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OILFIELD TECHN

OLOGY MAGAZIN

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FEBRUARY 2013

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ISSN 1757-2134

contents

Copyright © Palladian Publications Ltd 2013. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior permission of the copyright owner. All views expressed in this journal are those of the respective contributors and are not necessarily the opinions of the publisher, neither do the publishers endorse any of the claims made in the articles or the advertisements. Printed in the UK. Images courtesy of www.bigstockphoto.com.

Oilfield Technology is audited by the Audit Bureau of Circulations (ABC). An audit certificate is

available on request from our sales department.

69

| 03 | EDITORIAL COMMENT

| 05 | W0RLD NEWS

| 10 | GO WEST...Jeff Haworth, Department of Mines and Petroleum, Western Australia, examines the changing face of the oil and gas industry in this booming hydrocarbon region.

| 16 | REACHING THE PEAKBruce Robinson, ASPO-Australia, asks whether a downturn in oil production is just around the corner.

| 24 | TAKING CENTRE STAGEFocusing on short term economics and production gains from increased stage counts, Jason Baihly, Raphael Altman and Isaac Aviles, Schlumberger, USA, explain the performance of selected groups of Bakken wells in the Williston Basin.

| 30 | GOOD VIBRATIONSRoger L. Schultz, ThruTubing Solutions/TTS Drilling Solutions, USA, provides an overview of various vibratory downhole tools that are used for horizontal and extended reach completions.

| 35 | CHILDREN OF THE REVOLUTIONScott Lapierre, Pioneer Natural Resources, USA, provides some historical perspective on the US unconventional revolution.

| 39 | INDUCED SEISMICITY: MEASURE AND MITIGATEIndy Chakrabarti, MicroSeismic, Inc., USA, explains why industry and regulatory attention is moving towards improved monitoring of induced seismicity associated with unconventional resource development.

| 42 | GETTING IT RIGHT THE FIRST TIMEKevin Fisher, Flotek Industries, USA, explains how in the field of hydraulic fracturing, there are no second chances when it comes to getting fracs right.

| 48 | SPECIALITY CHEMICAL Q&A SESSIONOilfield Technology Editor, Anna Scordos, recently asked Nozi Hamidi, BWA Water Additives, USA, a few questions about the state of the speciality oilfield chemical industry.

| 53 | GETTING A SENSE OF SCALEKimberley MacEwan Ph.D, MWV Specialty Chemicals, USA, unveils some of the latest polymeric scale inhibitor advances.

| 56 | HORIZONTAL LEARNING CURVEJessica Bassett and Crystal Wreden, CSI Technologies, USA, discuss the zonal isolation techniques and lessons learned in the Marcellus Shale.

| 61 | THE LESSER OF TWO EVILSDon McClatchie, Sanjel, Canada, compares and contrasts the use of fishing and milling operations in multistage completions.

| 65 | THE EVOLUTION REVOLUTIONMarshal Bauer Harris, Abrado, USA, unveils the guiding forces behind the development process of new wellbore technologies.

| 69 | REAL TIME WELL INTEGRITYDr Liane Smith, Intetech, UK, examines how well integrity management systems can turn large volumes of operating data into actionable business intelligence to give users a 360˚ view of corporate risk.

Scientific Drilling International is a leader in wellbore placement services to the oil and gas, geothermal, mining and civil engineering industries. Founded in 1969, SDI has assembled a unique combination of experienced professionals and innovative technologies in both land and offshore drilling. SDI is the only company to offer a complete navigation solution that includes high accuracy gyro survey, MWD/LWD, MWD Ranging™ and production logging.SDI is committed to a customer experience that makes it easy to do business.

On this month’s cover >>

Copyright in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior permission of the copyright owner. All views expressed in this journal are those of the respective contributors and are not necessarily the opinions of the publisher, neither do the publishers endorse any of the claims made in the articles or the advertisements. Printed in the UK. Images courtesy of www.bigstockphoto.com.

Scientific Drilling International is a leader in wellbore placement services to the oil and gas, geothermal, mining and civil engineering industries. Founded in 1969, SDI has assembled a unique combination of experienced professionals and innovative technologies in both land and offshore drilling. SDI is the only company to offer a complete navigation solution that includes high accuracy gyro survey, MWD/LWD, MWD Ranging™ and production logging.SDI is committed to a customer experience that makes it easy to do business.

On this month’s cover >>

February 2013 Volume 06 Issue 02

OT_01-02_Feb13.indd 1 08/02/2013 16:08

After 50 years of operation, the Groningen gas field in the Netherlands is now, and also for the coming decades, able to continue supplying its clients. The facilities have been fully modernized. One key success factor was the long-term relationship of the operating company NAM and its contractors. Siemens has updated the compression and

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3569_Groningen_A4_eng.indd 1 25.09.12 10:27OT_01-02_Feb13.indd 2 08/02/2013 16:34

Anna Scordos

Editor

comment

Oilfield Technology subscription rates: Annual subscription £80 UK including postage/£95/e130 overseas (postage airmail)/US$ 130 USA/Canada (postage airmail). Two year discounted rate £128 UK including postage/£152/e208 overseas (postage airmail)/US$ 208 USA/Canada (postage airmail). Subscription claims: Claims for non receipt of issues must be made within three months of publication of the issue or they will not be honoured without charge. Applicable only to USA & Canada: Oilfield Technology Magazine (ISSN No: 1757-2134, USPS: 025-171) is published monthly by Palladian Publications Ltd GBR and distributed in the USA by SPP, 17B S Middlesex Ave, Monroe NJ 08831. Periodicals postage paid at New Brunswick, NJ. Postmaster: Send address changes to Palladian Publications, 17B S Middlesex Ave, Monroe NJ 08831.

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Last month, Shell signed a deal with the Ukraine to begin seismic testing and drill 15 test wells in the eastern part of the country. The company is hoping to fi nd economically

viable shale reserves, and the country’s government has intimated the investment could be worth up to US$ 10 billion.

In this issue of Oilfi eld Technology, our Pioneer Resources article (pg 35) offers some historical context on what it describes as three distinct shale gas ‘revolutions’ in the USA. The article makes the distinction between the initial ‘quiet rise of the Barnett shale’ and the subsequent ‘shale gas revolution’ connected with the discovery of the Haynesville well. The article suggests that industry players looking for future thrill rides should be looking overseas, as ‘the days of discovering the six county, 100 million bbl./square mile behemoth are likely numbered in the continental United States’. Here in the UK, the Chancellor recently unveiled tax breaks for shale gas exploration and ended a moratorium on hydraulic fracturing, which was imposed after tremors were felt as a result of shale gas activity in 2011. But how is the rest of Europe currently positioned towards the possibility of hosting its own shale revolutions? It remains divided. Shale gas extraction is allowed and permits are currently issued in, for example, the UK, Portugal, Germany, Poland, Greece and Turkey. Countries currently imposing a ban on activities include Bulgaria, the Czech Republic, the Netherlands and France. The French President, François Hollande, has gone so far as to say that the nationwide ban on hydraulic fracturing would unquestionably remain in place for the duration of his fi ve year term. Austria has allowed extraction in theory, but has imposed such costly

environmental compliance conditions that any company looking to develop shale reserves in the country would likely fi nd the enterprise overall uneconomical.

Interestingly, the shale boom in the USA has done more than just inspire Europe to follow suit. A recent news story in the Financial Times highlighted how the ‘revolution’ has led to an increased uptake of coal as a feedstock for European power plants, as a result of lower demand for domestic reserves of the fossil fuel at home in the US. However, Milton Catelin, head of the World Coal Association, has been quoted as saying, “We don’t see this as a renaissance of coal, it’s just economics”. Conversely, gas most certainly is universally acknowledged as experiencing a renaissance. The main slogan to accompany last year’s World Gas Conference was, tellingly, ‘The Golden Age For Gas’.

Europe has a long way to go to match the USA in terms of shale extraction. Even Poland, the most ‘pro-shale’ European country, only has around six drill rigs operating – compared to around 1200 rigs currently drilling in and around the USA’s main shale plays. But shale gas production on an American scale does have its issues. Currently, the USA is fi fth in the world in terms of the volume of gas it fl ares; just behind Russia, Nigeria, Iran and Iraq, and environmental concerns about the trend are growing. This month, the Financial Times ran a startling image on its front page. It was a nighttime satellite photo of the continental USA, and showed an area of bright lights the size of a major city somewhat incongruously situated in the heart of North Dakota. Amazingly, the light was being emitted from fl aring in the Bakken. This image could almost be a vision of the promise and challenges held in our mid to long term energy future...

The future is bright; the future is fraccing. O T

3OILFIELD TECHNOLOGY

February 2013

OT_03-04_Feb13.indd 3 08/02/2013 16:48

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05OILFIELD TECHNOLOGYFebruary 2013

world news

inbrief

Aker Solutions has won a US$ 368 million contract to provide a subsea production system for Statoil’s Aasta Hansteen field located on the Norwegian continental shelf.

The contract will see Aker provide three template manifolds, seven subsea trees along with wellheads, and workover systems. This latest contract comes only shortly after Aker was awarded a US$ 50 million contract to supply the Aasta Hansteen field with dynamic and static deepwater umbilicals, a riser base and associated equipment.

The Aasta Hansteen field is located in water depths of 1300 m, some 300 km west of Bodø. The project consists of three structures: Luva, Haklang and Snefrid South.

Statoil is the field’s operator and holds a 75% stake.

ROMANIAThe Romanian government has issued permits to Chevron Corp. that will allow the company to drill an exploratory shale gas well in the country’s 600 000 ha. Barlad concession.

The Romanian government had previously issued a moratorium on shale activity over concerns about the environmental impact of hydraulic fracturing.

The decision to allow Chevron to go ahead therefore, marks a change of heart in the country’s leadership. Prime Minister, Victor Ponta said, “If we can have alternative gas sources, [...] and they meet the EU environmental standards, I am for this.”

CYPRUSTotal has agreed to sign a deal with the Cypriot Government that will see the French supermajor gain access to two blocks offshore Cyprus.

Total was awarded blocks 10 and 11, which lie in water approximately 7400 ft deep, as part of Cyprus’ second licensing round held last year. Earlier this year, the eastern-Mediterranean island had agreed exploration and production sharing contracts with Eni and Kogas, which covered blocks 2, 3 and 9 across an area of 12 500 km2.

UKRAINEThe Ukrainian President, Viktor F. Yanukovich has signed an agreement with Shell that will allow the company to drill for shale gas.

According to statistics released by the government, Shell’s operations in the country could produce up to 8 - 11 billion m3 per year, a figure roughly equivalent to 20% of Ukraine’s total consumption. The areas targeted by Shell are believed to hold up to 113 billion m3 of shale gas.

// Aker Solutions // Wins new Statoil contract

Eni Australia and MEO Australia have agreed to extend their alliance in order to drill an appraisal well in the Blackwood area of NT/P68 block.

The well is intended to determine the commercial viability of a 2008 discovery that included a 48 m gas column. The initial well, Blackwood-1 was a dry gas well, with approximately 25 - 30% CO2 content and had been declared acceptable for methanol production.

MEO Australia holds a 50% stake in future development, and Eni will earn a 50% stake by fully funding the drilling and production of the well.

The Blackwood discovery is located near Shell’s Evans Shoal gas discovery, which is believed to hold 6.6 trillion ft3.

Swedish company Lundin Petroleum has announced that it is on target to produce approximately 33 000 to 38 000 bpd this year. According the company’s CEO, Ashley Heppenstall, once the Brynhild field offshore Norway begins production at the close of 2013, the company’s output should rise to 40 000 bpd.

A statement released by the company said its reserves had risen 2% to 201.5 million bbls and had been “positively impacted by the Bertam field, offshore peninsular Malaysia”. The statement also said, “further increases result from Lundin Petroleum’s main producing assets, the Alvheim and Vound fields offshore Norway, which yet again delivered better than expected reservoir performance”.

// Eni Australia // Blackwood appraisal

// Lundin // 38 000 bpd for 2013

//Apache, JX Nippon// Australia farm-in approved

Authorities in Western Australia have approved Apache and JX Nippon for a farm-in of the WA-435-P and WA-437-P blocks.

The exploration rights to the blocks had previously been held by a joint venture between Carnarvon Petroleum and Finder Exploration, where each party held a 50% stake. The farm-in deal will see Apache become the operator and take a 40% stake, while JX Nippon, Carnarvon and Finder will each hold a 20% stake.

The two blocks cover the Phoenix South and Roc prospects. Phoenix South is planned to target gas reservoirs in the lower Triassic and will be drilled to a minimum depth of 4500 m. Roc will also be aimed at reaching lower Triassic gas reservoirs and will reach a minimum depth of 4000 m.

OT_05-09_Feb13.indd 5 08/02/2013 12:53

06 OILFIELD TECHNOLOGYFebruary 2013

diarydates

webnews highlights

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To read more about these articles and for more event listings go to:

world news

US shale gas flaring visible from space

Lukoil fully replaces oil and gas reserves in 2012

Sonatrach CEO replaced after Amenas attack

05 - 07 MarchSPE IADCAmsterdam, The NetherlandsE: dguest@spe.orgwww.spe.org/events/dc/2013

10 - 13 MarchMEOS 2013Manama, BahrainE: fawzi@aeminfo.com.bh www.meos2013.com

20 - 22 MarchOMC 2013Ravenna, ItalyE: conference@omc.itwww.omc.it/2013

26 - 28 MarchIPTC Beijing, ChinaE: iptc@iptcnet.orgwww.iptcnet.org/2013 // BP// Angola PVSM production

begins after fi ve years

The BP-operated PVSM development in Block 31 offshore Angola has begun production, and is initially expected to reach a production level of 70 000 bpd; this figure is eventually expected to more than double over the next 12 months (to 150 000 bpd) as more fields come online.

The PVSM development is one of the largest subsea operations in the world and consists of the deepwater Plutao, Saturno, Venus and Marte fields. The fields, which lie up to 2000 m below the water, were first discovered between 2002 and 2004 and are BP’s second operation in Angola.

The PVSM development relies on a converted hull FPSO (the first in Angolan deepwater), which is capable of storing 1.6 million bbls. Once the development is complete, 40 separate wells (including gas and water injection wells) will be connected to the FPSO.

BP Exploration (Angola) is the operator of Block 31, with a stake of 26.67%. Other stakeholders include: Sonangol E. P. (25%), Sonangol P&P (20%), Statoil Angola (13.33%), Marathon (10%) and SSI (5%).

Angola is Africa’s second largest oil exporter, behind Nigeria, and has proven reserves of 9.5 billion bbls.

Chevron has posted a “larger-than-expected” rise in its quarterly profits, with net income rising to US$ 7.2 billion, up from US$ 5.1 billion in the same period last year. These results were bolstered by the US$ 1.4 billion gained by the company in an asset swap deal with Shell last year.

Total revenues for the entire 12 month period however, fell to US$ 241.9 billion, down from US$ 253.7 billion.

Chevron also posted a rise in production from 2.64 million bpd to 2.67 million bpd.

Chief Executive, John Watson made note of the additional 1.07 billion bbls of reserves that had been added last year through various projects around the world, including Gorgon in Australia.

Two of Petrobras’ FPSOs recently broke free of their moorings during high winds and collided in Brazil’s Honorio Bicalho shipyard, Rio Grande.

Petrobras has stated that the P-58 and P-63 platforms are now due to undergo inspection and damage assessment following the incident.

The P-58 platform had been scheduled to go into production in Q1 2014 at the subsalt Beleia Azul field; it is as yet unknown whether the collision will delay the platform’s deployment. The P-63 platform (capable of producing 140 000 bpd) had been due to finish construction later this year before deployment in the Papa Terra field of the Campos Basin.

Petrobras has had difficulty in boosting its output in recent years.

// Chevron // Q4 output and profi ts rise

// Petrobras // FPSOs break moorings, collide

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world news

08 OILFIELD TECHNOLOGY February 2013

// Rosneft // 7.2% profit rise; 2013 output up 1 - 2%

// Hardy Oil & Gas // Wins licence extension

// Gran Tierra Energy// Rising output & reserves

// PDC Energy // Gas assets to be sold off

// BG Group // 1 million bpd target to be missed

Hardy Oil & Gas plc has won an extension of the CY-OS/2 licence after a court tribunal in India found in the company’s favour. The licence extension will allow Hardy to continue appraisal work in the block for a further three years.

Hardy was forced to cease operations on the block after a dispute arose concerning whether or not the Ganesha-1 discovery was classified as an oil or gas discovery. Hardy’s Chief Executive, Ian MacKenzie said, “the award has resolved a key uncertainty and allows us to put in place a business plan for this asset.”

The 859 km2 CY-OS/2 block is situated in the northern part of the Cauvery Basin, offshore Pondicherry, India. The Ganesha-1 discovery was first announced in January 2007. The well was drilling to a depth of 4089 m and was tested and found to have a flow rate of 10.7 million ft3 per day and is believed to hold reserves of 130 billion ft3.

Canadian company, Gran Tierra Energy has reported a rise in annual production of 3.5% to 18 000 bpd, up from 17 408 bpd in 2011. Production from 2013 however, has outshone these figures with a daily rate of 21 000 bpd.

The company has also ended 2012 with a record level of crude oil reserves, increasing from 48.75 million bbls to 56.26 million bbls. The company’s gas reserves declined significantly, falling from 44 billion ft3 to 17.91 billion ft3.

In light of the increased production, the company has set a target of 27 000 bpd by the end of this year.

The company’s President and CEO, Dana Coffield attributed the success to “continued strong reservoir management, appraisal drilling and exploration success.” Coffield, outlined the company’s plans for 2013, which include continued appraisal drilling of the Moqueta and Ramiriqui discoveries.

PDC Energy has revealed that it has signed a final agreement that will see the company sell off its Colorado-based natural gas assets for US$ 200 million to Caerus Oil and Gas LLC.

The assets, including the Piceance and NECO holdings, are 99% natural gas and amount to 85 billion ft3 of proven reserves. These assets currently have a combined production of 42 million ft3/d. The sale of these assets has been predicted to cut PDC’s annual output by approximately 10 billion ft3.

James Trimble, PDC’s President and Chief Executive said that, “this planned divestiture positions [PDC] to accelerate the development of our high-return, liquid-rich Wattenberg and Utica Shale horizontal drilling inventory.”

According to Trimble, the sale is part of PDC’s transition towards a liquid-rich asset base with a reserve mix of 52% oil/liquids.

BG Group’s Chief Executive has announced that its previous target of producing 1 million bpd by 2015 is no longer feasible.

The company has blamed the continuing delays over resumption of production at Total’s North Sea Elgin field, which was shut down after a major gas leak last year. In addition to the Elgin shutdown, extended maintenance at the Buzzard field also hit the company’s output.

These interruptions brought output down to 640 000 bpd (a 2.1% fall) and meant that the company had missed analyst expectations of 648 000 bpd. Adjusted profit was US$ 1.03 billion, a figure below analysts’ predicted average of US$ 1.04 billion for the quarter.

OAO Rosneft has reported a 7.2% rise in profits for 2012 and stated that it expects its output to rise by 1 - 2% this year.

One of the main drivers behind the company’s continued production growh has been the Siberian Vankor field, which is expected to ultimately produce 430 000 - 440 000 bpd. The continuing growth of this field helped boost the company’s 2.5% production increase for 2012 (to 2.43 million bpd), despite the fact that other major fields are declining. Altogether, this combined to push the company’s revenues up by 13% to US$ 102 billion and led to a rise in profits of 7.2% to 342 billion Roubles (although this figure is lower than the anticipated 347 billion Roubles).

Ahead of Rosneft’s US$ 55 billion

purchase of TNK-BP, the company has been experiencing a shortage of free cash flow, with figures showing that the earlier 99 billion Roubles available has dropped to approximately 45 billion Roubles. Increased investment and declining income from operations have been attributed as factors behind this decline. The free cash flow shortage, coupled with the fact that the 7.2% rise in profits was lower than had been expected, saw the company’s share price fall 2.2% on the Moscow market.

However, the takeover of profit-making TNK-BP (expected to complete in the first half of this year) will support Rosneft’s ability to pay off the approximately US$ 30 billion of loans it took out to fund the bid.

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OT_05-09_Feb13.indd 8 08/02/2013 12:53

Offshore demands aren’t just steep; they’re relentless. And to help you meet them, CRC-Evans Offshore combines our leading-edge technology with in-depth experience to create intelligent, turnkey solutions you simply can’t � nd elsewhere. Our full spectrum of offerings includes Pipe Handling, Welding, NDE, Field Joint Coating, and Project Management. Put it all together with one partner, CRC-Evans, and experience all the integrated resources you need to meet the industry’s toughest of demands.

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A full line of con� dence. From a single source.

OT_05-09_Feb13.indd 9 08/02/2013 12:53

G west...

Jeff Haworth, Department of Mines and Petroleum, Western Australia, examines the changing face of the oil and gas industry in this booming hydrocarbon region.

OT_10-15_Feb13.indd 10 06/02/2013 11:51

Western Australia (WA) has long held the reputation of Australia’s premier petroleum producer, with recent figures showing WA’s

oil and gas industry accounts for approximately 70% of Australia’s total petroleum sales. As the largest state in Australia, WA covers 33% of the continent and is 20 times larger than the United Kingdom. Home to just 2.4 million people, WA has vast areas of land available – presenting significant opportunities for exploration and development.

In terms of petroleum, WA produced AUS$ 23.8 billion in petroleum sales in the 2011/12 financial year, whilst also attracting 66% of national petroleum exploration in the same period. Currently the state is producing 1 trillion ft3 (28.3 billion m3) of gas per year for export and domestic supply. WA’s fuel mix is set to be revolutionised by increased Chinese demand, an expanding LNG industry and its emerging onshore shale gas industry.

With industry commentators predicting natural gas to be the fastest growing fossil fuel globally by 2030, WA is well placed to take advantage of this market, with its onshore shale and tight gas resources estimated to be 300 trillion ft3 (8.5 trillion m3) and largely untouched. Australia’s position on the LNG supply ladder also continues to climb steadily as global demands for the commodity continue to increase.

World’s leading LNG supplier by 2020?Due to opportunities in the Asian markets, Australia has the potential to increase its share in the world’s LNG supply and become the world’s largest supplier of LNG by 2020.

Australia is currently the world’s fourth largest LNG supplier, producing approximately 10% of the world’s LNG with WA accounting for 87% this total.

It is estimated by 2020, WA’s LNG capacity will increase from 20 million t to up to 80 million t. This estimated 400% increase is supported by new major projects such as the world’s first floating liquefied natural gas (FLNG) project in the Browse Basin, 475 km northeast of Broome in northern WA. The 25 year project operated by Shell is worth AUS$ 13 billion and is scheduled to commence in 2016, producing at least 3.6 million tpy of LNG, plus LPG and condensate.

WA also currently has two of the world’s largest LNG projects under construction, Chevron’s AUS$ 43 billion Gorgon Joint Venture project (GJV) and AUS$ 30 billion Wheatstone project. The GJV project, which commenced construction in 2011, is based in the offshore Gorgon, Jansz/lo and Greater Gorgon Area gas fields near Barrow Island, which contain 40 trillion ft3 (1.1 trillion m3) of gas. GJV is capable of exporting 15 million tpy and 300 terajoules per day for domestic gas supply. The development, scheduled to have gas to market by 2015, will also host the world’s largest commercial-scale carbon geosequestration project, which will capture approximately 120 million t of

11

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12OILFIELD TECHNOLOGYFebruary 2013

CO2 into a sandstone reservoir over 2.4 km underground. The Wheatstone’s foundation project, which commenced construction last year, is based near Onslow and will include two LNG trains with a combined capacity of 8.9 million tpy and a 265 terajoules per day domestic gas plant. The project is scheduled to have gas to market by 2016.

All these new and exciting projects will complement the existing LNG projects including the North West Shelf joint venture project, which has been operating off the WA coast since 1989, providing power and gas to approximately 90 million people in Japan and 40% of Australia’s domestic oil and gas supply.

Supplying the Asian market Asia’s future growth in LNG demand will be driven primarily by China, which is anticipated to become the world’s third largest gas user in 2013. In 2011 - 12, WA’s petroleum exports totalled AUS$ 21.9 billion in value, with Japan (48%), China (17%) and Singapore (8%) receiving the majority of exports.

WA’s crude oil and condensate exports also totalled AUS$ 11.2 billion in the same year with China (28%), Singapore (16%) and Japan and South Korea (10%) rounding

out the top exporting countries. With strong relationships already established in these major Asian markets, WA anticipates that as demand continues to grow, so will the Asian markets’ reliance on Australia to provide energy solutions.

Australia’s relationship with China has also seen its biggest company, PetroChina Co. increasing its investment by moving into the Australian resources sector. In 2010, PetroChina jointly purchased (with Shell) Arrow Energy for AUS$ 3.2 billion and a non-binding deal with LNG Limited to supply gas to a small LNG plant planned at Fisherman’s Landing on the east coast of Australia. PetroChina is also believed to be in talks with BHP Billiton to purchase a stake in WA’s Browse LNG precinct project worth US$ 1.63 billion. This investment has been described by some as a vote of confi dence in Australia’s LNG sector.

The emerging unconventional gas industryProspects for shale and tight gas are providing exciting opportunities for WA’s unconventional gas industry, which is currently in its infancy. The prospectivity for liquids production from these shales is also encouraging.

WA is currently in the exploration/proof of concept phase for unconventional gas, estimated to be approximately 5 - 10 years behind the US industry in terms of time needed to reach the production phase. WA currently holds an estimated 288 trillion ft3 (8.1 trillion m3) of onshore shale gas and 12 trillion ft3 (229 billion m3) of tight gas. WA’s shale gas reserves account for 73% of Australia’s total estimated unconventional gas reserves, which are 396 trillion ft3 (11 trillion m3).

With industry commentators predicting unconventional gas will account for 30% of global production by 2040, WA’s state government is focused on strengthening its petroleum regulations to responsibly support this emerging industry.

Most of WA’s unconventional gas prospects lie in the Canning Basin in the central northern region of the state. The basin is approximately 530 000 km2, which is an area the size of France.

Due to the abundance of offshore petroleum supplies in recent history, the Canning Basin remains largely unexplored and is estimated to hold 229 trillion ft3 (6.5 trillion m3) of recoverable shale gas – representing twice the gas held in WA’s offshore areas. Recently, major international petroleum stakeholders have begun exploring in the region including Buru Energy/Mitsubishi, New Standard Energy/ConocoPhillips and Hess.

While originally exploring for gas, Buru Energy/Mitsubishi recently found the biggest oil discovery in WA in the past decade. The discovery, at the Ungani-1 well northeast of Broome, is estimated by Buru Energy to hold 9.9 million bbls (1.57 billion l) of gross contingent resources. The Ungani North-1 well, just completed, also has encouraging signs for oil and gas.

Unconventional gas exploration and proof of concept programmes were recently conducted in the state’s midwest region in the northern Perth basin. The most successful of these programmes was at Arrowsmith 2, located in the state’s midwest. In mid-2012, a fi ve stage programme targeted the High Cliff Sandstone, Carynginia Formation, shales in the Irwin River Coal Measures and the Kockatea Shale between 2639 m to 3300 m below surface.

In these early stages of exploration, WA lacks the modern high-tech equipment needed to drill and complete long horizontal production wells like the US and Canada. It also lacks other equipment to advance the industry. The gap in the market may

Figure 1. Australian natural gas resources. Source: DMP and EnergyQuest. Current as at end 2011. Unconventional gas volumes are estimates only.

Figure 2. Aerial view of the Gorgon plant looking toward the LNG jetty. Source: Chevron.

Casing Design For exCelOnshore • Shallow Water Offshore • Deep Water Offshore

Based on Standard API Bi-Axial Calculations

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