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contents GUEST COLUMN Paying Hefty Price for Being Transit Nation VOL. 10 NO. 3 APRIL – MAY 2013 MUMBAI ` 150

- Prof Jenik Radon

OFFSHORE WORLD R.NO. MAH ENG/ 2003/13269 Chairman Publisher & Printer Chief Executive Officer

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Paying Hefty Price for Being Transit Nation

Jenik Radon, Esq. Adjunct Professor, Columbia University, School of International and Public Affairs

Energy is an integral part of human being. Energy in the form of oil and gas is carried through the means of pipelines from producing nation to its destination ultimately the market. Transit nations from where pipelines are passing have to bear the burnt of environment pollution, challenges the residents who are dislocated from their places to make way for the construction of these pipelines. The author says that the cost transit nations pay is much more than they earn from laying off of these cross-border pipelines. www.oswindia.com

Junik Radon 6-10.indd 6

Pipelines are the roadways of the oil and gas industries. Pipelines deliver needed and wanted energy from producing areas, including from places not commonly heard of, whether from the fields of Hassi R’mel or Kirkuk, to industry, to homes and, simply put, to the market, both domestic (national) and international markets. But, internationally, until Russia, in a 2005-06 headline grabbing fight with Ukraine over transit fees and increased gas prices, stopped sending gas through pipelines in the Ukraine to the nations of Europe, no one really paid much attention to pipelines or transit nations, let alone their concerns or what it meant to be a transit nation. The continued operation of pipelines, even across borders, was taken for granted, as given, and potential international political problems and social challenges were until then ignored.

As is illustrated, for example, by the freedom of transit principle set forth in, and the other provisions of, the Energy Charter Treaty, adopted in 1994, crossborder or transit pipelines are there to transport an uninterrupted flow of energy in order to satisfy the needs and demands of consumers for energy, as well as that of the producers of energy. No one can argue with the fundamentals of the principle of freedom of transit. However, the Treaty also calls for cost-based transit tariff pricing. The conclusion from that is clear: transit tariffs, the fees charged by nations through which a pipeline crosses, are not to be guided by the free market principle of profit-making, notwithstanding, among other things, that transit nations will bear the cost of, and the stress caused by, the dislocation of residents whose property has to be used for the construction of a pipeline, the damage from any environmental pollution, and the challenges of other risks, such as security, in order to make possible the transport of oil and gas or energy from producing nations to consuming nations.

Energy ignites the imagination as well the emotions, especially economic and political emotions. The reason is simple. Energy is a necessary good. Energy, as we so well know, literally lights up our homes, makes it possible for students to read at school and at home, and drives our factories. Energy powers such megacities as New York, London and Tokyo, which are so vibrant at night and therefore brightly so lit that they can be seen from space. The world simply cannot do without energy; and since we cannot do without it, we demand it and we expect its flow to be uninterrupted.

Moreover, international energy companies (IOCs) are the darlings of Wall Street and the finance world with Exxon/Mobil, Shell and other IOCs composing six to seven of the top 10 firms in the world by revenue and also by profits. They are clearly handsomely rewarded for producing energy and bringing it to market from literally around the world. Energy rich nations, such as Norway, Saudi Arabia and Qatar, which have direct access to the energy consuming markets of Europe and the rest of the world, have achieved high GNPs per capita and continue to save their substantial earnings from the sale of oil and gas in sovereign wealth funds, which will provide financial support for future generations. But other resource rich, and comparably well endowed, nations, such as Russia, Azerbaijan, Algeria and Iraq, seeking to achieve similar economic success, are dependent, at least in part, on pipelines, mostly gas pipelines, that have to cross the transit nations of Ukraine, Georgia, Morocco and Turkey, respectively, in order to bring their oil and gas to the world markets. This requires the negotiation of complex inter- government agreements between producing nations and transit nations, as well as host government agreements between energy companies and transit nations, to establish the transit fees to be paid to them as well as the other terms of transit.

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But in the course of such negotiation, an age-old truism is too readily forgotten by the producing nations, namely that one is only as strong as the weakest link, which, in this context, potentially means the transit nation.

The logical consequence or implication of that saying is that nations which voluntarily open their borders for the construction and operation of transit pipelines need to benefit and be compensated for their contribution. In market terms, these nations need to make a profit as they provide the use of a valuable asset.

In real estate lingo, transit nations in fact have three very valuable assets: location, location and location.

They serve as the indispensible link in the supply chain between energy rich nations, especially those that are effectively land-locked, and the world’s energy market. But surprisingly, the critical location of transit nations has not translated into significant economic rewards or benefits for them.

In the case of the BTC (Baku-Tbilisi-Ceyhan) oil pipeline, for example, Georgia receives on average a maximum of $62 million per annum for the transit rights. The South Caucasus gas pipeline, also known as the Baku–Tbilisi–Erzurum Pipeline, pays Georgia 5% of the shipped volume. For having the Maghreb– Europe Gas Pipeline cross its territory from Algeria to Spain, Morocco receives a 7% transit fee which is paid in gas. But if significant fees are not the reward for the transit nations, what is?

>>According to Energy Charter Treaty, cross-border or transit pipelines are there to transport an uninterrupted flow of energy in order to satisfy the needs and demands of consumers for energy, as well as that of the producers of energy.

The Treaty also calls for cost-based transit tariff pricing.

Energy pipelines it is said, especially by the international (consuming) community, serve and benefit the common good, as the pipelines are the enablers for the supply of power and light, albeit to the consuming nations, and therefore serve as motors of and for the economy, albeit again their economy. This is certainly true at a general level.

Still, when pipelines stretch across borders, a number of questions need to be addressed, and answered, as it is not obvious that the common good is universal, a good shared by all: what constitutes the common good; what is the cost of achieving the common good; who bears the cost of such achievement; who bears the cost of maintaining this achievement; and who, in fact, actually benefit from these pipelines and who does not. The list of questions goes on. Reasonable people can reasonably differ on the answers, but reasonable people cannot, and should not, avoid asking these questions. And they need answers which are openly discussed and debated.

Even in the United States, which does not historically view itself as a transit nation, people are now asking those questions in respect of the prospective and controversial Keystone XL pipeline project which is to designed to bring tar sand oil from Alberta,

Canada to refineries in Houston, Texas. The Keystone project, given the controversy that surrounds it, still awaits US government approval for the pipeline to cross the US - Canadian border.

Some Texans, for example, are asking whether a one -time, one - off, payment for the taking/ use of their property for the Keystone pipeline is adequate compensation, especially taking into the consideration the fact that the pipeline will remain a permanent obstruction or fixture on their property and pose a permanent environmental threat as pipelines are known to fracture and therefore spill.

Is a one-time payment, as distinguished from a share of future profits from the project, adequate compensation for their sacrifice? Some are also questioning, and going to court to support their questioning, whether the power of eminent domain, which is traditionally associated with the taking of property for a generally and traditionally accepted public purpose, such as a school, a hospital or police station, should be used to further or support profitmaking economic or commercial activities such as the Keystone pipeline project.

Th e p i p e l i n e w i l l b e o w n e d b y Tra n s Ca n a d a Corporation, which has $48 billion dollars in assets and is registered on the Toronto and New York stock exchanges. Privately owned refineries in Houston will refine and market the shipped or transported oil. In other words, is a profit-making activity, even if it brings employment for some, a public purpose? Lawsuits questioning whether such a pipeline should be considered a common carrier, such as a telephone line, and have the statutory support of eminent domain, have been filed in the state of Texas.

If the power of eminent domain is not available, directly or indirectly, to a company to secure necessary rights of way for the construction of a pipeline, it is argued that private proper t y owners could effectively thwar t the pipeline’s construction and thereby, among other things, hinder the achievement of energy security for the

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US, notwithstanding that the oil, as noted below is to be sold in the open market, which includes, but is not limited to, the United States. Such owners could simply refuse to make their land available for the pipeline, irrespective of the amount of compensation offered. This could theoretically make the construction of the pipeline impossible, and, in any event, more expensive and certainly delay or extend the time necessary for construction.

M a ny o t h e r s a re a s k i n g w h e t h e r t h e r i s k o f environmental contamination or pollution from an accidental oil spill, or a negligent one, is wor th any compensation, not to mention the intense controversy concerning the potential environmental impact of the development of the Canadian tar sand oil fields themselves, which is not even within the jurisdiction of the United States to determine. Others have raised the issue of whether permitting the export of the refined tar sands oil from Houston refineries is in the US national interest since permitting such export will not improve US energy security.

In short, the overriding question that is being asked is whether it is in the national interest of the US to be simply a transit nation for Canadian tar sands oil, ironically without even charging transit fees? The specific question is what benefits are there in fact for the US and also for its citizens who are directly impacted by the construction of the pipeline?

Interestingly, the questions being raised by civil society in the US are in essence the same that every transit nation must address in considering a transit pipeline. What are the benefits for the nation, as well as for the people impacted by a transit pipeline, and what are the costs, which, after construction, invariably could be environmental costs, especially if there is ever a spill or explosion? In the case of Georgia, the BTC pipeline is constructed through a number of ear thquake faults and skir ts the Borjomi fresh water basin of Georgia. The threat of environmental damage is therefore ever present.

In addition to environmental damage, there are other potential costs for transit nations. People normally have to be relocated to permit pipeline construction with the consequence that their lives will have to be disrupted in order to achieve what www.oswindia.com

Junik Radon 6-10.indd 10

has been politically declared a greater national good.

What is fair and adequate compensation for people who have to be relocated or otherwise impacted, which question is exacerbated when the transported natural resource is not even a domestic resource?

transit nation as a whole, and its citizens who are impacted by the pipeline, do not adequately, and one can even say handsomely, benefit, the transit nation will potentially be a weak link in the energy supply chain.

Moreover, the energy pipelines in many parts of the world have become a magnet for terrorist action. This is true, for example, in the case of the Iraq-Turkish pipelines. Also when a pipeline from Iraq to Turkey is bombed, Turkey must endure negative press from around the world questioning its security practices.

The cost of security, of protecting, these pipelines, must therefore be taken into account and factored in, not to mention the cost in manpower and of lost and disrupted lives.

One can only speculate if Georgia had received p i p e l i n e t ra n s i t f e e s i n a m o u nt s t h at co u l d significantly suppor t the cost of government operations and contribute to powering its economy, would Georgia have been incentivised to focus more on diplomacy in settling its disagreements with Russia and thereby avoid the devastating 2008 war.

Although Nigeria is not a pipeline transit nation, it does stand as an example of the principle that national energy extraction and development, as

>> The logical consequence is that nations which voluntarily open their borders for the construction and operation of transit pipelines need to benefit and be compensated for their contribution. In market terms, these nations need to make a profit as they provide the use of a valuable asset.

The reward for Turkey in having such pipelines has clearly been political. Turkey is achieving its strategic vision by becoming an important energy hub for Europe, which may yet be Turkey’s ticket to EU membership, assuming, of course, that Turkey still wants membership. Also Turkey has benefited co m m e rc i a l l y a n d e co n o m i c a l l y f ro m t h o s e pipelines, as well as the prospective pipelines from Kurdistan region of Iraq, as Turkey has successes in securing energy for its industries and developing a refinery industry.

The general assessment, by applying a cost-benefit approach, is that Turkey benefits politically and economically from being a pipeline transit nation.

But such success has only been achieved as a result of a well thought out strategy, over time and though perseverance. And such success was never assured and has not come without cost.

It is important to realize, acknowledge and respect the fact that a transit nation bears costs, and often considerable costs, by accommodating the construction and the operation of a transit pipeline within its borders. Another nation, the producing nation, will earn the preponderance of the profits in the development of its oil and/or gas fields. If the

well as the construction and maintenance of the ancillary pipelines, require societal acceptance, a social license, to operate.

In other words, a society, including especially the impacted communities, must benefit from the sacrifices they are asked to make for a greater public or common good. They must also feel they have “ownership,” in the philosophical sense, of the projects that impact them. The concept of ownership of course needs clear articulation, even more so in the case, where the overwhelming benefits of a project, such as a transit pipeline, are outside of one’s own country.

Transit nations can only successfully function as such if they, and their citizens, become better off for, benefit by, being a transit nation. Transit nations should not be viewed as merely a means to an end, the closing of a link in the energy supply chain. Transit nations, and their citizens, should be recognized for their sacrifices, respected for their contribution, and both acknowledged and accepted as integral partners in the energy supply chain. A sustainable deal, which in the case of a pipeline needs to last a lifetime, requires such benefit as sw well as such respect.

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guest column

Putting a TAB on Cost

Dr M R Srinivasan Professor, Department of Petroleum Engineering & Geosciences University of Petroleum and Energy Studies

Developing a hydrocarbon field needs mainly four types of costs: 1. Exploration Costs: The cost involved for seismic, geophysical surveys, and geological interpretation, exploration, drilling costs, etc.

2. Investment Costs: This cost consists of delineation and appraised costs necessary to gain knowledge of reservoir.

3. Development Costs: This cost involved of drilling of producer, injector wells, construction of surface installation collection network, separator, treatment, storage, etc.

4. Operating Costs: The cost is mainly happened during the operation of the facilities etc which produces and treats hydrocarbon field.

The weightage of these costs may differ from project to project depending upon the nature of reservoir fluids, environment etc. Therefore, the cost re d u c t i o n / co s t co nt ro l s t rate g i e s m ay a l s o differ accordingly.

COST CONTROLLING STRATEGIES IN OPERATING COSTS Operating costs is the cost which is spent during the operation of facilities to produce and treat hydrocarbon fields. The paper elaborates the cost control strategies of operating costs.

The costs in developing an oil field vary from project to project d e p e n d i n g u p o n i t s n at u re o f reservoir fluids and environment, this paper discusses some of the cost reduction and cost controlling strategies on developing gas field….

Generally it is termed as Opex, related to operation of any plant/units etc.

• Two thirds of Opex - Consisting and major costs • General support by the Company - 20% of total.

• Well surface Ops. - 15% each • Maintenance & Logic - 15% each • Personnel Costs - Larger % of total; Balance include Contracts Purchase & services.

Remaining one third of expenditure like Inspection, Security, Work overs and new works. Accounts for 15-8 per cent of total Costs.

As a matter of Principle, tight control over operating costs to have a rigorous initiatives budding from conceptual studies i.e. development architecture & operating philosophy are selected. Below are the steps: • A specific emphasis is to be given on operating philosophy since it has a direct impact on Personnel costs to optimise the work force. When units are being conceived.

• To control Opex during the operations, they are categorised into main, secondary, equipment, components etc.

• A system of recording expenditure with automated procedures is to be in place.

• Application of ‘Value engineering‘ principles in some of the areas in Opex do results in considerable savings.

• Personnel Costs: Simplify Org. struc ture, Mechanise, Automate or subcontract.

• Ch e m i c a l s co n s u m p t i o n : Q u a l i t y, c h a rg e supplier process.

Exploration Cost

Cost to Investment

Develop

Operating

Cost

Hydrocarbon

Cost

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•

Field

Development Cost

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• •

Use of Spares: Analysing parameters, methodological analysis.

Storage Costs: Purchase and stocking policy, standardisation.

VALUE ENGINEERING APPLICATION In one of the Gas Processing Plants, the moisture adsorbant chemical Molecular sieve (Mol.seive) was being used. This was employed to adsorb the moisture content in (Hydrocarbon) H.C. gas before it was sent to the cryogenic unit for liquefaction and fractionating Products.

These Molecular sieves are used in two towers, which contain about 20 tonnes in each of these towers. They are required to be changed ever y two years.

The Plant was shut down for about 15 days for replacement of mol.sieves. It costs not only the cost of mol. Sieve of ` 1.0 Lakhs per tonne, but also indirect loss of revenue due to shut down for 15 days and Mobilising the equibments for this job of replacement. Otherwise in the normal plant life, a planned shutdown of the entire Processing unit used to be taken up not only for replacing the Mol. sieve but also to overhaul of all the machinery and Pr vessels.

A concept was initiated as why not to club the two yearly shut down for Mol. Sieve replacement with the four year scheduled/planned shut down of the plant. A suggestion for installing one more dryer with Mol.seive was conceptualised which prolonged the failure / replacement of the Mol.sieve and hence the replacement was done along with the total plant turn around shut down every four years instead of every two years saving the cost of Mol. sieve, direct loss of revenue & additional cost of executing the replacement of Mol.sieve ever y two years.

REVIEW OF TECHNICAL COSTS & ADOPT LATEST TECHNOLOGY • Similarly the review of technical costs and adopting the latest technology enhance cost reduction to quote few examples use of – and interpretation – to reduce the no. of exploration wells cost for estimation of reserves and optimal positioning of wells to lines the need of further deli. www.oswindia.com

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•

•

In drilling instead of si well drilled from a well site, 10 to 12 wells from a ‘Well Pad’ is to be done to reduce the land acquisition cost, Rig cost, etc.

Use of digital Process Control system, Higher performance communication network, Light weight turbine for Power generation, variable speed electronic drive and soft staters etc for electrical equipments.

• •

• COST CONTROL STRATEGY IN DRILLING Three areas of concerns dominate the cost control in drilling, viz: 1. Sensitive issue of maintain weight of Drilling Fluid or mud.

2. Low temperature creating problems of Rheology of mud.

3. Presence of required drilling riser heavy and in off shore, adopting the latest technology, like casing while drilling, Drilling with auto riser and under balanced drilling etc.

• • •

•

Practices, availability of equipments and an acceptable rise level.

Equipment selection with emphasis on reliability and maintainability.

Operating Stage:- Outsource total/par t of operating management functions optimized maintenance and Major maintenance with respect to the residual life of project Renegotiating contracts with respects to its competitors, skills required etc Cost control strategy by inhibiting risk awareness.

B oth increase/ maintain produc tion and controlling /reducing costs.

Innovating the processes led to shedding of conservation in H.C. industry .This led to even, a creation of new and additional reserves. But innovation involves risk less/more both in terms of financial and creditability.

A glaring example which can be given is the runway success of an multinational E&P company

>> Review of technical costs and adopting latest technology enhance exploration wells cost for estimation of reserves and optimal positioning of wells to lines the need of further deli.

These are able to reduce the cost of drilling until technology line laser drilling, slimhole drilling Air/foam drilling: revolutionise drilling cost reduction.

• Capital cost control strategy:- Cost reduction d u r i n g s c re e n i n g s t u d i e s & c o n c e p t u a l Preliminary dising has to be order of the day.

• Apart from this is to simplify and standardise the equipments, their lay out, which can bring in 25 per cent for construction and supervision and 40 per cent for structures and pipelines.

• Another innovative way is to utilise the human capital to be synergised with the contract/ subcontracting system while awarding contracts for the execution of jobs. Making them as partner instead of a contractor /sub contractor.

This is on the increase with projects getting more into complicity cost control strategy for operating costs.

• Design stage:- As indicated earlier use latest techniques of installation & erection management.

• A simplified control system with requisite instrumentation.

• Minimising the no of redundant. Equipment as standby or Back up. The Robust maintenance

in Rajasthan in funding huge reserve of H.C. While it was a ‘mirage’ for the Indian E&P companies.

RISK APPETITE Earlier the development oppor tunities were technology limited and hence risk taking was fairly low. The present times technological risk taking has become a consequence of commercial decisions taken on the basis of different consideration.

CONCLUSION An overview of the cost control strategy one among the four costs of the field development can yield such results, it is obvious that the Cost Control strategy of the other three costs will also no doubt yields Bumper benefits which has made in the list 10-15 years the entry of both Indian & Multinational and Non-core sw companies taking a bet on the H.C. venture.

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features Well Engineering

Chemistry of Diagenetic Scale Formed Under Simulated Downhole Conditions This paper describes the chemistry of diagenetic materials formed in the laboratory under simulated downhole conditions by allowing the reaction between formation sand, a specific alumina-based proppant, and water at elevated temperature with time. Diagenetic materials so formed were identified under a microscope and analyzed using x-ray diffraction (XRD) for chemical composition.

The concept of diagenesis within proppant packs, also known as proppant scaling, has been a matter of discussion since the process was initially described. The term diagenesis refers to physical and chemical changes to formation material and an alumina based proppant material when subjected to elevated temperature and pressure when water is present to act as a solvent. Diagenetic processes comprise the initial dissolution of material, fluid saturation, and finally precipitation of the most stable mineral species.

The rate of these processes is primarily controlled by the temperature of the system with the rate being very slow at low temperature but increasing rapidly at elevated temperature (Ref – 1).

The temperature of any formation generally correlates with burial depth and so these diagenetic processes become more pronounced and more economically important in the deeper, hotter wells. The final result of the diagenetic process is proppant pack weakening through partial dissolution of the grains and deposition of new material within the proppant pack. Both developments result in the loss of proppant pack integrity and conductivity (Ref – 2). Both result in restriction on the rate of production and concurrent detrimental well economics.

In this paper we present the results of an X-ray diffraction (XRD) study probing the identity of the diagenetic precipitates that form within both the proppant pack and the surrounding formation. Conventional wisdom initially suggested that these precipitates might be similar to those observed in natural sandstone formation processes. These processes generally involve the dissolution of complex silicate minerals such as feldspar and detrital clays. The precipitated species are most commonly authigenic clays, secondary quartz and occasionally feldspars.

The availability of a ready source of aluminum in the form of alumina based proppant alters the chemistry of the saturated solution within the proppant pack and results in the precipitation of zeolite species. Zeolites are complex silicates compositionally similar to clays and feldspars but are structurally unique. Previous elemental scans (EDXRF) of the diagenetic material during scanning electron microscopy (SEM) work suggested various compositions of

sodium aluminum silicate, potassium aluminum silicate, and calcium aluminum silicate. Our XRD work is in agreement with these previous results. Our data is also supported by inductively coupled plasma (ICP) analysis of water taken from the reaction cells after the diagenesis process.

LABORATORY APPLICATION The tests were conducted in cells containing chips of low permeability sandstone formation, alumina based proppant and de-ionized water. The cells were held at elevated temperature without any applied closure pressure for a period of 30 days for tubes 1 & 2 and 60 days for tubes 3 & 4. These conditions were set to match expected downhole conditions for a deep hot well with the exception of pore pressure or formation stress. Earlier studies had indicated that temperature and not pore pressure was the dominant driver for the initiation of the diagenesis processes.

At the end of the test period the cells were opened and examined for the presence of diagenetic material. The diagenetic material was easily confirmed under a stereo microscope and by SEM. The presence of new well-formed crystals on the formation chips or proppant grains indicated that diagenesis had taken place. The cooling of the material within the cell often dislodged some of the diagenetic material from the surfaces. This fine material, often called diagenetic dust, could be efficiently separated from the larger formation chips and proppant grains by selected sieves.

A small amount of formation material was often included in this material. X-ray diffraction studies were performed on these “dust” samples when sufficient material was recovered. Water from the test cells was also recovered. These water samples were analyzed to reveal what cation species were present in the post-test fluid.

The pre-test de-ionized water was also analyzed as a baseline for these tests.

Tubes 1 & 2 were prepared from Sandstone 1 and Tubes 3 & 4 were prepared from Sandstone 2. High strength alumina based proppant was used in all four tubes.

MICROSCOPIC STUDY OF DIGENETIC MATERIALS The samples were studied under a high resolution microscope to reveal the digenetic

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XRD STUDIES OF THE DIAGENETIC MATERIAL The recovered samples were ground to pass a 200 mesh sieve screen. The powders were mounted on x-ray diffraction slides and examined to produce a diffraction diagram. These patterns were analyzed and matched to known structures to identify the minerals present. Rietveld full pattern refinement was used to quantify each component identified. Crystallographic information files (CIF) were obtained from publicly available sources. XRD pattern files of original proppants, formation sands and resultant digenetic samples are given in Figures 2 – 7. Results of XRD studies are given in Tables 1 – 3.

Intensity (counts)

growths on the proppant surfaces. The surfaces with such growths were studied in detail by XRD. Microscopic pictures are cited in Figure – 1.

Quartz 8000

6000 Chlorite 4000

2000

Illite

Microcline

Muscovite

Albite

Kaolinite

Calcite

Quartz

Dolomite Siderite

0 10

20

30

40

50

60

70

Figure 3: XRD graph of sandstones used in analysis Intensity (counts)

DETERMINATION OF CATION CONCENTRATIONS IN THE TEST WATERS A small por tion of the recovered water from each of the test cells was

Sand Stone 1 Sand Stone 2

Tube 1 Dust Tube 2 Dust

2000

Peaks of Phillipsite at 2θ value of 10.4, 13.8, 17.5, 27.9 & 33.2

1500

Peaks of Garronite at 2θ value of 12.4, 17.9, 21.8, 28.3 & 33.5

1000

500

0 10

20

30

40

50

60

70

Intensity (counts)

Figure 4: XRD graph of diagenetic dust from Tubes 1 & 2

Tube 3 Dust Tube 4 Dust

6000

Peaks of Garronite at 2θ value of 12.4, 17.9, 21.8, 28.3 & 33.5 5000 4000

Figure 1: Images of diagenetic growth under stereo microscope Intensity (counts)

3000

Corundum Corundum

2000

2500 1000 2000

Corundum

0 10

1500

20

30

40

50

60

70

Figure 5: XRD graph of diagenetic dust from Tubes 3 & 4

appropriately diluted with de-ionized water and run against certified standards to determine the concentrations of cations present in the waters. This data serves to confirm the presence of cations that the XRD data show to be important in the diagenetic process. Water Analysis results are given in Table 4.

1000

500

Mg-Al-Ti-Oxide Quartz

0 10

20

30

40

50

60

70

Figure 2: XRD graph of alumina based proppant. (All larger peaks represent Corundum. Smaller peaks responsible for Mg-Al-Ti-Oxide and Quartz are also shown below.)

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Paper 13-15.indd 14

RESULTS The results of the X-ray diffraction analyses obtained from the original sandstones,

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Phase

Concentration

Phase

Concentration Sandstone 1

Concentration Sandstone 2

Corundum (Al2O3)

94

Mg-Al-Ti-Oxide

04

Quartz

44

26

Quartz (SiO2)

02

Calcite

09

11

Dolomite

11

08

Albite

04

05

Microcline

03

03

Chlorite

02

03

Kaolinite

02

02

Muscovite

02

04

Mixed Layer

02

01

Table 1: XRD of alumina based proppant used for study (%)

Phase

Garronite

Concentration Concentration Concentration Concentration Tube 1 Tube 2 Tube 3 Tube 4 (30 days) (30 days) (60 days) (60 days) 52

50

66

62

Phillipsite 47

48

-----

-----

Quartz

Trace

Trace

29

34

Na-feldspar -----

-----

3

2

Calcite

Trace

Trace

Trace

Trace

Illite

20

31

Anhydrite -----

Trace

-----

-----

Pyrite

01

Trace

Muscovite

1%

2

1

Siderite

-----

06

1%

Table 3: XRD of diagenetic dust recovered from four tubes (%)

Table 2: XRD of sandstones used for study (%)

Sample

Silicon

Sodium

Potassium

Iron

Calcium

Magnesium

Aluminum

DI Water

<1

004

<1

<1

003

<1

<1

Tube 1

43

177

275

<1

195

1

<1

Tube 2

46

181

239

<1

208

1

<1

Tube 3

50

216

068

<1

084

1

<1

Tube 4

46

210

071

<1

076

1

<1

Table 4: Cation concentration from test waters extracted from tubes after the test (ppm)

proppant, and test cell material are shown below. High concentrations of zeolites in the form of Garronite and Phillipsite are present in the four test cells included in this study.

REFERENCES 1. LaFollette, R. and Carman, P. 2010. Proppant Diagenesis: Results So Far. Paper SPE 131782 presented at the SPE Unconventional Gas Conference, Pittsburgh, Pennsylvania, 23-25 February.

CONCLUSION The above study clearly indicates formation of zeolites in the form of Garronite [Na2Ca5Al12Si20O64•27(H2O)] and Phillipsite [(Na,K,Ca)12(Si,Al)8O16•6(H2O)] as part of the diagenetic process. Formation of these zeolites will reduce the propped fracture conductivity achieved through original proppant arrangement. Results obtained from water analysis also indicated exchange of ions during the process, although the de-ionized water used in the process was initially free from any such ions.

In Tubes 1 & 2, both Garronite and Phillipsite were formed where in Tubes 3 & 4, only Garronite was formed. This is may be due to the time used for the experiments. Hawkins (Ref 3) have found that under suitable hydrothermal conditions phillipsite forms first and being thermodynamically unstable converts to other zeolites with time. Tubes 1 & 2 showed partial conversion of phillipsite to garronite. As tubes 3 & 4 were kept for longer duration, it helped in maximum conversion of phillipsite to garronite. From this study, it may be concluded that formation of zeolites in the diagenetic processes is also dependent on the chemistry of sandstone and various downhole factors like temperature sw and water quality.

2. Zhu, G. 1982. Effects of Diagenesis on Pore Texture and Petrophysical Properties of Sandstone Reservoir and Its Geological Significance. Paper SPE 10560 presented at the International Petroleum Exhibition and Technical Symposium, Beijing, China, 17-24 March.

3. Daniel B. Hawkins, Kinetics of Glass Dissolution and Zeolite Formation under Hydrothermal Conditions, Clays and Minerals, Vol. 29, No. 5, 331-340, 1981

JaJati Nanda Sr. Scientist Halliburton Technology Center – Pune E-mail: jajati.nanda@halliburton.com Ray Loghry Sr. Scientific Advisor Halliburton Technology Center – Houston E-mail: ray.loghry@halliburton.com

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features Innovation

SliPIPE â&#x20AC;&#x201C; New Pipeline Expansion Concept This article highlights SliPIPE concept which is beneficial in the area where transporting oil and gas from highpressure and high temperature reservoirs through pipelines is difficult.

Finding easy and conventional sources of hydrocarbons has become harder, while the global demand for hydrocarbon products continues to grow. Oil and gas operators have turned to new geographical areas to tap new resources. These areas are challenging and can be remote, in harsh environments or in deep-water, where high-pressure and/or high-temperature (HPHT) reservoirs are often found.

Transporting the oil and gas by flowlines and pipelines from these HPHT reservoirs is a major challenge. SliPIPE is a new concept developed to deal with the end expansion of a rigid pipeline subject to HPHT. A pipeline laid on or buried in the seabed responds to high pressure and high temperature by expanding against the frictional resistance from the soil, resulting in axial displacement (also known as end expansion), lateral buckling, upheaval buckling, or a combination of these, depending on whether the pipeline is fully restrained or unrestrained. In some cases, pipeline walking may occur after the pipeline in operation is cooled down, for example in a shutdown, and heated up for operation and then the thermal cycles are repeated.

These pipeline movements can cause failures in the midline or at the tie-ins connected to the pipeline end and are critical to the integrity of a pipeline. When a pipeline is subjected to high pressure and high temperature, its ends expand longitudinally and exert forces and bending moments onto adjacent tied-in structures connected to it. The tied-in structures must be designed to withstand these expansions and loads. Dumping rocks along the pipeline has conventionally been adopted to reduce end expansion. A giant spool installed at the pipeline end is another alternative. They are often used in combination to eliminate end

ADVANTAGES OF SLiPIPE TECHNOLOGY Avoids fabrication and complicated installations associated with giant spools Minimises costly post-installations subsea intervention work Space-efficient and ideal in areas congested with many subsea facilities

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expansion when it is very large. However, such post-lay intervention work is costly and requires a long offshore time. Thus, a major challenge is to improve on the ways the pipeline end movements can be controlled â&#x20AC;&#x201C; improvements which are simple, safe and cost-effective. SliPIPE offers a new possibility.

CONCEPT SliPIPE works to reduce the wall force exerted at the tie-in by absorbing the end expansion through sliding within itself and simul-taneously reducing or eliminating the effective axial compressive force in the pipeline.

SliPIPE consists of an outer pipe connected alongside to a pressure chamber and an inner pipe that can slide inside them. Seals are placed at the contacts between the pressure chamber and the inner pipe. The inner pipe slides in or out of the outer pipes in response to an axial stress that can either be more or less than a certain value. This value is pre-determined in the SliPIPE design and causes an axial tension in the pipe wall to develop, which opposes the effective axial compressive force component arising from the inner fluid pressure.

The axial tensile pipe wall force is produced by letting fluid pressure in, through holes in the inner pipe, to one side of the pressure chamber, separated from the other side of the pressure chamber by an annular partition wall. As the pressure in that side of the chamber freely builds up, it pushes against the partition wall and the pressurised end of the chamber in opposite directions to one another until an equilibrium is reached. This in turn develops a tensile force in the pipe wall which can be scaled to a desired value by pre-sizing the cross-sectional area of the pressure chamber. Between the outer pipe/pressure chamber and the inner pipe of the SliPIPE are two main seals, a partition wall seal, an environmental seal and a scraper seal.

Each main seal consists of a pair of chevron seals and T-seals with backup rings, capable of preventing a single failure from causing the loss of both barriers.

Other equivalent double barrier seals may be used. Around the rim of the annular partition which moves within the pressure chamber is a set of double T-seals.

Each T-seal is reinforced with backup rings on either side and these provide efficient resistance to extrusion of the seals. The seals are made of materials that allow them to function at high temperatures of up to 150 degrees Celsius and pressures between 100 and 400 bars. Chevron seals are made of thermoplastic while T-seals are made of elastomer.

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onto the seabed and connected to a manifold or riser via a short tie-in spool. A misalignment flange may be included.

SliPIPE consists of an outer pipe connected alongside to a pressure chamber and an inner pipe that can slide inside them.

Environmental seals and scrapper seals remove marine growth and other contamination on the surface of the inner pipe before it makes contact with the main seal. Before use, all seals must first be qualified for HPHT conditions and to ensure the long-term reliability of the seals to function under the frequent twodirectional sliding of the surfaces that come into contact with them.

Several practical issues that will influence the operation of the SliPIPE were studied and feasible ways to overcome them looked into, such as: • The double seals at the annular partition wall are relied upon to keep the differential pressure between the non-pressurised compartment and the pressured compartment of the chamber. To safeguard against the pressures on either side of the partition wall equalising over time, a one-way relief valve, suitable for underwater application, can be installed at the far corner of the non-pressurised compartment through which any built-up pressure in the compartment can be vented out into the sea. Alternatively, a small pipe connecting the non-pressurised compartment to a faraway existing flare-off facility, if available, will produce the same effect.

• Assembling the components and seals together to create the SliPIPE is feasible by casting, forging, welding and assembling the components in a certain production sequence. Damage to the seals from the heat generated by welding parts together can be avoided by careful selection of the welding locations.

• The seals can be inspected after the final factory-acceptance test by modifying the free end of the pressure chamber to create a pair of flanges with a metal seal between them, one flange connected to the chamber body and the other connected to the chamber end. The flanges can be unbolted to disassemble the components so that the seals can be inspected. The metal seal located between the flanges is then replaced with a new one before the SliPIPE is reassembled.

• In order for the main seal to hold against leaks, it is crucial that the environmental and scraper seal can be relied upon to clean the surface of the inner pipe that comes into contact with the main seal. This can be improved by extending the free end of the pressure chamber using external tubular housing that has a tight-fit end and is long enough to shield the contactable inner-pipe surface from fouling.

INSTALLATION A SliPIPE used for absorbing end expansion may be pre-installed on a PLET which is then transported and installed offshore on the end of the pipeline, lowered

Alternatively, a direct tie-in (without a PLET and short tie-in spool) is also feasible with the use of a suitable installation guide currently available on the market, e.g.

Subsea Installation Guide (SIG). The SIG is placed on the subsea structure close to the connection point and guides the pipeline end towards the hub on the subsea structures until they are separated by a small gap. The SliPIPE is then allowed to slide until the small gap is completely closed and the connectors clamped together.

No post-installation metrology, fabrication of the short spool, additional spool installation or subsea tie-in need be performed. In the direct tie-in method, SliPIPEs have to be locked to restrict any uncontrolled movement and the lock released before tie-in. A SliPIPE must be designed to have at least the same capacity as the adjacent linepipe, which has already been designed to resist the maximum tensile forces and bending moments.

APPLICATION SliPIPE is a concept well-suited for installing tie-ins between a submerged rigid pipeline and a subsea well, subsea structure or riser, typically from 10.75 inches to 24 inches (273 mm to 610 mm) in diameter, with operating temperatures up to 150 degrees C and a pressure range from 100 to 400 bars. Compared to a giant tie-in spool, SliPIPE is a relatively simple yet effective alternative means to eliminate the effects of end expansion on tie-in structures.

Key Advantages: • SliPIPE avoids the fabrication and complicated installation associated with giant spools.

• SliPIPE minimises costly post-installation subsea intervention work.

• SliPIPE is space-efficient and ideal in areas congested with many subsea facilities, as are often encountered in brownfield modification work, where safeguarding the facilities’ integrity during intervention work can be a formidable task.

DNV has been instrumental in developing and upgrading the safety and integrity regime and standards for offshore pipelines over the past few decades.

Today, more than 65% of the world’s offshore pipelines are designed and installed to DNV’s offshore pipeline standard.

SliPIPE is conceptual and will require refinement and engineering through basic and detailed design before it can be realised in an actual project. A global team of experienced engineers from Singapore, Oslo, Perth and Groningen, combining youth and experience and headed by DNV in Singapore, has developed the concept. The team has also taken into account comments received from the offshore pipeline industry. Besides a university professor, the personnel consulted sw are from two major installation contractors and a seal company.

Chia Chor Yew Head of Section Subsea, Structures & Pipelines DNV Singapore E-mail: Chor.Yew.Chia@dnv.com

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features Cooling System Selection

Selection of Cooling Medium System on Offshore Process Platforms Exploring oil and gas from deep sea fields and harsher marine environment needs an offshore processing platform that is equipped with not only the processing facilities, but also supplemental facilities like utilities and living quarters. In order to export marketable products in the form of crude, condensate or gas, several processing operations are to be carried out, which require cooling. This article describes various options that are available for the purpose of cooling and the selection of an option which is most feasible economically as well as operation point of view.

Increasing demand for fuel has made mankind leave the familiar territory of land and venture into deeper and harsher marine environment, thus exploring oil and gas fields in deep sea. Key component in this is the offshore processing platform, the main function of which is to extract and deliver marketable products in the form of crude, condensate or gas. A process platform is equipped with not only the processing facilities, but also supplemental facilities like utilities and living quarters. In order to export the marketable product, several processing operations are to be carried out, which require cooling. Temperature of well fluid produced from the reservoir can be considerably high. Equipment like pumps, compressors and facilities like HVAC (Heating Ventilation and Air Conditioning) also require cooling.

Various options are available for the purpose of cooling. Selection of an option which is most feasible economically as well as operation point of view, during initial stage of the project carries utmost importance. Particularly for offshore processing, there are many factors which need to be considered for selecting the right type of cooling option.

coolers if compared with typical Shell and Tube type water cooled exchangers, lower operating cost normally makes use of air coolers an economically attractive option. But space is an extremely critical parameter when it comes to offshore platforms and this makes selection of liquid cooled system as an advantageous alternative. Also, if seawater is being used for injection purpose, incremental cost of using liquid cooled system can be reduced to a great extent. Once it is decided to go with the liquid cooled system, the task which assumes importance is selection between direct seawater system and indirect cooling medium system, which is discussed henceforth.

DIRECT SEAWATER COOLING Figure 1 describes all the steps of direct cooling system using seawater.

TC

AIR COOLING Air can be used as a cooling medium for process cooling. Air cooled heat exchanger is an option which provides the means of losing the heat from the well fluid to ambient air without environmental concerns. For this system, climatic conditions and ambient temperature of air are important parameters. As air is more liable to temperature fluctuations, process control requires attention. The air fin coolers can be of natural draft, forced draft or induced draft type.

In case of air cooled systems, the heat transfer coefficients are relatively low. Hence air cooled exchangers require higher heat exchange area which results into high space requirement on the platform. Although capital investment is higher in air www.oswindia.com

Selection of cooling medium system on offshore process platforms_Edited.indd 18

HC Analyzer Vent

TC PC

The three main options for cooling on offshore process platform are: • Air cooling • Direct cooling using seawater • Indirect cooling (using seawater and cooling medium)

AT

Electro Chlorination Unit

Seawater Coarse Filter

Seawater Dump Caisson TC

TC

Process Coolers Seawater Lift Pump (s)

To Overboard

Figure 1: Direct Seawater Cooling System

Direct seawater cooling system consists of lifting seawater and using it as a cooling medium. The seawater should be pressurised, filtered and chlorinated to avoid marine growth before supplying it for cooling purpose. Mostly, vertical centrifugal submersible pumps are used for lifting seawater. Other equipments required are seawater coarse filter and electro-chlorination unit. The used seawater is dumped overboard or it can be used for injection purpose as solubility of oxygen reduces in warm seawater. Deaeration facility may be provided for oxygen removal depending upon reservoir conditions, if seawater is to be used for injection.

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INDIRECT COOLING Figure 2 describes the all possible steps of indirect cooling medium system.

PC

Inert Gas HC Analyzer

TC

AT

Vent

TC

Seawater Dump Caisson Electro Chlorination Unit

Seawater Coarse Filter

Expansion Tank

TC FC

TC TC

Cooling Medium Cooler

Cooling Medium Recirculation Pump Process Coolers

Seawater Lift Pump (s)

Based on the Process Flow Diagram (PFD) and data which is obtained from simulation and material selection, equipment required for each cooling method and their tentative sizes can be estimated.

To Overboard

Figure 2: Indirect cooling medium system

Indirect cooling is a closed loop process, i.e., the cooling medium is circulated through the processing facility for cooling purpose and the heat load is taken up by seawater. Typical cooling mediums used are Glycol (Mixture of Mono Ethylene Glycol (MEG) or Tri Ethylene Glycol (TEG) with Fresh water) or inhibited fresh water.

Inhibited fresh water is used where freezing cannot occur.

CRITERIA FOR SELECTION Concept System Definition is the first step in case of any greenfield project. In order to develop the concept, main input is the reservoir data obtained from geological studies and product quality and conditions at which it is desired.

Based on this, simulations are to be carried out using process simulators in order to decide the processing facility and conditions at which it can be operated.

Based on this, a basic process flow diagram is prepared which helps in arriving at various governing process parameters.

Selection of cooling medium system is an essential part which is carried out typically in the FEED (Front End Engineering Design) stage of the project.

Parameters on selection of cooling medium system: • Total number of cooling consumers and their cooling loads.

• Total cooling load (maximum and minimum).

• Conditions for hydrate formation/ scaling.

From comparison between direct and indirect cooling systems (Refer Figure-1 and Figure-2), it can be seen that following are the additional equipment required in case of an indirect cooling medium system: • Cooling medium cooler(s); • Cooling medium expansion tank; • Cooling medium circulation pump(s); and • Cooling medium filter (if required).

Thus, due to the additional equipment and their associated piping and valves indirect cooling medium system is likely to have higher weight as well as footprint as compared to direct seawater cooling system. Thus from the perspective of weight and space, direct system gains advantage over indirect system.

Weight and space are also affected by the type of heat exchangers used. Typically, direct seawater system employs Shell and Tube and Plate Heat exchangers. Though Shell and Tube type of heat exchangers are most common, Plate Heat Exchangers (PHEs) are also used because of their compactness. Another option which may prove effective in terms of weight and space for offshore processing facilities is Printed Circuit Heat Exchangers (PCHEs). The weight and space required for a PCHE is around one-fourth of that for a Shell and Tube type of heat exchanger. However, in case of direct cooling system where seawater is the cooling medium a PCHE cannot be used due to potential clogging of the channels.

MATERIAL SELECTION MOC (Material of construction) is a governing factor while selecting between direct and indirect cooling systems, as it has a direct impact on the capital investment and weight. Material selection is based on factors like type of fluids coming in contact with the material, operating process conditions, evaluation of corrosivity etc. Design life of the processing facility, ambient conditions and type of environment (here, marine / saline) are some points which are also considered while evaluating materials.

Typically, seawater has very high potential of corrosion and scaling. Hence use of materials like Super Duplex SS (25 Cr), Titanium or GRP (Glass Fiber Reinforced Plastic) is recommended.

Apart from the process parameters discussed above, following vital aspects need consideration for selection of direct/indirect cooling medium system; Apart from the process parameters discussed above, some vital aspects need to be consider for selection of direct/indirect cooling medium system that are discussed below: WEIGHT AND SPACE This is one of the most important criteria of selection between direct and indirect system, particularly for offshore applications.

In case of indirect cooling medium system, material like carbon steel can be used due to reduced possibility of scaling and absence of corrosive components. Selection of material aims at achieving lowest Life cycle Cost (LCC).

In case of direct seawater cooling system, in addition to the seawater lift pumps and seawater coarse filter, all the process heat exchangers having seawater as the cooling medium use exotic materials like super duplex and titanium as materials of construction. For a facility where numbers of cooling consumers are more, this can have a substantial impact on capital cost. In such cases, indirect cooling medium system can prove economical in terms of cost of materials.

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For indirect cooling medium system, except cooling medium cooler(S) which use seawater, all other exchangers can be manufactured in non-expensive materials like Carbon Steel.

SAFETY AND OPERATION There are several issues related to safety and operations which are to be looked into while selec ting bet ween direc t and indirec t cooling medium systems.

• Scaling and Corrosion: Direct seawater system is prone to scaling and corrosion. Corrosive substance like chlorine is present in the system.

High temperature in the seawater system needs to be avoided to prevent scaling. Usually, the system is designed such that maximum seawater return temperature is limited to 45 degree Celsius. Scale inhibitor needs to be injected if seawater temperature exceeds this limit.

•

CASE STUDY The case study is carried out for an international project for an offshore process platform having oil and gas trains for selection between direct and indirect cooling system. The field in this case produces gas as well as oil. Simulation is carried out using HYSYS and cooling loads are established.

The study is based on evaluation of four process coolers which constitute for the major part of total cooling load of the processing facility.

Table 1 shows the equipment, corresponding cooling loads and process side temperature conditions.

For indirect system, problems of scaling and corrosion are relatively much lower for process coolers and are restricted only to the cooling medium cooler where seawater is used as cooling fluid.

Equipment

Hydrate Management: Hydrates are solid crystals which are formed when hydrocarbon gas molecules get trapped in between water molecules at high pressures and low temperatures.

Export Gas cooler

In case of direct seawater cooling system, risk of hydrate formation is aggravated because of low seawater inlet temperature. This low seawater temperature, if not controlled, may lead to cooling of the process gas to a temperature below its hydrate formation temperature. Processing facilities which encounter colder climate (e.g. North Sea) are prone to witness hydrate formation as the seawater inlet temperatures can be as low as 5 degree Celsius. Hydrate formation is not a problem in case of indirect cooling as cooling medium inlet temperature is adjusted accordingly.

•

In short, for every project, detailed study is required to estimate capital expenditure (CAPEX) and operating costs (OPEX) in order to select better alternative.

Control and Maintenance: As described earlier, number of equipment is more in case of indirect cooling medium system than direct seawater system.

Hence additional instrumentation and controls are required.

When Shell and Tube type exchangers are selected for direct seawater cooling system, attention should be given to the possibility of tube rupture and ingress of seawater into the hydrocarbon system.

TOTAL COST Life Cycle Cost (LCC) should be one of the criteria applied in determining the optimal system solution. The optimisation is based on operating life of the processing facility.

Following are additional components considered for LCC analysis: • Initial (Fixed) cost (for example. Number of equipment, piping, material, instrumentation); • Energy cost; • Operation, maintenance and repair costs. www.oswindia.com

Selection of cooling medium system on offshore process platforms_Edited.indd 20

Duty (kW)

27880

Inlet temperature T1 (oC)

Outlet temperature T2 (oC)

104.4

27

First stage process gas 3487 compressor suction cooler

78.9

27

Second stage process gas 1850 compressor suction cooler

88.9

27

Third stage process gas 2294 compressor suction cooler

94.3

27

Table 1: Cooling loads for process coolers

The exercise is performed to study the effect of direct and indirect cooling medium system on the cooling medium/seawater flow and heat transfer area requirement.

Following temperature conditions that describe in Table 2 are considered for seawater and cooling medium.

Direct cooling system (For Seawater) o C

Indirect cooling system (For Cooling medium) o C

Inlet temperature (t1)

Outlet temperature (t2)

Inlet temperature (t1)

Outlet temperature (t2)

12

40

20

45

Table 2: Temperature conditions for seawater and cooling medium

Inlet temperature from seawater is obtained from Met-ocean data of the location of the processing facility. Outlet temperature of seawater is restricted at 40 oC in order to avoid scaling.

For indirect cooling medium system, as seawater is used to take up heat load from cooling medium and hence cooling medium is likely to have higher temperature than seawater. Based on good engineering practices, cooling medium inlet and outlet temperatures have been considered.

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Table 3 shows the result obtained in direct and indirect cooling system.

Seawater Return

Equipment

Cooling fluid flow rate m3/hr

LMTD o C

Direct system

Indirect system

Direct system

Indirect system

Seawater

Cooling Medium

Seawater

Cooling Medium

Export Gas Cooler

874

1049

33.9

24.5

First Stage compressor suction cooler

109

131

25.1

17.1

Second stage compressor 58 suction cooler

70

28.7

20.1

Third Stage compressor suction cooler

72

86

30.6

21.7

Total

1113

1336

-

-

Table 3: Comparison between direct and indirect system

Data in Table no. 3 indicates that cooling fluid requirement is less in case of direct seawater cooling system as compared to the indirect system. Cooling fluid flow rate determines the pump capacity and power required for circulation.

Further, for indirect cooling medium system, separate seawater system will be required to take up heat load of the cooling medium. This adds to the operating cost (OPEX) in the form of cost of pumping.

As mentioned earlier, the cooling medium is likely to be warmer than sea water, thus resulting into lower LMTD (Log mean Temperature Difference). Here, it can be seen that the LMTD in case of direct seawater cooling system is substantially higher than that for the indirect cooling medium system, leading to much smaller heat exchangers if compared with those in the indirect system. This helps in offshore installations where weight and space are critical issues.

Even if direct system looks advantageous in terms of operating cost, space and weight, it is should be noted that employing direct system requires use of heat exchangers made of Titanium. Although they are smaller in size, high capital investment due to cost of exotic material like Titanium can offset the other advantages offered by the direct system and result into much expensive installation.

FC TC

Process Cooler TC

Seawater Supply

Hot Seawater Recirculation Pump

Figure 3: Hot seawater recirculation

However, it should be noted that this option implies additional cost in terms of the equipment (circulation pump) and power.

CONCLUSION Extensive study needs to be carried out for determining the cooling system to be selected. Direct seawater cooling system offers advantage with respect to weight, simplicity of operation, space and operating cost. However, it involves use of exotic materials and may lead to high capital investment. Typically, direct seawater system is favored for processing facilities having less number of cooling fluid consumers.

As per process and operation point of view, generally indirect cooling medium system is favored as it significantly reduces the possibility of scaling and eliminates corrosion and hydrate formation. But factors like weight and footprint may require consideration due to additional equipment present in indirect system.

For direct and indirect system, factors like process conditions, weight, space, materials, safety and operational requirement may have different impact with respect to overall cost. Hence for each project, it is very important to carry out parallel evaluation with respect to all the parameters which affect the selection between direct and indirect system. In addition to this, client philosophy also needs consideration.

Based on a thorough techno-commercial evaluation, best suited option needs sw to be selected.

Similar to this study, comparison studies with respect to other aspects like material, weight, space, layout, operations are performed for selecting the most favourable solution.

ADDITIONAL CONSIDERATION FOR DIRECT SEAWATER COOLING SYSTEM After thorough evaluation, if direct seawater system is selected and there is possibility of hydrate formation, then option of hot seawater recirculation can be employed to mitigate this problem. Hot seawater recirculation ensures stable operation by avoiding hydrate formation, as it maintains the inlet temperature of the seawater going to the process cooler above the hydrate formation temperature.

Figure 3 shows typical schematic for hot seawater recirculation arrangement.

Prajakta Desai Engineer - Oil and Gas (Process) Aker Powergas Pvt Ltd E-mail: prajakta.desai@akersolutions.com Vishal Pawar Chief Engineer - Process Aker Powergas Pvt Ltd E-mail: vishal.pawar@akersolutions.com

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5/29/2013 4:59:53 PM

features Sharing Responsibility

CSR: The Art of Giving CSR fund (Corporate Social Responsibility) is the medium through which companies can share some part of their profit with community of the area from where they operate. Under the ‘Bill’, it has been made mandatory to keep some part of companies’ income for the fund. This is the best way for corporates to serve people and take measures for minimizing ill effects of pollution.

Workers of oil and gas exploration companies often operate in challenging and hazardous conditions. So, the magnitude of risk they face is very high. They face environmental, health and safety risks and liability risks, which could ultimately lead to reputation risk. Community or people who live in the vicinity of these companies pay price for the production of oil and gas. The risk of environmental pollution is very high which may pose serious threats to health of people and workers. Sometimes, workers endanger their lives leading to grave injuries or even deaths too.

While granting exploration and production rights, the Government and contractors enter into a Product Sharing Contract (PSC) under which the contractor have to bear all exploration risks, production and development costs in return for its stipulated share of production resulting from this effort.

Under the PSC, these companies are required to carry out operations in a manner that is conducive to the environment. They should also take measures for health and safety of workers and employees. Therefore, one can assume that oil and gas companies would be taking necessary steps for minimizing the health, safety and environmental risks.

Another step towards this, though not applicable only to oil and gas companies, is arising out of the Companies Bill 2012 (‘the Bill’). This Bill proposes a framework for meeting the prescribed criteria to contribute a part of their companies’ profits for specified Corporate Social Responsibility (‘CSR’).

Promoting Education Social business Project

Environmental sustainability CSR Activities Eradicating hunger and poverty

Enhancing vocational skills Empowering women

However, the proposed mandatory CSR implication puts greater responsibility on them to set out a clear framework and process to ensure strict compliance.

The Bill makes it mandatory for all companies having a net worth of ` 500 crore or more, or turnover of ` 1,000 crore or more or a net profit of ` 5 crore or more to spend every year at least 2 per cent of its average net profits of three preceding financial years towards its CSR activities.

MANDATING CORPORATE SOCIAL RESPONSIBILITY CSR activities have been looked upon by corporates as a mean of giving returns to society in which they operate and external stakeholders from whom they draw their resources to generate profits.

The eligible companies are required to constitute a CSR Committee whose role is to: • Formulate and recommend the CSR Polic y indicating ac tivities to be undertaken; • Recommend amount of expenditure to be incurred on CSR activities; and • Regular monitoring of CSR Policy

>> The Government and contractors enter into a Product Sharing Contract (PSC) under which the contractor have to bear all exploration risks, production and development costs in return for its stipulated share of production resulting from this effort.

Companies usually conduct the activities as part of CSR in need-based sectors such as: • Environment Sustainability • Promoting education • Social business projects

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• • • • •

Enhancing vocational skills Empowering women and promoting gender equality Reducing child mortality and improving maternal health Eradicating extreme hunger and poverty Combating life threatening and other diseases

>> Oil & gas companies such as Cairn, Shell and Reliance (to name a few) as well as public sector companies like Indian Oil have been carrying out CSR activities with a view to sharing benefits with local communities and reducing impact of their operations on these communities as well as on the environment.

The Bill also mandates companies’ Board to approve the CSR Policy, disclose its contents in the Board Report, make it public on the company’s website and deploy funds towards CSR spending. Reasons for not spending the amount earmarked for CSR activities are also required to be specified in the Board Report. The Bill has been passed by the Lok Sabha (i.e. Lower House).

IMPLICATIONS FOR OIL & GAS COMPANIES The implementation of CSR funds is the sole responsibility of the company and its Board. It is required to oversee that these activities are undertaken in their true spirit. Although no penal consequences have been separately mentioned for non-compliance of these provisions, reputational risk arising from a negative comment in the Board’s repor t will deter companies from non-adherence.

It will not be right to comment that now companies will carry out CSR activities only because it has been made mandatory. Oil & gas companies such as Cairn, Shell and Reliance (to name a few) as well as public sector companies like Indian Oil have been carrying out CSR activities with a view to sharing benefits with local communities and reducing impact of their operations on these communities as well as on the environment. However, these companies and others which are carrying out CSR activities in one form or the other would need to assess their current activities and align it with those envisaged under the Bill. Also the quantum of spend would need to match, if not exceed, the mandatory requirement.

•

•

Should CSR activities be directly undertaken by the company or be entrusted to a separate entity capable of running such projects and yet help meet company’s CSR obligations?

Can activities undertaken over and above that mandated by PSC and other laws be regarded as CSR activities?

There are open issues that should get addressed once the rules and guidelines are framed. Though there is a mandatory need for companies to take up CSR activities for oil and gas companies, it becomes complicated by the multiplicity of environments – technical, legal, political, cultural, ethical – in which they operate. Their impact on the environment, communities and workers is generally much higher than companies operating in other sectors.

CSR in such companies therefore needs to be put closer to the center of business decision-making. The CSR programs should be more strategically-sophisticated to achieve the twin objective of risk management and reputation enhancement. sw

Companies which are not doing anything towards CSR should view it as an opportunity to manage their health, safety and environment risks. They could look at a CSR policy where the additional expenditure of 2 per cent of profits required to be made by them generate value not only for the society and external stakeholders but also benefits the company’s operations in the long run as well.

ISSUES FOR CONSIDERATION Once the Bill is enacted, companies would need to adhere to the CSR requirements and apportion 2 per cent of their average net profits of preceding three financial years towards CSR spending. Couple of issues that could come to mind are – • Do the provisions apply to a company with loss in the current year and profits in preceding years because it meets the net worth or turnover criteria?

• Can activities undertaken by companies that provide a social benefit and also save money, such as being more energy efficient, be regarded as CSR activities?

• Can amounts already being kept aside and spent by oil & gas companies (which are by law required to carry out some of the activities prescribed in the Bill) be said to be towards the mandated CSR activities?

Neetu Vinayek E-mail: nvinayek@kpmg.com

Nidhi Agarwal E-mail: nagarwal@kpmg.com

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5/29/2013 5:26:24 PM

features Energy Review

Energy Commodities on Weak Trend Barring Natural Gas Barring natural gas, most other energy commodities witnessed weak price trend in the two months under review i.e.

March and April. While NYMEX natural gas futures registered the maximum price rise of 24.58 percent in the two months on weather related demand and smaller than expected increase in weekly US gas supplies, on the other hand EUA futures prices on ICE-ECX platform fell by 36.04 percent on increasingly uncertainty over the future of carbon market.

Release of disappointing Chinese manufacturing data and record euro-zone unemployment at the start of the month of March led light sweet crude oil (WTI) futures on NYMEX (CME) start the period under review at US$ 90.68, down by 1.49 percent from previous month’s close.

sector, strong showing of US durable-goods orders and unexpected decline in US crude oil inventories. Brewing up of tensions in Korean peninsula also added bullish sentiments in oil prices. Consequently NYMEX crude oil futures moved to the period high of US$ 97.8 on April 1.

Later, better-than-expected US data and easing of worries over the euro zone as ECB and BOE kept their rates unchanged; making no changes to quantitativeeasing program helped the recovery in oil prices. Further, release of strong Chinese oil import data and a jump in US nonfarm payrolls offered positive signals for demand, helping rise in oil prices.

Later, release of disappointing pace of expansion in the US manufacturing sector not boding well for potential energy demand triggered down fall in oil prices from period high levels. Further larger-than-expected increase in US crude supplies, reported weekly and a slowdown in private-payrolls growth combined to push prices below $95 a barrel. Price fall was also supported by a disappointing monthly report on US jobs provoking concerns that energy demand could weaken.

The rise in oil prices was not uninterrupted. Uncertainty surrounding a bailout plan for Cyprus clouded the outlook for energy demand in the euro zone. The fall in prices was accentuated as Cypriot lawmakers rejected a controversial levy on bank deposits as part of the rescue deal. Later with an agreement finally reached between Cyprus and the troika of the European Commission, the European Central Bank and the International Monetary Fund — to avert a potential collapse of the European nation’s financial system, oil prices moved up. The rise was then supported by growth data from the US manufacturing

335

The steady decline in oil prices was however disrupted by a lack of progress in nuclear talks between world powers and Iran and conflicts in Nigeria stirring up worries about oil supplies. But, oil prices were quickly back on down trend on decline in US retail sales and consumer sentiment, downgrades to global oil-demand forecasts by IEA and a surprise climb in weekly levels of US distillate. Consequently, NYMEX crude oil futures stooped down to periodlow of US$ 85.61 on April 18.

NYMEX Heating Oil (UScents/gal) - LHS

NYMEX Gasoline (UScents/gal) - LHS

NYMEX WTI Crude Oil (USD/barrel)

ICE Rotterdam Monthly Coal (USD/MT)

100

321

95

307

90

293

85

279

80

265

75

3/1/2013

3/8/2013

3/15/2013

3/22/2013

3/29/2013

4/5/2013

Futures Price Movement: March - April 2013

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MCX 24-25.indd 24

4/12/2013

4/19/2013

4/26/2013 Source: Bloomberg

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0.3

5.5

0.24

4.9

0.18

4.3

0.12

3.7

0.06

3.1

0

2.5

3/1/2013

3/8/2013

3/15/2013

ICE-ECX CERs (Euro/tonne) - LHS

3/22/2013

3/29/2013

4/5/2013

4/12/2013

NYMEX Natural Gas (USD/mmBtu)

4/19/2013

4/26/2013

ICE-ECX EUAs (Euro/tonne)

Futures Price Movement: March to April 2013

Source: Bloomberg

Following the registering of period-low, oil prices moved up as market participants mulled the prospects for an output cut from the Organization of the Petroleum Exporting Countries given the low prices prevailing then.

Later by end of the period, smaller than expected increase in weekly US oil inventory levels and expectations for a boost in economic stimulus from global central banks helped oil futures to close the period at US$ 93.46, marginally up by 1.53 percent in the two month period. The downtrend witnessed in oil prices especially in the month of April was also reflected in the price fall of its derivates such as heating oil and gasoline.

world’s largest - at risk of collapse. As such, The European Union Emissions Trading System is by far the biggest carbon market, accounting for 89 percent of the $61 billion in trading worldwide in 2012, according to data compiled

by Bloomberg.

Moreover, the failure of the ETS to set a price signal is causing individual member states to introduce ad hoc measures like carbon price floors and energy taxes. On the other hand CER (Carbon Emitted Reduction) futures, which have sw been close to zero euro moved little in the two month period.

Overall, futures prices of both gasoline and heating oil on NYMEX platform saw a fall of 3.90 percent and 3.31 percent respectively during the two-month period. On the contrary, other major energy commodity natural gas futures (traded on NYMEX-CME platform) saw a price rise of 24.58 percent in two month period as AccuWeather forecasted hot summer in US pushing up the prospects for high gas demand.

According to Dale Mohler, expert senior meteorologist at AccuWeather.com, “Temperatures for the three summer months may be 3-5 degrees [Fahrenheit] above normal in different parts of US (Plains, upper Midwest and the Rockies), increasing natural gas consumption by 40-60% above what is normal”. Also smaller than expected increase in weekly US gas supplies, thereby pushing gas stocks at their lowest level in roughly two years helped the rise in gas prices.

Among other energy commodities, ICE Rotterdam monthly coal futures prices declined by 7.34 percent largely on increased supply and subdued demand in India and China, the key coal-importing nations. In emission market segment, European Union allowances (EUA) continued to its south bound journey, as its futures prices on ICE-ECX platform fell by a massive 36.04 percent.

European Parliament’s rejection of a proposal by 334 votes to 315 to reform the European Union Emissions Trading System, added to the growing uncertainty over carbon market. In fact, the vote left Europe’s carbon-trading market - the

Niteen M Jain Senior Analyst, Department of Research & Strategy Multi Commodity Exchange of India Ltd E-mail: niteen.jain@mcxindia.com Nazir Ahmed Moulvi Senior Analyst, Department of Research & Strategy Multi Commodity Exchange of India Ltd E-mail: nazir.moulvi@mcxindia.com

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5/28/2013 6:59:00 PM

news features

Deepwater Drilling: A Global Challenge Deepwater drilling activity is on the rise in India. E&P operators to drill deeper and more complex wells require more sophisticated rigs and technology. Indian Oil and Gas sector is looking forward to explore the technology as it may face a stiff competition from global market. Rina Samsudin, Senior Analyst, IHS shares her thoughts on the evolving technology, economy, challenges and trends of deepwater activity.

Deep-water is no longer a frontier area but a reality. The scenario of deep-water activity is undergoing a sea change around the world. While expressing her views on changing landscape of Asia Pacific region and India, Samsudin says that offshore hydrocarbon exploration and production (E&P) is moving into deeper waters and also to remote/challenging areas as the world’s shallowerwater basins mature. The industry is drilling deeper and more complex wells, requiring more sophisticated rigs and technology.

Facts of Deepwater Drilling in India • • • •

India does not own any drilling rigs for deepwater (>3000 ft depth) ONGC and RIL have gone upto depths of 10,385 feet and 10,194 feet respectively >45 drillships & semi-submersibles to be delivered by 2014.

Average ultra-deepwater driiling rig cost is over USD 600 million

The number of deepwater drilling rigs working worldwide has increased significantly over the last decade and is expected to grow in the coming years as deepwater E&P activity rises.

high in other parts of the world, they are likely to be high in India as well.

If global deepwater rig availability is tight, then India may also struggle to secure rigs.”

The capabilities/specifications of these deepwater drilling rigs have also increased/expanded. Demand for deepwater drillings is expected to grow not only in India, but also in the Asia-Pacific and globally.

She also says that China recently took delivery of the Hai Yang Shi You 981 deepwater semisubmersible rig. This is the country’s first China-built and Chinese-owned deepwater drilling rig. Not only is this a national symbol for China but it also ensures security of (deepwater rig) supply for the country. This may be a model for India to consider. A deepwater drilling rig typically costs over USD 600 million to build, requiring a significant amount of investment.

There are also costs to operating and manning these rigs.

She expresses her views on the current state of the global and Indian offshore field development. She says, “India would like to see more investment in offshore E&P. The country does not own any deepwater drilling rigs (definition of deepwater is >3,000ft water depth), India will have to secure/procure these rigs from the global markets. This means Indian oil and gas companies will have to compete with those elsewhere in the world and may have to pay international market rates to hire these rigs. Thus if deepwater day rates are

Deepwater Drilling Rig

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Rina 26.indd 26

EXPLORATION & DEVELOPMENT ON EAST COAST According to her, the Indian authorities are hoping to promote E&P activity off the east coast of India, which can be a challenging area to work in because there (i) are two monsoon seasons leaving only four months of moderate weather to operate in and (ii) the continental shelf is small and then has steep slopes. This means that beyond the near-shore areas, technically-suited deepwater-capable rigs may be needed. Other challenges for oil and gas companies may include less attractive fiscal terms and bureaucratic red tape.

For example, the World Bank’s International Finance Corporation puts India at 132nd place out of 185 countries in its ‘Ease of Doing Business’ rankings for 2012.

ECONOMICS OF DEVELOPING DEEP & ULTRA DEEPWATER SATELLITE FIELDS Development of the deep and ultra deepwater satellite fields is very expensive.

While discussing the economics, she says, “While developing new fields, oil companies will have a ‘cost per barrel’ figure and need oil/gas prices to be at/ above a certain level (cost plus profit margin) in order for the project to be economically feasible.”

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5/29/2013 5:29:12 PM

She states that it is necessary to keep costs low while maintaining the highest HSE standards as possible to ensure the safety of everyone involved and to preserve the environment. Oil/gas prices will also need to be sufficiently high for the project to be economical, and oil/gas prices also need to be stable and not volatile.

There are various challenges, the sector has to face while developing a field. According to her, these are the hurdles faced by the sector: 1. Project clearances – Short turnaround for project approvals/clearance facilitates the E&P process and can otherwise delay projects 2. Manpower – The industry will need a lot of manpower in the coming years (e.g. more rig crews, oil company workers etc.) and companies are already finding it challenging to recruit and retain people 3. Infrastructure – Lack of infrastructure onshore and offshore can add to project costs and time

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TRENDS ACROSS DEEP WATER RIG SUPPLY AND DEMAND Summarising new trends, she expresses that Deepwater rig supply is expected to increase in the coming years due to a lot of newbuilding. More than 45 deepwater drillships and semisubmersibles will be delivered this and next year in total. The current deepwater drillship and semisubmersible count worldwide (delivered rigs) is around 200.

Deepwater day rates have been rising since the last couple of years and the average for ultra-deepwater drilling rigs is around USD 600,000 per day.

Operating costs for non-North Sea class deepwater rigs are typically USD 150,000-190,000 but they vary from company to company and region to region.

Rig owners have seen rising operating costs in recent years.

Samsudin is not aware of the recent Production sharing contracts mechanism in the Indian oil & gas sector. But she suggests that India can look to countries that have been successful in attracting deepwater investment from the multinational oil and gas companies due to attractive fiscal terms.

EVOLVING TECHNOLOGIES Concluding on evolving technologies, she articulates that one example of evolving technologies is advances in well control (e.g. blowout preventers) to help prevent incidents such as the Macondo disaster in the Gulf of Mexico in 2010.

For blowout preventers, more rams are being added for additional redundancy.

Another example is using automation wherever possible to minimise accidents on board rigs. There are lots of new opportunities if deepwater activity increases. Lots of new equipment, facilities and services needed for sw upcoming projects.

For Details Contact

Jasubhai Media Pvt. Ltd. Taj Building, 3rd Floor, 210 Dr D N Road Fort, Mumbai - 400 001 Tel: 022-4037 3636, Fax: 022-4037 3635 Email: industrialmags@jasubhai.com

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5/29/2013 6:19:58 PM

India CCI to Clear 31 Oil and Gas Projects New Delhi: After clearing 5 ‘No-Go’ areas for oil and gas exploration, the Cabinet Committee on Investment (CCI) will ease stringent conditions imposed by Defence Ministry on 31 other blocks, said Finance Minister P Chidambaram. He added that the Ministry of Defence and Oil Ministry, DRDO and others have sorted out the problem.

In all, 8 blocks including Reliance Industries’ Krishna Godavari basin KG-D6 block that has been in production since September 2008, and gas discovery area of NEC-25 in the North East Coast (NEC) region, were declared ‘No-Go’ zones for reasons like overlapping with proposed Naval base or being close to missile launching and Air Force exercise area.

The CCI has already cleared 5 of these blocks for oil and gas activities. On 31 other blocks, the Defence ministry imposed stringent conditions like asking companies not to locate any pipelines or structures on sea surface in the blocks cleared for exploration and production activities.

DIPP Turns Down Oil Companies Demand New Delhi: The commerce and industry ministry has rejected the demand of oil exploration firms to be given fiscal incentives such as subsidy for their activities in northeastern India. Oil companies such as ONGC, Oil India, Jubilant Energy and Assam Company urged the government to include exploration and production (E&P) business in the list of industries getting fiscal incentives under the North East Industrial and Investment Promotion policy (NEIIP).

The Department of Industrial Policy and Promotion (DIPP) has turned down the proposal saying oil and gas explorers do not manufacture products. DIPP said the government had decided not to expand the service sector under NEIIP since subsidies offered by the department was aligned to the national manufacturing policy to boost manufacturing. NEIIP provides subsidies to manufacturing and select service sector enterprises on condition that the beneficiary units should refund subsidies if they stop their activities within five years of commencing commercial production.

The subsidy policy was launched in 2007 to provide 10-year fiscal incentives that included 100 per cent income tax and excise duty exemptions. The policy also provides capital investment and interest subsidies.

Its benefits include reimbursement of insurance premium. But industries in the negative list are not eligible for these incentives.

The northeastern region has huge hydrocarbons potential and an unambiguous fiscal incentive package would attract investments, executives of oil companies said. According to industry estimates, the region has about 5.75 billion barrels of oil reserves and more than 21 trillion cubic feet gas. The Assam-Arakan basin that covers an area of 116,000 sq km is highly prospective.

Insurance Fund for Iranian Crude Refiners New Delhi: The government is considering establishment of an insurance fund for offering coverage to crude oil refining units in Iran.

RIL-BP Gets Drilling Nod Mumbai: Reliance Industries and its partner BP plc have received approval to drill a well on the MA oil field. This is in the KG-D6 block and it is meant to improve natural gas production.

The government is considering such a plan in light of refusal by Europe-based re-insurers to cover such refineries. The insurance fund being planned is worth ` 2,000 crore.

Financial Services Secretary Rajiv Takru said that the fund can only be initiated once refineries begin contributing money. General Insurance Company would be involved in management of the insurance fund. This fund shall also see contribution from oil industry players and insurance entities.

This move by the Indian government shall aid refineries, which import crude oil from Iran, NEC-25 Basin Development Plan Goes whose present insurance coverage is set to lapse in May. Mangalore Refinery & Petrochemicals to Review Ltd is one such company and is yet to get a Mumbai: Niko Resources Ltd has submitted to the new insurer. government of India its field development plan for offshore block NEC-25. While awaiting response, Currently, general insuring companies from an independent reservoir engineering firm is doing India offer coverage to oil refining units and a reserves and economic evaluation of the block. later re-insure risk with global players from the The block covers almost 3.6 million acres (1.45 re-insurance segment. For the ongoing fiscal, million sq km) including a deltaic channel complex India shall slash Iranian crude purchase volume to in the Bengal basin. Reliance Industries Ltd is the a figure lower than 13 million tonnes against 18.1 operator with 90 per cent working interest. Niko million tonnes seen in FY 2012-13. holds the remaining 10 per cent.

Rajiv Takru, Secretary, Financial Services

This was approved by a panel headed by the Directorate General of Hydrocarbons (DGH).

They have given a nod to the RIL and BP drilling MA-8 well on the oil field.

RIL submitted a fresh field development plan for the MA oilfield in last February. This oilfield has been producing crude oil since September 2008.

RIL plans drilling one gas well (MA-8) to augment gas production from the field and side tracking of two ceased wells (MA-6H and MA-7H).

RIL runs the KG-D6 block. It has a 60 per cent stake here, while BP plc has a 30 per cent share.

The remaining 10 per cent is with Canadian firm Niko Resources. www.oswindia.com

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news Govt Invites Suggestions on Draft Policy for Shale Gas Exploration New Delhi: Government of India has invited suggestions from the general public, all stake holders, experts in Oil & Gas sector, environmental Vivek Rae, Petroleum Secretary experts, NGOs, other persons and entities concerned, on the draft policy for exploration and exploitation of Shale Oil and Gas in India.

Before, there is no commercial exploitation of shale gas in the country. Petroleum Minister M Veerappa Moily announced last month to take up the shale gas exploration policy. The Director General of Hydrocarbons has taken steps to identify the prospective areas for shale gas exploration

and a multi organisational team has been formed to analyse the existing data set and suggest the methodology for its development in the country.

India has several Shale formations indicating the presence of Shale Oil/Gas. Preliminary estimates suggest that fairly thick sequences with high shale gas potential are extensively present in the oil, gas and coal sedimentary basins such as Cambay, Gondwana, Krisha-Godawari on land and Cauvery onland. With new exploration technologies, such as multistage hydraulic fracturing or ‘fracking’ combines with horizontal drilling, Production of shale gas has become easier and economic, contrary to the different countries has the potential to bring about drastic changes in composition of their energy basket.

The Petroleum Ministry may allow existing oil and gas explorers to also find shale gas in their

The Petroleum Secretary Vivek Rae said that bids to set up National Data Repository (NDR) would be invited shortly. NDR is a pre-requisite that hosts seismic data of exploratory block for launching open acreage licensing policy (OLAP).

The government proposes to replace the current auctioning of oil and gas blocks under New Exploration Licensing Policy (NELP) by OALP. The new mechanism will help any explorer to examine an area anytime of the year and place a bid to acquire it.

ONGC to Build Fertiliser Unit

LNG Terminal at Ennore Chennai: Indian Oil-Petronas Pvt Ltd (IPPL), a joint venture between Malaysia-based Petronas and Indian Oil Corporation (IOCL), has inaugurated a terminal for import and export of liquefied petroleum gas (LPG) at Ennore to reach out its drive to households in the Southern part of India. The new terminal shall meet demand for LPG in the states of Karnataka, Tamil Nadu and Andhra Pradesh.

The Ennore facility comes with installed capacity of 600,000 tonnes on an annual basis. IPPL has a top notch LPG Import Terminal in West Bengal’s Haldia. The latter accounts for bulk LPG and propane sale of around 9,000 tonnes every month. With the Ennore terminal, IPPL aims selling propane and LPG up to 5000 tonne every month. Tamil Nadu requires 1.2 million tonne LPG every year. Presently, it has availability of 0.4 million tonnes annually. This demand-supply gap was met with LPG movement from a Mangalorean terminal. The IPPL terminal shall largely contribute to bridge the gap.

The company has plans to increase the number of auto-LPG dispensing stations to touch the 50 mark in a bid to enhance sales of auto LPG to 2000 tonnes against the existing 400 tonnes every month.

Oil Firms May Lose Revenue New Delhi: Oil companies might experience loss in revenue on cooking fuel and diesel sales slashed by more than 30 per cent slash for the ongoing financial year. The estimated figure stands at ` 112,000 crore and can be attributed to subsequent decline in international rates of oil. The projects figure is below the erstwhile estimation of ` 130,000 crore.

Companies such as Bharat Petroleum Corp (BPCL), Hindustan Petroleum Corp (HPCL) and Indian Oil Corp (IOC) saw loss slightly lower than ` 160,000 crore for FY 2012-13 in context off sale of kerosene, domestic LPG and diesel at rates dictated by the government. The government rates stand much below the market price for these commodities. Cumulatively companies undergo looses of more than 320 crore every day on sales of all these fuels. For the last quarter of FY 20012-13, BPCL, HPCL and IOC collectively lost close to ` 40,000 crore.

Offshore World | 29 | APRIL - MAY 2013

India News 28-33.indd 29

respective blocks. But, the final nod rests with the Union Cabinet. According to the nodal Ministry, this modus operandi would help faster exploitation of shale gas. Other option is to hold auction rounds, which may take couple of years more. Public sector explorer ONGC has already under taken an experimental project to explore shale gas.

Agartala: The Oil & Natural Gas Corporation (ONGC) has signed an agreement with K K Birla Group company, Chambal Fertilisers and Chemicals, in the presence of Tripura Manik Sarkar, Chief Minister, Tripura Chief Minister Manik Sarkar for setting up a fertiliser unit near Kumarghat in Unakoti district of Tripura.

The estimated cost of the project for producing 1.3 million tonne of fer tiliser per annum is ` 5,000 crore.

The construction of the plant would be completed by 2016.

Sudhir Vasudeva, Chairman and Managing Director, ONGC, said that ONGC would deliver natural gas which would be used as raw material for producing urea and Tripura government has agreed to provide land and other logistic supports.

He added that Manik Sarkar, Chief Minister, Tripura first proposed us to set up such a project as the eastern part of the country is still fertiliser deficit. www.oswindia.com

5/29/2013 5:13:26 PM

Petroleum Ministry Shifts Key Officials New Delhi: A new team has taken charge in key positions in the petroleum ministry and has firmly directed bureaucrats in the Directorate General of Hydrocarbons (DGH) to quickly act on long-pending decisions that have held up big oil and gas projects and soured investor sentiment. These top officials have gradually assumed charges in five months since Veerappa Moily replaced Jaipal Reddy as Oil Minister.

Vivek Rae became petroleum secretary in February after G C Chaturvedi retired. The ministry also made changes in assignments of three joint secretaries to facilitate faster decisions on crucial issues of natural gas pricing and marketing. Giridhar Armane, who was appointed joint secretary for exploration and gas pricing when Reddy was the minister, will now look after only exploration.

Gas pricing will now be under P K Singh, who joined the ministry as a director when Murli Deora was in charge and was promoted to the rank of joint secretary during Moily’s tenure. He will also look after gas allocation and marketing, which has been taken away from Neeraj Mittal, joint secretary, marketing. Apart from gas pricing and marketing, Singh will continue to hold the charge of international cooperation. Another crucial position, the head of the DGH, who leads the management committees of most private oil and gas fields and is the technical advisor for the oil ministry, is also being changed.

New CFO for Essar Energy Mumbai: Essar Energy plc, the India-focussed integrated energy company, has appointed Deepak Maheshwari as Chief Financial Officer in place of P Sampath, who moves to a new role as the President of Business Optimisation and Improvement for the company.

Maheshwari most recently served as the CFO of Reliance Power, and has over 19 years of experience in project and corporate finance, investment banking and treasury management. At Essar Energy, he will report to Naresh Nayyar, CEO. www.oswindia.com

India News 28-33.indd 30

Energy Independence by 2030 New Delhi: Minister for Petroleum and Natural Gas M Veerappa Moily has said that the government will work towards securing energy independence for India. He has rolled out new vision and set ambitious targets to reduce crude oil imports by 50 per cent by 2020, 75 per cent by 2025 and eventually achieve self-sufficiency and energy independence for India by 2030.

He added that as only 73 billon barrels out of 205 billon barrels of prognosticated hydrocarbon resources have been established so far, leaving 133 billion barrels to be unlocked. To speed of implementation of new exploration programmes across the country, Petroleum Ministry recently constituted a committee under the Chairmanship of Vijay Kelkar, to prepare a roadmap for enhancing domestic production of oil and gas and sustainable reduction in import dependency by 2030.

Minister for Petroleum and Natural Gas M Veerappa Moily

Stressing need for increasing domestic oil and gas production, he said that the government will make every effort to reduce nation’s dependence on imported oil. This is particularly important given that last financial year we imported crude oil worth about USD 140 billion, he added. He further said the government is working to create enabling and conducive environment to promote investments, by making fiscal terms that are simple to administer.

He also said that the recently set up Cabinet Committee on Investments (CCI), a committee to fast-track large-delayed projects, has already given clearance for 5 out of 7 exploration blocks in the ‘No Go’ area.

OVL Eyes Foreign Assets, Acquires Two Caspian Assets Mumbai: State-owned energy major ONGC is likely to dominate India’s outbound M&A space, given that most private players are reeling under debt and those that have cash are adopting a wait-and-watch strategy amid global economic uncertainties.

ONGC’s overseas arm OVL is in advanced stages of negotiations to buy USD 10 billion worth of energy assets this quarter alone. It recently concluded a USD 1-billion deal to acquire a participating interest in Azerbaijan. The assets OVL is targeting include a 20 per cent stake in Mozambique gas fields for USD 5 billion and an 8.4 per cent stake from ConocoPhillips in Kashagan field for another USD 5 billion. If things go as planned, both these deals could be sealed in the current quarter.

This will make ONGC shell out USD 11 billion in 2013 alone, an amount that outnumbers what the company has spent since 1965 in acquiring a total of 27 energy assets in 14 countries.

The overseas arm of state-run Oil and Natural Gas Corporation has acquired stakes in oil-rich Chirag and Guneshli fields and an associated pipeline in Azerbaijan from US-based Hess Corporation. The acquisition would bring 9 per cent additional proved reserves to OVL portfolio and daily oil production of about 19,000 barrels.

The company had signed a deal with Hess Corp in September last year. The deal includes acquisition of Hess Corp’s 2.72 per cent stake in Chirag and the deepwater portion of Guneshli fields in the prolific Caspian Sea region and a 2.36 per cent stake in the Baku-Tbilisi-Ceyhan pipeline.

BP-operated oil and gas fields are located in the south Caspian Sea, about 95 km off the coast of Azerbaijan. OVL’s other partners in the fields are State Oil Company of Azerbaijan Republic, Chevron, Statoil, ExxonMobil, Inpex, Turkish NOC-TPAO and Itochu.

Offshore World | 30 | APRIL - MAY 2013

5/29/2013 5:13:31 PM

news Petronet LNG to Raise Fund through NCDs Mumbai: Petronet LNG Ltd, India’s biggest liquefied natural gas importer, plans to raise ` 600 crore in debt to fund expansion of its Dahej LNG terminal in Gujarat. Petronet plans to raise capacity of its Dahej import terminal to 15 million tonnes by putting up additional storage and regasification facility and a third jetty by next year.

The company has leased out most of the new capacity being built to state-owned GAIL India Ltd and Gujarat State Petroleum Corp (GSPC) on ‘useor-pay’ basis.

Petronet LNG has entered into long-term tolling arrangements for 2.5 million tonnes of capacity with GAIL and 2.25 million tonnes with GSPC. As per this arrangement, Petronet would provide GAIL and GSPC facilities for receipt, storage and re-gasification of LNG for contracted quantities without assuming responsibility for gas procurement. The firm would receive longterm advances under these tolling arrangements, which would help partly fund the equity part of the capex. These contracts, along with its existing long-term sale and purchase agreements with LNG suppliers and customers, would provide stable cash

Mumbai: Cairn India, the country’s largest private-sector oil producer, is keen to start city gas distribution in Rajasthan as it sees a huge natural gas potential in its block.

The company, which has discovered huge oil reserves in the Barmer region of the state, is keen to partner Rajasthan State Petroleum Corporation’s (RSPCL) joint venture with GAIL India for the new business, while the state government is supportive of the plan. A government official said a decision would be taken shortly.

Last November, RSPCL and Gail agreed to form a joint venture, Rajasthan State Gail Gas Company, where RSPCL is the nodal agency and facilitates Gail in acquiring land for city gas infrastructure.

In the joint venture, Gail has a 26 per cent stake while RSPCL has a 24 per cent.

CCI to Probe Report on Petrol Price Fixing New Delhi: The Competition Commission of India (CCI) said that it would shortly in the process of finalising its report on the probe into alleged cartelisation by the state-run oil marketing companies in fixing petrol prices.

In the sidelines of a seminar organised by the Associated Chambers of Commerce and Industry of India (Assocham) on competition law, CCI Chairman Ashok Chawla said that the regulatory is in the process of finalising the probe soon and are completing formalities for sending them an order which will ensure that there is investigation to see what is happening in terms of fixing of petrol prices.

The CCI had also written to the Petroleum and Natural Gas Ministry seeking its view on the cartelisation issue but the Ministry had said that it was not involved in fixing of petrol prices as it was a deregulated commodity since June 2010.

He said about 25-26 cases were now under investigation by the Director General. Noting that the Commission had responded to cases within a reasonable timeframe, he said the amount of information being received by it had increased in the last few months. He said the regulator had dealt with around 340 cases related to anti-competitive agreements and abuse of dominant position in the market.

Offshore World | 31 | APRIL - MAY 2013

India News 28-33.indd 31

Petronet has a 7.5 million tonnes per annum supply contract for LNG with RasGas of Qatar for its Dahej terminal and a 1.44 million tonnes supply contract with Australia’s Gorgon project for its completed, and soon to be commissioned 5 million tonnes Kochi terminal.

Besides dahej terminal expansion, Petronet is also setting up a new 5 million tonnes terminal at Gangavaram in Andhra Pradesh.

India, China Race for Gas Fields

Cairn – GAIL JV in Pipeline

Ashok Chawla, Chairman, Competition Commission of India (CCI)

flows over the contractual period and insulate the company from volatility in LNG prices or demand.

New Delhi: The great game between India and China to secure energy assets around the world is now all set to play out in the deep waters of Mozambique - home to the world’s biggest gas discovery in a decade. Just hours before the deadline for the non-binding bids for Videocon’s 10 per cent stake in Rovuma offshore block in Mozambique were to be submitted, China’s largest oil producer, China National Petroleum Corporation (CNPC), picked up a strategic 20 per cent stake in ENI’s Mozambique asset for USD 4.2 billion. With this acquisition, CNPC will get access to 75 trillion cubic feet (TCF) of in-place resources, or more than Norway’s existing reserves. Incidentally, the block in question Rovuma Offshore Area 4 - adjoins Rovuma Area 1, where Videocon and consortium partner Anadarko are both selling 10 per cent each. With the entry of the Chinese, a bidding war for the adjoining acreage is, therefore, also anticipated by most.

With expected recoverable gas reserves of close to 60 trillion cubic feet, Rovuma-1 is among the most sought-after global gas asset today. Even at a 50 per cent probability of recovery success – ‘P2 or proven plus probable reserves’ in industry parlance - the expectation is of 42 TCF of natural gas. To put it in context, this is twenty times India’s current annual gas consumption. Mozambique may have 250 TCF of reserves, according to Empresa Nacional de Hidrocarbonetos, the country’s state-backed energy company.

The state-owned ONGC Videsh (OVL) and Oil India are expected to compete with Asian peers like Sinopec along with some of the biggest global names Shell and BP for a strategic toehold in Mozambique as the bids for Rovuma 1. www.oswindia.com

5/29/2013 5:13:34 PM

OIL and IOT Ink for EPC Jobs Mumbai: Oil India Limited (OIL) and IOT Infrastructure & Energy Services Limited have inked Memorandum of Understanding (MoU) for the EPC (Engineering-Procurement-Construction) jobs.

According to MOU both the companies will explore development of city or Natural Gas distribution network in India and overseas.

As per the agreement, OIL and IOT Infrastructure & Energy Services Limited will jointly take up construction jobs for Natural Gas/ Crude Oil/ Product Pipelines & associated Pump Stations, within the country & overseas besides pursuing any other business opportunities, which are mutually beneficial to both the parties. Both the companies have decided to cooperate in sharing technology & knowledge, in areas of mutual interests.

ONGC to Overhaul More Offshore India New Delhi: ONGC plans a revamp of unmanned platforms on its Mumbai High, Neelam and Heera assets offshore western India.

The BPA and BPB processing complexes serving the prolific Bassein field and satellite were commissioned respectively in 1987 and 1989. Both handle and process acidic and corrosive gas (with H2S) for onward delivery to the Hazira gas processing plant. Their original design lives were each 25 years.

ONGC’s revamp proposal covers various fixed equipment and pipelines, with work due to be performed on BPB during 2013-2014 and on BPA in 2014-2015.

In the Krishna Godavari basin offshore eastern India, the company has found gas and condensate with the Saveri # 1 well in NELP block KG-OSN-2004/1. The location is in the KG shallow offshore basin, 25 km (15.5 mi) south of Narsapur.

On test the well flowed gas from one interval and gas and condensate higher up from another interval.

ONGC views this as a high-potential discovery, boosting volumes added from the Chandrika South and Alankari finds on the same block, with potential for a cluster development.

Heidelberg ProMinent to Enter Indian Oil and Gas Sector Bengaluru: Bengaluru-based Heidelberg ProMinent Fluid Controls, the wholly-owned subsidiary of the Germany-based ProMinent Group, plans to tap Indian oil and gas sector as it sees huge potential in the country.

Heidelberg ProMinent manufactures about 60 per cent of the product range manufactured by Prominent in Germany. A certain range of products are now manufactured only in India and exported to group companies in countries including Australia, Brazil, China, Germany, Malaysia, Singapore, Thailand and so on.

The ProMinent group is manufacturer of components and systems for the metering technology, water treatment solutions partner for over 50 years. It is based in Heidelberg, Germany with around 2,300 employees in 57 dedicated sales, production and service companies and agencies in over 100 countries guarantee that the company’s products and services are available all over the globe.

The Indian subsidiary Heidelberg ProMinent, with its famility in B Bengaluru, manufactures Dosing Pumps, Dosing systems, Chlorine di oxide generators and allied equipments. It is one of the seven manufacturing locations of ProMinent worldwide. Dosing pumps are used in all segments of Industry including chemical, fertilizer, process, paper, sugar, pharmaceutical, engineering etc. All the leading companies in India are on the customer list of Heidelberg ProMinent. www.oswindia.com

India News 28-33.indd 32

Paradip Port – IOCL Mull over LNG Terminal New Delhi: Paradip Port Trust (PPT) has initiated dialogue with Indian Oil Corporation for setting up an LNG terminal at the port. S S Mishra, S S Mishra, Chairman Paradip Port Trust (PPT) Chairman, PPT, said that the port furnished all the information IOC had asked for and it is now for them to respond. About IOC’s MoU with Dhamra port, the State’s first port sector joint venture between Tata Steel and Larsen & Toubro, he said that by all accounts, Paradip port is much better placed for handling LNG. To support his argument, he said that first, IOC’s Paradip refinery, to be commissioned within a year or two, was located close by and the refinery and other industries in the region would consume at least 1.5-2 million tonnes of LNG annually.

Next, connectivity-wise Paradip port was second to none and finally, about 200 to 300 acres of land, which might be required for the proposed terminal, was readily available with the port.

MRPL Plans Expansion Mangalore: Mangalore Refinery & Petrochemicals Limited (MRPL), the subsidiary of Oil and Natural Gas Corporation Limited P P Upadhya, Managing Director, (ONGC), is all set MRPL to expand into a 21 MMTPA refinery with a Pet coke Gasification Unit and an LAB (Linear Alkyl Benzene) unit.

In line with the Perspective Plan 2030, the company also planned to diversify into petrochemicals, said P P Upadhya, Managing Director, MRPL. He added that a Polypropylene plant is getting ready in MRPL Phase III while a JV company, ONGC-Mangalore Petrochemicals Limited (OMPL), is off to a running start and is expected to commission its aromatic plant by September 2013.

Offshore World | 32 | APRIL - MAY 2013

5/29/2013 5:13:37 PM

news Kelkar to Head Energy Security Panel

HPCL Receives BML Munjal Award New Delhi: Hindustan Petroleum Corporation Limited (HPCL), the state-owned oil and natural gas company, has received the coveted ‘BML Munjal Award’ for Excellence in Learning and Development. HPCL Chairman and Managing Director, S Roy Choudhury, Chairman & Managing Director, S Roy Choudhury and Director – HR, HPCL, receives the award from Union Minister of State Pushp Joshi received the award from for Human Resource Development Shashi Tharoor Hon’ble Minister of State for Human Resource Development, Shri Shashi Tharoor.

The founding Chairman of Hero Group, Dr BML Munjal and the Joint Managing Director of Hero Motor Cor Shri Sunil Kant Munjal were also present on the occasion.

The award was presented during the Mindmine Summit held recently in New Delhi, which is the annual flagship event of the Hero Corporate Services Limited, a Hero Group Company.

New Delhi: The Petroleum and Natural Gas Ministry has constituted a new committee headed by economist Vijay Kelkar to put in place a policy on energy security and prepare a roadmap for enhancing domestic oil and gas production to reduce dependence on exports by 2030.

Dr Kelkar, who had also prepared a roadmap for Dr Vijay Kelkar, Economist deregulation of the retail oil and gas sector, has been asked to submit his report within six months. India at present imports 80 per cent of its oil and gas requirements and about half of its natural gas requirement. The panel has also been asked to suggest utilisation of Oil Industry Development Board (OIDB) cess and other innovative resource mobilisation approaches for appraising the unexplored /partly explored acreages and development and promotion of indigenous service industry in the E&P (exploration and production) sector.

The committee would also review institutional mechanism for acquisition of oil and gas assets abroad as well as pursuing diplomatic and political initiatives for import of gas from neighbouring and other countries with emphasis on trans-national gas pipelines. The committee has invited comments from stakeholders on this matter.

Oil Ministry to Devise Framework for Gas Pooling New Delhi: The Petroleum Minister M Veerappa Moily has said that he would approach an Empowered Group of Ministers (EGoM) to derive a roadmap for gas pooling mechanism for power sector. The Petroleum Ministry is considering the step after a delegation of Anil Ambani, Chairman, Reliance; G M Rao, Chairman, GMR;

and Madhusudan Rao, Chairman, Lanco, presented to the Minister that if such a mechanism is not put in place nearly 24,000 MW would turn into non-performing assets (NPAs).

“They (head of power companies) have suggested solutions to overcome gas shortage to power projects

spread all over the country. Around 24,000 MW of power have been denied (natural gas) and they are partially or fully non-operational,” said Moily.

Moily added that a lot of other Ministries are also involved such as Power, Fertiliser and Agriculture.

There are many decisions taken on priority.

Punj Lloyd Forays into Middle East

Kerala High Court Sends Notices to Union Govt, IOC, HPCL

New Delhi: Indian infrastructure major Punj Lloyd has bagged a contract worth ` 3.14 billion (USD 57.75 million) from Al-Khafji Joint Operations for an offshore project in Al-Khafji, Saudi Arabia. The project, worth Rs 3.14 billion, is scheduled for commissioning in September 2014.

Thiruvananthapuram: Kerala High Court has issued notices to the Central Government, Indian Oil Corporation (IOC) and Hindustan Petroleum Corporation Ltd (HPCL) on a petition by the Kerala State Road Transport Corporation (KSRTC), seeking to grant it diesel subsidy.

Al-Khafji Joint Operations is a joint operation of two companies, Aramco Gulf Operations Company Ltd (AGOC) of Saudi Arabia and Kuwaiti Gulf Oil Company (KGOC), for oil and gas exploration development and production in the offshore area of the partitioned neutral zone between Saudi Arabia and Kuwait.

Justice V Chidambaresh admitted the petition filed by the KSRTC Managing Director, seeking a declaration that the diesel price hike, compelling KSRTC to pay the enhanced rate was ‘illegal and arbitrary’, and issued the notices.

Counsel for the oil companies contended that the state is charging Rs 12 as sales tax towards one litre of diesel and they are not prepared to forgo it. The petitioner submitted that in a similar situation in Tamil Nadu, the High Court had directed to provide diesel subsidy to state owned buses.

The scope of work for the project entails detail design, engineering, procurement, testing, transportation and construction/installation of a new 20” OD crude transmission line, 40 km submarine rigid pipeline, mechanical completion among others.

The purpose of this project is to install a new crude transmission pipeline as a replacement for the existing transmission line.

The court had ordered interim injunction restraining charging of diesel at a higher rate. According to the corporation, they are facing an acute financial crisis and there was deficiency of ` 940 million in a month and annual revenue gap of ` 11.28 billion. The restriction imposed by the government is discriminatory.

Offshore World | 33 | APRIL - MAY 2013

India News 28-33.indd 33

www.oswindia.com

5/29/2013 5:13:40 PM

Americas FoundOcean Completes Pipeline Installation in GoM US: FoundOcean has completed installation and grouting for a clamp repair on an 18-inch pipeline in the Gulf of Mexico under contract from Saipem America.

The seabed a water depth of 750 m (2,460 ft) was dredged at around the damaged area of the pipeline. An ROV maneuvered the two steel halfshells of the clamp into position and pre-tightened the bolts. FoundOcean then connected the hose to the inlet valve on the clamp and delivered the grout using its deepwater grouting umbilical system. Due to the extra load, a fabric formwork was installed under the clamp to provide more support.

EMGS, Spectrum Agree in Geophysical Coverage Offshore Brazil Brazil: Electromagnetic Geoservices ASA (EMGS) and Spectrum ASA (Spectrum) have agreed to cooperate on offering geophysical coverage of Brazil’s Foz do Amazonas basin.

Spectrum has over 21,000 km (13,049 mi) of multi-client 2D seismic data for this area of the equatorial margin. EMGS has access to this data for planning and improved imaging purposes and plans acquisition of 3D resistivity data in a regional, multi-client program covering approximately 8,000 sq km (3,089 sq mi).

BOA Galatea will start 3D EM data acquisition close to the border of French Guiana’s territorial waters and work its way southeast. Survey completion is expected in August 2013. The deliverables include seismicconstrained 3D EM inversion cubes, interpreted lead maps, and probabilistic resource estimates.

BP Confirms Oil Discovery Offshore Brazil Brazil: BP has completed a successful flow test of the Itaipu-1A discovery well offshore Brazil. The drillstem test achieved flow rates of up to 5,600 b/d for 32 hours through a 40/64 choke from a limited perforated interval. Results from the pressure build-up after the main flow indicated good connectivity in the reservoir. Long-term pressure monitoring gauges were also set in the wellbore prior to the end of operations.

In total 28 metric tonnes (30.86 tonnes) of cement was used: 4 metric tonnes (4.4 tonnes) for the clamp and 24 metric tonnes (26.46 tonnes) for the fabric formwork. The pipeline damage resulted from an anchor drag during bad weather.

Cal Dive to Install Subsea Pipeline in Bay of Campeche US: Pemex has contracted Cal Dive International Inc to engineer, procure, install and commission a 12 km (7.5 mi) long 8-inch subsea pipeline and tie-ins involving four platforms in Abkatun-PolChuc field in the Bay of Campeche.

Work on the USD 63-million award is expected to begin in third quarter of 2013 and include the services of three of Cal Dive’s vessels. Cal Dive has done work in the area before.

Neil Piggott, Vice President Exploration, BP - Brazil

drilled in 2009 by Devon.

Neil Piggott, BP Vice President for exploration Brazil, said that this is a good result for the Itaipu project, indicating that commercially viable flow rates can be achieved from this presalt carbonate reservoir.

The Itaipu-2 appraisal well was drilled in 2011. A second appraisal well location, Itaipu-3, has been agreed with the Brazilian National Petroleum Agency (ANP), and will be the next operation at the Itaipu field later this year. BP is the operator of BM-C-32 with a 40 per cent equity. Other equity holders are Anadarko Petroleum Corp (33.3 per cent) and Maersk Energia Ltda (26.7 per cent).

Oil Discovers in Deepwater GoM Mexico: Chevron Corp, an American multinational energy corporation headquartered in San Ramon, California, United States, has an oil discovery at the Coronado prospect in the deepwater US Gulf of Mexico. Walker Ridge block 98 Well No. 1 encountered more than 400 ft (122 m) of net pay. The well is located approximately 190 mi (308 km) off the Louisiana coast in 6,127 ft (1,868 m) of water and was drilled to a depth of 31,866 ft (9,713 m).

SeaBird to Collect Seismic Data in Caribbean Mexico: SeaBird Exploration Plc, the global provider of marine 2D/3D/4D seismic data, and associated products and services to the oil and gas industry, has signed a USD 12.5-million, 85-day, agreement for the Geo Pacific to collect marine seismic data in the Caribbean.

Work is expected to begin later this month following completion of sea trials offshore Las Palmas.

Earlier this year, SeaBird contracted the Harrier Explorer to MultiClient Geophysical to acquire seismic data offshore Barbados. www.oswindia.com

International News 34-40.indd 34

The Itaipu-1A presalt well is located in block BM-C-32 in the deepwater sector of the Campos basin, 125 km (78 mi) offshore Brazil. The well was

Gary Luquette, President, Chevron North America Exploration and Production Co

“The Coronado discovery continues our string of exploration successes in the Lower Tertiary trend, where Chevron is advancing multiple projects,” said Gary Luquette, President, Chevron North America Exploration and Production Co.

Gary Luquette, President, Chevron North America Exploration and Production Co, said that the Coronado discovery continues Chevron’s string of exploration successes in the Lower Tertiary trend, where the company is advancing multiple projects. He added that It also highlights the importance of the deepwater Gulf of Mexico as a source of domestic energy for the United States.

Offshore World | 34 | APRIL - MAY 2013

5/29/2013 5:08:15 PM

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news

Africa Afren to Drill Offshore Nigeria

Offshore Peru Platform All Ready to Drilling

Nigeria: Afren is preparing to drill two exploration wells offshore Nigeria.

Peru: BPZ Energy has announced that platform monitoring and control system modifications are under way offshore Peru to prepare the new CX-15 platform for the start of development drilling.

Offshore lease OML 115, which the company operates in partnership with Oriental Energy Resources, surrounds the Ebok and Okwok development area, and is close to the Zafiro complex in Equatorial Guinea.

Temporary equipment is tracking platform response to weather and ocean conditions, and draft during the engineering/installation work. As a precaution, an anchoring system under construction in Peru will be fitted to provide redundancy to the spud can that anchors the platform.

A joint technical team is close to finishing its review of the new Corvina field 3D seismic data to update geological interpretation.

The GSF Monitor is likely to spud the first well this spring on the Ufon structure, which is structurally and geologically analogous to the nearby Ebok and Okwok fields but with deeper exploration potential.

Offshore lease OPL 310, operated by Optimum Petroleum Development, is next to the Aje field, which has been declared commercial. The acreage is in an under-explored basin with a proven working hydrocarbon system, and is close to the recently completed West African Gas Pipeline (WAGP), which has the capacity to tie in future gas discoveries.

Afren has identified various prospects in the same Cenomanian, Turonian, and Albian sandstone intervals that yielded discoveries along the West African Transform Margin in Ghana and Côte d’Ivoire.

The partners are continuing detailed technical work and well planning ahead of a planned exploration well prior to mid-year.

Anguille to Deliver Soon Offshore Gabon Gabon: Total has announced the Phase 3 of offshore Gabon is continuing on schedule. Four wells have been drilled by the Setty rig from the new AGMN platform. Three subsea flowlines have been installed and connected to the platform to tie it back to the central complex.

First oil should be achieved soon. Installation of the power grid for the Anguille and Torpille sectors has been completed. The onshore power plant on the PG2 site and the new electrical systems installed offshore on Anguille/Torpille sectors are undergoing tests.

Commissioning of the new power grid is expected to follow next month.

Elsewhere off Gabon, Total says drilling of the Diaman-1 exploration well on the Diaba license has been postponed to later in the current quarter, due to delayed availability of the drillship Ocean Rig Olympia.

FAR Expands Acreage Offshore Kenya Kenya: FAR Ltd is stepping up its involvement offshore Kenya. The Kenyan government has confirmed a 60 per cent expansion of FAR’s L6 exploration permit off the coast of Kenya. This additional area increases the total permit area to 5,010 sq km (1,934 sq mi).

From recently acquired processed 3D seismic data and earlier 2D seismic data, FAR has found a new Miocene carbonate reef play that extends into the new acreage, and estimates the total prospective resources on L6 to be 3,962 MMbbl of oil or in a gas only success case, 10,689 bcf (unrisked, best estimate, 100% basis).

Nobel Spuds Offshore Equatorial Guinea Guinea: The semisubmersible Atwood Hunter has spudded the Noble Energy-operated I-7 exploration well on the Carla South prospect offshore Equatorial Guinea.

According to partner PA Resources, the prospect is on trend with the Carla North discovery that was appraised recently in block O, north of block I. The target is Tertiary sandstones of similar age to those in the discovery to the north. It is expected to take about 25 days to reach total depth, with a side track likely to follow. Later this year, another appraisal well could be drilled on the Diega discovery in block I.

HRT Spuds Deepwater Offshore Namibia Namibia: The semisubmersible Transocean Marianas has spudded the Wingat-1 well offshore Namibia for HRT Walvis Petroleum (Proprietary). The well targets the Wingat prospect on petroleum exploration license 23 in the Walvis basin, 200 km (124 mi) northwest of Walvis Bay. Water depth is 1,034 m (3,392 ft).

HRT is targeting an elongated combination trap with a potential P10 area of 381 sq km (147 sq mi), including a four-way structural closure of 42 sq km (16 sq mi). The main objective is to test the resource potential of the Albian carbonate platform, which has a well-defined seismic amplitude anomaly in the PSDM 3D data set. Reservoirs will likely be encountered at 3,950 m (12,959 ft) below sea level. Wingat-1 will be drilled to a projected TD of 4,100 m (13,451 ft), with total drilling time estimated at 60 days. This is the first of three back-to-back wells for HRT, in partnership with Portugal’s GALP Energia.

Dolphin Applies Seismic in Offshore South Africa South Africa: Dolphin Geophysical has used a seismic survey spread that it describes as the world’s largest floating object. The eight streamers were 8 km (5 mi) long and separated by 200 m (656 ft), giving a total area covered under tow of 11.2 sq km (4.3 sq mi). The equipment was used offshore South Africa under contract with Shell and using the Polar Duchess seismic vessel. The big spread was used to get 8,000 sq km (3,089 sq mi) surveyed during a limited weather window of four months. Shell’s processing center in Houston validated the initial returns and is processing the data.

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Russia & EU 3D Seismic Survey in Offshore Norway Norway: CGG has started acquiring Phase 1 of its Steppingstone BroadSeis 3D multi-client survey program offshore Norway.

Steppingstone Phase 1, also called Halten Terrace, covers 2,260 sq km (873 sq mi) and targets the southern trend of Jurassic reservoirs and Cretaceous discoveries. The three-month program is being acquired by the Oceanic Champion.

The BroadSeis acquisition and processing parameters are optimized to focus on providing better imaging of prospective Jurassic rotated fault blocks, inversion anticlines, and shallow targets. The survey is expected to open potentially prospective late Cretaceous/Tertiary turbidite plays to the west.

Northern Hopes Significant Oil in Offshore Italy Italy: Northern Petroleum is expecting its Cygnus prospect offshore southern Italy could hold up to 790 MMbbl of recoverable oil within the F.R39.NP permit.

Cygnus is adjacent to and updip of Eni’s producing Aquila oil field. The resource estimate, based on the common oil/water contact between the two structures, follows analysis by ERC Equipoise (ERCE).

Northern adds that its mapping of available 2D seismic data has not found a separation or barrier from the producing Aquila oil wells. ERCE was commissioned following the publication of previously undisclosed well data relating to the Aquila field in an environmental submission by operator Eni. The Aquila wells are in the production concession adjacent to Northern’s permit. The prospect trap for Cygnus is predominantly stratigraphic, with the same reservoir as the Aquila field, comprising Cretaceous re-sedimented carbonates derived from the Apulian platform.

Northern plans to acquire new 3D seismic over Cygnus, the similar nearby Cebus prospect and the Rovesti oil discovery off the Italian east coast, following receipt of environmental approvals. The company has started collating data for submission of an environmental impact assessment for regulatory approval for drilling and testing a well on Cygnus. It is seeking partners for both the well and the seismic surveys. www.oswindia.com

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More Oil Found in Luno Area Norway: Lundin Norway has a new oil discovery on the Utsira High region of the Norwegian central North Sea. The semisubmersible Bredford Dolphin drilled well 16/4-6S on the Luno II prospect on license PL359 in a water depth of 101 m (331 ft). The location is on the southwest flank of the Utsira High, 15 km (9.3 mi) south of the Lundin-operated Edvard Grieg field development.

The well has drilled through a section comprising around 200 m (656 Ashley Heppenstall, President and ft) of sand with a high net-to-gross content, proving a light oil column CEO, Lundin Petroleum of more than 40 m (131 ft) gross. Oil-water contact was encountered roughly 1,950 m (6,397 ft) below mean sea level. Pressure data indicate that the petroleum system is different to that in the Edvard Grieg and Johan Sverdrup fields. A production test will follow, along with coring, logging, and fluid sampling. Ashley Heppenstall, President and CEO of parent company Lundin Petroleum, said that the reservoir quality, whilst not the same as Johan Sverdrup, appears good and will now be tested. The company expects to provide a range of recoverable resources from the discovery after testing is completed in two to three weeks time. After completing the test program the rig will switch to PL501 to continue appraisal drilling for Lundin on Johan Sverdrup.

Schlumberger to Design Wells in Caspian Field Russia: LUKOIL has contracted Schlumberger to design wells for the V Filanovsky field development in the northern Caspian Sea. In 2012, subsidiary company LUKOIL-Engineering opened the Center of Geologic Exploration Technologies at its premises in Moscow. It was established for integrated studies of prospective assets in the company’s licensed areas, applying advanced geologic exploration technologies and equipment supplied by Schlumberger, LUKOIL’s partner in the project.

Hardware and software developed by the center is designed to make reservoir modeling more reliable, forecasting of oil and gas incidents more precise, and to lessen geological risks and uncertainties. V Filanovsky was discovered in 2005. It is LUKOIL’s second offshore project in the Russian sector of the Caspian Sea. Production is scheduled to start in 2015.

EMAS AMC Secures Offshore Pipelay Contract for Aasen Field Norway: Det norske oljeselskap ASA has awarded EMAS AMC a USD 165-million contract for rigid pipelay and related subsea work at the Ivan Aasen field in the Norwegian North Sea. The contracted scope of work includes project management, detailed engineering and procurement, construction, and installation of three 10-km (6.2-mi) rigid pipelines via reels, including spools, pipeline end terminations (PLETs), and seabed intervention.

The contract also has an option for EMAS AMC to procure and install a subsea power cable connecting the neighboring Edvard Grieg platform to the Ivar Aasen platform. Project management and engineering work will commence immediately and will be managed from EMAS AMC’s office in Oslo. Offshore activities are scheduled to commence in 2015, with completion in 2016.

BG Commences Production from Everest East Project UK: BG Group has started production from its Everest East expansion project in the UK central North Sea. This involves two subsea wells connected to the North Everest platform and brownfield modifications to the existing production system. Output should build to a peak of more than 10,000 boe/d. Total reserves under development are 20.6 MMboe. BG Group operates the Everest field with a 99.1 per cent interest. Production started in 1993.

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news

South East Asia Newfield Strikes Gas Offshore Sarawak

CNOOC Commences Production from Beibu Gulf Platform

Malaysia: Newfield Exploration Co has a natural gas discovery in the block SK 310 production sharing contract 50 mi (80 km) offshore Sarawak in approximately 250 ft (76 m) of water. The B-14 well encountered 1,800 ft (549 m) of gross column and 1,585 ft (483 m) of net natural gas pay in the main carbonate objective. A drillstem test has confirmed commerciality of the reservoir. Newfield estimates that gas initially in place (GIIP) ranges from 1.5 – 3.0 tcf.

China: China National Offshore Oil Corp (CNOOC) has started first production from the WZ 6-12 wellhead platform offshore China in the Beibu Gulf. The A5H and A2 development wells are the first online and three more production wells are anticipated within a few weeks. The HYSY 931 jackup drilling rig will drill three additional development wells (A8, A9, and A10). The successful A6 and A7 wells, drilled late 2012, will be equipped for production. A number of completion hook-up and commissioning activities are in progress.

On completion, 10 wells will have been drilled from the WZ 6-12 platform and connected to the production system, five more wells than originally contemplated.

This is Newfield’s second pinnacle reef natural gas discovery in the region and is less than 3 mi (4.8 km) from the first pinnacle reef gas discovery, B-15, also on block SK 310. Recoverable reserves here are estimated at approximately 265 bcf and will be developed in conjunction with the B-14 discovery. Newfield operates block SK 310 with a 30 per cent interest. Partners Diamond Energy Sarawak, a wholly owned subsidiary of Mitsubishi Corp. and Petronas Carigali, have 30 per cent and 40 per cent interests, respectively.

Petrofac Finds More Oil Offshore Malaysia Malaysia: Petrofac has drilled a successful appraisal well on the Cendor field offshore Peninsular Malaysia. The company said that the Cendor Graben-2 well was drilled on block PM304 to a depth of more than 1,000 m (3,281 ft), confirming the presence of oil and some gasbearing reser voirs. Amerada Hess discovered the field in 2001. At the time it was considered marginal with recoverable resources estimated at 12 MMboe. Petrofac assumed Amerada Hess’ operating interest in 2004.

The drilling rig is expected to move to WZ12-8 West wellhead platform for the final phase of development drilling during the third quarter. Production from the Beibu fields will progressively ramp up through the year as batches of development wells are drilled, completed and brought on line. Participating interests in the Beibu Gulf Development Project are CNOOC, 51.0 per cent; Roc Oil (China) Co., 19.6 per cent; Horizon Oil (Beibu) Ltd and Horizon Oil (Nanhai) LLC1, 26.95 per cent; and Oil Australia Pty Ltd (Majuko Corp), 2.45 per cent.

Technip to Pipelay Offshore Malaysia Malaysia: Shell has awarded Technip pipelay contracts for two projects offshore Malaysia. Sarawak Shell Berhad has commissioned two new gas-export lines at the Laila and D12 fields. Laila is 50 km (31 mi) northwest of Miri in a water depth of 75 m (246 ft), and D12 is 140 km (87 mi) offshore Bintulu in 50 m (164 ft) of water.

Technip will design, fabricate, and install one 5-km (3-mi), 7-inch diameter flexible pipeline, and one 10-km (6.2-mi), 12.8-inch flexible pipeline, using its new construction vessel Deep Orient. The company will additionally provide diver installation of riser clamps at both jacket platforms, pre-commissioning of the flowlines, and project management. Technip’s operating center in Kuala Lumpur will manage the program, scheduled for completion in 1Q 2014. The flexible flowlines will be manufactured at the group’s Asiaflex Products plant in Tanjung Langsat, Malaysia. Sabah Shell Petroleum Co has commissioned Technip for pipelay for the Malikai deepwater projectoffshore Sabah, in 650 m (2,132 ft) of water. The scope covers transportation, installation, and pre-commissioning of one 50-km (31-m), 8-inch gas line and one 55-km (34-mi), 10-inch liquid pipeline, plus steel catenary risers. The pipelines will extend from the Malikai tension leg platform site to the Kebabangan platform. Technip centers in Kuala Lumpur and Singapore will execute the work, scheduled for completion in 2Q 2015, with the S-Lay vessel G1201 performing offshore installations.

Pipelay Proceeds from Offshore Myanmar Subsequent appraisal and development has transformed Cendor into one of Malaysia’s largest oil fields, Petronas said. First oil was produced in September 2006 using a leased mobile operating production unit, the first in service at the time offshore Malaysia. Since then, the field has performed above expectation, leading to further activities both on Cendor and surrounding areas of the block, and culminating in Cendor Phase 2 and other new developments in PM304. These have lifted the recoverable reserves estimate to more than 200 MMbbl. The other projects on the block, fasttracked over the past two years, are expected to enter production in stages throughout 2013, raising production to around 30,000 b/d by year-end.

Myanmar: Pipelay is under way offshore Myanmar to take natural gas 230 km (143 mi) from Zawtika field to shore. The field is operated by PTTEP International. Installation of the line is being supported by Hallin Marine’s Penrith DP-2 offshore support vessel with third-party work-class ROV. The ROV will check free spans, and those exceeding specification will be infilled with grout.

Vietnam FPSO Set to Deliver More Oil Vietnam: Hoang Long Joint Operating Co has completed the first phase of a multi-stage test of the Te Giac Trang (TGT) field FPSO oil production handling capacity. This follows approvals from the Vietnamese authorities and the vessel owner. TGT is in the Nam Con Son basin offshore southern Vietnam. Its minimum contracted oil production is 55,000 b/d, but the test successfully processed sustained output of more than 60,000 b/d. According to partner SOCO Energy, this confirmed expectations, based on detailed pre-test simulations, that only minor modifications to the low-pressure separator system would be needed. The changes will now be implemented ahead of the next phase of the testing program when volumes of more than 60,000 b/d will be processed.

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Middle East Petrofac Secures Engineering Contract for SARB Complex UAE: Abu Dhabi Marine Operating Co (ADMAOPCO) has awarded Petrofac a USD 500-million engineer, procure, install, and commission contract for the offshore Satah Al Razboot (SARB) Package 3 project. The work is expected to complete by 2016.

SARB is a new field development off the northwest coast of Abu Dhabi. Drilling will be performed from two artificial islands (SARB1 and SARB2) with the well fluids sent by subsea pipeline to a facility on Zirku Island for processing, storage, and export.

Petrofac will supply 200 km (124 mi) of subsea pipelines for well fluid, water injection, gas injection, flare, and export; 3 km (1.8 mi) of onshore pipeline; and 55 km (34 mi) of subsea power and communication cables. Additionally it will provide two riser platforms and four flare platforms with four interconnecting bridges and one singlepoint mooring buoy to be located north of Zirku Island. Onshore scope includes provision of drilling utilities, foundations for SARB1 and SARB2, transport, installation, hook up, and assistance in commissioning of the accommodation modules.

Last Jacket Installs at Offshore Iran Iran: Pars Oil and Gas has loaded out the third and final jacket for the South Pars Phase 19 gas development offshore Iran. It has been transported to the offshore location in the Persian Gulf, and should be installed soon. Jackets A and C are already in place. According to Phase 19 project director Hamidreza Massoudi, this latest six-legged jacket weighs 1,800 tonnes, and is designed to provide more capabilities than four-legged structures elsewhere on South Pars. This phase of South Pars involves drilling 15 development wells and a connection to a satellite platform on South Pars Phase 1, which has six production wells.

Nobel Confirms Gas Build-up Offshore Israel Israel: Noble Energy has reported that all five of the Tamar field deepwater subsea wells offshore Israel are online, and collectively producing 300 MMcf/d of gas. This, combined with the partners’ existing volumes from the nearshore Mari-B facilities, brings total current sales to nearly 500 MMcf/d, with levels expected to build to 1 bcf/d during the summer demand peak. Initial sales started on March as natural gas flowed from the subsea wells to the shallowwater Tamar platform, and from there to the Ashdod onshore terminal.

Charles D Davidson, Noble Energy’s Chairman and CEO, said that In just over four years from discovery, the Tamar project is fully operational and delivering significant volumes of natural gas to Israel. The project is a technological and commercial milestone for Noble Energy and our partners.

Charles D Davidson, Noble Energy’s Chairman and CEO

He added that this is the third major global project the company has brought online in the last 18 months and it will make a significant contribution to the company’s continuing production growth. Building on this success, the company is now working with the government and its partners to sanction the next phase of development at Tamar and the domestic phase of Leviathan.

Reserves at Tamar have been upgraded from 9 tcf to 10 tcf, following results of development drilling and ongoing reservoir analysis and modeling. The development includes five subsea wells, each capable of flowing 250 MMcf/d of natural gas through what is claimed to be the world’s longest subsea tieback (more than 90 mi, or 145 km, to the platform near the existing Mari-B structure).

Dragon to Expand Caspian Offshore Drilling Fleet Turkmenistan: Dragon Oil expects to step up development drilling later this year on the Cheleken Contract Area (CCA) of the Caspian Sea, offshore Turkmenistan. Currently, two rigs are in operation. One is a leased platform rig that is drilling the side track well Dzheitune (Lam) 28/151A. The other, a jackup, is batch drilling the Dzheitune (Lam) 21/180 and 21/181 development wells, and will continue to work for Dragon through May 2015. During the second half of this year, the company expects to take delivery of three more rigs. Two platform rigs are expected to start drilling on the Dzhygalybeg (Zhdanov) later in 2013, while the new jackup Caspian Driller is expected to arrive in mid-year.

Dragon has converted one well in the target Dzheitune (Lam) 75 area into an injector-type well, and plans to start constant injection of water next month. Currently, intermittent water injection is being performed on one well in the Dzheitune (Lam) 13 area, and the company is considering further extensions of the waterflood project. The Dzhygalybeg (Zhdanov) A platform is currently being installed and is expected to be ready for drilling in 2013. The Dzhygalybeg (Zhdanov) B platform is under construction in Dragon’s yard in the harbor area in Hazar, and is due to be installed and ready for drilling in 2H 2013.

Iranian First LNG Plant All Ready to Launch Punj Lloyd Secures EPC Contract from Al-Khafji Iran: Regardless of European Union futile attempts putting ban on Irans energy sector, Iran is ready to launch the initial phase of its first liquefied natural gas (LNG) plant in the country. A 1100-megawatt power plant, LNG and liquefied petroleum gas (LPG) storage facilities in addition to offshore docks are included in the first phase of the plant. The due time for the plant to dispatch its first LNG consignment to international markets is before March 2014. www.oswindia.com

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Saudi Arabia: Al-Khafji Joint Operations has awarded Punj Lloyd Group an Engineering, Procurement and Construction (EPC) contract for a project offshore Saudi Arabia. The USD 57.75-million project is scheduled for commissioning in late 3Q 2014. The scope of work entails detail design, engineering, procurement, testing, transportation, and construction/installation of a new 20-inch OD crude transmission line, 40-km (25-mi) submarine rigid pipeline, mechanical completion, pre-commissioning, commissioning/start up, and performance testing. The scope also includes modifications at Ratawi Gathering Station, scraper launcher, tie-ins with existing facilities including utilities, valves and piping, riser and riser clamps, deck extension for installation of new facilities and onshore section at Al-Khafji from landfall to scraper receiver, scraper receiver, tie-ins with existing facilities including utilities, valves and piping.

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products

PORTABLE PETROLEUM HYDROCARBON ANALYZER Swan Environmental West Pvt Ltd offers a wide range of portable petroleum hydrocarbon analyzer. This is the ideal instrument for precise measurement and quantification of petroleum hydrocarbons dissolved in water and/or as vapour.

It is designed to meet rigorous field monitoring requirements and has proven itself in industrial, off-shore oil platform and remote field operation applications, while eliminating delays and costs associated with typical laboratory testing.

For details contact: Swan Environmental West Pvt Ltd Row House No: C-3, Sector-4 Opp: Fire Brigade, Airoli, Navi Mumbai 400 708 Tel: 022-27792701, Fax: 91-022-27792701

Pall presents the second in its family of HLP Series fluid conditioning purifiers – the HLP22 oil purifier.

The HLP Series combines the water removal performance of mass transfer purifiers with high reliability and ease-of-use to help ensure maximum equipment up-time and lowest cost of ownership – enabling you to focus on your process, and not your equipment. Pall HLP Series purifiers come with dissolved water sensor (Pall Model WS10); low watt density heater (15 kw output) and condenser with gravity drain.

For details contact: Hima Marketing Pvt Ltd F-101, 201, 202 & 301, Laxmi Residency 7-1-55/1, Dharam Karan Road Ameerpet, Hyderabad Andhra Pradesh 500 016 Tel: 040-23750705 Fax: 91-040-23732920

OIL PURIFIER Pioneer Maritime Corpn offers oil purifier from vessel brought to Alang recycling yard and reconditions them. As per customer requirement Pioneer Maritime Corpn also provide reconditioning services through Alfa Laval service center.

For details contact: Pioneer Maritime Corpn 103, Rucha Apartment Plot No: D-11 Sec 20, Airoli, Navi Mumbai 400 708 Tel: 022-65168454

HIGH PRESSURE GAS FILTER Reliable Thermocraft offers Type H welded steel horizontal high pressure gas filter and pipes which can be custom designed.

These filters are designed for high pressure systems that require the filter of highest quality and specifications. Available as standard quick release closure and designed for pressures up to 100 Bar – 1,440 Ib/in2. The double and triple length elements reduce the servicing time.

OIL PURIFIERS It is sturdy in construction and purifies oil with perfection. This range of purifiers has gained a wide appreciation for their trouble free operation and durability.

For details contact: M Harakhji & Sons 255, Madhavdarshan Waghawadi Road Bhavnagar, Gujarat 364 002 Tel: 0278-2424591, 2524407

OIL PURIFICATION EQUIPMENT

The welded construction enables the inlet and outlet nozzles for radial positioning to match site pipe operation. Filter closure are bolted even a quick release closure is used. Made with latest manufacturing techniques these are known for robust performance and require low maintenance.

For details contact: Reliable Thermocraft SR No: 81, 82, Plot No: 18, M I D C Ambad, Nashik Maharashtra 422 010 Tel: 0253-6628665 Fax: 91-0253-6628665

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MINI GAS ENCLOSURE

MAAG INDUSTRIAL PUMPS Pump Solutions Group (PSG) offers a new product platform, Maag Industrial Pumps, which combines PSG’s existing external/ internal gear and screw pump technologies under the Maag brand name.

Maag Industrial Pumps will feature a new brand image and pump platform targeting industrial applications in the oil and gas, chemical and marine markets. PSG’s highly engineered external/internal gear pumps, together with their screw pump technologies, consolidates PSG’s collective pump and systems expertise and engineering competency under one global gear and screw pump platform.

Maag’s Industrial Pumps platform will offer PSG’s customers a wider range of applications and best-in-class critical transfer solutions worldwide.

Maag Industrial Pumps will feature the following pump technologies: EnviroGear seal-less internal gear pumps; G Series internal gear pumps; and S Series screw pumps.

For details contact: Dover India Pvt Ltd – PSG 40, Poonamallee By-pass Senneerkuppam, Chennai 600 056 Tel: 044-26271020 E-mail: sales.psgindia@psgdover.com

Lemis India Pvt Ltd offers a compact array of portable LPG density meter conforming to the ASTM D1657 Standards. The Windowsbased software facilitates in processing and simplifying operation for personnel. Combined with PC it renders a complete data managing system. Readings on the LCD facilitate measuring process and eliminates eventual mistakes.

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For details contact: Applied Energy Systems Inc 180 Quaker Lane, Malvern, PA 19355, U.S.A. Tel: 610-647-8744 E-mail: mkasper@semi-gas.com

VAPOUR SUPPRESSION SPHERES FOR FIRE FIGHTING

PORTABLE LPG DENSITY METER

For details contact: Lemis India Pvt Ltd No: 603, Platinum Techno Park Plot No: 17/18, Sector 30/A, Vashi Navi Mumbai 400 705 Tel: 022-67215655

SEMI-GAS Systems offers the Xturion MGE-X, a mini gas enclosure that provides safe and continuous gas delivery from small process and purge gas cylinders. it includes all of the same operational and safety features required for two complete source systems, with four process and purge cylinders. The MGE-X includes two separate compartments, each designed for a process and a purge cylinder. The system is also available in a single source design, with one empty compartment that is expandable for future applications. To provide a flexible, custom tailored fit-up, each unit comes equipped with adjustable steel shelves and cylinder straps as well as adjustable back mounted exhaust ducts. The system features a SEMIGAS GigaGuard GSM controller, which continuously checks system conditions for alarms and performs an automatic shutdown in the event of a risk. All MGE-X systems meet SEMI S2 and uniform fire code requirements and are equipped with UL-approved fire sprinklers and ¼” safety glass windows.

Trelleborg offers advanced composite material specifically designed as a fire and vapour suppression agent for large storage tanks containing hydrocarbon polar or non-polar fuels. As the product is capable of handling high temp and has an oil repellant outer coating, the barrier lasts indefinitely. The individual spheres, which vary in size from 3 to 5 mm, are applied dry and self-assemble into a foam-like structure that is lighter than both oil and water. The resulting foam suppresses vapours to the point of extinguishing the liquid hydrocarbon fires. Since the spheres do not rely on water to put out fires, they are most suitable for applications where water is scarce and in regions of the world where low temperatures pose freezing issues.

For details contact: Trelleborg Offshore 1902 Rankin Road, Houston, TX 77073, U.S.A. Tel: +1 (832) 456 8300, Fax: +1 (281) 774 2626 E-mail: offshore@trelleborg.com / ruth.clay@trelleborg.com

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products

LIQUID NITROGEN

LIQUID NATURAL GAS

Ekta Enterprises offers liquid nitrogen, which is a type of liquid and can be easily converted into solid. This process can be done by placing in a vacuum chamber, which is pumped by a rotary vacuum pump. By using frictional distillation method, it can be industrially produced in large quantity. For over clocking a central processing plant, liquid nitrogen gas offered is also used as a cooling supplement.

For details contact: Ekta Enterprises No: 156, Chander Puri Opp: Navyug Market Ghaziabad Uttar Pradesh 201 001 Tel: 0120-2850037

The liquefication process involves removal of certain components, such as dust, helium, water and heavy hydrocarbons, which could cause difficulty downstream. The natural gas is then condensed into a liquid at close to atmospheric pressure (Maximum Transport Pressure set around 25 kPa (3.6 psi )). The reduction in volume makes it much more cost-efficient to transport over long distances where pipelines do not exist. Where moving natural gas by pipelines is not possible or economical, it can be transported by specially designed cryogenic sea vessels (LNG carriers) or cryogenic road tankers.

LIQUID PETROLEUM GAS Indian Inorganics, Kolkata offers liquid petroleum gas.

Liquefied petroleum gas (also called LPG, GPL, LP Gas, or autogas) is a mixture of hydrocarbon gases used as a fuel in heating appliances and vehicles, and increasingly replacing chlorofluorocarbons as an aerosol propellant and a refrigerant to reduce damage to the ozone layer.

Varieties of LPG bought and sold include mixes that are primarily propane, mixes that are primarily butane and the more common, mixes including both propane and butane.

LPG is usually derived from fossil fuel sources, being manufactured during the refining of crude oil or extracted from oil or gas streams as they emerge from the ground.

For details contact: Indian Inorganics 74e, Purna Das Road, 1 st Floor Nr Triangular Park Kolkata 700 029 Tel: 033-40080734, 40637136

Liquefied natural gas or LNG is natural gas (primarily methane, CH 4) that has been converted to liquid form for ease of storage or transport. Liquefied natural gas takes up about 1/600 th the volume of natural gas at a stove burner tip. It is odorless, colorless, non-toxic and non-corrosive.

For details contact: Indian Inorganics 74e, Purna Das Road, 1st Floor Nr Triangular Park Kolkata 700 029 Tel: 033-40080734, 40637136

DRILLING RIGS Swarna Oil & Gas Field Pvt Ltd offers drilling rigs and its parts. The model comes with ZJ20DBS, ZJ30DBS, ZJ40DBS, ZJ50DBS and ZJ70DBS. The available tools are Tricone rock bits: TCI and steel tooth bits 3 7/8”-36”, PDC bits matrix body and steel body 3 1/8” - 17 1/2”, drag bits 3-wing and 4-wing step type and chevron type, PDC cutter for oil well drilling bits, coal-field mining drilling bits, geology exploring, drill collars (spiral and slick and non-magnetic):size 3 1/8”-11”, heavy weight drill pipe and square kellys and hexagonal kellys, drilling jars and stabilizers, casing centralizers and solid control equipments.

For details contact: Swarna Oil & Gas Field Pvt Ltd Darul Amn, Mirzamahalla Midnapur, West Bengal 721 101

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5/28/2013 7:48:15 PM

events diary PetroWorld India 2013

Oil & Gas World Expo 2014

Date: August 22-24, 2013 Venue: Bombay Exhibition Center, Goregaon, Mumbai, India Event: Addressing the demanding needs of the Indian market, the inaugural PetroWorld India provides a unique platform for assembling the region’s key leaders for discussion of technical, strategic and business topics affecting the Indian oil & gas industry. With a specific focus on topics of interest to both Indian and international markets, PetroWorld India will showcase the tremendous scope of the oil & gas sector in India while providing a practical, solutions-oriented program for doing business in this rapidly expanding region of the world. PetroWorld India will bring together qualified senior management / executive decision makers who have the authority to purchase, or influence the purchase of products and services, as well as production and exploration managers, engineers and consultants from oil & gas sector across the world.

Date: February 10-12, 2014 Venue: Bombay Exhibition Centre, NSE Complex, Goregaon, Mumbai, India Event: Oil & Gas World Expo 2014, the 6 th International Exhibition & Conferences, scheduled in 10-12 February, 2014, will organise by CHEMTECH Secretariat and supported by CHEMTECH Foundation, who are pioneers in conceiving international Exhibitions and Conferences since 1975. For the entire ‘Upstream’ value chain related to Oil & Gas exploration, production and transportation, the expo will provide a platform to showcase India’s growing engineering and technological capabilities in the entire upstream hydrocarbon value chain. The increasing number of exhibitors since its first edition in 2004 reflect India’s growing role in the global hydrocarbon sector.

For details contact: C K Arora/ Siddharth Chibba Inter Ads Exhibitions Pvt Ltd M: + 91- 9910863683 / 7503010430 F: + 91- 124- 438-1162; T: + 91-1244524204/4524200 Email: ckarora@interadsexhibitions.com / siddharth@interads.in PETROTECH-2014 Date: January 12-15, 2014 Venue: India Exposition Mart Limited, Greater Noida, Delhi (NCR) Event: The PETROTECH series of International Oil & Gas Conference and Exhibitions is a biennial platform for national and international experts in the oil & gas industry to exchange views and share knowledge, expertise and experiences.

The event also aims to explore areas of growth in petroleum technology, exploration, drilling, production and processing, refining, pipeline, transportation, petrochemicals, natural gas, LNG, petroleum trade, economics, legal and human resource development, marketing, research & development, information technology, safety, health and environment management in the oil & gas sector. As the prime showcase of India’s hydrocarbon sector, this mega event attracts scientists, technologists, planners and policy makers, management experts and entrepreneurs to solicit their views in order to catalyse achievement of global energy security. PETROTECH-2014 is being organized under the aegis of the Ministry of Petroleum & Natural Gas, Government of India, by Oil and Natural gas Corporation Limited and PETROTECH. For details contact: PETROTECH-2014 Secretariat Oil & Natural Gas Corporation Ltd Jeevan Bharati, Tower - II, Indira Chowk, New Delhi - 110001 (INDIA) Tel.: +91-11-23312607/ 23301169/ 23301170; Fax: +91-11-23315207 Email: secretariat@petrotech.in www.oswindia.com

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For details contact: Chemtech Secretariat 26, Maker Chambers VI, Nariman Point, Mumbai 400 021, India Tel: +91-22-40373737; Fax: +91-22-22870502 Email: conferences@jasubhai.com Gas and Oil Expo North America 2013 Date: June 11-12, 2013 Venue: Stampede Park, Calgary, Canada Event: In 2013, the conference in conjunction with Gas & Oil Expo will feature a notable lineup of speakers and presentations that explores the challenges facing the industry — from the ground to market.

For details contact: Janina Kano Marketing Manager dmg :: events (Canada) inc.

302, 1333 – 8th Street SW Calgary, AB Phone: +1 (403) 209-3555 Fax: +1 (403) 245-8649 Offshore Safety Summit 2013 Date: June 17-19, 2013 Venue: Houston, Texas, USA Event: The Offshore Safety Summit 2013 brings you the latest insights and case studies on effectively managing offshore HSE risk and creating a rigorous system to pre-empt major and costly accidents. Through real-life, practical case studies, the Offshore Safety Summit 2012 will help oil and gas operators and contractors understand the human and technical factors involved in process safety and ensure a solid hazard prevention framework.

For details contact: IQPC http://www.oilandgasiq.com/

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project update

Media Barter with gulfoilandgas.com

Projects Database Petrochemical Plants and Refineries Major Projects in the Middle East, Africa and Caspian Sea

Project

Country

Value ($)

Status

Bahrain Refinery Expansion

Bahrain

6,500,000,000

Bidding

Yateem Oxygen - Carbon Dioxide Extraction Plant

Bahrain

-

Execution

Middle East

Nasiriyah Grassroots Refinery

Iraq

8,000,000,000

Bidding

New Karbala Refinery

Iraq

6,500,000,000

Study

Daura Refinery - Fluid Catalyst Cracking (FCC) Unit

Iraq

2,500,000,000

Bidding

Khor Al-Zubair Fertilizer Plant (Fertilizer Complex-3)

Iraq

-

Bidding

Mina Al Ahmadi Sulfur Handling Facilities

Kuwait

500,000,000

Bidding

Clean Fuels Project (CFP)

Kuwait

18,500,000,000

Bidding

Sohar Refinery Expansion

Oman

1,500,000,000

Bidding

Duqm Refinery and Petrochemical Complex

Oman

6,000,000,000

Bidding

Zauliyah Gas Plant

Oman

200,000,000

Execution

Ras Laffan Condensate Refinery - Phase 2

Qatar

1,200,000,000

Bidding

QP/Shell - Ras Laffan Olefins Complex

Qatar

3,000,000,000

FEED

QP - Ras Laffan Aromatics Project

Qatar

-

Study

Shoaiba Bulk Storage Facility

Saudi Arabia

600,000,000

FEED

SATORP - Jubail Export Refinery

Saudi Arabia

9,600,000,000

Execution

Jizan Export Refinery

Saudi Arabia

7,000,000,000

Execution

PCC - Nylon 6,6 Plant

Saudi Arabia

500,000,000

Execution

Borouge 3

UAE

4,500,000,000

Execution

IPIC - New Fujairah Oil Refinery

UAE

3,500,000,000

FEED

DUGAS - MTBE Plant Expansion

UAE

-

FEED

Ruwais Refinery Expansion - Fluid Cracking Unit (RFCC)

UAE

3,100,000,000

Execution

Algiers Refinery Revamping

Algeria

300,000,000

Execution

Skikda Refinery Upgrade

Algeria

2,600,000,000

Execution

Lobito (SonaRef ) Refinery

Angola

8,000,000,000

Execution

Soyo Refinery

Angola

-

Planning

Cameroon Ammonia Urea Fertilizer Plant

Cameroon

1,400,000

Study

Alexandria Petrochemicals Complex - Polyethylene Plant

Egypt

-

Execution

Africa

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Africa

Country

Value ($)

Status

ERC - Mostorod Refinery

Egypt

3,700,000,000

Execution

E-Styrenics Polystyrene Plant

Egypt

758,000,000

Execution

KIMA - Aswan Ammonia Plant

Egypt

600,000,000

Execution

Tahrir Petrochemicals Complex [NEW]

Egypt

3,700,000,000

Study

Port-Gentil Refinery [NEW]

Gabon

1,000,000,000

Planning

Tema Fuel Storage Tanks

Ghana

-

Study

Mbini Refinery

Guinea

404,000,000

Execution

Kenya Petroleum Refineries Limited (KPRL) Mombasa Refinery

Kenya

17,000,000

Execution

Mellitah Complex

Libya

-

Execution

OCP-Diammonium Phosphate Facilities

Morocco

170,000,000

FEED

Zinder Refinery (Soraz)

Niger

980,000,000

Execution

Akabuyo Refinery

Nigeria

7,500,000,000

Planning

Eleme Fertilizer Plant

Nigeria

1,200,000,000

Execution

Coega (Mthombo) Refinery

South Africa

10,000,000,000

FEED

Mnazi Ammonia/Urea/Methanol Project

Tanzania

-

Study

Hoima Oil Refinery

Uganda

2,500,000,000

Study

Baku Heydar Aliyev (Azerneftyanajag) Refinery Upgrade

Azerbaijan

-

Execution

Oil, Gas Processing & Petrochemical Complex (OGPC) Project

Azerbaijan

15,000,000,000

Study

Sumgayit Nitrogen Fertilizer-Urea Complex

Azerbaijan

-

Study

Abadan Refinery Upgrade

Iran

3,000,000,000

Execution

Bandar Abbas Refinery Upgrade

Iran

300,000,000

Execution

Bandar Imam Petrochemical Complex

Iran

-

Execution

Esfahan (Isfahan) Refinery Expansion

Iran

2,500,000,000

Execution

Farashband Refinery Extention

Iran

-

Execution

Imam Khamenei Gas Refinery

Iran

-

Study

Karoon Isocyanates Complex

Iran

-

Execution

Lavan Refinery Upgrade

Iran

-

Execution

Parsian Gas Refinery

Iran

400,000,000

Execution

Persian Gulf Star Gas Condensate Refinery (PGSCR)

Iran

2,600,000,000

Execution

Atyrau Petrochemical Complex

Kazakhstan

5,200,000,000

Execution

Atyrau Refinery Upgrade

Kazakhstan

1,040,000,000

Execution

Karachaganak Gas Refinery

Kazakhstan

3,700,000,000

Study

Achinsk Refinery Upgrade

Russia

759,500,000

Execution

Nakhodka Petrochemical Complex Project

Russia

5,000,000,000

Study

Nizhnekamsk Refinery and Petrochemicals Complex

Russia

5,000,000,000

Execution

FEPCO Project

Russia

5,000,000,000

Study

Omsk Refinery Upgrade

Russia

5,000,000,000

Execution

Volgograd Refinery Upgrade

Russia

-

Execution

Caspian Region

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book shelf WORLD OFFSHORE FIELD DEVELOPMENT GUIDE VOLUME 2: ASIA, INDIA, (WORLD OFFSHORE FIELD DEVELOPMENT GUIDE) [PAPERBACK] Author: OPL Staff A Price: USD 275 P Paperback: 365 Pages P Publisher: Oilfield Publications Inc; 3 rd edition P Book Description: Full field development, platform and production data for: Australia, Brunei, China, India, Indonesia, Japan, Malaysia, Myanmar, New Zealand, Papua New Guinea, Philippines, Taiwan, Thailand and Vietnam. National exploration and production d backgrounds - Full information on licensing and exploration for each nation with data on historical, current and potential development prospects. Field data - Full information on over 301 fields with ownership, discovery dates, overall development concepts, characteristics, reserves, daily and peak production. Platform data - Full details on over 915 platforms with specifications, installation dates, fabricators, functions, transportation systems including pipe/flow lines, terminals and offshore loading installations.

BASICS RESERVOIR ENGINEERING (OIL AND GAS FIELD DEVELOPMENT TECHNIQUES) [PAPERBACK] AAuthor: Rene Cosse PPrice: USD 104.50 PPaperback: 346 Pages PPublisher: Editions Technip Book Description: The volume provides clear and concise information on reservoir engineering methods, ranging from specific geological and geophysical techniques applied to reservoirs, to the basics of reservoir simulation, with reference to well logging, flfluidd PVT P studies and well testing. Emphasis is placed on recent methods such as the use of type curves in well test interpretation, and on horizontal drain holes. The information will help all specialists in the relevant disciplines such as geologists, geophysicists, production engineers and drillers. It will also be useful to a broader range of specialists such as computer scientists, legal experts, economists and research workers, in placing their work within a wider professional context and incorporating it into a multidisciplinary field of activity.

O F F S H O R E F I E L D D E V E LO P M E N T AT L A S O F N O R T H W E S T E U R O P E [ PA P E R B A C K ] AAuthor: OPL Staff PPrice: USD 24.88 PPaperback: 48 Pages PPublisher: Oilfield Publications Inc; 2 nd edition BBook Description: Orientation maps (scale 1:2,000,000) covering the whole re g i o n f ro m N o r t h e r n N o r way to t h e English Channel and west to the Atlantic Margin. Field location maps for ever y field in production, under construction o r f o r p ro b a b l e / p o s s i b l e d e v e l o p m e n t.

Comprehensive field data including - operator, block, status and full concept information (eg, timescales, production techniques, pipeline and transportation), index of all fields with operator and Block numbers, index of fields in production, index of fields for probable development, index of fields for possible development.

ENHANCED OIL RECOVERY: FIELD PLANNING AND DEVELOPMENT STRATEGIES [HARDCOVER] AAuthors: Vladimir Alvarado and Eduardo Manrique M PPrice: USD 85.97 HHardcover: 208 Pages PPublisher: Gulf Professional Publishing Book Description: Enhanced-Oil Recovery (EOR) evaluations focused on asset acquisition or rejuvenation involve a combination of complex decisions, using different data sources. EOR projects have bbeen traditionally associated with high CAPEX and OPEX, as well as high financial risk, which tend to limit the number of EOR projects launched.

The first edition of this atlas, published in the spring of 1997 was our most popular new publication of the year. A combination of data taken from the North Sea Map and the North Sea Field Development Guide would provide users with a unique highly valuable and easy to use new reference source.

For this second edition the publisher stuck to the same formula and brought every shred of data completely up to date. This new atlas is the best reference of its kind ever produced and once youâ&#x20AC;&#x2122;ve got your copy youâ&#x20AC;&#x2122;ll wonder how you ever made do without it.

In this book, the authors propose workflows for EOR evaluations that account for different volumes and quality of information. This flexible workflow has been successfully applied to oil property evaluations and EOR feasibility studies in many oil reservoirs.

The methodology associated with the workflow relies on traditional (look-up tables, XY correlations, etc) and more advanced (data mining for analog reservoir search and geology indicators) screening methods, emphasizing identification of analogues to support decision making. The screening phase is combined with analytical or simplified numerical simulations to estimate full-field performance by using reservoir data-driven segmentation procedures.

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