4.03.0

2.0

Figure 7- 2010 Extended Reach Well Limits and Classifications (Bennetzen, 2010)22

Extended Reach Drilling

Figure 7 shows two graphs illustrating the horizontal de-parture of extended reach drilling (ERD), wherein the up-per graph depicts the progressive technology increases from 1975 to 2010 while the lower graph shows the categories of ERD.

Figure 7 also clearly shows that five (5) kilometres hori-

zontal departure from the wellhead was an average extended reach well almost a decade ago.

Accordingly, the five (5) kilometre radii in Figure 6 and Figures 24-27 represents an average extended reach horizon-tal departure from the sea bed wellhead and indicates that it is possible to drill such distances with current technology to connect two or more small pools with a single tie-back to existing infrastructure.

10

Terms of Reference


faultfault

133/8-in. or 14-in. casingat intermediate depth

9 5/8 10 3/4

10 3/4

or casingat deep depth

9 5/8 or casingat deep depth

16-in. casingat shallow depth

3,000-ft900-m

6,000-ft1,800-m

9,000-ft2,700-m

12,000-ft3,600-m

TVD

sub

sea

Sea level6,500-ft

2 km3,300-ft

1 km

Offshore Rig over Extended Reach Wells

Conventional Medium Reach Well

Extended Reach Well

7 -in. linerabove reservoir

5/8

Figure 8 - Heel of an Extended Reach Well (Allen, 1997)23

Extended reach drilling is more costly and time consuming than, for example, the low or medium reach categories shown in Figure 7; however, Oilfield Innovations have invented a method of batch drilling the same section for up to three (3) wells to reduce the cost of ERD wells by immediately apply-ing lessons from one well to the next and avoiding the costly process of changing bottom hole assemblies (BHA).

Batch Drilling

Conventional big-bore 18 ¾ inch subsea wellhead systems are capable of hanging 16 inch, 14 or 13 ⅜ and 10 ¾, 9 ⅞ or 9 ⅝ inch casing strings, wherein Oilfield Innovations have devised a way to batch drill and batch set each of these casing sections.

For example, Figures 8 and 9 show the heel and toe sec-tions of an extended reach well with a 5 kilometre departure, wherein after setting surface casing three (3) back-to-back 17 x 20 inch bi-centre bit (see Figure 36) hole section can be drilled and followed by the running of three back-to-back 16 inch casing strings for significant time and cost savings.

Generally, drilling shallow geology is relatively easy but running casing can be challenging. Picking-up, handling and laying down bottom hole assemblies (BHA) is also time con-suming and costly.

Oilfield Innovations have invented a whipstock system that can be rotated within a conductor sharing arrangement to allow drilling of hole-sections, pulling-out-of-the-hole (POOH) and racking back the BHA followed by rotating the whipstock and running-in-the-hole (RIH) to drill the next section.

By rotating a whipstock in a conductor sharing arrange-

ment, three 17 x 20 inch hole sections can be drilled in suc-cession and followed by running three 16” inch casing sec-tions, wherein the relatively short drilling time, large hole size and heavy drilling mud maintain the hole until each of the casing strings are run and cemented after sequentially ro-tating the whipstock to select one of the three boreholes.

Running and cementing three 16 inch casing strings re-moves time normally spent waiting on cement hardening since the first cement job will have hardened by the time the last cement job is carried out.

The efficiency gains of repeatedly doing the same task in batches allows the lessons from the previous job to be imme-diately applied to the next job.

Accordingly, significant time and cost is saved by picking up and laying down the same BHA once for three wells and the same casing running equipment and the same cementing equipment once for three wells.

Additionally, speciality crews who are typically brought to the rig to run casing are mobilised and demobilised once and used in close succession to minimise daily crew costs, daily rental costs and transportation costs to and from the rig.

Depending upon the geology, the same savings can be real-ised on the 14 ½ x 17 ½ inch bi-centre bit (see Figure 36) and 13 ⅜ or 14 inch casing section.

In instances where, for example a fault (see Figure 8) or other geologic issue increase the probability of time depen-dent hole instability, the 12 ¼ inch hole section can be drilled and 9 ⅝ or 10 ¾ inch casing run and cemented before rotating the whipstock to begin the next batch drill and case section. The same time savings for the BHA will be applicable and

11

Terms of Reference


16,000-ft5 km

13,000-ft4 km

10,000-ft3 km

7 -in. linerabove reservoir

Rig overConventionalLow Reach Well

5/85-in. linoror sand-screencompletion

Fault

16-in. casing

Shallow Gas

at shallow depth

133/8-in. or 14-in. casing at intermediate depth

9 5/8 or casing at deep depth10 3/4

3,000-ft900-m

6,000-ft1,800-m

9,000-ft2,700-m

12,000-ft3,600-m

Figure 9 - Toe of an Extended Reach Well compared to Conventiional Well (Allen, 1997)23

the casing costs will increase marginally for rigging up and down, but rig moves are avoided and the lessons learned on one hole-section can be applied to the next to reduce both risk and cost.

Drilling Challenges

Extended reach wells are more challenging than common low to medium reach wells because proper drilling practices are critical to success.

Batch drilling and casing off hole-sections has the advan-tage of immediately correcting any mistakes made on the pre-vious operations and repeating any successes on the next op-eration, whereby ERD becomes much easier, faster and lower cost.

Additionally, geologic and hole instability uncertainties can be reduced by adjusting or keeping drilling fluid proper-ties based upon the information gained in the previous hole section passing through approximately the same geologic time periods.

Drilling and well construction challenges are often driven by the unknown, wherein perceived problems may not ex-ist and/or over-compensation or under-compensation for real problems can exacerbate the challenges.

Batch drilling and casing the first hole-section will uncov-er real challenges or dispel expected challenges that never materialise, wherein the second and third batched drilled and cased hole section will learn from the first hole section to lower well cost. This is particularly advantageous when, for example, a medium reach hole-section can be drilled first and followed by a more challenging extended reach well hole-section.

Comparison to Conventional Wells

Conventional medium reach wells (see Figure 8) are com-mon place and are considered average risk. Typically, subsea locations are selected to avoid any shallow gas and reduce well complexity and comprise conventional low reach wells like that shown in Figure 9.

Drilling technology has advanced to the level that boring through rock is relatively straight forward and it is the “flat-times” for casing and other operations carried out between boring that are driving cost, whereby Oil and Gas UK are currently carrying out studies to measure “flat-times” in an effort to improve efficiency.

As shown in Figures 8 and 9, casing locations are selected primarily according to the geologic formation and true verti-cal depth and, therefore, the same number of casings can be required for a low, medium or extended reach well. Because the “flat-times” between drilling operations are driving costs more than the boring of rock, when properly executed, ex-tended reach wells are not necessarily that much more expen-sive.

It is the casing and “flat-times” that are primarily con-trolling cost and, therefore, the cost of wells are not the ratio of their drilled lengths.

Accordingly, drilling consecutive sections for multiple ex-tended reach wells of 5 kilometres horizontal displacement can have a significantly lower cost than drilling multiple low reach wells with 5 kilometres of tie-back pipeline and umbil-ical.

12 |www.oilfieldinnovations.com

New Conductor Sharing Technology

Figure 10- Plug and Play 48” Cloverleaf Conductor Sharing Specification

22” Branch OD

22” Branch OD22” Branch OD

23.25” Branch ID

1.875” Wall Thickness

4.2” Avail. for otherbundled lines beside tubing.

19” Branch ID

19” Branch ID

19” Branch ID8.7” Avail. for Tubing andclamp and control line passage

1.5” Wall Thickness

26” Wellhead OD

18.75 Wellhead ID

9.3” Avail. for Separator Piping

48” Separator OD

49.25” Separator Coupling OD

48” CONDUCTORSHARING

New Conductor & Casing Sharing Technology

Oilfield Innovations’ new technology adapts existing stan-dards and, therefore, uses standardised sizes and interfaces in in a new way within the accepted boundaries of current established specifications.

Oilfield Innovations’ have nicknamed our patented casing sharing technology the “Magic Crossover” (see Figures 15 and 16) and our patented conductor sharing technology the “Cloverleaf” (see Figures 10-11, 13-14 and 19), wherein both are compatible with standard wellhead and extended reach drilling technologies usable with subsea trees, to enable tie-back of multiple pools of stranded hydrocarbons through a single pipeline.

With regard to the “Cloverleaf” technology specification in Figure 10, numerous examples of multiple wells through a single conductor exist, like the North Sea Magnus wellhead and trees depicted in Figure 1, and three conductor sharing North Sea Britannia wellhead and production trees in Figure 12, whereby such technology has been documented by many authors (Sund5, 1997; Dharaphop6, 1999; Tuah7, 2000; Anch-aboh8, 2001; Faget9, 2005; Santos10, 2006; Matheson11, 2008; Hicks1, 2009; Damasena2, 2014; Terimo13, 2016).

Offshore platforms have developed conductor sharing because they lacked slots for additional wells and, unfortu-nately, the technology has never been translated to a subsea arrangement until Oilfield Innovations patented a subsea con-ductor sharing arrangement that uses a rotatable bore selector

whipstock to select a one of up to three well bores.

As previously described, the technology allows concurrent drilling of multiple wells using batched drilled hole-sections accessed by a rotatable bore selector whipstock as shown in Figure 11.

Where the North Sea Magnus Field used 46 inch conduc-tors (Hicks, 2009)1 a subsea version of the conductor sharing could use a 48” conductor to provide three conventional 22 inch wellhead casing hanger systems in a “Cloverleaf” pattern accessible using a rotatable bore selector whipstock through an 18 ¾ inch conventional wellhead housing as shown in Fig-ures 10 and 11.

Figure 10, shows that the equivalent internal diameter of three (3) 9 ⅝ inch casings (8.7 inches) can be accommodat-ed through and 18 ¾ inch subsea wellhead housing for three conventional tubing strings with associated control lines and clamps.

Accordingly, casings can be hung-off below the whipstock with three (3) independent tubing strings passing through an 18 ¾ inch wellhead housing internal diameter.

As depicted in Figure 11, Oilfield Innovations proposes that a conventional big-bore subsea wellhead housing and casing hanger system be split by a rotatable whipstock ar-rangement to select which well bore will be entered. New technology development does not get any simpler nor more adaptable to standardisation that allows rapid development and widespread usage.

13June 2017 - PROSPECTUS |


18" Casing

INDUSTRY PROVEN18 ¾" BigBoreWellhead Housing

Illustration depicts a36" x 28" x 22" x18" x 16" x 14" x 10-3/4"casing program

36" Conductor Wellhead

36" Supplemental Adapter

36" x 28" Casing Hanger

36" Casing22" Casing14" Casing

10-3/4" Casing

22" x 16" SupplementalAdapter

16" Seal Assembly

22" x 16" SupplementalCasing Hanger

16" Casing

22" x 18" SupplementalAdapter

18" Seal Assembly

22" x 18" SupplementalCasing Hanger

SECTION A-A

AA

SECTION B-B

BB

BB

A

A

NewCloverleaf

Bore SelectorWhipstock

Technology

Note:Looking up

from thebottom

Whipstock

ChamberWear

Bushing

HelicalOrientation

Bullnose

SPLITPROVEN

WELLHEADSYSTEM

WITHINTERMEDIATE

WHIPSTOCKAND

COMBINEWITH

PROVENCONDUCTOR

SHARING

ExistingWellhead

Technology

ExistingCasing Hanger

Technology

Figure 11 - New Cloverleaf Whipstock Technology

Use PDF zoom to see more

14

Terms of Reference


Figure 12 - Britannia Triple Wellhead Arrangement (Matheson, 2008)11



Figure 13 - Theoretical Plan View of a Conductor Sharing Subsea Tree

18 3/4” WellheadHousing ID

Control Line Stab

Common Blockand Stab Connection

Remote Operated Vehicle(ROV) Access Panel

Common AnnulusAccess Passageand Valving

5 1/8” Tree Bore ID

Flow Blocks

Commingling Manifold

Export FlowlineAnnulus Flowline

ActuatorsConventionalPermanentGuidebase

An example of a three-well conductor sharing arrangement is shown in Figure 12 for the UK North Sea field Britannia (Matheson, 2008)11. The existence of a proven three well surface conductor sharing arrangement indicates that subsea conductor sharing is feasible using, for example, the conduc-tor sharing subsea arrangement illustrated in Figure 13.

The primary differences between surface and subsea pro-duction trees comprises annulus access and the ability to ac-tuate valves both hydraulically and with a remote operated vehicle (ROV).

Figure 13 illustrates a scaled version of 48” Cloverleaf subsea conductor sharing arrangement depicting how a com-mon central block can be bored to accommodate flow blocks and actuators for a three well subsea production tree.

Flow from the three (3) separate well wells can be directed from the flow blocks to a commingling manifold or, alterna-tively, individually to a conventional subsea manifold.

The Cloverleaf three well arrangement has a common an-nulus passageway between the three wells that can also be ac-cessed through an annulus flowline in a conventional manner.

The Figure 13 arrangement fits within a conventional per-manent guide base having 72 inch radius guide posts for blowout prevention stacks (BOPs), wherein the arrangement of tree and BOPs can be seen in Figures 33 and 35 of the ap-pendix.

To further reduce cost, the tree can be configured as a ver-tical tree with light well intervention vessel (LWIV) access to the three individual well bores via a subsea lubricator (see Figure 37) to allow the rig to drill the well and go off con-tract, with a lower cost LWIV setting the tree and performing hook-up operations.



52Optional in.PressureReinforcement

50 in. ID

48 in. ODSeparator Housing

44 in. ID

OptionalReinforcementRibs securedto SeparatorH(see separatesubmittal)

ousing

18.25 in. DrillingWear BushingRemoved beforeCompletion 17.25 in. ID

9.625 Annulus Separatorinstalled beforeCompletion

or 10.75 in

8.535 in. ID

7 in. Separator Access Piping

6 in. OD

Vertical Separator Volume

Figure 14 - Cloverleaf Vertical High Pressure Water Disposal Separator

Large Diameter High Pressure Conductors

One of the downsides of large diameter piping is a relative-ly low pressure rating. Fortunately, Oilfield Innovations have also patented solutions to this dilemma as shown in Figure 14, which is described in more detail with another prospectus on our website.

Low burst and collapse pressure rating for large diameter piping are associated with the propensity of large diameters pipe expansion and compression, respectively. Oilfield Inno-vations have patented the principle driving ribs between con-ductors to compress a large diameter inner pipe and expand a larger diameter outer pipe, to form a composite large diame-ter structure that has high pressure and bending strength.

For instance, as described in Figure 29 of the appendix, 52 inch conductor can be jetted into the seabed on the temporary guide base on the temporary guide base. A 50 inch hole open-er (RHO, 2017)32 with a 24 inch pilot bit can then drill a hole for a 48” inner conductor that can pass through a standard 49 ½” rotary table to fit within the 52 inch outer conductor to provide substantial bending resistance for the Figure 13 subsea tree.

With regard to pressure rating, the API 5CT pressure rating for X-80 grade pipe with 1.875 wall thickness shown in Fig-ure 10 is rated to 5,500-psi (374-bar) while 110-ksi material

would be rated to 7,500-psi (510-bar).

The Figure 14 patented solution to increase conductor pres-sure ratings can, for example, use a 36 inch pilot bit with a 56 inch hole opener to bore a hole for one (1) inch wall thickness 52” outer conductor run and cemented with the Temporary guide base as shown in Figure 28.

A Figure 14 Cloverleaf with a 48 inch diameter and con-ventional reinforcement ribs comprising, for example, con-ventional solid blade casing centralizers attached to casing can expand the 52” outer conductor that will marginally com-press 48” ribbed inner conductor to create a metal-to-metal contact composite wall with 12,000-psi burst pressure assum-ing an 80% efficiency for an API 5CT calculation.

Figure 14 enhanced bending and pressure rating can facili-tate the double independent wall safety factors necessary for the downhole vertical separator arrangement that can be in-stalled below the Cloverleaf whipstock technology to dispose of waste water.

The separator can be managed and cleaned through 7 inch access piping as shown in Figure 14. Water disposal can occur in various ways, wherein it is possible to install the Figures 15 and 16 “Magic Crossover” arrangement (further explained in a separate prospectus on our website) within one of the well bores to inject water into the same horizon



PLU

G

Inner Tubing

Cross Section A-A

Outer Tubing

Flow Ports

Flow Ports

Housing

O�-the-Shelf Plug

O�-the-Shelf-Packer

A A

Well #1 Production or Injection

TubingHangers

Well #2 Production or Injection

Well #1 Safety Valve

Well #2 Safety Valve

InterventionSliding Valve

InterventionWireline Plug

MPIX - Multi-Production or Injection Crossover

MPIX Packer

Production Packer(e.g. 9 5/8”)

Intermediate Casing(e.g. 14” x 13 3/8”)

Production Casing(e.g. 10 3/4” x 9 5/8”)

Production Annulus

Well #1 - Inner Tubing(e.g. 4 1/2”)

Well #2 - Tubing (e.g. 8 5/8”x7 5/8”)

Use PDF zoom to see more

Figure 15 - Magic Crossover Simplication

Figure 16 - New Casing Sharing Tecnhology

from which it came to, effectively, sweep the reservoir and increase hydrocarbon production (see Figures 18 and 20).

Magic Crossover (2-for-1 Well Costs)

Landing surface casing within a conventional profile below the Figure 14 separator and landing a 9 ⅝ or 10 ¾ inch casing within a conventional profile above the separator can maxi-mise separator volume and provide both annulus monitoring and the ability to produce and inject through a single casing string using the Figure 16 “Magic Crossover” arrangement. This is accomplished with independent concentric flow for both production and injection through the same casing. Please note that additional detailed information on our Mag-ic Crossover is contained within another prospectus on our website.

Figures 15 and 16, illustrate how a simple crossover with no moving parts can be used between conventional comple-tion equipment to flow two differently pressured flow streams through a single wellbore, wherein the flow streams can flow in the same or opposite directions.

18

Terms of Reference


Figure 17 - Troll Subsea Separation Pilot (Tveter, 2015)24

Downhole Separation

As shown in Figure 17, Statoil have used subsea separa-tion in Norway on the Troll field (Tveter, 2015)24. Looking at the size of the separator relative to the people shown in the Figure 17 photo, and considering the double shell nature of a sea bed separator, an equivalent or larger internal volume for the Figure 14 separator can be achieved with a vertical depth greater than the length of the Figure 17 Troll horizontal separator.

As shown in Figure 18, fluids produced from the reservoir

Figure 18 - Troll Subsea Separation Pilot (Tveter, 2015)24

are directed into the high pressure water knock-out separa-tor with two phase flow down the pipeline and water dispos-al comprising re-injection of produced water back into the aquifer below the reservoir.

Tveter24 describes in Figure 20 that subsea water separa-tion and disposal prior to entering the pipeline extends the life of the field and increases recoverable reserves.

Accordingly, adding downhole separation can be a signif-icant improve the economics of developing stranded hydro-carbons.



Figure 19 - Cloverleaf Vertical Separator

ThermallyInsultedbyOverbuden

ThermallyInsultedbyOverbuden

SeparatorAnnulusStraddle

SeparatorAnnulusStraddle

ProducedWaterDisposal

ProducedWaterDisposal

Pump pressurecan be addedfor injection

Pump pressurecan be addedfor injection

+/- ReservoirTemp. Export+/- ReservoirTemp. Export

OilfieldInnovationsWhipstockTechnology

OilfieldInnovationsWhipstockTechnology

MonitorAnnulusIntegrity

MonitorAnnulusIntegrity

ConventionalCasingHangers


OilfieldInnovationsVerticalDownholeSeparator(casingpass thruseparatorlike a heatexchangertubes)

OilfieldInnovationsVerticalDownholeSeparator(casingpass thruseparatorlike a heatexchangertubes)

GuideBase

Whipstock

Annulus9 5/8 in.SeparatorStraddle

Annulus9 5/8 in.SeparatorStraddle

WellheadHousing

CasingHangers

VerticalSeparator

DownComer

Plate

Cloverleaf Vertical Downhole Separator

Figure 19 describes how the Figure 11 separation of the wellhead housing connector and casing hangers can be further separated to create a downhole vertical separator, while Figure 10 shows the available space for separator piping. Please note that a conventional single well subterranean vertical separator and/or monopod jacket vertical separator are explained in our High Pressure Conductor Pro-spectus.

As depicted in Figure 19, produced fluids from the wells can be directed to a Cloverleaf downhole vertical separator where gravity separates the lighter hydrocarbons from the heavier water.

Hydrocarbons are taken from the top of the Figure 19 vertical sep-arator and produced water is taken from the lower portion of the vertical separator, wherein the down comer plate and length of the hydrocarbon entry and exit piping would be designed according to the gas-to-oil ratio of the hydrocarbons.

To provide a clearer depiction, Figure 19 shows disposed water being pushed into the overburden, however, space for three 7 inch separator pipes shown in Figure 14 exists and can comprise the hy-drocarbon pipe feeding the separator, the hydrocarbon export pipe feeding the pipeline and the water disposal pipe which can pump water from the bottom of the separator and, for example, use the Figure 16 “Well #2 Production or Injection” Magic Crossover flow stream to dispose of water into the water leg of the reservoir being produced, which provides the same functionality as Figure 18 with-out the cost of a disposal well.

With regard to barriers, Figure 14 describes use of Oilfield In-novations patented pressure reinforced double separator hull, which can be cemented within the shallow overburden such that the double hull, cement and overburden insulated vertical separator can pro-vide approximately reservoir temperature export fluids when the heat exchanger nature of the wells running through the separator and the mass transfer of heat from disposed water are considered. Each well uses a common pressure integrity monitoring annulus, which is separate from and runs through the vertical separator within the insulation of cement and surrounding overburden to maximise the temperature and increase the flow assurance properties before hydro-carbons enter the tie-back pipeline.

Piping separate from the wells may be accessed from above via the lubricator of a light well intervention vessel (see Figure 37) to allow cleaning and maintenance of the vertical separator, wherein a light well intervention vessel could use coiled tubing to clean out the separator periodically if, for example, it became filled with produced solids.

Because a subterranean separator can be, for example, 500-ft or 152 metres in height, it can handle a large volume of fluids and pro-duced solids, wherein optical fibre temperature and pressure moni-toring of the separator volume can provide sufficient data to manage

20

Terms of Reference


Host Facility Max. Water HandlingCapacity w/o Subsea Separation

Additional Production0

1

2

0 5 10 15Time

Pro

duct

ion

rate

OilGasWater

GasWater

Reduction inwater through thetie-back pipeline

Increase in oil and gas productiondue to reduced wellhead pressure

Figure 20- Troll Subsea Separation Pilot (Tveter, 2015)24

the separator and determine whether, or not, it needed to be cleaned out.

Also, hydrocarbons from three (3) separate small pool res-ervoirs could be commingled in the separator together with any necessary chemical additions within the insulated near reservoir temperatures of the vertical separator to improve mixing and associated flow assurance through the tie-back pipeline.

Metering of each of the wells and sampling taken when one or more of the wells is shut-in can be used for allocations and determination of the properties and qualities of the hydrocar-bons from each previously stranded hydrocarbon pool.

Increased Recoverable Reserves

Developing stranded hydrocarbon pools is not necessarily strictly a cost cutting exercise. It also involves increasing the recoverable reserves as shown in the Troll subsea separation example of Figure 20.

Stranded hydrocarbon development economics can often be impeded by the host facility’s inability to handle produced water, wherein the economics of stranded hydrocarbons nor-mally considers early cessation of production due to pro-duced water, before reservoir pressure is fully depleted.

In Figure 20, Tveter24 depicts how the subsea disposal of produced water allows higher production rates that reduce wellhead pressure and increase recoverable reserves by re-ducing the volume of water through the tie-back pipeline be-low the water handling capabilities of the host facility.

Accordingly, additional production added by downhole separation can be added to the economics of small pools to

increase their viability.

The Large Impact of Three Small Innovations

Previous industry standardisation initiatives are critical for growth of an industry, but standardisation will not necessarily improve the economics of small pools unless innovation oc-curs within said standardisation.

Oilfield Innovations can provide three small innovations within present standardised systems that can have a large positive impact on the development of stranded offshore hy-drocarbons.

Our Cloverleaf conductor sharing technology provides the relatively small adaptation of standardised technology comprising splitting a standard subsea wellhead housing and hanger systems with a rotatable whipstock to allow conven-tional extended reach wells that remove the need for tiebacks to a central manifold.

Our Magic Crossover technology provides the relative-ly small adaptation of standardised technology comprising crossing over concentric flow streams to allow conventional completion jewellery to control the internal tubing diameter of two differently pressured fluid stream flowing in the same or opposite directions.

Our Large Diameter High Pressure conductor technology provides the relatively small adaptation of tubular standards comprising the use of ribbing to engage one conductor within another conductor to increase its bending, burst and collapse pressure capabilities significantly.

Combining these three small innovations has the signifi-cant impact of reducing development cost by reducing subsea

21

Terms of Reference


Threshold of Pain(economic viability)

The same technologies are evaluated andcontinue to demonstrate uneconomic natureof stranded hydrocarbon discoveries

Appraise Frameof Possible Alternatives

Select Phase

ConventionalTechnology assembledin a differen way to marginally improveeconomics to theflip-of-a-coin decision

New Technology Improve Economics(enhancements built upon existing

standards that combine proventechnology to substantially

improve economics)

New Paradigm:Subsea Conductor Sharing and ERD,Subterranean Vertical Separator Water Disposal andConcentric Dual Flow Wells via a Simple Crossover.

Figure 21 - New Plug-and-Play Paradigm (Iterative Approach, Hopper, 2016)18

infrastructure to an absolute minimum while providing the ability to access multiple differently pressured small pools and/or fault blocks through a single wellhead.

Oilfield Innovations’ Cloverleaf can provide three autono-mous wells while our Magic Crossover can provide two dif-ferently pressure flow streams through each autonomous well to, thus, provide six (6) separate differently pressured flow streams through a single wellhead, whereby each of the six (6) separately pressured flow streams can be flowed through a high pressure thermally insulated water knock-out vertical separator that can provide a commingled chemically treated hydrocarbon flow stream to a single tie-back pipeline.

Oilfield Innovations three small adaptations could be stan-dardised to better facilitate widespread use and development of supporting new technologies that can be used to reduce costs, increase recoverable reserves and develop stranded offshore hydrocarbons.

New Paradigm

As illustrated in Figure 21, the three possible outcomes of further evaluating development of stranded hydrocarbon dis-coveries are that previous development scenarios are repeat-ed and fail, new scenarios of using marginally less expensive approaches provide marginal economics or new technology is developed that make stranded hydrocarbons discoveries eco-nomic despite the normal risks of offshore development.

Because fracking technologies will limit the price of oil and gas for some time, development of stranded offshore hy-drocarbons requires a new paradigm that substantially chang-es the economics of tie-backs to existing infrastructure.

With Oilfield Innovations’ limited adaptation of existing standardized technologies, a new paradigm can be created with limited risk that substantially changes the economics using batch (assembly line) drilling techniques, utilisation of previous wasted well bore space and downhole water separation and disposal before two (2) to six (6) separately pressured hydrocarbon streams enter a single tie-back pipe-line with a single umbilical using a combined subsea tree and manifold.

Oilfield Innovations may be a two man dog-and-pony-show that may lack the credibility necessary to single-hand-edly create such technology, but we own the patents and we are looking for commercial entities with sufficient credibility, experience and funding to bring enormous amounts of strand-ed offshore hydrocarbon to market.

Commercial considerations could be agreed to open source connection interfaces to Oilfield Innovations’ patented tech-nology to allow any vendor to interface with the new technol-ogy, wherein the legal rights associated with the patents could be managed by a service provider such that the interfaces are standardized in an open source manner.

Providing large and small service providers with access to interfacing with the new technology would improve the like-lihood of acceptance, create competition and keep costs as low as reasonably practicable.

For example, Shell released the technology of bi-centre bits (see Figure 36) and now most bit companies produce bi-centre bits using standardized API rotary connections.

The North Sea has since the booms of the 1970’s and early



Commercialization Components

StrategicDevelopmentSweet Spot

Frame

ProjectFrame

BusinessFrame Defines the Project

• Facilities • Subsurface

Defines the Value• Commercial/Tariffs• Operators/Government

Defines the Playing Field• Plug-and-Play Standardization • Supply Chain Optimization

• Most people focus on the Project Frame

• Most problems occur in the Business Frame

• Most synergies (future developments)are made in the Strategic Frame

30%-50%Cost ReductionNecessary forDeveloping Small Pools

Figure 22 - Commercialisation Components, Hopper, 2016)18

1980’s been relatively resistant to change and, therefore, cre-ating a standard that is distributed worldwide could provide the necessary use in other countries to influence its accep-tance in the North Sea.

Required adaptations proposed herein are relatively minor and lower in cost than other innovations that have provided step changes in performance.

For example, Oilfield Innovations are proposing splitting a subsea hanger system, adapting a whipstock and making a crossover according standardised pipe sizes, whereas the step changes in extended reach drilling between 1975 to 2010, shown in Figure 7, required complete retooling of drilling systems from rotary kelly drilling to top-drives, positive dis-placement fluid motors and rotary steerable systems, albeit each involved a sequence of understandable and acceptable changes that were built upon API standards for rotary con-nections.

Commercialisation

As illustrated in Figure 22, the sweet spot for small pool development requires solving issues in the project, business and strategic frames, wherein collaboration between Oilfield Innovations and OGTC could provide two of the three neces-sary characteristics for development.

Most people, including Oilfield Innovations, focus on the technical aspects of the project.

Plug-and-play open sourcing could be used to focus on the strategic frame.

As a micro-company, the business frame is beyond Oilfield Innovations’ control and we are looking for investors. Plug and play open sourcing is one idea, but we are open to any commercial arrangement.

As described in Figure 23, a business case can be built by identifying various UK North Sea small pools, see Figures 24 to 27, which can analysed and evaluated to provide business cases that may further influence industry to develop and use the technology.

Standards can be selected and amalgamated under a single plug-and-play standard for industry use with the proposed



Business CaseIdentify groups of small pool candidates that can use the technology to tie multiple laterally separated hydrocarbon resevoirs back to existing infrastructure.

Standards SelectionIdentify and select industry standards that can be amalgamated under a single plug-and-play standard for use within the New Technology employing said standards.

New TechnologyWork with a Qualified Service Company to Develop New Technology to existing selected industry standards and qualify the tooling for use on a “pool of small pools.”

StandardizationDevelop and Publish the Standard for Licensed Qualified Service Providers and Manufacturers

SmallHydrocarbon

Pools

DEVELOPMENT PLANPlug-and-Play North Sea Small Pools Development

Figure 23 - Plug-and-Play Approach to Subsea Casing and Conductor Sharing Technologies

Conclusion

“Small” offshore hydrocarbon discoveries are substantially larger than many economic discoveries. “Small” refers to the pool’s economic development size and not necessarily oil and gas in place. As offshore small pools are substantially larger than remaining pools of onshore hydrocarbons, the key to de-veloping offshore hydrocarbons is reducing cost and improving recovery.

When a small pool of hydrocarbons was discovered, subsea development and tie-back options to existing infrastructure were evaluated and, therefore, the small economic size of the stranded hydrocarbons did not justify the subsea infrastructure cost, tariffs, waste water disposal, well count or drilling cost options evaluated.

Standardizing plug-and-play approaches which have already proved uneconomic is unlikely to reduce cost sufficiently to de-velop stranded hydrocarbons and a new approach to develop-ment is required.

Also, costs for developing small pools of offshore hydrocar-

new technology, as further described in Figure 23.

In addition to assisting with creation of an open source plug-and-play specification, Oilfield Innovations are also qualified to identify business casings within the 100 oppor-tunities identified in Table 1 and Figures 24 to 27.

Oilfield Innovations’ new technology can easily be de-veloped and qualified by qualified service companies.

Commercially, Oilfield Innovations need to recoup their patent investment costs with the potential for a relatively small return on investment once the technology is success-ful, while the United Kingdom needs the tax revenue gen-erated by developing small pools.

Oilfield Innovations will accept virtually any viable commercial proposal and can assign control of their pat-ents to any entity who can fund and manage development and the business provided we can recoup our patent costs.

Accordingly, the new technology can be standardized and published for use by qualified vendors and service pro-viders as further stated in Figure 23.

As our new technologies requires minimum adaptations and works within standardised oil and gas technologies as

well as conventional proprietary technologies, it is a good fit with OGTC’s call for plug-and-play innovations.



bons must be competitive within current pricing set by on-shore fracking.

Accordingly, a new paradigm is needed for developing small pools of offshore hydrocarbons; however, said para-digm cannot significantly deviate from existing standards upon which the oil and gas industry is built.

Oil and gas drilling have used plug-and-play standard-ization for decades. The various sizes of tooling for drill-ing and completion have been standardized through API and ISO such that conventional extended reach drilling technology can be used to eliminate tie-backs to a central subsea manifold.

Also, conventional conductor sharing can be adapted to subsea applications using Oilfield Innovations rotatable whipstock bore selector to improve drilling and casing ef-ficiency using hole-section batch operations.

Changing the paradigm of uneconomic small pools of offshore hydrocarbons discoveries requires not only mini-mising subsea infrastructure and improving drilling perfor-mance but also limiting well count and managing produced waste water disposal.

Disposing of produced water before it reaches the tie-back pipeline can increase recoverable reserves and min-imise development costs, wherein increased recovery and lower costs can make small pools of hydrocarbons more economic.

Oilfield Innovations can open source our patented tech-nology in a supply chain plug-and-play manner, wherein the legal rights afforded by our patents can provide supply chain control during and after standardization to ensure competitive pricing.

The supply chain organisation who controls our patents would have the legal right to make critical standardization decisions and control quality assurance of the standard.

For example, for quality control purposes, a patent con-trol supply chain organisation could license use to only qualified vendors who adhere to the publish standards.

Accordingly, Oilfield Innovations technologies are 100% plug-and-play compatible.

Three minor standardized tweaks to industry proven technology comprising:

• a split conventional wellhead with an intermediate ro-tatable whipstock and “cloverleaf” shaped conductor sharing arrangement,

• a “magic” crossover that allows discrete control of two flow streams through the same wellbore, and

• “ribbing” that can be used to create large diameter high pressure conductors which can be used to retain larger hole sizes at well total depth, facilitate monopod jack-ets in deeper water depths and/or provide double walled subsea or subterranean vertical separators,

can change the paradigm of North Sea small pools develop-ment without significantly deviated from standard industry practice.

Insanity is doing the same thing over and over again, and expecting a different result (Albert Einstein).

It is unlikely that North Sea small hydrocarbon pools can be changed without doing something different and it is im-portant to work within the boundaries of present industry standards.

Oilfield Innovations can offer minor changes, which can be standardized in a plug-and-play manner within proven indus-try standards, that can change the way small pools of hydro-carbons are developed.

If our ideas are of interest, we would be pleased to discuss how they could be further developed. For additional infor-mation please read our accompanying submittals.

25

Terms of Reference


Further Information

Addition detailed information on the Oilfield Innovations’ Conductor Sharing Technology described above is included in Appendix A, please provide this document to your engi-neers and we would be happy to answer any further queries. For additional information or further queries please contact Clint Smith or Bruce Tunget at the below email addresses.

Notes and referencesa Clint Smith is Professional Engineer in the State of Texas, began working in the Drilling, Intervention and Well Operations in 1978 and lives in Houston, Texas, USA; Curriculum Vitae (CV) available upon request; [email protected]

b Bruce Tunget earned a PhD. and MSc in Mineral Economics and a BSc in Mineral Engineering from the Colorado School of Mines, is a Chartered Financial Analyst, began working in Drilling, Intervention and Abandonment Operations in 1982 and lives in Aberdeen, Scotland; Curriculum Vitae (CV) available upon request; [email protected]

† Various photograph have been taken from the following cited references.

‡ Footnotes.

1 S.E. Hicks, A. Moore, M. Honey, BP Exploration; I.R. Farmer, Schlum-berger; B. Smart, R. Ekseth, Gyrodata; D. Brown, Cameron; Magnus: Util-isation of Conductor Sharing Wellhead Technology to Access Additional Hydrocarbons via a Slot-Constrained Platform, SPE 124233, 2009.

2 E. Damasena, Petrofac; S. Kencana, H. Kasim, H. Ismail, A. Mos, Solar Alert; Unique Splitter Wellhead Design for Fit for Purpose Casing Design and Offline Work, OTC-24908-MS, 2014.

3 K. S. Durham, MWL Tool Co.; Tubing Movement, Forces, and Stresses in Dual-Flow Assembly Installations, SPE 9265, 1982.

4 S. Barua, Simulation Sciences Inc.; Computation of Heat Transfer in Well-bores With Single and Dual Completions, SPE 22868, 1991.

5 G. V. Sund, B. Wenande, Amoco Norway Oil Co., C. L. Weaver, Baker Oil Tools, J. M. Addams, Kvaerner National Inc.; Downhole Splitter Well For Simultaneous Injection and Production at the Valhall Field, SPE 38498, 1997.

6 J. Dharaphop, C. Borisutsawat, V. Chaisangkha, PTT Exploration and Pro-duction PLC; K. Boyne, E. Thouvenin, TOTAL Exploration and Production; Conductor Sharing - A Viable Alternative to Multilaterals and Slot Recover-ies, SPE/IADC 52876, 1999.

7 J. B. Tuah, M. Rujhan, B Mat, L. F. Nam, PETRONAS Carigali; Triple Wellhead Technology in Sarawak Operations, SPE 64277, 2000.

8 L. Anchaboh, F.P.A. de Lange, Shell; C.J. van Beelen, Riyan , R.K.W. Tan, Cooper Cameron; Conductor Sharing Wellheads - More For Less, SPE 68699, 2001.

9 J.B. Faget, J.C. Monneyron, A. Bourgeois, N. Payer, Total E&P Indonésie; L.H. Cherng, Cooper Cameron Singapore; 10K Dual Splitter Wellheads: First Worldwide Application on the Development of an Offshore Gas Field, SPE 96154, 2005.

10 A. Santos and A. Floch, Total ABK; 5K Dual Splitter Wellhead System: 1st Middle East Deployment on an Offshore Oilfield, Combining Simultaneous Production and Drilling on Adjacent Wells Within the Same Conductor, SPE 101736, 2006.

11 A. E. Matheson, Peter Tayler, ConocoPhillips; R. S. Nash, Chevron; J. McAuley, VetcoGray; Development and Installation of a Triple Wellhead on the Britannia Platform, SPE 115698, 2008.

12 M. I. Khalid, R. E. Poit, PETRONAS, M. S. Jumaat, Schlumberger; Col-laboration in Extracting More Oil in Mature Dual Completion Wells, SPE 124443, 2009.

13 J. Terimo, H. K. Zaman, PETRONAS; G. Pallath, Shell; T. Cherchawankul, H. Costeno, M. Djohor, R. Mokhti, L. D. Gonzalez, Schlumberger; Optimiz-ing Offshore Infill Drilling: Application of Conductor Sharing and Casing Drilling Techniques, IADC/SPE-180579-MS, 2016.

14 E. P. Anthony, H. Al-Zuabi, Kuwait Oil Company; Dual Parallel Simultane-ous Injection and Production SIP Completion in Single Wellbore Reduces Development Costs and Accelerates Production, SPE-182171-MS, 2016.

15 A. M. Zahrani, M. A. Amri, and K. S. Yateem, Saudi Aramco; G. D. Mendes, Baker Hughes; First Five-Zone Smart Completion Technology Deployment in ERC Well, SPE-183814-MS, 2017.

16 B. Bouldin, R. Turner, I. Bellaci, Y. Abu Ahmad, Saudi Aramco; S. Dyer, T. Oliveira, A. B. Al-Sheikh, Schlumberger; Intelligent Completion in Laterals Becomes a Reality, SPE-183949-MS, 2017.

17 A. Dulaijan, M. Shenqiti, K. Ufondu, B.r Zahrani, K. Abouelnaaj, Saudi Aramco; M. Shafiq, Schlumberger; Case History: A Decade of Experience Using Intelligent Completions for Production Optimization and Water Shut-Off in Multilateral Wells in the World’s Largest Oilfield, SPE/IADC-184629-MS, 2017.

18 C. T. Hopper, Moving Future; Resilient Field Developments That Can Ac-commodate Uncertainty Are the Best Solution for a Sustained Low Oil Price Environment, SPE-180176-MS, 2016.

19 D. S. Huber; C. D. Smith, Hardy Oil and Gas; The Mustique / Shasta Proj-ect: A Small Operators Deepwater Management Challenge, OTC 8250, 1996.

20 OGTC, Oil and Gas Technology Centre Website, http://theogtc.com/solu-tion-centres/small-pools/

21 OGA, Oil and Gas Authority; UK Continental Shelf Unsanctioned Discov-eries Information Pack, https://www.ogauthority.co.uk/media/2960/420297-small-pools-22.pdf .

22 B. Bennetzen, Maersk Oil; J. Fuller; England; E. Isevcan; Qatar; T. Krepp, R. Meehan, N. Mohammad, J.F. Paupeau, Texas, USA; K. Sonowal, Zakum Dev. Co., Abu Dhabi, UAE; Extended Reach Wells, Oilfield Review, 2010.

23 F. Allen, P. Tooms, BP; G. Conran, England; B. Lesso, P. Van de Slijke, Texas, USA; Extended-Reach Drilling: Breaking the 10-km Barrier, Oilfield Review, Winter 1997.

24 B. N. Tveter, Statoil, Subsea Processing, UiO, 22 September 2015.

25 S. Duthie, Oil & Gas UK Efficiency Task Force; Subsea Technology Stan-dardization Overview – Current Status, 26th May 2016, Website: http://oilandgasuk.co.uk/wp-content/uploads/2015/09/Subsea-Technology-Stan-dardisation-Project-Overview-v2.pdf.

26 S. Dail, BP Group Chief Economist; New Economics of Oil, Society of Business Economics Annual Conference, London 13 Oct. 2015.

27 Exxon Mobil shifts investments to quick-earning shale; J. Carroll; World Oil (internet version), March 1, 2017.

28- C. Williams, US Editor, Microsoft has crafted a switch OS on Debian Linux. Repeat, a switch OS on Debian Linux, The Register, 9 Mar. 2016, https://www.theregister.co.uk/2016/03/09/microsoft_sonic_debian/.

29 Varel Oil & Gas Drill Bits, Fixed Cutter Bits Product Catalog, 2016-2017, www.vareloilandgas.com.

30 R. G. Casto, Use of Bicenter PDC Bit Reduces Drilling Cost, Oil & Gas Journal, website, 13 Nov. 1995.

31 XL Systems, XL Systems Engineered Connectors Brochure, www.xlcon-nectors.com.

32 RHO Hole Opener Brochure, www.holeopenter.com.

33 T. Halvorsen, FMC, Subsea UK, Subsea Development Status and Trends, Source: Internet.

This document is copyrighted by Oilfield Innovations and may be free distribut-ed but not altered without written consent.

http://theogtc.com/solution-centres/small-pools/

http://theogtc.com/solution-centres/small-pools/

https://www.ogauthority.co.uk/media/2960/420297-small-pools-22.pdf

https://www.ogauthority.co.uk/media/2960/420297-small-pools-22.pdf

http://oilandgasuk.co.uk/wp-content/uploads/2015/09/Subsea-Technology-Standardisation-Project-Overview-v2.pdf



https://www.theregister.co.uk/2016/03/09/microsoft_sonic_debian/

https://www.theregister.co.uk/2016/03/09/microsoft_sonic_debian/

http://www.vareloilandgas.com

http://www.xlconnectors.com

http://www.xlconnectors.com

http://www.holeopenter.com

26

Terms of Reference


Additional Terms of Reference

APPENDIX A

27

Terms of Reference


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30/13- 2

30/13- 1

22/16- 6

21/28- 1

21/17- 4

21/17- 3

16/29- 4

16/23- 2

16/22- 2

15/26- 1

15/19- 9

14/18- 1

14/15- 2

14/14- 1

30/25a- 4

30/01a- 7

29/06a- 3

28/09a- 6

23/16d- 6

22/27a- 1

22/22c- 3

22/14b- 3

22/13b- 3

22/13a- 2

22/04b- 6

21/28a- 6

21/27b- 7

21/20f- 7

21/15a- 2

20/03- 2A

16/12b- 6

15/29a- 9

15/17- 8A

15/17- 26

15/17- 24

30/11c- 6C

29/01c- 9Z

22/24c- 11

22/12a- 10

22/11b- 13

21/23a- 8Z

16/21b- 34

15/21b- 50

15/21b- 45

15/19b- 10

30/02- 1

30/02a- 2

29/02a- 2

22/27a- 2

22/08a- 2

15/17- 25

14/30a- 2

14/29a- 4

30/02a- 10

30/01d- 1230/01d- 10

23/22b- 6Z

22/30a- 17

22/30a- 16

22/23c- 8X

30/13- 3

30/08- 3

30/08- 229/10- 4

29/10- 2

29/07- 1

28/02- 1

22/29- 2

22/19- 1

22/18- 3

22/15- 4

22/15- 3

22/04- 3

21/27- 2

21/24- 4

21/24- 1

21/02- 2

21/02- 1

20/08- 2

20/03- 4

16/23- 4

16/22- 5

16/22- 4

16/18- 1

15/30- 5

15/30- 2

15/18- 2

15/13- 2

14/20- 6

30/29a- 1

30/11b- 430/11b- 3

30/01c- 3

29/09b- 2

29/09a- 1

29/08b- 2

29/08a- 4

29/08a- 3

29/05a- 1

29/03b- 9

28/03- 1B

23/21- 6Z

22/24b- 8

22/23b- 5

22/22b- 2

21/30- 2521/30- 1721/30- 12

21/29b- 9

21/29b- 4

21/28a- 2

21/27- 1A

21/20b- 4

21/20a- 5

21/08- 4Z

21/06b- 8

20/04a- 8

15/27-E1Z15/26b- 9

15/24a- 4

15/22- 16

15/21a- 7

15/18a- 6

15/12b- 4

30/07a- 1230/07a- 10

30/01a- 11

28/09a- 5A

22/24e- 1221/29d- 11

21/13b- 1A

21/05a- 6Z

16/13a- 2Z

15/23d- 13

15/21b- 47

15/21a- 51

15/21a- 46

15/18b- 11

15/13a- 10

14/20b- 17

30/17a- 14Z

30/01f- 13Z

20/05a- 10Y

15/27a- 12A

15/25c- 15A15/21a- 38Z

21 2223

28 29 30

1615

20

31

27

14

BRITANNIA

EVEREST

JUDY

JOANNE

AUK

FORTIES

FRAM

NELSON

ORION

JASMINE

PIPER

SCOTT

FRANKLIN

CLAYMORE

TARTAN

ARBROATH

MONTROSE

ATHENA

THELMA

BRAE

BRODGAR

STELLA

AFFLECK

PICT

DONAN

KYLE

CYRUS

BUCHAN

MACHAR

ELGIN

SHAW

HOWE

MUNGO

JADE

ENOCH

FLEMING

LOMOND

ALBA

KINNOULL

ROCHELLE

GALLEY

GANNET A

FLYNDRE

HARRIER

MAUREEN

MARIA

CLYDE

SCAPA

ERSKINE

ALMA

SHEARWATER

GUILLEMOT WEST

GODWIN

BURGHLEY

CURLEW

CALEDONIA

TELFORD

ANDREW

LARCH

BANFF

TONI

FARRAGON

PIERCE (oil)

GOLDENEYE

BALMORAL

DURWARD

BLANE

BRENDA

GANNET D

COOK

ALDER

HERON

MEDWIN

AUK NORTH

GANNET C MADOES

IONA

RENEE

CALLANISH

CAWDOR

HIGHLANDER

BACCHUS

CLAPHAM

GANNET F

SALTIRE

MARNOCK-SKUA (cond)

SHELLEY

FULMAR

STARLING

TWEEDSMUIR SOUTH

CAYLEYMALLARD

HUNTINGTON

MERGANSER

DAUNTLESS

HAWKINS

LEVEN

DUART

JANICE

BIRCH

HALLEY

LOCHRANZA

CATCHER

MIRREN

KITTIWAKE

MILLER

MACCULLOCH

INNES

GANNET B

TIFFANY

TEAL

WOOD

BLAIRGLAMIS

GUILLEMOT A

CHESTNUT

DRAKE

SYCAMORE

RUBIE

SCOTER (gas)

GANNET E

TWEEDSMUIR

BURGMAN

GALIA

MAULE

BLENHEIM

CURLEW C

BITTERN (oil)

MOIRA

SEYMOUR

GADWALL

TONTO

NICOL

BRECHIN

GROUSE

ANGUS

MONAN

ROB ROY

ARKWRIGHT

CARNOUSTIE

CHANTER

STIRLING

SAXON

MARNOCK-SKUA (oil)

GLENELG

ENOCHDHU

TEAL SOUTH GANNET G

IVANHOE

HANNAY

BALLOCH

GUILLEMOT NORTHGUILLEMOT NORTH WEST

EGRET

SCOLTY

JAMES

PIERCE (gas)

BLADON

VARADERO

BARDOLINO

BEAULY

CRATHES

PIERCE (gas)

PETRONELLA

GOOSANDER

BITTERN (gas)

NETHAN

BRIMMOND

HAMISH

SCOTER (oil)

FLORA3°E

3°E

2°E

2°E

1°E

1°E

0°

0°

58°N

58°N

57°N

57°N

Esri, DeLorme, GEBCO, NOAA NGDC, and other contributors

0 20 4010 Miles

0 30 6015 Kilometres

1:300,000

Coordinate System: ED 1950 UTM Zone 31N

Date: 07/10/2016

Contains Data from ESRI, CDA, NPD, TNO and OGA© Crown copyright 2016. You may re-use this information (not including logos) free of charge in any format or medium, under theterms of the Open Government Licence. To view this licence, visit http://www.nationalarchives.gov.uk/doc/open-government-licence/version/3/ or write to the Information Policy Team, The National Archives, Kew, London TW9 4DU, or email: [email protected] enquiries regarding this publication should be sent to us at [email protected].

CNS Unsanctioned Discoveries including Small Pools

LegendOGA - Licensed Blocks

Condensate Field

Gas Field

Oil Field

Licensed PoolsCondensate

Gas

Oil

UnLicensed Pools (Gas)P50 recoverable (mmboe)

0 - 10

10 - 20

20 - 30

30 - 50

50<

UnLicensed Pools (Oil)P50 recoverable (mmboe)

0 - 10

10 - 20

20 - 30

30 - 50

PipelinesOil Pipeline

Gas Pipeline

Other Pipeline

Mixed Hydrocarbons Pipeline

Surface/Subsurface Infrastructure" Platform&- FPSO$ Tee Piece# Manifold

Norwegian Discoveries

Norwegian Facilities

OIL

= O

, O&

G

GA

S =

G, G

&O

, GC Scale

Circle Diameter of10 kilometers assumesCloverleaf in Centrewith 5 kilometer ERDin each direction

Figure 24 Central North Sea Small Pools Map (OGA, 2016)21


Terms of Reference

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16/29- 4

16/23- 2

16/22- 2

15/26- 1

15/19- 9

15/07- 1

14/18- 1

14/15- 2

14/14- 1

13/30- 2

13/23- 1

12/25- 4

12/25- 2

22/14b- 3

22/13b- 3

22/13a- 2

22/04b- 6

21/15a- 2

20/03- 2A

16/12b- 6

16/06b- 6 16/06b- 5

16/06a- 8

16/03a- 4

16/02b- 4

15/29a- 9

15/17- 8A

15/17- 26

15/17- 24

13/21b- 7

12/26c- 5

11/24a- 2

22/12a- 1022/11b- 13

16/21b- 34

16/03a- 11

15/21b- 50

15/21b- 45

15/19b- 10

14/26a- 10

12/27- 1

9/23b- 19

22/08a- 2

15/17- 25

14/30a- 2

14/29a- 4

13/22b- 4

9/28b- 19A

16/08c- 13

22/15- 4

22/15- 3

22/04- 3

21/02- 2

21/02- 1

20/08- 2

20/03- 4

16/23- 4

16/22- 5

16/22- 4

16/18- 1

15/30- 5

15/30- 2

15/18- 2

15/13- 2

14/20- 6

12/21- 3

9/28a- 18

21/08- 4Z

21/06b- 8

20/04a- 8

15/27-E1Z

15/26b- 9

15/24a- 4

15/22- 16

15/21a- 7

15/18a- 6

15/12b- 4

14/26b- 5

14/26b- 4

13/29b- 5

13/26a- 2

13/24a- 2

13/23d- 8

13/23b- 5

21/13b- 1A

21/05a- 6Z

16/13a- 2Z

15/23d- 13

15/21b- 47

15/21a- 51

15/21a- 46

15/18b- 11

15/13a- 10

14/20b- 17

13/21a- 1A

20/05a- 10Y

15/27a- 12A

15/25c- 15A

15/21a- 38Z

16

15141312

5

22

6

21

7

20

11

1918

89

17

23

10

203

BRITANNIA

EVEREST

FORTIES

BRAE

ROSS

NELSON

PIPER

MILLER

BUZZARD

SCOTTCAPTAIN

CLAYMORE

TARTAN

ATHENA THELMA

ATLANTIC

BRODGAR

DONAN

ETTRICK

CYRUS

BUCHAN

HOWE

ENOCH

BLAKE

FLEMING

BEATRICE

GOLDEN EAGLE

ALBA

KINNOULL

ROCHELLE

DEVENICK

GALLEY

KINGFISHER

MAUREEN

MARIA

EAST BRAE

SCAPA

BURGHLEY

CALEDONIA

TELFORD

ANDREW

LARCH

TONI

FARRAGON

GOLDENEYE

BALMORAL

BRENDA

ALDER

CRAWFORD

IONA

RENEE

CALLANISH

HIGHLANDER

BACCHUS

WEST BRAE

SALTIRE

SHELLEY

TWEEDSMUIR SOUTH

BEINN

HUNTINGTON

HAWKINS

DUART

CROMARTY

BIRCH

LOCHRANZA

MACCULLOCH

TIFFANY

DAUNTLESS

BLAIRGLAMIS

LYBSTER

DRAKE

CHESTNUT

SYCAMORE

RUBIE

BLACKBIRD

TWEEDSMUIR

MAULE

BLENHEIM

MOIRA

SEYMOUR

BRAEMAR

JACKY

TONTO

NICOL

ROB ROY

CHANTER

STIRLING

ENOCHDHUSOLITAIRE

IVANHOE

HANNAY

BALLOCH

SCOLTY

BLADON

BARDOLINO

BEAULY

CRATHES

PETRONELLA

PEREGRINE

MONTROSE

BRIMMOND

HAMISH

GOOSANDER2°E

2°E

1°E

1°E

0°

0°

1°W

1°W

2°W

2°W

3°W

3°W

59°N

59°N

58°N

58°N


0 25 5012.5 Miles


1:300,000Coordinate System: ED 1950 UTM Zone 30N Date: 07/10/2016

Contains Data from ESRI, CDA, NPD, TNO and OGA© Crown copyright 2016. You may re-use this information (not including logos) free of charge in any format or medium, under the terms of the Open Government Licence. To view this licence, visithttp://www.nationalarchives.gov.uk/doc/open-government-licence/version/3/ or write to the Information Policy Team, The National Archives, Kew, London TW9 4DU, or email: [email protected] enquiries regarding this publication should be sent to us at [email protected].

MFB Unsanctioned Discoveries including Small Pools


Condensate Field

Gas Field

Oil Field


Gas

Oil


0 - 10

10 - 20

20 - 30

30 - 50

50<


0 - 10

10 - 20

20 - 30

30 - 50


Gas Pipeline

Other Pipeline





OIL

= O

, O&

G

GA

S =

G, G

&O

, GC Scale


Figure 25 - Moray Firth Small Pools Map (OGA, 2016)21

29

Terms of Reference


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3/07- 3

3/10b- 1

3/07a- 8

2/05- 10

15/07- 1

3/15a- 14

211/28- 6

211/22- 2

211/22- 1

16/06b- 6 16/06b- 5

16/06a- 8

16/03a- 4

16/02b- 4

9/23a- 30Z

211/28a- 7

211/21- 11

211/08c- 4211/08a- 2

206/10a- 1

206/05a- 3

16/03a- 11

211/23b- 12

211/27e- 13Z

3/25- 1

3/17- 2

9/24b- 3

9/15a- 1

9/10b- 1

9/23b- 19

3/09a- 11

214/30- 1

9/28b- 19A

3/15a- 16Z

16/08c- 13

9/21- 2

9/19- 4

9/19- 3

9/18- 2

9/12- 38/15- 1

4/26- 23/30- 3

3/11- 1

3/04- 7

9/19- 16

9/12b- 6

8/15a- 3

4/26- 1A

3/30a- 4

3/28a- 2

3/19b- 2

9/28a- 18

9/18a- 15

3/11b- 4Z

211/23- 6

208/17- 3

207/01- 3

9/14a- 10Z

211/07a- 2

210/29a- 3

206/04a- 3

210/25c- 6A

210/25a- 11

78 9

6

12 3 4

10

207

211210209208

13 14 15 16

214

206

5

NINIAN

FRIGG

BERYL

BRUCE

BRENT

DUNBAR

BOA

BRAE

RHUM

TERN

HARDING

HEATHER

SKENE

MARINER

MILLER

STATFJORD

LYELL

MAGNUS

NORTH ALWYN

LEADON

DEVENICK

PELICAN

NUGGETS N1

CORMORANT NORTH

BROOM

NEVIS

DON

NORTH WEST HUTTON

KINGFISHER

CHEVIOT

FORVIE

HUTTON

CLADHAN

DUNLIN

EAST BRAE

THISTLE

MURCHISON

PENGUIN EAST

KRAKEN

GLENLIVET

EIDER

ELLON

CRAWFORD

STAFFA

JURA

OSPREY

HUDSON

WEST BRAE

HARRIS

PENGUIN WEST

BEINN

NESS

GRYPHON

NUGGETS N4

WEST DON

OTTER

STRATHSPEY (oil)

DON SOUTH WEST

KESTREL

GRANT

BRAEMAR

SOUTH CORMORANT

MERLIN

STRATHSPEY (cond)

CORMORANT EAST

KEITH

BUCKLAND

MORRONE

ISLAY

DEVERON

FALCON

NUGGETS N2

BARRA

MACLURE

MAGNUS SOUTH

PLAYFAIR

NUGGETS N3

CAUSEWAY

CONRIE

ORLANDO

KRAKEN NORTH

LINNHE

DUNLIN SOUTH WEST

LOIRSTON

FIONN

BARNACLE

2°E

2°E

1°E

1°E

0°

0°

1°W

1°W2°W

61°N

61°N

60°N

60°N

59°N

59°N


0 25 5012.5 Miles


1:350,000


Date: 07/10/2016


NNS Unsanctioned Discoveries including Small Pools


Condensate Field

Gas Field

Oil Field


Gas

Oil


0 - 10

10 - 20

20 - 30

30 - 50

50<


0 - 10

10 - 20

20 - 30

30 - 50


Gas Pipeline

Other Pipeline





OIL

= O

, O&

G

GA

S =

G, G

&O

, GC Scale


Figure 26 - Northern North Sea Small Pools Map (OGA, 2016)21

30

Terms of Reference


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"

"

"

"

"

"

"

"

"

"

53/01- 3

49/28- 2

49/02- 4

44/28- 3

44/17- 2

43/27- 2

43/23- 1

43/17- 2

43/16- 2

49/26- 29

49/21- 9Z

49/18- 5Z49/16- 15

49/11a- 9

49/09a- 5

49/08c- 4

49/08b- 3

48/24b- 2

48/24a- 3

48/24a- 1

48/20b- 6

48/16b- 2

48/08a- 1

48/01- 2A

47/15b- 5

44/28d- 5

44/28a- 6

44/17a- 5

44/16- 1Z

43/21b- 5

43/20b- 2

41/25a- 1

53/01a- 13

48/15b- 10

48/11c- 13

48/11a- 12

47/14b- 11

44/19b- 7A

43/26b- 10

49/03- 3

48/23- 3

48/22- 4

48/02- 1

47/10- 8

47/03- 2

44/28- 4

44/27- 1

44/19- 344/16- 3

43/18- 1

42/29- 742/29- 6

42/22- 1

41/20- 2

54/01b- 6

50/26b- 6

49/22- 17

49/22- 16

49/21- 8A

49/17- 15

48/25b- 5

48/22b- 6

48/22b- 5

48/18a- 4

48/17b- 3

48/02b- 3

47/05d- 6

44/19a- 8

42/15b- 1

42/15a- 2

41/24a- 1

53/05a- 8Z53/02a- 15

49/21- 10A

48/12e- 11

48/12c- 10

43/25a- 2W

43/13b- 6Z

42/10b- 2Z

4748 49

4243 44

51 52 53

41

45

50

46

O54

383736 3935

LEMAN

CYGNUS

HEWETT

BREAGH

RAVENSPURN

BARQUE

ORCA

GALLEON

KETCH

ANN

AUDREY

VULCAN

BOULTON

WINGATE

WEST SOLE

MARKHAM

MINKE

CARRACKENSIGN

TRENT

AMETHYST EAST

GORDON

CHISWICK

YORK

PICKERILL

SATURN

GROVE

WATT

ANGLIA

HYDE

KELVIN

ESMOND

SKIFF

MERCURY

KATY

CERES

KILMAR

MUNRO

KEW

CAVENDISHHAWKSLEY

ERISROUGH

RITA

JULIET

INDEFATIGABLE

SCHOONER

VICTOR

MURDOCH

AMETHYST WEST

RAVERNSPURN SOUTH

NEWSHAM

CLEETON

TETHYS

TOPAZ

CLIPPER NORTH

MINERVA

SOUTH SEAN

GARROW

EXCALIBUR

NORTH VALIANT

VIKING B

NORTH SEAN

FORBES

CUTTER

HOTON

BABBAGE

JOHNSTON

VIKING A

APOLLO

LANCELOT

ARTHUR

MIMAS

CLIPPER SOUTH

MCADAM

GAWAIN

CARAVEL

DELILAH

TYNE SOUTH

EUROPA

SHAMROCK

MORDRED

TYNE NORTH

BELL

DAVY

ORWELL

GUINEVERE

GALAHAD

HUNTER

ALISON

SINOPE

VISCOUNT

HELVELLYN

VIKING E

ARTEMIS

CAISTER CARBONIFEROUS

BURE

THAMES

WAVENEY

YARE

VIKING C

WENLOCK

BIG DOTTY

ROSE

NEPTUNE

DURANGO

VANGUARD

DEBORAH

WHITTLE

GANYMEDE

SEVEN SEAS

VIXEN

SOUTH VALIANT

WINDERMERE

VICTORIA

HORNE

STAMFORD

MALORY

BESSEMER

DELLA

BRIGANTINE C

CAISTER BUNTER

VIKING D

LEMAN SOUTH

INDEFATIGABLE SOUTH WEST

CORVETTE

WOLLASTON

CALLISTO

BRIGANTINE A

DEBEN

THURNE

WELLAND NORTH WEST

WISSEY

BOYLETRISTAN NORTH WEST

ABERDONIA

CAMELOT CENTRAL SOUTH

EAST SEAN

DAVY EAST

VAMPIREVALKYRIE

BAIRD

WREN

DAWN

LITTLE DOTTY

TRISTAN BROWN

WELLAND SOUTH

BRIGANTINE B

CAMELOT NORTH EAST

BARQUE SOUTH

NORTH DAVY

CAMELOT NORTH

BEAUFORT

WENSUM

BRIGANTINE D

3°E

3°E

2°E

2°E

1°E

1°E

0°

0°

55°N

55°N

54°N

54°N

53°N

53°N


0 20 4010 Miles


1:300,000


Date: 07/10/2016


SNS Unsanctioned Discoveries including Small Pools


Condensate Field

Gas Field

Oil Field


Gas

Oil


0 - 10

10 - 20

20 - 30

30 - 50

50<


0 - 10

10 - 20

20 - 30

30 - 50


Gas Pipeline

Other Pipeline



OIL

= O

, O&

G

GA

S =

G, G

&O

, GC Scale


Figure 27- Sothern North Sea Small Pools Map (OGA, 2016)21

31

Terms of Reference


Figure 28- Installing Temporary Guide Base

Tensioners

Drillpipe

Guidewires

Sea Level

Rig Floor

J-Slot RunningTool

Temporary GuideBase

52 in. OuterConductor

Optionally,Drill 56 in.Hole prior toLanding Temp.Guide Base

Installation Sequence

For those unfamiliar with subsea well operations, Figures 28 through 35 describe the installation process for Oilfield Innovations “Cloverleaf” new well technology.

Temporary Guide Base

Subsea operations generally begin with running of the tem-porary guide base through which the initial top hole section is drilled.

As depicted in Figure 28, the temporary guide base is run on drill pipe and landed on the sea bed to establish guide lines after the running tool is pulled back to surface.

32

Terms of Reference


Utility Guideframe

24" PilotDrillbit

50" Hole

Rig Floor

Sea Level

Opener

Figure 29- Drilling 52” Hole

50” Hole Section

As illustrated in Figure 29, a utility frame at-tached to the guide wires is used to stab the drill-ing assembly into the temporary guide base.

In this instance a 24 inch pilot bit and 50 inch hole opener is used to drill the initial top hole sec-tion through the 52 inch outer conductor jetted in with the temporary guide base as shown in Figure 28.

33

Terms of Reference


PermanentGuidebase

3 ea. 20" Casing

3 ea. SnapConnectors

(Merlin)


(Merlin)


(Merlin)

CloverleafWhipstockTechnology

RunningTool

Drill Pipe

ConventionalWellheadConnector


3 ea. ConventionalCasings

Cemented

Figure 30- Running Permanent Guide Base and 48” Cloverleaf Multi-Well Conductor

Cloverleaf Whipstock Installation

Figure 30 shows installation of the permanent guide base on the guide wires followed by running casing equipment through the guide base.

Merlin™ snap connectors can be used to run a bundle of three 20 inch casings through the permanent guide base at the same time.

A bundle of three conventional casing hangers at the bot-tom of the Cloverleaf Whipstock can then be snapped onto the 20 inch casings.

A running tool is then attached to the conventional subsea wellhead at the top of the Cloverleaf Whipstock and the per-manent guide base and casing are run into the hole and landed in the temporary guide base.

The entire assembly is then cemented within the open hole.

34

Terms of Reference


PermanentGuidebase

48” VerticalSeparatorHousing

48” Coupling SeparatorPiping

3 ea. CasingShoe

CloverleafWhipstock

Technology

ConventionalCasing Hanger

System

RunningTool

Drill Pipe

ConventionalWellhead

Connector

Separator PipingExternal toWell Annulus

48” VerticalSeparatorHousingTop Joint

Cemented

Figure 31- Running Permanent Guide Base and 48” Cloverleaf with 48” Vertical Separator

Installing Cloverleaf and Separator

Figure 31 illustrates installation of the permanent guide base on the guide wires followed by running casing equip-ment through the guide base.

An assembly with three drill out casing shoes is attached to a 48 inch vertical separator housing run through the guide base. Further 48 inch joints are screwed together using, for example, XLW™ connectors shown in Figure 38 and run in the hole through the permanent guide base.

Once the desired length of 48” pipe for the vertical sep-arator has been run, internal separator piping and guides are run using a false rotary table for make-up of the separator’s internal piping.

Three conventional casing hanger conduits and the Clo-verleaf Whipstock are attached to the top joint of the vertical separator with separator piping strapped eternally.

A running tool is then attached to the conventional subsea wellhead at the top of the Cloverleaf Whipstock and the per-manent guide base and casing are run into the hole and landed in the temporary guide base.

The entire assembly is then cemented within the open hole.

35

Terms of Reference


Bell Nipple

Floating Drilling Rig

MarineRiser

RiserTensioners Telescopic

Joint

FlexJoint

HydraulicLatch

GuideframeBlowout

Preventers

LowerMarine

RiserPackage

Figure 32- Running BOPs on Floating Rig

Floater BOPs and Drilling Operations

Figure 32 depicts the installation of a floating drilling rig’s blowout preventers (BOPs) onto the 18 ¾” subsea wellhead.

All equipment is sized for passage through the standard 18 ¾ inch BOP and wellhead internal diameter, whereby the Cloverleaf whipstock is retrieved, rotated and re-in-serted through the BOPs to access each of the wells below the Cloverleaf assembly.

With the exception of pulling, rotating and re-inserting the bore selector whipstock, drilling operations continue as they would during any other batch operations.



Floating Drilling Rig

MarineRiser

TelescopicJoint

FlexJoint

Guideframe

SubseaTree

Bell Nipple

RiserTensioners

Hydraulic

BlowoutPreventers

LowerMarine

RiserPackage

Latch

Figure 33- Running Tree on Floating Rig

Floater BOPs and Completion Operations

Figure 33 shows the installation of a floating drill-ing rig’s blowout preventers (BOPs) on top of the subsea production tree during completion operations.

Either a vertical or horizontal subsea tree can be used.

All completion equipment is sized for passage through the standard 18 ¾ inch BOP and subsea tree, whereby the Cloverleaf whipstock is used to run the completion strings for each of the wells.

The completion strings are hung-off within the Cloverleaf arrangement until all of the completions strings have been run into each well. The rotatable whipstock is then removed and each of the comple-tion strings is lifted and connected to a centralised bundle where control lines and cables are connected, tested and then landed in the wellhead before setting the production packers or, alternatively, using con-ventional mandrels stabbed into polished bore recep-tacles (PBRs) attached to the top of each pre-set pro-duction packer.

The subsea completion arrangement and trees would be similar to conventional conductor sharing arrangements, which would require design assistance from a qualified vendor.



HydraulicLatch

Guideframe

BlowoutPreventers

Bell Nipple

Marine Riser

Texas Deck

Jack-up Drilling Rig

Figure 34- Running BOPs on Jack-Up Rig

Jack-up BOPs and Drilling Operations

Figure 34 depicts the installation of a jack-up drilling rig’s blowout preventers (BOPs) onto a high pressure riser attached to the 18 ¾” subsea wellhead with a conventional connector.

Many newer jack-ups have begun using 18 ¾ inch BOPs that are suited to such operations.

All equipment is sized for passage through the standard 18 ¾ inch BOP and wellhead internal diam-eter, whereby the Cloverleaf whipstock is retrieved, rotated and re-inserted through the BOPs to access each of the wells below the Cloverleaf assembly.

With the exception of pulling, rotating and re-in-serting the bore selector whipstock, drilling opera-tions continue as they would during any other batch operations.

38

Terms of Reference


Hydraulic

SubseaTree

Latch

Guideframe

HydraulicLatch

BlowoutPreventers

Bell Nipple

Marine Riser

Texas Deck

Jack-up Drilling Rig

Figure 35- Running Tree on Jack-Up Rig

Jackup BOPs and Completion Operations

Figure 35 shows the installation of a jack-up drilling rig’s blowout preventers (BOPs) on top of the subsea production tree during completion operations.

Either a vertical or horizontal subsea tree can be used.

All completion equipment is sized for passage through the standard 18 ¾ inch BOP and subsea tree, used by newer jack-up drilling rigs, whereby the Clo-verleaf whipstock is used to run the completion strings for each of the wells.

The completion strings are hung-off within the Clo-verleaf arrangement until all of the completions strings have been run into each well. The rotatable whipstock is then removed and each of the completion strings is lifted and connected to a centralised bundle where control lines and cables are connected, tested and then landed in the wellhead before setting the production packers or, alternatively, using conventional mandrels stabbed into polished bore receptacles (PBRs) attached to the top of each pre-set production packer.

The subsea completion arrangement and trees would be similar to conventional conductor sharing arrange-ments, which would require design assistance from a qualified vendor.

39

Terms of Reference


Figure 36- How a Bicentre Bit Works (Varel®, 2017)29

BitCenter

CasingCenter

No ContactOn Cutters

Bit & WellboreCenter

Drilling withCenter Cutters

Bi-Center Running Inside the Casing Bi-Center Drilling in Formation

CasingCenter

BitCenter

Bit & WellboreCenter

Coiled tubing

Wireline or slickline

Controlumbilical

WellIntervention

Package

ROV umbilical

ROV tether

Guidelines

Coiled tubing,slickline or

wireline

Subsea wellhead

Subsea BOP

ROV

Figure 37- Rigless Light Well Intervention Vessel (LWIV) Equipment (Schlumberger)

Bi-centre Bits

Figure 36 illustrates how a bi-centre bit can drill a larger diameter hole than the casing through which it passes.

Bi-centre bits are an example of how open sourcing new technology can be used to introduce new technology.

Light Well Intervention Vessels

Figure 37 depicts a Light Well Intervention Vessel (LWIV) which can be used to intervene in subsea wells after production has started.

Oilfield Innovations’ Cloverleaf technology is compatible with LWIV opera-tions and can be used in instances where commingled flow from multiple wells in amalgamated into a single flow stream downhole or, alternatively, where multiple production strings are passed through the wellhead to separate production trees that are commingled after passing through the production choke manifold.

40

Terms of Reference


Features Benefits

Connector ratings meet or exceed full pipe body strength

Reliable performance under extreme loading conditions

Integral lift shoulder

Internal metal seal Reliable pressure integrity

Wedge thread technology Easy spin-up, high torque capacity, excellent resistance to anti-rotation

XLW™ CONNECTORSPipe-to-Connector Weld

PIN

PIPE

Wedge ThreadNarrow thread near the connector end face and wider thread near the connector back shoulder

Dovetail Thread Shape

Thread Fit SealClose tolerance thread design creates a secondary

Metal SealInternal metal-to-metal pressure seal

Integral Pin Thread

Integral Lift Shoulder

Weld-on Box

BOX

48” OD

49.25” OD 5100-psi (X80 1.75” Wall Thickness)5830-psi (X80 2” Wall Thickness)6560-psi (X80 2.25“ Wall Thickness)7290-psi (X80 2.5” Wall Thickness)

Figure 38- XLW® 48” Pipe Connector (XL Systems, 2017)31

Example Conductor Coupling

Figure 38 illustrates an XL Systems™ proprietary connec-tor that is capable of being used within a Cloverleaf down-hole separator arrangement.