Oilfield Technology June 2011

OILFIELD TECHN

OLOGY MAGAZIN

E JUN

E 2011

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w.energyglobal.com

VOLUME 04 ISSUE 04-JUNE 2011

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ISSN 1757-2134June 2011 Volume 04 Issue 04

Copyright© Palladian Publications Ltd 2011. 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.

On this month’s cover >>Oilfield Technology is audited by the Audit Bureau of Circulations (ABC). An audit certificate is

available on request from our sales department.

contents

| 49 | DRILL BIT SOLUTIONS Leading suppliers; Century Products, NOV Downhole and Varel, provide details of advanced drill bit technologies.

| 55 | THE MANY SHADES OF GREEN Kelly Harris, BWA Water Additives, UK, takes a look at screening tests in order to find more environmentally friendly chemicals.

| 60 | SPOTLIGHT ON: ANTISCALANTS Michael Hurd, Kasia Millan and Dr. Mohan Nair, Kemira, USA, offer a supplier’s view of antiscalants in oil and gas markets.

| 64 | A NOVEL APPROACH Siv Howard and John Downs, Cabot Specialty Fluids, Scotland, describe how cesium acetate brine could make a novel high-performance drilling, completion and workover fluid.

| 69 | ADDRESSING CHALLENGES WITH INNOVATION Dave Allison, Neil Modeland, Bart Waltman and Kirk Trujillo, Halliburton, USA, consider innovations in fluids, completion designs and equipment to address HPHT stimulation challenges.

| 73 | UNDER PRESSURE Asad Mehmood, Weatherford International Ltd, Pakistan, discusses the use of drilling control systems to navigate narrow pressure margins and access deep drilling targets.

| 76 | SOUTH CHINA SEA Mohd Hairi Abd Razak and Fuad Mohd Noordin, Petronas, Malaysia, and Mohd Nur Afendy and Rahmat Wibisono, Schlumberger, Yemen and Malaysia, present an example of the planning and execution of coil tubing (CT) operations on platforms too small to accommodate all the required equipment.

| 80 | AD INDEX

| 03 | EDITORIAL COMMENT

| 05 | WORLD NEWS

| 10 | THE ARCTIC HEATS UP Climate change may be opening up the Arctic to an exploration boom, but other factors may be shutting it down. Oilfield Technology Correspondent Gordon Cope takes a look at these factors.

| 16 | THE RUSSIAN RIDDLE Ekaterina Kozinchenko, Jake Leslie Melville, Hege Nordahl and Adrian Del Maestro, Booz & Co., UK, contribute their perspective on ensuring the long term success of Russian oil and gas.

| 21 | CREATING INVESTOR OPPORTUNITIES Kevin Forbes, Epi-V, UK, explores the opportunities for private equity investors in the upstream services sector, which is set for the next phase of industry investment.

| 25 | THERE ARE LIMITS... Kristofer Tingdahl, dGB Earth Sciences, USA, addresses the limitations of seismic interpretation.

| 31 | SHARPENED VISION Henning Trappe, Gerald Eisenberg-Klein, Juergen Pruessmann, TEEC, Germany, discuss the use of CRS analysis on seismic data to improve the view of reservoir structure and lithology.

| 38 | A MOVE TO IMPROVE Rusty Petree, Drilformance, USA, looks at ways of improving drilling efficiency at the bit.

| 43 | PEERLESS PERFORMANCE Charles Douglas and Josh Passauer, Smith Bits, a Schlumberger company, USA, consider a new bit optimised for shale, saving significant rig time in the Haynesville Play.

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Opec will meet in Vienna, Austria, on 8 June 2011 for its 159th Ordinary Meeting. For the first time since December 2008, when the group set

its production target at 24.85 million bpd, there is a genuine possibility that this figure may at last be set for an increase. Although purely speculative, reports indicate that an increase of between 500 000 bpd and 1.5 million bpd is on the cards. In reality, Opec members have been actively flouting production targets all along with an actual current production total, due to member ‘non-compliance’ of closer to 26.3 million bpd, in spite of Libya’s 1.4 million bpd of lost production. However, what is important is the apparent recognition, should an increase be confirmed, that Opec is awake to the spectre of demand destruction and the impact of consistently high oil prices on the recovering global economy.

Whilst Brent crude prices have already dipped amidst the speculation, the impact of such a meagre increase would be symbolic rather than medicinal as demand for crude oil is forecast to escalate further during the second half of 2011. The same issues face key commodities across the spectrum be they oil, wheat or gold, in that there is a fundamental tension between falling supply and rising demand. Whether the cause is the unprecedented economic growth not just in China, but across many emerging Asian nations, the Fukushima nuclear crisis in Japan or the now extended period of unrest in the Middle East, the reality is that this type of price volatility is likely to become the norm rather than a temporary blip. The dual effects of a rising population

and increasing economic development worldwide are placing intense pressure on an already creaking supply chain. The very fact that isolated weather events or political upheaval can impact commodity prices to quite such an extent as we have witnessed in recent months/years is a testament to how finely balanced the ‘system’ has become.

The oil and gas sector is a case in point with the market lurching from being comfortably supplied in early January to a sharp rise in oil prices from sub US$ 100 to US$ 125 in the space of a few weeks on the back of events in the Middle East. The effect has contributed in no small part to the rise in global inflation and the threat of an end to the global economic recovery as analysts forecast even greater prices hikes over the course of the next 12 months.

For Opec at its forthcoming meeting, the actual level of any increase in production, be it 1 million bpd or higher, is largely immaterial, as it will inevitably be quickly soaked up by global demand. What is important is that the cartel is seen to be reacting sympathetically to an escalation in the current price of crude oil. By showing intent to address rising oil prices its efforts will go some way to defusing the growing clamour from the renewable energy lobby intent on the substitution of fossil fuels with alternatives such as wind, solar and nuclear energy.

This month’s issue begins with an article by Contributing Editor, Gordon Cope that looks at the Arctic frontier as the largest remaining region of untapped oil and gas reserves and an effective illustration of how the industry is pushing back every conceivable barrier in its quest to meet future oil and gas demand. O T

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world news

05OILFIELD TECHNOLOGYJune 2011

inbriefStatoil is pushing forward with its first fast-track project, Visund South, which is expected to come onstream next year.

Visund is an oil and gas field in blocks 34/8 and 34/7, 22 km northeast of the Gullfaks field in the Tampen area of the Norwegian North Sea.

Onstream in spring 1999, this development encompasses a floating production, drilling and quarters platform. The subsea-completed wells on the field are tied back to the floater with flexible risers. Oil is piped to Gullfaks for storage and export. The Visund field began producing gas and exporting it to continental Europe on 7 October 2005.

Statoil submitted the plan for development and operation of Visund South in January. It has now built the first seabed template for the

USALawmakers in Texas have passed a bill requiring disclosure of most of the chemicals used in hydraulic fracturing. Although the industry has voluntarily begun sharing frac fluid details in response to public concerns about hazards relating to the chemicals, the new law will make it mandatory for all Texas wells. The law still exempts chemicals deemed ‘trade secrets’.

AMERICASThe Atlantic basin is expected to see an above-normal hurricane season this year, according to the seasonal outlook issued by NOAA’s Climate Prediction Center; a division of the National Weather Service. The seasonal average is 11 named storms, whilst the 2011 hurricane season can expect to see 12 - 18 named storms, with the possibility of 3 - 6 of those becoming ‘major hurricanes’.

WORLDRealm Energy International Corp. has contracted Halliburton’s Consulting and Project Management team to work with Realm Energy to significantly expand the technical evaluation and ranking of the highest potential shale deposits found in emerging prospective basins globally.

NEW ZEALANDNew Zealand’s new environmental protection laws dealing with its exclusive economic zone, (much of which is earmarked for oil exploration) will come into effect in July 2012. The Environmental Protection Authority will be responsible for issuing consents under the new law; monitoring and enforcement of activities within the EEZ, situated 12 - 200 nautical miles offshore and the Extended Continental Shelf, which extends further than the EEZ.

// OPEC // Raising output?

// Statoil // Visund South: fast-tracking nicely

With oil demand predicted to rise this year, it has been reported that OPEC’s oil ministers will discuss raising production quotas for the first time in almost four years.

The last time that OPEC producers chose to raise output quotas was in September 2007, when 522 000 bpd was added to the market. It is expected that raising the quotas to 1 - 1.5 million bpd will be discussed at a meeting in Vienna this month.

The violence in Libya has caused a net 1.4 million bpd to be removed from the market. This is despite a production increase by Saudi Arabia. As the maintenance season for European refineries comes to an end, a rise in demand for crude oil during the summer is expected.

first fast-track project, with the aim of cutting the time from discovery to production in half.

The template is the first to have been built from a standard catalogue for subsea equipment. This will form the basis for the continuing development and use of the standard catalogue in the fast-track portfolio.

The company has been working closely with the supplier industry to develop standard equipment for this part of its field development portfolio. This means that it can start to build equipment more quickly and develop smaller finds more efficiently.

It has taken less than a year to build the Visund South structure from the signing of the contract for subsea equipment with FMC. Subsea 7 will carry out the actual installation on the seabed.

Centrica has mothballed its South Morecambe gas field, which supplies 6% of the UK’s gas annually, following through on a statement of intention made last month in response to increased taxes.

The UK government’s decision to raise offshore drilling taxes had apparently made the field uneconomical.

Centrica claims that the site will be brought back into operation once the wholesale gas price reaches a level where it becomes economical again.

UK Chancellor George Osborne raised a supplementary tax on oil and gas production in his Budget from 20% to 32% in an effort to raise £2 billion to fund a cut in fuel duty. Centrica claims this raised the effective rate of tax on the South Morecambe field to 81%.

// Centrica // Mothballs gas field

world news

06 OILFIELD TECHNOLOGY June 2011

diarydates

30 August - 1 September3P Arctic 2011Halifax, Nova Scotia, CanadaE: [email protected]

6 - 8 SeptemberSPE Offshore EuropeAberdeen, ScotlandE: [email protected]/palladian

25 - 28 SeptemberMEOS 2011BahrainE: [email protected]

4 - 6 OctoberOTC BrazilRio de Janeiro, BrazilE: [email protected]

30 October - 2 NovemberATCEDenver, USAE: [email protected]/atce

7 - 11 NovemberWorld Shale GasHouston, USAE: [email protected]

4 - 8 December20th World Petroleum CongressDoha, QatarE: [email protected]

// BP // Settling Deepwater Horizon claims

Noble Energy, Inc. has announced a discovery at the Santiago exploration prospect in the deepwater Gulf of Mexico. The well, located in 6500 ft of water on Mississippi Canyon Block 519, was drilled to a total depth of approximately 18 920 ft. Open hole logging identified approximately 60 ft of oil pay in a high quality Miocene reservoir. Noble Energy is the operator at Santiago with a 23.25% working interest.

Santiago is the third discovery in the company’s Galapagos project, in addition to the prior successes at Santa Cruz and Isabela. Total gross resources discovered in the larger Galapagos project, including the Santiago well, are estimated by Noble Energy to be 130 million boe. Approximately 75% of the discovered resources are oil.

BP has announced that it has reached agreement with MOEX Offshore 2007 LLC and its affiliates, Mitsui Oil Exploration Co., Ltd and MOEX USA Corp. to settle all claims between the companies related to the Deepwater Horizon accident. MOEX, which had a 10% interest in the Macondo well, has joined BP in recognising and acknowledging the findings by the Presidential Commission that the accident was the result of a number of separate risk factors, oversights and outright mistakes by multiple parties and a number of causes. Like BP, MOEX Offshore has also recognised and acknowledged the conclusions of the US Coast Guard that, among other things, the safety management systems of both Transocean and its Deepwater Horizon rig had significant deficiencies that

// Noble Energy // Discovery

Malaysia’s Petronas is making bold moves to intensify its efforts in unlocking potential resources. Shamsul Azhar Abbas, Chairman at Petronas, has recently suggested that the company is poised to explore small and medium sized oilfields that are as yet undiscovered in the region, with the aim of raising crude oil production by 1.7 billion bbls.

“Geology-based assessments suggested that Asia’s mean undiscovered oil resources is in the order of about 50 billion bbls,” he said. “These undiscovered resources would translate into a resource base one-and-a-half times the combined proved reserves in Indonesia, Vietnam and Malaysia today,” he claimed at the 16th Asia Oil and Gas Conference this month.

// Petronas // Expanding exploration

rendered them ineffective in preventing the accident. MOEX has concluded that entering into a settlement with BP is in its best interest. The agreement is not an admission of liability by any party regarding the accident.

Under the settlement agreement, MOEX USA Corp., the parent company of MOEX Offshore 2007, will pay BP US$ 1.065 billion. BP will immediately apply the payment to the US$ 20 billion trust it established to meet individual, business and government claims, as well as the cost of the Natural Resource Damages.

The parties have also agreed to mutual releases of claims against each other. BP has agreed to indemnify MOEX for compensatory claims arising from the accident. BP’s indemnity excludes civil, criminal or administrative fines and penalties, claims for punitive damages, and certain other claims.

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world news

08 OILFIELD TECHNOLOGYJune 2011

// Shell // Upgrader Expansion Project // Total // Aquires interest in Qatari offshore block

Total has announced that it has signed an agreement with CNOOC Middle East (Qatar) Ltd, a wholly-owned subsidiary of CNOOC International Ltd, to acquire a 25% interest in Qatar’s Block BC (pre-Khuff) exploration license. CNOOC Middle East (Qatar) Ltd will continue to be the operator with a 75% interest.

Located 130 km east of the Qatari coast, the offshore block covers an area of 5649 km2, with water depths ranging from 15 to 35 m.

The Block BC Exploration and Production Sharing Agreement (EPSA), entered into with the Government of the State of Qatar, stipulates that 2D and 3D seismic surveys will be conducted and that at least three exploration wells will be drilled by 2014.

Commenting on Total’s participation in the Block BC EPSA, His Excellency Dr Mohammed Bin Saleh AI-Sada, Qatar’s Minister of Energy and Industry said, “We would like to welcome our long time partner, Total, into the Block BC EPSA, and we wish them and CNOOC all success with the exploration activities, which we believe are always enhanced when quality companies such as Total and CNOOC join efforts.”

“The farm-in transaction is another step forward in the partnerships forged with Qatar Petroleum and CNOOC, and reflects Total’s commitment to expanding its exploration and production operations in promising geological basins”, stated Christophe de Margerie, Chairman and Chief Executive Officer of Total.

Present in Qatar since 1936, Total has a 100% interest in the Al Khalij field, a 20% interest in North Field Bravo (NFB) block and a 10% interest in the Qatargas 1 liquefaction plant. The Group also has a 24.5% stake in the Dolphin Energy Ltd company and a 16.7% stake in Qatargas 2 Train 5. Total’s Qatari production averaged 164 000 boe per day last year.

// ExxonMobil // Angola strategy

The Offshore Technology Conference (OTC) presented ExxonMobil Development Co. with a special citation for the development and implementation of the ‘Design One, Build Multiple’ strategy that successfully delivered large-scale deepwater projects offshore Angola on Block 15, which achieved peak production of over 700 000 bpd of oil with the aid of two tension leg platforms and five of the world’s largest floating production, storage and offloading vessels.

The projects in Block 15, approximately 90 miles off the coast of Angola, established industry benchmarks for completion time and unit development costs for deepwater projects of their size and complexity. To date, over 1 billion of the 5 billion bbls discovered on the block have been produced. Current production is approximately 500 000 bpd.

Marathon Oil Corp. has announced that it has reached a definitive agreement with Hilcorp Resources Holdings, LP to purchase its assets in the core of the Eagle Ford shale formation in Texas in a transaction valued at US$ 3.5 billion. Along with other transactions expected to close by the end of this year, Marathon’s Eagle Ford acreage position is expected to more than double to 285 000 net acres.

In addition to the six rigs currently under contract related to this acquisition and two in Marathon’s other Eagle Ford acreage, Marathon has five drilling rigs on order and expects to be operating at least 20 drilling rigs in the Eagle Ford within 12 months of closing this transaction. As a result, the company expects to grow production from its total Eagle Ford acreage position to a peak of approximately 100 000 net boe per day by 2016.

// Marathon// Shale assets purchase

Shell has announced the successful start of production from its Scotford Upgrader Expansion Project in Canada. The 100 000 bpd expansion takes upgrading capacity at Scotford to 255 000 bpd of heavy oil from the Athabasca oil sands.

“This start-up is an important milestone for our heavy oil business,” said Marvin Odum, Shell Upstream Americas Director. “It adds new capacity from an important source of oil in a world requiring more secure energy.”

This is the first commercial production from the upgrader expansion. The Scotford Upgrader

processes oil sands bitumen from the Muskeg River Mine and Jackpine Mine, for use in refined oil products.

Production capacity at the Athabasca Oil Sands Project is now at 255 000 bpd. Engineers will focus on improving efficiency and adding capacity through debottlenecking.

Design and engineering work also continues on the proposed Quest carbon capture and storage project at the Scotford Upgrader. Quest could capture and store underground some 1 million tpy of CO2. A final decision to begin construction could come in 2012, once all regulatory approvals are in place.

The Arctic is one of the most desolate places on Earth, starting at a latitude 66˚ 33N, it covers some 21 million km2, or 6% of the planet’s

surface. One third is land and two thirds sea; for much of the year, it is shrouded in darkness, ice and raging blizzards.

But the Arctic is also a land of tremendous bounty. Whales feast on abundant sea life, polar bears hunt the shores for seals, and herds of caribou wander the vast tundra. Beneath the surface rests immense fuel reserves; according to the United States Geological Survey (USGS), more than 400 oil and gas fields, containing 40 billion bbls of oil, 1136 trillion ft3 of natural gas, and 8 billion bbls of natural gas liquids have been identified and developed, mostly in the West Siberian Basin of Russia and on the North Slope of Alaska.

And much more remains to be found. In a 2008 study, the USGS assessed all potential sedimentary basins north of the Arctic Circle and estimated that approximately 30% of the world’s undiscovered gas (1670 trillion ft3) and 13% of the world’s undiscovered

oil (90 billion bbls), could be found there. “I think the USGS survey is conservative,” says Dr. Benoit Beauchamp, a professor of Geoscience at the University of Calgary and the Director of the Arctic Institute of North America. “They did a good job of the Beaufort Sea and the Mackenzie Delta, but downplayed the potential of the Sverdrup Basin in the Canadian Arctic Islands and the Baffin Bay basin between Greenland and Canada.”

Recently, the search for oil and gas in the far north became a lot easier. Due to rising temperatures, the area of the polar region subjected to permanent sea ice has begun to shrink, from an annual summer minimum of 9 million km2 in the 1990s to 6 million km2 in 2007; some scientists predict a total clearance of ice by 2040. The retreat has not only opened up northern shipping lanes, it has extended the period of seismic offshore research and drilling by several months.

The result has been a resurgence in oil and gas exploration not seen since the 1970s. Infield Systems, a London-based consultancy, estimates that capital expenditure in the Arctic region should increase steadily

THE ARCTIC HEATS UP

10

Climate change may be opening up the Arctic to an exploration

boom, but other factors may be shutting it down. Oilfield Technology

Correspondent Gordon Cope takes a look at these factors.

11


throughout this decade, rising to over US$ 7 billion annually through 2017.

In Alaska, Repsol has announced a plan to spend at least US$ 768 million exploring 2000 km2 on the North Slope over the next several years. Development of this region’s offshore continental shelf (OCS) has been estimated by the American Petroleum Institute to have the potential to produce 10 billion bbls of oil and 15 trillion ft3 of gas, generating almost US$ 200 billion in government revenues over the next four decades.

In Russia, the immense Shtokman field, with reserves of over 24 billion boe, is tentatively due onstream in 2016. CGGVeritas and JSC Geotech Holding have announced a joint venture to supply ice class vessels to shoot 2D and 3D seismic in Arctic waters to delineate further targets. Rosneft and BP have formed a joint venture to tap into Arctic regions previously reserved for Russian companies.

Several companies have announced plans to institute and continue exploration in Greenland, which has a potential for over 50 billion boe in its offshore waters. Cairn drilled three wells in 2010, one of which showed signs of oil, and plans to drill another four during the 2011 season. Shell and Statoil have been awarded two large exploration blocks in West Greenland totalling more than 20 000 km2.

In the Canadian Beaufort Sea, Shell and Exxon have spent almost C$ 1.8 billion in the last two years meeting lease obligations, and hope to drill an offshore well on the continental shelf within five years.

ProblemsThere are many challenges facing Arctic exploration and development. First and foremost is the harsh climate; winter daily averages hover near -30 ˚C, and total darkness can stretch for six months.

Secondly, the Arctic is gas prone; about three times as much undiscovered reserves are considered to be gas, the rest is oil and natural gas liquids. Current markets for natural gas in North America are depressed by the glut of shale gas. This surplus has already cast doubt over the viability of the recently approved Mackenzie Gas Pipeline (MGP), a C$ 16 billion project designed to ship up to 1.9 billion ft3/d from the onshore Mackenzie Valley fi elds 1200 km south to markets in Alberta, and the Alaska pipeline, a proposed US$ 35 - 40 billion project to send 4.5 billion ft3/d of stranded gas in the Prudhoe Bay fi eld to the lower 48 states.

The trend toward rising temperatures is not without its downside, either. “Climate warming is a blessing and a curse,” says Beauchamp. “With less sea ice, you can navigate in the Northwest Passage (NWP) and the Beaufort Sea, which aids in seismic exploration and commercial traffi c, but you are also getting bigger, faster icebergs that scrape the ocean bottom much deeper, which means you have to bury pipelines quite deep to avoid damage.”

Climate change also complicates drilling. “During the fi rst round of exploration in the 1970s, the industry used some clever devices to drill, such as building artifi cial ice islands by spraying sea water in the cold conditions so that they could land large planes and install huge rigs,” says Beauchamp. “Now, there is some question if such devices would still actually work, and companies may need to bring in steel-reinforced ice platforms at much greater expense.”

Onshore infrastructure can also suffer. “Climate warming can destabilise the permafrost, causing roads to buckle and

buildings to collapse,” says Beauchamp. “Right now, engineers don’t know what the effect will be, and industry doesn’t like to deal with such large unknowns.”

Politics as usualIn addition to geological and meteorological considerations, navigating Arctic waters will require a steady hand when it comes to social, sovereign and environmental issues.

The Arctic has a permanent population of 4 million residents in Alaska, Northern Canada, Greenland and Russia. Most of them are aboriginal people, and their emphasis is on preserving their environment and livelihoods. For the last several years, Shell has attempted to drill licences held in the Beaufort Sea and Chukchi Sea (a body of water between Alaska and Russia that may hold as much as 30 billion bbls). Aboriginal groups objected to Shell’s programme, and late last year, a federal Environmental Appeals Board judge ruled that the Environmental Protection Agency (EPA) had not adequately evaluated the effect of drilling emissions on nearby aboriginal villages, and repealed two EPA permits. Shell, in turn, announced it would postpone drilling until the issue was resolved.

Environmental groups are adamantly opposed to Arctic drilling, and may have good reasons to be worried. BP’s Gulf of Mexico deepwater drilling disaster last year (in which 11 crew members were killed and almost 5 million bbls of oil were released), highlighted the diffi culties of countering a major spill even in an accessible, warm climate. Experts painted a glum picture of the ability to respond to a similar spill in an Arctic accident. Retired Admiral Thad Allen noted that only one of three US Coast Guard ice breakers is currently operational. The drill-staging community of Barrow, Alaska has no ability to house the hundreds of extra workers needed to handle a spill, and limited ability to handle emergency aircraft. Harsh weather and ice fl oes would further complicate remediation efforts.

The National Oil Spill Commission, appointed by the White House after the BP disaster, also iterated these concerns, saying that much more offshore research was necessary to ensure the ability to overcome the challenges imposed by the extreme Arctic environment. “Before the spill, there was talk of BP and Exxon drilling a subsea well in the next fi ve years,” says Beauchamp. “They were also seeking to remove a drilling clause that called for their ability to drill a relief well in the same season. Now, I don’t think removal of that clause will fl y at all. Industry will have to come up with serious plans to control any disaster fi rst.”

There are also many sovereignty issues to be sorted out. The NWP is a convoluted channel that passes between Canada’s mainland and its Arctic Archipelago. For centuries, seafarers seeking a shortcut from Europe to Asia have sought an ice free route, to no avail. Now, climate warming has opened the NWP completely for months at a time, creating an opportunity to safely transit the sea route.

Unfortunately, there is no international agreement on who can use the passage, and when. The United Nations Convention on the Law of the Sea (UNCLOS) allows free travel of vessels through certain bodies of water that transect jurisdictions (such as the Strait of Hormuz and the Strait of Gibraltar). Individual nations, however, control passage through internal bodies of water (such as the Mississippi River in the US). When UNCLOS was being created in the 1970s, Canada pushed for the latter designation. “As a sovereign water, Canada can say

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no to vessels carrying nuclear waste, or insist on double-hulled vessels carrying crude,” says Dr. Rob Huebert, the Associate Director of the Center for Military and Strategic Studies at the University of Calgary.

The US and EU disagree with Canada, however, and argue that the NWP is an international strait. “If the NWP is considered an international strait, then the ability of Canada to control shipping is limited,” says Heubert. “You can have military vessels and nuclear powered subs, as well as the right to military flyovers.”

“There is also an environmental aspect to control of the NWP,” says Beauchamp. “International laws are less enforced than Canadian laws. It would be more difficult to control the dumping of wastes.”

Unlike the Antarctic, which is not claimed by any nation, there are five nations that claim sovereignty over parts of the Arctic: Canada, the US, Denmark (Greenland), Russia and Norway (known as the Arctic 5). Several disputes over international boundaries remain to be solved. In 1825, Russia and Great Britain established the north-south boundary between Alaska and British North America as the 141st meridian of longitude. After the US purchased Alaska from the Russians and Canada became independent, however, a disagreement arose over where the boundary actually rested offshore. Each country covets a pie-slice of territory that covers some 21 000 km2, and may hold as much as 1.7 trillion m3 of gas and 6 billion bbls of oil.

The near futureOver the next few years, research may begin to dispel some of the concerns regarding the Arctic. The region, which is 30 times the size of Texas, has only a few thousand wells in total; it may be far more oil-prone than geoscientists expect. During a recent Arctic technology conference, representatives from Total SA postulated that exploration in deeper waters and around the rims of basins might find oil that was displaced by such giant gas reservoirs as the Snøhvit field off Norway, and the supergiant fields in the Yamal Peninsula/ Kara Sea off northern Russia.

Industry and nations are working to find solutions to above-ground problems. Experts note that aboriginal reluctance regarding oil and gas production depends on how companies approach communities. “You can’t make blanket statements in regards to aboriginal attitudes and development,” says Huebert. “When you look at the Canadian side of the Arctic, you have aboriginal groups that are favourably oriented, such as the Aboriginal Pipeline Group pushing for construction of the Mackenzie Valley Pipeline, which is a reflection of the homework that BP and Exxon did there. The Greenlanders are also really looking forward to oil and gas development; the Danes and Greenlanders have worked out an agreement that will see independence talks move ahead when they reach a certain degree of prosperity.”

In 2010, Russia and Norway announced that they had resolved a 40 year old Arctic boundary dispute, encompassing 170 000 km2, to their mutual satisfaction. Canada and the US also launched a joint expedition survey in order to map the Arctic’s North America continental shelf. Not only will it ascertain the extent of the OCS, the data will also help resolve the maritime boundary between the two countries.

The Arctic Council, an international body that has traditionally been used to communicate concerns between five main aboriginal groups and the eight nations that rim the Arctic (Norway, Sweden, Finland, Russia, Denmark’s Greenland, Canada, the US and Iceland), has taken a further step forward and created an international treaty that will divide search-and-rescue responsibilities among the nations and co-ordinate emergency response efforts.

In the longer term, the industry will design exploration and production hardware designed to deal with harsh Arctic conditions. Seabed Rig, based in Stavanger, Norway, in conjunction with Statoil, is developing a remote controlled rig that would sit on the Arctic seabed, well away from ice. The rig would be remotely controlled through an interactive 3D interface located on a surface vessel above. The rig is sealed to prevent contamination of the surrounding water, and has zero-liquids discharge during operations.

Numerous shipbuilders around the world, including Teekay in Vancouver and FLEX LNG in the UK, are working on building floating LNG plants capable of handling 75 - 100 million ft3/d of gas. Designed to circumvent the long, expensive process of building a liquefaction plant on land, the self-propelled vessels can pre-treat, liquefy, store and offload LNG. Such vessels are ideally designed to produce remote gas fields in the Arctic during ice-free months, then move out during inclement winter weather.

Changing economics may also make Arctic pipeline projects more viable. “I’m cautiously optimistic about the MGP,” says Beauchamp. “Shale gas is the big bogeyman; many people think that we won’t need the MGP or Alaska pipeline for a long time. But I think that the industry may have already picked the low hanging fruit of shale gas. The growing oilsands production will soon need that gas.”

In addition, an untapped source of energy may eventually come to the fore in the Arctic. Gas hydrates are complex water ice structures in which methane is trapped. Geoscientists reckon that there are several thousand trillion ft3 of methane trapped in hydrates around the world, with significant concentrations in Arctic permafrost and seafloor sediments. For the last several years, the US National Research Council, the Geological Survey of Canada and other researchers have been conducting experiments at the Mallik field in the Mackenzie Delta. Their studies have shown that hydrates can be produced in commercial amounts from conventional gas wells.

ConclusionsAlthough many obstacles remain, the Arctic is still the largest remaining region of untapped energy, and is relatively free of political restraints that place most of the world’s energy supplies off limits to IOCs. “In 10 years from now, I see significant oil and gas production in the Beaufort, the Russian high Arctic, and off Greenland,” says Huebert.

Dr. Beauchamp agrees. “Other regions with the potential for large conventional discoveries have warlords and terrorists and unfriendly governments,” he notes. “The Arctic is under Canadian and US jurisdiction, which have stable governments and regulations. That makes the Arctic less risky and more appealing.” O T

Notes1. Dr. Rob Huebert is the Associate Director of the Center for Military and

Strategic Studies at the University of Calgary.2. Dr. Benoit Beauchamp is a professor of Geoscience at the University of

Calgary and the Director of the Arctic Institute of North America.

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The Russian riddleEkaterina Kozinchenko, Jake Leslie Melville, Hege Nordahl and Adrian Del Maestro, Booz & Co., UK, contribute their perspective on ensuring the long term success of Russian oil and gas.

W inston Churchill once described Russia as ‘a riddle, wrapped in a mystery, inside an enigma.’ That remark still resonates with Russia’s foreign investors

– particularly with those involved in the energy sector. Today Russia stands at a major crossroads with regards to the evolution of its oil and gas industry. What is undisputed is that the country boasts some of the world’s largest hydrocarbon reserves, and is the largest oil and gas producer.

Geographically, Russia sits strategically between the large energy demand centre that is Europe, and the rapidly growing demand centres of China, India and other Asian economies. It remains very important geopolitically.

What is less clear is how well prepared Russia is to face the array of challenges to further develop its energy resources; a growing fiscal burden, ongoing investor concerns about the regulatory framework, inconsistent government intervention in

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the energy sector, overlaid as a costly place to do business from an expatriate perspective. An additional concern relates to the age and the types of fields both in production, and those still to be developed. Can the oil and gas sector meet the growing technical and operational challenges in accessing the country’s additional hydrocarbon reserves?

New oil and gas developments in Russia are increasingly complex, with operators having to explore and produce in

remote and frontier basins under difficult conditions, such as offshore Arctic. The industry needs to further develop the technical capabilities required to deliver large capital projects in both the upstream and downstream segments. Developing these capabilities – often by working side by side and in collaboration with international companies that have the requisite expertise – will be key for the long term success of the sector and critical in enabling domestic players to increase

17


production, build local infrastructure, and to execute expansionist strategies overseas successfully.

The size of the prize is truly significant…The importance of Russia as a major hydrocarbon basin cannot be over emphasised. As illustrated in Figure 1a, Russia boasts the largest gas reserves in the world - representing nearly a quarter of global resources - and competes with Saudi Arabia as the largest global oil producer, (Figure 1b).

Russia remains the major gas supplier to Europe, and is also a large crude supplier. Despite recent economic woes, its importance is undiminished. More than 80% of the country’s crude oil exports go to Europe and Eurasia, while nearly half of gas exports by pipeline go to Germany, Ukraine and Italy alone. The political turmoil that is sweeping the Middle East and North Africa has served to reinforce the importance of Russia as a major hydrocarbon supplier.

Figure 1a. Proven gas reserves by country, 2009. Source: Booz & Company research.

Figure 1b. Top 10 oil producers, 2009.

It appears that international oil companies (IOCs) have been expressing growing confidence in Russia. This year alone has witnessed the announcement of the BP Rosneft alliance (yet to be completed) focusing on exploration opportunities in the Arctic South Kara Sea, as well as Total’s US$ 4 billion investment to acquire a 12% stake in the gas producer Novatek. Similarly, Shell announced a strategic alliance with the Russian gas giant Gazprom towards the end of 2010, signalling its continued interest in Russia after the events of 2006, when the super major was forced to cede majority control of one of its flagship projects, Sakhalin II. Investor confidence in the Russian energy sector is not just limited to the oil majors. Wintershall (the upstream subsidiary of BASF) has a long history of co-operation with Gazprom. Indeed the two companies have three gas-marketing joint ventures, as well as production joint ventures in Russia and Libya. They also recently signed a memorandum of understanding on joint development of gas fields in West Siberia and the North Sea.

…but there are challenges aheadDespite the renewed interest of the international oil majors, West Siberia, the country’s most prolific oil province, is in sharp decline due to basin maturity and the lack of sufficient investment in existing infrastructure and new project developments. Partly for this reason, and as illustrated in Figure 2, oil production after a decade of substantial growth now appears to be plateauing.

As a result, energy companies are having to develop new prospects in frontier territories, driving up their costs significantly.

Growing capital project capabilities will be a fundamental hurdle for the industryLooking across the whole oil and gas value chain, there are a number of major capital projects under development by Russian companies, both at home and abroad, as illustrated in Figure 3.

Their ability to deliver these projects in a timely and cost-effective manner depends upon two major factors. First, Russian companies will need to have core project delivery capabilities, including diligent project scoping and concept development, use of new technology, risk management, rigorous project planning, appropriate contracting strategies, and a decision driven project delivery model. Second, they will need to manage and understand the operating context in light of difficult new frontier operating environments and local content requirements, as well as expertise in stakeholder management of government and local partners. All in all, the project organisation and governance set up needs to be tailored to the delivery challenges and operating context (including appropriate contracting strategies and capability

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levels). Specifically, the Russian oil and gas industry needs to strengthen technology development and improve capital project delivery capabilities, such as:

Front end loading: scoping, planning and detailing of design and concepts, to avoid re-work: stakeholder management for approvals.

Execution: contracting strategies, risk management, project control (design freeze, quality, plan and cost, decision gated maturation), commissioning – stakeholder management for licence to participate.

Transition/handover to operations: production and resource (capability) ramp up and operating model – stakeholder management for licence to operate.

Developing or assembling these capabilities will require setting up a delivery, governance and stakeholder management model that takes into account operating context, contracting strategy, access to capability, local content and regulations, JV configurations and enabling effective decision making (clarity on accountabilities and decision rights) and delivery both during project execution and during operations.

Figure 3. Source: BP Statistical Review of World Energy June 2010; Booz & Company research.

Figure 2. Russian oil production, 2000 - 2009. Source: BP Statistical Review of World Energy June 2010; Booz & Company research.

Options for developing the key capabilitiesGiven the challenges facing the Russian oil and gas sector, Russian oil and gas operators have three main strategic options:

Partnerships. Working closely with IOCs and collaborating on research and development is a viable and popular option. Examples of such joint ventures would include Gazprom’s collaboration with Statoil and Total in the Shtokman development in order to access advanced Arctic technologies. Part of the rationale underpinning the alliance between BP and Rosneft was to establish an Arctic technology centre to develop innovative technologies for the safe exploitation of the Russian Arctic shelf. According to recent press commentary, Gazprom is also considering shale gas joint ventures in North America in order to learn the technology. It is possible the gas giant will enter the US shale gas market in the next six to 12 months collaborating with smaller and more well-established players.

M&A. Acquiring the required capabilities in capital construction is another option. Lukoil, for example,

recently announced it was interested to work alongside North American companies in shale gas and ‘shale oil’ technologies.

Centres of excellence. This route involves establishing internal learning centres where best practice is captured and best in class processes and methodologies are developed. TNK-BP, Lukoil and Transneft have all respectively pioneered the creation of internal capital construction centres of excellence.

ConclusionChurchill concluded his famous comment on the riddle of Russia by noting that ‘the key [to solving it] is Russian national interest.’ That interest, happily, is the same as the interests of the global energy industry, as well as those of consumers in Europe and Asia: with the right sets of capabilities in place, foreign energy companies present the best path forward for Russia to develop and capitalise on its incomparable oil and gas reserves, and to ensure abundant supplies for these key markets in future decades. O T

Note Founded in 1914 by Edwin Booz, Booz & Co. is a global management consultancy, working with businesses, governments and organisations.

Technology has been crucial in supporting the sourcing and production of hydrocarbons since the modern age of oil and gas exploration began.

These technologies are developed to reduce capital expenditure, improve reservoir recovery, access new hard-to-reach reserves or minimise the environmental impact of exploration. Each requires signifi cant fi nancial capacity to develop, commercialise, test and position in order to achieve market adoption.

Parke A. Dickley, the petroleum geologist, once famously wrote of oilfi eld exploration in the 20th century: ‘Several times in the past we thought we were running out of oil and gas, whereas, actually, we were only running out of ideas.’

Over the next few years, ideas in the form of innovative oil and gas technology will be more important than ever as the sector faces a raft of notable challenges.

The industry needThe ongoing need to make the extraction of challenging conventional reserves more cost-effective creates a fertile environment for new technologies to emerge. Progress in this area is helping the industry to exploit reserves that had previously been uneconomical; building future value for their owners.

CREATING INVESTOR OPPORTUNITIES

Kevin Forbes, Epi-V, UK, explores the opportunities for private equity investors in the upstream services sector, which is set for

the next phase of industry investment.

21


However, one of the barriers remaining is changing non-conventional reserves into cost-effective, efficient prospects. Accessing this new oil requires intensive drilling and new completion methods, which in turn necessitate significant capital investment. Epi-V has successfully invested in technologies such as the i-Tec I-FRAC ball drop activated fracturing sleeve; that are helping to unlock these resources efficiently. These new, innovative technologies will be vital if the industry is to meet energy demand, which is predicted to grow by 40 - 50% to 2035 by the International Energy Agency (IEA).

For emerging fast moving services businesses, the industry climate is bringing considerable new growth opportunities to the fore. These opportunities include technology that is able to cost-effectively address the difficulties posed by deepwater, geologically complex reservoirs and unconventional reserves, such as shale gas.

Moreover, with oil prices above US$ 100 and the industry increasing its capital expenditure by 11% this year, 2011 is as good a time as any to back oil and gas services, as the sector enters its next significant spending cycle, with notable capital investment expected.

Entrepreneurial technology-driven oil and gas services businesses are highly attractive to a specialist investor, such as Epi-V, where, through a mixture of growth capital, industry insight and commercialisation competence, it can turn potential into a flourishing company of significant strategic value to the industry.

The shale challengeThe swift rise of shale gas and oil is just one of many segments of the oil and gas industry that is creating significant opportunities to invest in groundbreaking innovations that optimise production and drive process efficiencies.

Shale’s extremely low permeability and the extraction challenges this created meant that it was previously considered completely uneconomical. However, the combination of horizontal drilling, hydraulic fracturing and high tech multi-stage completions is allowing us to realise some of the potential of these vast reserves, with greater than 50% of US rigs now drilling horizontal wells and more than 150 drilling in one basin alone.

The challenges this market poses are both technical and economic, and they are placing strategic premiums on new technology capable of maximising reservoir contact and inflow performance, while improving efficiency and reducing time and costs.

Epi-V is looking at a broad range of businesses with technology that, when applied to this market, will address specific process challenges. These include maximising economic reservoir contact for the well and improving drilling and completion efficiency safely.

An investor’s active approachAs mature participants in the upstream services sector, Epi-V has witnessed a number of technologies with potential to exploit these new high value growth markets.

The organisational maturity of the majority of ambitious, technology-led oil and gas services companies means that investment alone is not enough. To access new growth areas, funding should be considered as only one requirement in a company’s long-term growth strategy.

To position companies to bring game-changing technologies to market, initially, they require capital investment to allow for product development, qualification and commercialisation - overcoming the challenges of industry adoption.

A notable challenge for new companies is to define potential applications and markets for a given technology. Epi-V works closely with management teams to chart all conceivable industry opportunities and how the technology can bring most value to the industry operators. In many cases, technology companies commercialise ineffectively as a result of failing to appreciate the adverse implications of changing current operator workflows or target applications that have low value to the operator. The broader perspective of an experienced, specialist investor can bring insight into the true commercial opportunities. This stage should assess the feasibility, use, development time and markets for the given technology, and consider additional applications that can speed adoption, identity value from an operator’s perspective and, ultimately, create a profitable business.

Strategic market positioning can then be taken to the next level, with the company actively engaging with its target customers having understood their requirements. By aligning technology with customer requirements, the business can then build persuasive marketing and brand strategies.

There are also more practical issues to take into account. How does the business translate the founder’s science and innovative IP into a development programme to create robust products? Does the company manufacture or outsource? What facilities are required? How will the business cope with geographic distribution? How will management recruit and manage a diverse workforce to meet growth targets? In the midst of all this change, the business must take an objective and disciplined approach to funding and cash flow, as this is the lifeblood of any new business. Experienced investors can provide significant support to guide emerging businesses though this process.

Combined, these stages allow a technology-led oil and gas services company to find its market, perfect its proposition and build a presence that allows for rapid adoption and profitable business growth.

Ideas transformed into successful companiesInnovation and technology will become increasingly central to the fortunes of oil and gas exploration businesses as companies explore resources in ever more challenging environments. The opportunities for investors and investee companies alike are significant, so long as the proposition is well positioned in the marketplace.

In seeking funding, businesses should look to potential partners with deep industry experience, not just funding. The industry is very competitive and traditionally slow to embrace new technologies, and financial backing alone is simply not enough to gain competitive advantage.

Emerging oil and gas services companies should seek both investment and the alternative viewpoint that an experienced investment partner can bring to its companies to help them realise their growth potential. When commercialisation is effective, upstream oil and gas services businesses can seize opportunities.

By identifying specific market opportunities and working closely with management to fully exploit their technology in that space, it’s possible to turn a nascent technology into a significant growth business that drives innovation for the entire industry. O T

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FI-00101 Helsinki, FinlandTel. +358 10 8611www.kemira.com

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Few would argue against the premise that seismic interpretation tools and their ease of use have improved significantly over the last few years.

From advances in attribute analysis to fault mapping and horizon picking, seismic interpretation has made substantial advances in developing geologically consistent 3D representations of the subsurface. Interpreters today can also enjoy a highly visual graphics environment on which to rigorously interpret their geological data and maximise its value for future reservoir management decisions.

This being said, however, seismic interpretation today still comes with certain limitations, which are manifested in a number of ways. For example, many geological models, often containing gigabytes of data, still remain highly generalised. All too often, it is just kilobytes and megabytes of data, including just a few mapped horizons, from which important interpretations are derived. The result is that huge amounts of potentially valuable seismic information are being lost.

There is also often a lack of understanding of the full structure of the seismic data, a lack of integration across the workflow and a manual-focus to interpretation activities.

Kristofer Tingdahl, dGB Earth Sciences, USA, addresses the limitations of seismic interpretation.

25


In this way, users are unable to gain a clear picture of the data’s depositional history, and horizons and faults often have to be picked and edited manually.

Against this context, there is a clear need for today’s seismic interpretation software to generate improved quantitative rock property estimations and clearer defi nitions of stratigraphic traps, create more accurate and robust geological models, and extract more value from the terabytes of high resolution seismic data.

This article will look at how these challenges are being met through a new automated horizon tracking tool and an improved graphics-focused environment.

The importance of horizonsHorizons – the term used to denote the surface in or of a rock or a particular layer of rock that might be represented by a refl ection in seismic data – have always been central to seismic interpretation. Seismic horizon interpretation can result in

automatic fault detection and defi nition and the accurate structural modelling of both fi elds and prospects.

While conventional interpretation workfl ows might only require a limited number of key horizons to be mapped, however, it has become clear to us that, by automating horizon tracking and creating a denser set of horizons, interpreters can extract more geology from their seismic data.

A dense set of auto-tracked horizons can help guide well correlations, generate an improved insight into the depositional environment, interpret systems tracts, and improve the chances of fi nding stratigraphic traps where oil might be found.

Furthermore, in comparison to standard workfl ows where the low frequency model is often considered to be the weakest link, having a dense set of horizons can result in a much more detailed model being built to be put forward for seismic inversion. By interpolating well data along the dense set of horizons, detailed geologic models can be generated that are fully consistent with seismic measurements.

This is the rationale and thinking behind the dip-steered auto-tracker dGB Earth Sciences has developed, known as the HorizonCube.

Building the HorizonCubeThe HorizonCube is a new plugin which is part of the company’s OpendTect seismic interpretation software, where a dense set of correlated 3D stratigraphic surfaces are developed into a set of continuous,

chronologically consistent horizons through an advanced algorithm. All correlated 3D stratigraphic surfaces are assigned a relative geological age.

Figure 1 outlines the process as well as the impact the HorizonCube can have on all elements of the seismic interpretation workfl ow, from well correlation to inversion to sequence stratigraphy.

To create a HorizonCube, all the user must do is input dip and azimuth cubes, at least two mapped horizons, and (optionally) mapped fault planes. Horizons are then created either in a model-driven way (through stratal or proportional slicing, for example) or in a data-driven way via a dip-steered, 3D chronostratigraphy auto-tracker.

The auto-tracker algorithm tracks the dip/azimuth fi eld to generate horizons that are typically separated by one sample at the starting position. The dip/azimuth fi eld is smoothed, reduces the impact of random noise, and allows the user to control the detail that needs to be captured by the horizon tracker.

Figure 1. The HorizonCube process and the impact it can have on all elements of the seismic interpretation workfl ow.

Figure 2. The power of high density horizon tracking for chronostratigraphic correlation. All tracked events are assigned a relative geological age displayed with a corresponding colour.

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Another advantage is that smoothed dip fields are more continuous than amplitude fields, that are used by conventional auto-trackers that pick amplitudes and/or trace similarities and then stop when the constraints are no longer satisfied. The result is a series of patchy horizons rather than continuous, chronologically consistent horizons as is the case here with HorizonCube. Horizons with watertight intersections at the faults are also generated through the HorizonCube by automatically stopping against mapped fault planes.

Figure 2 demonstrates the power of high density horizon tracking for chronostratigraphic correlation. To facilitate correlation, a random line created from the 3D volume through the wells and a dense set of horizons is auto tracked. All tracked events are assigned a relative geological age displayed with a corresponding colour with an interactive slider used to add or remove these chronostratigraphic events.

The process highlights in detail how events are correlated between the wells and aids in the understanding of how rock properties vary laterally. For example, the sandy shelf-edge facies observed in the right well correlates with a shaly, toe-of-slope facies in the well on the left.

The benefits of HorizonCubeSo what are the benefits of the new HorizonCube?

Firstly, the auto-tracked horizons allow a detailed and accurate low frequency model to be developed. Figure 3,

for example, demonstrates the difference between the HorizonCube and the conventional workflow in regard to not only the quality of the model but also the quality of the Acoustic Impedance (AI) inversions.

The simple model uses only top and bottom horizons to guide the well interpolations (a). The detailed model uses 19 additional horizons (d). The simple low-frequency model (b) does not fully honour the seismic while the detailed model does. The inverted results which are driven by the input models reflect these differences (c & f).

In this way, operators can get a lot more geology out of their 3D models and highly accurate low frequency models can be used to create geologically correct AI and Elastic Impedance (EI) cubes through the use of Deterministic and Stochastic Inversion plugins.

A clearer image of reservoir geometries can also be obtained. For example, Figure 4 shows the thickness maps of the depositional sequences

with and without HorizonCube interpretation on a field, offshore Abu Dhabi.

In this case, one of the main challenges of the seismic interpretation was the poor quality of the 3D data, where, due to this poor quality, the automated tracking of chronostratigraphic unit boundaries was not possible using conventional tracking methods (amplitude and phase responses were too indistinct for the tracker to trace for any distance in a consistent manner).

Through HorizonCube, however, it was possible to create a dense set of auto-tracked horizons and seismic-based maps of depositional cycles and system tracts – in this case, reflecting sediment build-up on the reef surface.

Well correlation and seismic/well data integrationTwo of the biggest challenges in seismic interpretation today are the ability to effectively use seismic data to aid well correlation and to support this through the integration of well-based sequence stratigraphy with seismic sequence stratigraphy.

To this end, the densely tracked horizon mapping and the interactive slider of HorizonCube allows interpreters to correlate and update well markers and horizons in order to improve well correlation. It allows the interpreter to reveal the spatial evolution of the sedimentary succession by visually moving forwards and backwards in geological time, highlighting in detail how events are correlated between the wells and aiding in the understanding of how rock properties vary laterally.

Figure 3. The difference between the HorizonCube and the conventional workflow in regard to not only the quality of the model but also the quality of the Acoustic Impedance (AI) inversions.

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Furthermore, in partnership with third-party specialists, dGB now offers the stratigraphic framework analysis of associated well log data, as an add-on to its Sequence Stratigraphic Interpretation System (SSIS).

Here, the stratigraphic analysis of well logs is conducted interactively with the seismic data analysis, adding to both the robustness and resolution of the resulting chronostratigraphic scheme.

In particular, dGB offers unconventional, data-driven attribute analysis of well logs with which it can either QC preferred well log markers for consistency with its SSIS results, or build a completely new log-based framework, based on sequence stratigraphic principles.

Like seismic data, well logs carry geological information in attributes that are unseen in conventional displays, and that are therefore unexploited for stratigraphic interpretation.

Based on linear predictions, the transforming of a facies-sensitive log (such as GR) reveals depositional patterns - correlatable from well to well - even across lateral facies variations. These define packages of strata, bounded by

Figure 4. The thickness maps of the depositional sequences with and without HorizonCube interpretation on a field, offshore Abu Dhabi.

Figure 5. Seismic interpreters can use HorizonCube to interact directly with the tablet in their editing and visualisation activities.

surfaces corresponding to the flooding surfaces and base level falls of sequence stratigraphy. The packages range in scale from the sequences and para-sequences of seismic stratigraphy down to the limits of the resolution of the logs. The analysis is carried out using the CycloLog software package from Enres International and is deployed by consultants with extensive experience in this method.

The combination of this innovative approach to the stratigraphic analysis of well data with dGB’s SSIS technology offers clients a powerful means of building a stratigraphic and hence depositional framework.

The importance of an accessible, intuitive workflowHorizonCube can only be fully effective, however, if interpreters move away from the manual-focused and limited graphics environments of the past and operate in an

environment where workflow processes are more accessible and intuitive.

It’s with this in mind that dGB has teamed up with the Japanese company Wacom, a world leading manufacturer of pen tablets and digital interface solutions, allowing seismic interpreters using HorizonCube to interact directly with the tablet in their editing and visualisation activities (see Figure 5).

This allows for the drawing of horizons, faults and objects within a highly user-friendly and graphics-focused environment, with the interactive pen display allowing the user to directly work with the pen on the screen and thereby making the process of analysing data much more efficient. This is due to the perfect hand-eye co-ordination of the pen display and the fact that the user works exactly at the point on the screen where he wants the cursor.

To this end, HorizonCube can be used for sequence stratigraphy interpretation where the horizons are used to mark sequence boundaries and faults can be directly drawn into the data set. The result is a highly innovative but practical tool.

Generating a different perspectiveSeismic interpretation today is all about generating a different perspective on the geological and stratigraphic aspects of data volumes and squeezing maximum geological value out of this data.

With applications, such as HorizonCube, and partnerships with companies such as Wacom, where dGB is using its experience in the photography, graphics, and fashion design industries and applying it to seismic interpretation, the company is seeing how seismic interpretation has the power to innovate and the overcome limitations of the past.

Geoscientists will finally be able to enjoy the full benefits of knowing the complete structure of their reservoir data, leading to geologically sound rock-property predictions, effective well correlation and more geological information from seismic than ever before. O T

Three ingredients are required to obtain a good resolution of our hydrocarbon reservoirs from reflection seismic data. These are an imaging method that is able to collect

and relocate the reflections pertaining to a specific reflector, an accurate set of data dependent parameters that steer the imaging process, and, hopefully, good data.

Highly accurate imaging methods are available today, but quite often cannot fully exploit their strengths. Data noise and irregularities deteriorate both the determination of accurate imaging parameters, and the actual imaging process, thus requiring effective ways to increase the robustness of imaging and lithology prediction. Such effective measures are demonstrated by recent strategies of the Common Reflection Surface, or CRS method that enhance the subsurface resolution in both, the prestack domain of measured data, and poststack domain of stacked data.

During the last decades, the determination of the seismic imaging parameters, and the actual imaging process have seen a steady development to more and more sophisticated numerical methods that went hand in hand with the increase of

numerical computer power. Modern depth imaging by prestack depth migration (PreSDM) provides the most accurate methods for a combined realisation of the two imaging steps, the focusing of all reflections from a single subsurface structure, and their relocation to the original position in depth.

Especially in complex geology, however, these PreSDM methods are very sensitive to the signal-to-noise ratio of the seismic data, and even more to the velocity depth model. Model building has thus become the most crucial and costly step in depth imaging, since PreSDM requires an accurate and even more consistent global field of imaging velocities. Here again, the data quality has a strong influence on the model building process.

The CRS approach now offers a preconditioning of seismic data that strongly raises the signal quality, and optionally compensates for irregularities in the spatial distribution of seismic recordings as well. The main idea of this CRS strategy is to collect and focus seismic reflection events belonging to a local common subsurface structure, the so called common reflection surface, before entering further imaging or reservoir

SHARPENED VISIONHenning Trappe, Gerald Eisenberg-Klein, Juergen Pruessmann,

TEEC, Germany, discuss the use of CRS analysis on seismic data to improve the view of reservoir structure and lithology.

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characterisation steps. As an example, Figure 1 illustrates the effect of CRS focusing by PreSDM sections of low fold 3D seismic land data.

Further advantages of this CRS data preconditioning for imaging in time and depth, model building and reservoir studies are outlined in the following, after a closer look at the CRS imaging principles.

CRS methodCRS focusing is characterised by both a high resolution, and a general robustness. Dense local measurements of seismic data parameters are collected from each imaging point into so-called CRS attribute volumes providing the high resolution. The robustness with respect to local parameter errors is based on the local independence of the measurements, in contrast to the mutually dependent estimates of PreSDM imaging parameters in a global model.

Another advantage is the high number of contributions that are used in CRS focusing of individual reflections events, leading to a strong suppression of noise. This multiple contribution, the so called fold, is a consequence of the general CRS subsurface assumptions of local reflector elements with dip and curvature in the subsurface. In the seismic data, the seismic reflection produced by one of these complex reflector elements is certainly not confined to a specific common mid-point (CMP) of the shot and receiver pairs, but extends across many neighbouring CMP locations. Collecting the contributions from all these CMP locations amounts to a much larger stacking fold than in conventional CMP stacking using one CMP location at a time only.

The CRS contributions to a certain image point are collected along a hyperbolic time surface for zero-offset stacking, that was presented by Mann et al. (1999) and Jäger et al. (2001) following initial work by Gelchinsky (1988). Corresponding to the complex reflector geometry, a complex set of stacking parameters is required to define this time surface, comprising the wavefield dip α, and the wavefield curvatures RNIP and RN at the surface. They are related to hypothetical wavefronts from a point source at the normal incident point (NIP) on the reflector, and from an exploding reflector, respectively. This is indicated in Figure 2 (top) for the case of 2D seismic data.

The advantages of CRS stacking as opposed to conventional NMO/DMO stacking were illustrated by Hubral et al. (1999) in the schematic display of Figure 2 (bottom). The high fold and the increased S/N ratio of the CRS stacked section are attributed to the better fit of the CRS travel-time approximation (green) to the actual reflection times (blue) in a much larger area of the offset and CMP domains. CRS stacking obviously collects a much larger portion of the actual reflection. Stacking along the full CRS travel time approximation provides a CRS stack, whereas partial stacking in small offset and CMP intervals is used to produce CRS gathers with an enhanced signal contents.

The main factor assuring the high resolution of the CRS stack is the automatic estimation of an optimum set of stacking parameters, the so-called CRS attributes, at each point of the image. Due to this detailed attribute search, CRS imaging is a computationally intense method, especially in 3D applications. This advance in seismic processing can thus be regarded as another consequence of the increased

Figure 1. Kirchhoff prestack depth migration of CMP gathers (top) versus CRS gathers (bottom). Note the improvement of sedimentary reflections and salt boundary.

Figure 2. The CRS stacking attributes comprise the emergence angle α and the wavefront curvatures RNIP and RN at the surface, which can be related to hypothetical experiments with (a) a point source, and (b) the exploding reflector, respectively, in the subsurface (top row, after Jäger et al., 2001). The fit of (c) DMO and (d) CRS stacking surfaces (green) to the CMP/offset-dependent travel times (blue) are illustrated for an anticlinal model (gray, bottom of graph), showing a large area with excellent fit for CRS stacking (bottom row, after Hubral et al., 1999).


power of modern computers, just like the evolution of new depth migration techniques.

Increased CRS fold for noise suppression in low fold dataSeismic imaging generally faces problems when dealing with extremely low-fold or sparse seismic datasets. In order to obtain a good image in those cases, the redundancy of the data must be identified and exploited to the highest degree. Obviously, CRS imaging is well suited for this task by tracing seismic reflections through large portions of prestack data. This CRS imaging strength at sparse data has been illustrated by the depth sections of Figure 1 with strongly improved 3D PreSDM results from CRS gathers.

A more systematic investigation on CRS stacking in low-fold data was presented by Gierse et al. (2007) starting from 3D seismic land data with a fold of 15. Acquisition at an even lower fold of eight was simulated by omitting every second shot line or every second receiver line, respectively, and finally acquisition fold was reduced to four using both types of omissions. For each configuration, CRS zero-offset stacks were obtained by full CRS stacking.

Figure 3 compares the reference NMO/DMO stack from the original 15-fold data to the CRS stack of the final 4-fold data. CRS imaging fully compensates for the loss of acquisition fold, providing an image that is even superior to the conventional full-fold result in many areas. CRS imaging thus represents a processing option for 3D surveys acquired at low fold due to limited access or economic reasons. An additional advantage of CRS processing is observed in Figure 3 where the data is partly interpolated into the muted near surface zone by CRS using data from neighbouring inlines.

CRS gathers for enhanced prestack applicationsThe previous CRS imaging examples have shown that CRS stacks of good quality may be produced for low-fold data, and then used for further processing in poststack time or depth migration. A much larger potential for improved imaging, however, lies in prestack applications of the CRS processing producing CRS gathers.

The construction of CRS gathers makes use of the dense CRS attribute volumes that comprise local kinematic measurements for each point of the image, thus providing a detailed and accurate kinematic description of the seismic events in the data: this information can be used for mapping seismic data to any existing, or new prestack trace geometry. Event data from original traces in the vicinity of a target trace is mapped to that target trace by dip-consistent partial CRS stacking, based on the CRS attributes.

The CRS data mapping may be used to solely decrease the noise level in the existing data traces by considering exactly these input traces as target traces of the trace extrapolation. Each initial data trace is then replaced by an extrapolated CRS trace at the same location as shown in Figure 4, which obviously preserves the original shot geometry in the CRS shot gather but increases the signal-to-noise ratio by partial CRS stacking. CRS shot gathers with preservation, or enhancement of the original shot geometry are well suited for shot-based depth migration techniques like wave-equation PreSDM or RTM.

Alternatively, new geometries can be introduced for reconstructing shots and target traces away from the existing

Figure 3. DMO reference stack of original 15-fold land seismic data (left), versus CRS stack of reduced 4-fold data (right). Note the preservation and enhancement of structural resolution.

Figure 4. Original shot gather (top), and associated geometry-preserving CRS shot gather (bottom).

Figure 5. Moveout corrected CMP gather (left), geometry-preserving CRS gather (middle), and CRS gather with offset regularisation (right).


data configuration, or for regularising the data geometry in CMP/offset domain. Figure 5 compares an original CMP gather from 3D land data with corresponding CRS gathers. Geometry preservation as performed in the CRS shot gather construction of Figure 4, leaves the irregular data distribution in the CMP/offset domain untouched but enhances the signal contents (Figure 5 middle). Regularised CRS gathers with a uniform CMP/offset coverage (Figure 5 right) may interpolate the seismic reflections in large data gaps and even reconstruct seismic features like air waves. These CRS gathers are well suited for CRS-AVO investigations, and for Kirchhoff prestack migration in time or depth as shown in Figure 1.

CRS based depth imaging workflowBoth the CRS gathers, and the event information in the CRS attributes may be used to design a complete depth imaging

workflow. Commonly the first step to depth is the fast derivation of an initial velocity model in depth from processing parameters of the time processing. The traditional Dix conversion of stacking velocities into a starting model in depth is restricted to mainly flat structures since stacking velocities do not contain any useful dip information (Dix, 1955).

The CRS attributes, on the contrary, comprise an explicit dip measurement. Inversion of CRS attributes by grid tomography into a velocity depth model thus well reconstructs the dipping trends. This was demonstrated in a case study of CRS depth imaging in salt geology by Pruessmann et al. (2008), using 3D seismic data from the coast of the Gulf of Mexico. In this case study, the velocity model from CRS tomography followed the seismic depth structures much better than the Dix model from stacking velocities (Figure 6).

The costly refinement of the velocity depth model that uses iterative PreSDM with subsequent moveout analysis in depth gathers, can as well be shortened significantly by migrating CRS gathers. The flatness of the depth gathers as a measure of the model accuracy is more clearly visible in the CRS depth gathers with a high signal-to-noise ratio. The CRS depth imaging workflow finally produces a depth image with superior resolution of the near surface sediments, a better definition of the salt body, and much clearer sub-salt reflections in comparison to the result of the conventional workflow (Figure 7).

CRS characterisation of reservoir structure Based on the local optimisation of the CRS attributes the CRS processing may reveal local details that have not been present in previous stack sections. This is shown for a suspected gas-water contact, which is clearly outlined after CRS processing but much less in a conventional stack (Figure 8).

Another example of structural reservoir characterisation from Eisenberg-Klein et al. (2008) compares time slices of 3D

Figure 7. Final prestack depth migration from conventional depth imaging flow (left), and from CRS flow (right). Note the improved definition of the salt body.

Figure 6. Dix model (left) versus CRS tomography model (right) with respective CRS poststack depth migrated sections.

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Figure 8. Stack from conventional processing (top), and CRS processing (bottom). The suspected gas-water contact is much better resolved by CRS, forming a horizontal line through the centre of the ellipse.

Figure 9. Time slices at 1256 ms through coherence volumes calculated from conventional prestack time migration (left), and poststack time migration of the CRS stack (right), demonstrating the noise suppression and associated fault enhancement by CRS processing.

coherency volumes calculated from a conventional prestack time migration, and a poststack time migration of a CRS stack (Figure 9). The slice of the conventional prestack time migration shows a strong noise contamination in some areas, while the CRS processing removed the noise and highlighted the faulting. Prestack time migration on CRS gathers provides a similar suppression of noise but was not considered in the work by Eisenberg-Klein et al.

CRS-AVO and reservoir lithologyBesides structural investigations at reservoir level, CRS processing may also contribute to the lithology prediction, e.g. in impedance inversion of high quality CRS images, or by AVO investigations at CRS gathers as illustrated in Figures 10 and 11. For 3D land seismic data from a gas storage site, three moveout-corrected CMP gathers with standard amplitude-preserving preprocessing are shown at locations A, B and C, respectively (Figure 10 top). The noise contamination is obvious, producing a patchy amplitude distribution. Furthermore, acquisition irregularities had caused a varying offset coverage with several trace gaps.

In the corresponding moveout-corrected CRS gathers, regularisation in the CMP-offset domain has filled the trace gaps by event-consistent data contributions from neighbouring CMP locations (Figure 10 bottom). Uncorrelated noise has been largely removed, revealing seismic reflections that were partly or fully buried in the noise before. Correlated noise, however, has not been eliminated as is demonstrated by the ground roll at location A.

In general, the CRS gathers exhibit a good reflection continuity allowing a first rough evaluation of the offset-dependent amplitude behaviour. The most obvious feature is provided by the high reflection amplitude in the upper part of the CRS gather at location B. An increased amplitude level may also be recognised in the corresponding CMP gather, but due to the noise-induced fluctuations it does hardly stick out from the average amplitude distribution as represented at location C. The CRS gather at location B, on the contrary, does not only show this strong amplitude increase very clearly but also its confinement to large offsets.

Based on the CMP and CRS gathers discussed before, AVO analyses in the un-migrated domain produced the shallow vertical sections through the gather locations A, B, and C displayed in Figure 11. These sections contain the product (P*G) of the AVO attributes intercept (P), and gradient (G). The conventional result in the top row of Figure 11 clearly shows the noise contamination which is increasingly harmful when approaching minimum fold near zero time. In the whole section, the reflection information is completely hidden by the noise influence which is much stronger than any trends of the reflection amplitude.

The CRS-AVO result in the bottom row of Figure 11 shows a strong noise reduction, now revealing the reflected structure forming an anticline. Most parts of the section show blue colours corresponding to the wet trend of water-saturated sediments, or decreasing amplitude with offset. The red colour mainly appears at anticline reflections at medium time where the gas-bearing reservoir is located. This colour corresponds to an increase of reflection amplitude with offset, and indicates the presence of gas. This effect is especially strong near the top of the anticline as confirmed by the CRS gather of Figure 1 at location B, and


decreases at the flanks. As a result, the CRS approach provides a robust AVO analysis with meaningful results at data where conventional AVO completely fails.

ConclusionsThe CRS method that was originally developed as a generalised seismic stacking technique in time domain, has developed into a universal tool for robust parameter estimation and model building, enhanced lithology prediction and reservoir analysis, and high resolution poststack and prestack migration in time and depth, for 2D/3D land and marine data. The extension of the CRS stacking range over several CMP locations and over the full offset range strongly increases the fold, allowing a stable determination of the stacking parameters, the so-called CRS attributes, for each point of the image. These densely sampled attribute volumes represent a highly detailed event description of the seismic data for high-resolution applications in imaging and beyond.

The increased fold of the local event description, and the associated increase of the signal-to-noise ratio in CRS imaging is effective in both land and marine data of various fold.

Especially in low-fold data, CRS imaging uses the redundancy of the event information to a maximum extent in order to reveal reflections and faults that are mostly buried in noise in the associated conventional time and depth images. CRS may thus be regarded as a versatile complement of sparse 2D or 3D seismic acquisition in surveys with limited access, or severe cost restrictions.

A powerful approach to combine CRS processing with modern prestack imaging techniques is the partial CRS stacking into so-called CRS gathers. CRS partial stacking reduces the data noise in prestack time or depth migration, and CRS data regularisation minimises the migration noise in these processes. CRS data regularisation in shot domain is well suited for wave-equation depth migration and RTM, whereas regularisation in CMP/offset domain improves Kirchhoff prestack migration in time and depth, but also AVO analysis, or simply the manual stacking velocity analysis in poor data.

A comprehensive CRS depth imaging workflow comprises both the model building, and the prestack and poststack depth migration. In a first step, the detailed event information of the CRS attributes is inverted by grid tomography into a reliable starting model of the velocity in depth. Dip is well honoured in this model, in contrast to conventional models from Dix inversion of stacking velocities. The reliable starting model, and the improved model update on CRS-based depth gathers effectively reduce the model building time and cost. The final depth migration of CRS gathers increases the general resolution, and especially improves the definition of salt bodies and sub-salt reflections.

The structural reservoir analysis strongly benefits from the high resolution of CRS imaging, and from the local optimisation of the CRS imaging parameters. Coherency measures from CRS images show a significant noise suppression revealing the fault systems in noise zones. A similar noise suppression is observed in CRS-AVO analysis, which allows to expand AVO to deeper targets and noise zones especially in land data. Further CRS tools are available, thus composing a complete processing chain from initial CRS residual statics until the final CRS reservoir studies, a chain that is steadily expanded by new developments. O T

Figure 11. Conventional AVO (top) versus CRS-AVO (bottom): product section of AVO intercept and gradient across a gas storage with indication of gather locations A, B, C of Figure 10.

Figure 10. CMP gathers (top) versus regularised CRS gathers (bottom) from 3D land seismic data across a gas storage. Note the CRS signal enhancement in general. At location B, the increase of amplitude with offsets is highlighted by the CRS result, and trace gaps are filled.

<COVER STORY>

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For more than 50 years, drillers have utilised technologies that enable them to drill directionally and through difficult formations. While the benefits provided by these technologies are extremely compelling, the rate of innovation remains surprisingly

slow. A study conducted by McKinsey & Co. estimates the average time from idea to 50% market penetration is over 30 years for oilfield technologies in general, compared to less than seven years for consumer products.

Overcoming the technology adoption paradigmDrilformance® is a drilling technology company formed to create and rapidly deliver innovative equipment to improve well economics for E&P operators. By coupling reliability and risk reduction with step-change improvements, its mission is to provide drillers with bottom-line benefits from tomorrow’s advanced technology - today. Specifically, Drilformance technology development focuses on next-generation polycrystalline diamond compact (PDC) drill bit systems. Drilformance bits integrate high PDC drill bit speeds with roller-cone toughness to

A move to

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drill through both soft and hard formations, while eliminating extra trips for bit changes.

The true cost of drillingDrilling costs account for 60% of E&P operator budgets, on average, and 60% of total drilling process time is spent tripping in and out of the hole. Cost-effective technologies that can effectively reduce pipe trips and increase drilling efficiency will be essential if the industry is to feed the world’s growing appetite for energy in the years ahead.

Drilformance approaches new PDC bit development in a collaborative manner with its customers. The company takes a logical, methodical approach to developing, manufacturing and

testing its PDC drill bits, with each step of the process analysed through the lens of industry needs.

Answering the tough questions to drive technology developmentDrilformance’s technology development approach aims to answer fundamental questions: “Why is the rate of penetration (ROP) slower when sliding compared to rotating?” and “Why must an unnatural bias be created in a bottomhole assembly to drill directionally?”

To tackle the tough questions head-on, the research team incorporates extensive field data, rigorous modelling, meticulous testing and tools ranging from basic logic to advanced materials science. By tackling problems holistically, limitations are resolved and barriers to success eliminated.

Manufacturing techniquesDrilformance uses a methodical approach to manufacturing, keeping unique processes simple and streamlined. Fewer steps, systematic processes and rigorous quality control ensure delivery of uniformly high quality bits with dependable field reliability and predictable results.

Utilising manufacturing techniques from the aerospace industry, each Drilformance PDC bit is milled from a block of solid steel, providing maximum structural integrity and a high degree of elasticity to reduce bit chatter and eliminate fishing jobs due to broken blades. Drilformance bits have an extremely short make-up length, and incorporate a patent-pending make-up system that eliminates the need for a welded shank behind the bit, further reducing make-up length while increasing structural integrity. Each bit is machined to the same tight tolerances and precise pocket accuracy, ensuring consistent field performance. Proprietary manufacturing processes enable higher blade standoff, increasing the junk slot area for better hole cleaning. Fit-for-purpose manufacturing processes also help the bits stay in gauge, eliminating reaming operations that waste rig time.

Dynamic force balancingBit stability and control is enabled by tightly integrated bit frame components. Drilformance proprietary engineering and manufacturing methods uniquely address common PDC usability issues such as stick-slip, bit-whirl, and non-uniform weight distribution across a breadth of dynamic environments.

This attention to detail in development and manufacturing produces PDC drill bits that allow operators to achieve total depth (TD) in significantly less time and, as some of the cases below illustrate, with only a single drill bit.

Drilformance PDC bit field results

Wolfberry Trend, West TexasAn operator drilling offset wells in this Permian Basin formation required a minimum of two, and typically three bits to complete the production hole section. After selecting a Drilformance 7 7/8 in. DF613R2 PDC bit for the production interval, the operator reached TD in 119 hours with a single bit. The run shaved off three days of drilling time and eliminated a 12 hour trip, for estimated savings of more than US$ 150 000. Additional wells in the trend have been consistently drilled with a single DF613R2, enabling a step-change in performance improvement from the operator’s perspective.

Figure 1. Drilformance Acel DrillTM PDC bit system.

Figure 2. Comparison of drilling time using Drilformance PDC bits (left) versus the drilling time for other drill bits (right), demonstrating a time saving of 143 hours.


In another area of the same trend, the operator typically required three to five production bits to drill to TD. After selecting Drilformance PDC solutions, the first well took two production bits and 200 hours of drilling time, compared to 343 hours on a previous well, resulting in savings per well estimated at over US$ 200 000. Additional wells have realised similar performance gains.

Bone Springs Trend, New MexicoThe operator was looking for a bit that could beat their best bit run to date (close to 80 ft/hr) and drill the entire interval in one run to reach kick off point. Using an 8 ¾ in. DF613R2 PDC bit, the rig drilled the entire vertical section in one run at 89 ft/hr for an 11% gain over the previous best record.

Eagle Ford Shale Trend, South TexasThe operator’s goal was to drill an entire production hole interval, which contained multiple sections including tangent, curve and lateral, with one bit to a planned TD of approximately 16 400 ft. No bit had drilled the entire section on a well of this length in this area.

The operator selected an 8 ¾ in. DF513R bit for the operation. The bit’s stable, aggressive cutting structure allowed the entire interval of approximately 12 000 ft to be drilled, reaching TD with no problems. The bit held angle in the tangent and maintained 13 deg/100 ft build rates in the curve, with sections of the curve sliding at over 60 ft/hr. The operator confirmed that the Drilformance drill bit achieved the best results for that rig to date.

Results of another operator in the Eagle Ford Shale trend for three wells drilled on the same pad using competitor bits on two wells and a Drilformance DF513R bit on the other well are shown below:

The Drilformance bit drilled the interval 24 hours faster than the best offset run on the pad, and reached TD in 56 hours.

The Drilformance curve ROP average was more than 50 ft/hr and lateral ROP average was more than 100 ft/hr.

This example highlights the DF513R’s directional and rate of penetration capabilities. Drilformance bits tend to stay on target, resulting in fewer corrections and more time rotating with better ROP. On this pad, the Drilformance run resulted in approximately 10% less time sliding compared to the competitor offset run, (Figure 3).

Marcellus Shale Trend, Pennsylvania An operator was looking to optimise results in the surface hole, curve, and lateral intervals. A 12 ¼ in. DF513 was utilised to drill the surface hole 50% faster than previous methods. The challenge for the curve and lateral sections was to find a bit that could achieve the desired build rates in the curve and still get high ROP in the lateral section. An 8.75 in. DF513R was utilised to drill both intervals to TD in a single run. The bit achieved excellent build rates in the curve and showed a 40% increase in ROP versus previous competitor offset runs.

Cardium Trend, AlbertaAn operator had been looking for a bit to drill the vertical and curve section in one run in the Willesden Green Field. To this point, no other bit had successfully completed the interval. The operator chose an 8 ¾ in. DF516R and drilled the entire 1832 m interval to casing point, saving valuable rig time. The dull was 1-2-CT compared to competitors’ previous attempts that had resulted in bits being pulled and found damaged beyond repair.

Recent breakthroughs Drilformance’s design philosophy is to push the limits of what can be drilled with PDC systems, while maintaining optimal performance across the wide range of applications. The Drilformance Advanced Technology Development team has created PDC systems that focus on the driller, emphasising steerability and control, in addition to high penetration rate and durability.

Recent advancements include the Heli PathTM radial spiral structure, coupled with a Compact UnibodyTM design and Opti TracTM modelling, providing both stability and directional control. Shadow PathTM enhances bit shoulder durability while extending PDC cutter life. Rhino ArmorTM provides maximum protection on all critical surfaces, minimising erosion from high solid mud systems. Cryo EdgeTM PDC cutter technology

Figure 4. Average drill out run (metres) drilled, Willesden Green Field, Alberta, Canada.

Figure 3. A comparison of Drilformance’s PDC bit performance with two competitor bits, demonstrating Drilformance’s significantly lower drilling time and higher ROP.


provides excellent impact resistance, abrasion resistance and thermal stability.

Rhino ArmorDrillers who seek to maximise their PDC intervals require both strength and durability. Drilformance utilises proprietary Rhino Armor hard facing to achieve maximum protection for PDC systems. Precise temperatures and application width are enforced in the application to prevent delamination and maximise fracture resistance. Material volume is augmented on the bit shoulder and gauge to provide additional protection to high-wear surfaces.

Cryo EdgeThe principle behind the architecture of the cutter is to minimise fracturing and increase thermal resistance by

Figure 5. An aggressive cutter profile engages the most demanding formations with ease, while the patent-pending Shadow Path work sharing system enables longer cutter life by reducing heat build-up.

Figure 6. Superior directional control and stability is achieved by Opti Trac modelling and the patent-pending Heli Path radial structure on the bit face.

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providing the optimal angle of attack for the cutter edge. Drilformance’s Cryo Edge PDC cutters consist of a single piece of tungsten carbide substrate bonded to a high quality PDC compound. Cryo Edge is a combination of proprietary manufacturing process and materials, which include a precise angular micro-bevel applied to each cutter before insertion into the bit pocket. This calibrated displacement impacts the shear potential of each cutter, permitting a more aggressive profile to maximise depth of cut with each revolution.

Accel DrillTM: next generation drillingDrilformance has integrated all of its current technologies into Accel Drill, providing step-change advances in drilling capabilities. For example, Accel Drill incorporates Drilformance’s Dynamic NutationTM system, which enables longer intervals to be drilled faster, particularly in tough formations. Adamas BaseTM advanced materials are incorporated in high-wear moving components of the system for significantly increased tool life. Drilformance’s Accel Drill system bit-to-bend length is 10 in., as compared to conventional directional assemblies having typical bit-to-bend lengths of 3 - 6 ft. Accel Drill’s shorter bit-to-bend length reduces unnatural lateral stresses associated with conventional assemblies, and significantly increases dogleg severity capability.

The combination of these advances means complex geometry wells can be drilled from surface casing to TD without tripping out of the hole to change BHA assemblies. Consistent reliability and notable increases in versatility and ROP contribute directly to bottom-line drilling economics.

Measurable productivity is the name of the gameUnconventional and complex geometry well economics are driven by increases in operational efficiency. Operators and directional drillers are using manufacturing-style approaches to achieve reliable, predictable and low cost results. Rather than relying on instinct or tried and true approaches, increasingly we turn to field data to determine ‘what’s really working.’ Drilling programmes have reached a stage of maturation such that different bit technologies have been tried in different zones and formations, and steerability, durability, elimination of sliding, improved ROP, and impact on NPT can be directly observed and measured. Both operators and directional drillers now benefit from data driving smarter, more economic drilling decisions and quicker technology adaption. O T

In the fast-paced drilling industry, performance is king. Increasingly, challenging demands are placed on drill bits. And why not? After all, they are the tip of the spear.

Bits are required to drill faster, last longer, and produce better quality boreholes than ever before. But these attributes don’t come easy. Formations are increasingly complex; targets are deeper, hotter and harder to reach.

The recent nationwide shale play is spilling across our borders as North American operators are proving the value of shale drilling, and worldwide plays lie just around the corner. Yet while huge shale gas reserves potential beckons operators, there is a constant push for greater efficiency to

minimise costs. Natural gas is a commodity, and as a result, operators cannot independently raise prices to offset costs. With prices set by local markets, the only recourse to

improve profitability is to attack costs. In the mature arena of well construction, cost reduction is a tough challenge and even significant investments in

technology often result in marginal gains. Nevertheless, every so often, perseverance and innovation are rewarded.

Designing the ultimate shale bitA Smith Bits team of field engineers,

design engineers and hydraulics experts was assembled to

carefully study shale drilling, pulling

together their

Charles Douglas and Josh Passauer, Smith Bits, a Schlumberger company, USA, consider a new bit optimised for shale,

saving significant rig time in the Haynesville Play.

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experience and learnings from thousands of wells drilled to date. They considered the operators’ needs together with the geomechanical scenarios they faced. While understanding that there probably would not be ‘one solution that fits all’ situations, they were able to isolate the predominant impediments to shale drilling and borehole quality and address them.

The following drilling characteristics of the majority of shale wells were identified:

Over the past few years, shale well profiles have shifted from vertical to horizontal.

Drillers generally use different bits to drill the vertical section, the build (or curve) section and the lateral.

Most shale wells are drilled using positive displacement mud motors and are completed using hydraulic fracturing.

Effective borehole cleaning is a must, especially in the lateral section.

Bit vibration must be controlled to optimise drilling efficiency and bit longevity as well as to avoid damaging LWD/MWD equipment.

Almost immediately, the team concluded that considerable time could be saved if a high performance bit could be designed that could drill the entire well, while delivering acceptable borehole quality and cuttings transport. They reached into their toolbox and implemented several proprietary modelling and database programs including:

IDEAS* integrated drillbit design platform shows how the bit behaves as an integral part of the whole drilling assembly. IDEAS-designed, bits go from concept to proven performance in minimum time.

i-DRILL* engineered drilling system design for predictive bottomhole assembly (BHA) modelling identifies solutions that minimise vibrations and stick-slip during drilling and optimise bit performance for any given environment.

YieldPoint RT* drilling hydraulics and hole cleaning simulation program optimises bit hydraulics for the specific well plan being simulated.

DRS* Drilling Record System, a collection of data from 3 million bit runs, helps engineers quickly locate similarities in drilling conditions and bit performance.

The result was the Smith Bits Spear* shale-optimized steel body polycrystalline diamond compact (PDC) drill bit.

Combination of technologies delivers resultsBy combining an aggressive design with a tough steel body construction, engineers produced a bit that could drill both the curve and the lateral in a single trip while delivering high penetration rates and effective borehole cleaning. The benefits of the leading curve section bit, the 6 ¾ in. SDi711, were combined with those of the leading lateral hole performer, the 6 ¾ in. SDi513, to create the new SDi611 Spear.

Switching from the traditional matrix body to steel offered increased ductility and allowed the blades to be made much taller and thinner, leading to a dramatic improvement in junk slot area and face volume and providing a larger area for cuttings removal and evacuation from the face of the bit. This, coupled with a unique hydraulic design directed drilling fluid to sweep across the cutting surfaces to keep them clean and minimise the re-grinding that robs energy from cutting new rock. Where vibration is predicted, optional MDOC* depth-of-cut inserts can be fitted behind the shoulder and

Figure 1. DBOS drill bit optimisation system log summarises drilling challenges for Haynesville operators, and helps with bit selection.

Figure 2. Smith Bits Spear 6 3/4 in. SDi611 steel body PDC drill bit as specially designed for Haynesville Shale horizontal well drilling.

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gauge cutters. Bit vibration is the principle cause of excessive cutter wear and poor drilling effi ciency.

Spear bits proved to achieve target build rates in the curve section by facilitating good tool face control, and fast penetration in the lateral while maintaining desired direction and inclination. In addition, the hydraulic enhancements made to the bit design meant that the blades and nozzles did not pack up with shale during drill pipe connections.

With its short make-up length to ensure desired dogleg severity, the new bits have successfully been run under the following operating parameters with varying BHA confi gurations:

PDM speeds ranging from 0.52 rev/gal. to 1.02 rev/gal.

Motor bend angles ranging from 1.5˚ to 2.6˚.

Flow rates ranging from 200 gal./min. to 260 gal./min.

Weight-on-bit ranging from 2000 lbf to 20 000 lbf.

Drilling fluid weights ranging from 14.5 lb/gal. to 17.0 lb/gal.

Haynesville shale well exampleA typical Haynesville drilling program calls for drilling and wireline logging a vertical or directional 9 7/8 in. intermediate section to the casing point using water-based drilling fl uid. The fl uid is then displaced with oil-based mud for drilling the curve and lateral sections. Since bottom-hole temperatures are severe, the use of rotary steerable systems (RSS) and logging-while- drilling (LWD) tools is limited and PDM steerable motors are primarily used to build and drill the curve section and lateral.

Up until now, operators have been faced with a dilemma. Previous bit designs were either optimised for the curve section with strong build tendencies and directional-friendly steerability or they targeted the lateral section with fast, aggressive penetration rates. To get the best performance, a bit trip was required so the best bit could be used for each section. Alternatively, the operator could elect to use the same bit for

both the curve and lateral, giving up performance on one section or the other depending on the bit chosen.

To maximise sensitivity to the operator’s needs, Smith Bits placed an Advanced Services Engineer (ASE) in the operator’s offi ce as a technical advisor to provide recommendations and support to the operator. ASE engineers have access to Smith Bits proprietary engineering tools to assist in recommending the ideal bit and provide operational expertise for each particular application. The practice of placing technical specialists within operating companies is widespread. Logging and pumping services engineers have proved their value through deep domain expertise for many years. It follows that drilling experts will provide similar benefi ts. Working with the operator’s drilling engineers and well design specialists, Smith Bits engineers selected two offset wells belonging to the same operator and with formation characteristics as close to those of the case study well as possible to test the new SDi611 Spear bit.

To ensure the best match between the well design and geomechanical constraints imposed by the formations to be drilled, a DBOS* drill bit optimisation system log plotted from the best available data, including lithology and mineralogy, and unconfi ned compressive strength of the rock is often used. This takes into account both the curve section and the lateral, and shows engineers that the bit will perform well in both sections and can help facilitate the decision to drill to total depth without a bit trip.

The fi rst offset well was drilled using three PDC bits of another manufacturer. It kicked off at 10 500 ft and drilled curve and lateral to a measured depth of 16 324 ft. Penetration rates for the three bits were 23 ft/hr, 39 ft/hr and 31 ft/hr respectively.

Offset well number two kicked off at 10 455 ft using the Smith Bits SDi513 Spear bit for the curve and drilled 1012 ft; then switched to another manufacturer’s PDC bit to drill 479 ft. To complete the lateral, the SDi513 bit was used and drilled

Figure 3. Comparison of Smith Bits Spear steel body bit profi le (left image) with that of a typical matrix body bit (right image) shows junk slot area increased by 45% as a result of extended blade height, reduced blade thickness and bullet shape body.

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on the case study well. Total savings were estimated by the operator at US$ 365 000.

Since the case study well was drilled, the operator has been increasing its use of Smith Bits Spear bits in the Haynesville.

No silver bulletDrilling the shale plays is not a simple task. Each play must be carefully studied to determine its geomechanical properties and formation parameters so the optimum bit can be selected. The fundamental design parameters of the new Spear bits address the most challenging aspects of curve and lateral shale drilling, maintaining a high rate of penetration while delivering an accurate wellbore trajectory and a good quality borehole so subsequent completion activities can proceed without problems.

The Smith Bits Spear design can be fitted with premium ONYX* PDC cutters for hard rock drilling applications. Many years of experience have shown that bit selection is a science. There is no ‘one-type-fits-all’ situation. Drilling engineers find that they obtain the best performance when the bits are carefully matched to the well design and the geomechanical constraints presented by the formations to be drilled. O T

References * Mark of Schlumberger.

4552 ft to total measured depth of 16 498 ft. Penetration rates for the three bits were 14 ft/hr, 10 ft/hr and 31 ft/hr respectively.

The case study well was kicked off at 10 720 ft and was drilled entirely with the SDi611 Spear bit to a total measured depth of 16 783 ft. A single bit was used. Penetration rate was 49.7 ft/hr; a Haynesville record. There are a few faster lateral runs, but so far none have been able to drill both the curve and the lateral at that rate.

Considering both the penetration rate gains plus the elimination of bit runs a total of 124 hours of rig time was saved

Figure 4. Comparison of case study well with two nearby offset wells of the same operator highlights single bit run performance of the Spear SDi611 bit (left) in a record-setting run for Haynesville horizontals.

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Today’s competitive environment demands constant creation and improved application in all areas of the drilling arena, especially in the magnum size bit

range. Century Products, Inc. is a US-based manufacturer specialising in the development of magnum sized drilling tools. High quality, durable bits that offer a high rate of penetration and on target steering performance is the focus of Century’s R&D.

The industry’s attention has been directed towards the development of the smaller, PDC bit range. Century is fi lling a void by offering a complete range of drilling tools for borehole enlargement from 16 in. – 72 in. With two complementary product lines, Hole Openers and three cone Rock Bits, engineers are provided with custom designed options to choose from so drilling plans do not have to be modifi ed.

The Hole Opener line covers from 20 in. – 72 in. and the three cone Rock Bit line ranges from 16 in. – 36 in. Both are available in IADC codes ranging from 1-1-5 to 5-3-5 and feature the highest load and energy bearing seal combination in the industry. They are available with Tungsten Carbide Inserts (TCI) or a

Milled Tooth (MT) bearing design to perfectly attack the various formations drillers encounter.

A six-point stabilisation feature is standard on the Rock Bit line (Figure 1). This allows for better stability, which results in

smoother running parameters and less vibration to help reduce other potential downhole failures. Three interchangeable jet nozzles are extended to aid in the stabilisation as well as provide exceptional hole cleaning abilities.

The Hole Opener line incorporates stabilisation features as well, which results in a well-balanced tool machined to exacting tolerances. A rebuildable design allows for multiple cutting structures to be inserted into one body, transforming an otherwise disposable piece of equipment into an asset, (Figure 2).

These stabilisation features are critical when drilling with larger diameter drilling tools. Inherently these larger sized tools experience severe vibration and have diffi culty maintaining minimal borehole deviation. Borehole enlargement tools that fall within this range

require a dedicated engineering effort to ensure optimal drilling performance, which yields a high ROP with minimal vibration. As a technology leader, Century continually strives to optimise

DRILLER: EQUIPPED

Jack Castle, Century Products, Inc., USA, details the company’s range of drilling tools.

Figure 1. 36 in. Magnum Rock Bit.

DRILL BITSOLUTIONSLeading suppliers; Century Products,

NOV Downhole and Varel, provide details

of advanced drill bit technologies.

49


drilling performance while lowering the cost per foot through innovative advancements to the larger size drilling tools.

Design featuresThe correct bit choice is an integral component in the overall drilling performance achieved. There are four different bearing sizes to choose from, 12.5 in., 16 in., 22 in. and 26 in. and three different cutting structures to select, incorporating TCI Conical and Chisel profiles as well as Milled Tooth. The following information provides an overview of innovative features built into each bit used on the Hole Opener and Rock Bit lines to eliminate common problems drillers encounter out in the field:

Century high load/high energy bearingFigure 3 features:

Extreme Pressure (EP) lubricant and dual reservoir system. Century Products Cutters use the latest in synthetic grease. This, along with the compensator design, ensures proper circulation is maintained under the most stringent applications.

HSN O-Ring Seals: largest seal area in the industry. HSN Material is utilised for its wear, heat compression and chemical resistance properties for the O-Rings. It has a service range of -40 to +325 ˚F. For the high energy required, Century has designed and utilises the largest cross section O-Rings for longer seal life.

Crowned roller bearings. Premium crowned roller bearings are used, which gives the bearing the capability to withstand the extreme high loads.

Ball bearing cone retention. Ball bearing cone retention is provided as the most reliable method of cutter retention in the industry.

Premium silver plated floating bearing system. Fully floating thrust bearing system allows for reduced frictional heat build-up to ensure lower operational temperatures under high-energy operations. This design facilitates the longer bit life that Century’s reputation has been built around.

Gage row protection. Double the number of tungsten carbide inserts that actively cut the gage diameter and assists in maintaining tight tolerances and extending in-gage bit life.

Figure 2. 24 in. Century Hole Opener.

Figure 3. 22 in. replaceable arm and cone assemblies.

Shirttail/leg protection. Hard facing along with carbide inserts blanket the shirttail and leg, providing superior wear resistance.

Interchangeable jet nozzles. Interchangeable jet nozzles with carbide jets from 8/32nd to 24/32nd.

An improved hydraulic design has also been incorporated, which is especially effective as the size of the hole increases. For example, a 72 in. hole equals 1.05 yds3 of rock for every foot of penetration. This is equal to the volume of 67.71 ft of an 8 - 4 in. hole. Designs must be modified for magnum size products to address these increased volumes.

When these bearings are teamed with the latest innovation in bit designs, you have a winning combination. These bits are designed to handle the tough, hard over thrust formations from Canada to Columbia, and the sharper, abrasive formations in the Middle East. This high energy bearing design is also suited for the longevity required in the North Sea. As much as three times the bit life versus non-sealed products can be expected.

Case study Length: 7456 ft River Crossing.

Country: Quebec, Canada.

Pipe: 20 in. steel.

Bore size: 30 in.

The Canadian Province of Quebec, in the French speaking city of Trois Riviers, 88 miles northeast of Montreal on the banks of the St. Lawrence Seaway, served as the setting for the 7456 ft River Crossing Project of The Year in 2006.

A 12.5 in. pilot hole was drilled with the intersect method which employs two drill rigs that start from opposite ends of the project site and meet somewhere in the middle. In effect, one drill provides the pilot bore for the other.

Once the pilot bore was completed, a 30 in. Century Hole Opener with 5 – 22 in. TCI (Tungsten Carbide Inserts) cone was attached to the drill system to handle the one pass ream. With the

larger cones, the 30 in. Hole Opener was able to reach down to the 12.5 in. pilot hole.

The larger cones enabled the drilling company to skip a reaming pass and complete the borehole in considerably less time. The majority of the drill was mainly drilled through bedrock


that ranged in compression strength from 4000 to 8000 psi. Both shale and limestone rock were encountered.

The reaming process took 400 hours at an average RPM of 30 and weight on bit between 145 000 – 165 000 lbs. The reaming process was cut in half by using a single

LARGE DIAMETER DRILLING: CHALLENGES AND SOLUTIONS

NOV Downhole discusses the company’s solutions in large diameter drilling.

The drilling of deeper oil wells is rapidly becoming more commonplace in today’s oil and gas industry. Hydrocarbon sources are less and less at our fingertips,

leading the industry to develop new and more sophisticated technologies in order to reach these distant resources. This in turn brings its own challenges, and certainly demands its own solutions (Figure 1).

NOV® Downhole has introduced the ReedHycalog® TitanUltra™ drill bit product line designed to overcome the unique challenges of large diameter drilling. Due to the substantial difference between bottomhole assembly (BHA) and hole diameter, extremely high forces can be generated. Lateral and torsional vibrations amplify the magnitude of these forces, affecting ROP and directional control, and can ultimately destroy the bit and downhole tools. Furthermore, bottomhole cleaning and the risk of hole washout make optimal hydraulic design essential for improving borehole quality and drilling performance.

Reflecting the design focus on the four fundamental areas of improved stability, rate of penetration, durability and steerability to maximise performance in large diameter applications, TitanUltra bits have set world records in deepwater projects offshore in the Gulf of Mexico, Australia and Russia.

Stability: ultra-stable bit designs The new concept of stability developed for the TitanUltra products, goes beyond the development of the cutting structure itself. It also considers new techniques developed for other critical parts of the design such as the bit body and the secondary components.

Cutting structure designs: proprietary mathematical modelling enables the design of extremely high laterally and torsionally stable cutting structures.

Blade global asymmetry: the difference in the angle between each one of the design blades, has proven to increase the bit’s ability to mitigate externally created lateral vibrations and diminishes build up of whirl energy magnitude.

Secondary components: new Torque Fluctuation Controllers (TFCs) smooth out torque spikes that may be encountered during drilling.

ROP: aggressive bit designs New cutting structure layout: unique cutting structure

spacing and exposure allows maximum ROP while drilling smoother and longer intervals.

Hydraulic design: hydraulic modelling enables designs that efficiently clean the hole and maximise ROP. Other achivements with the new hydraulic design include:

Figure 1. The ReedHycalog TitanUltra product line from NOV Downhole is designed to overcome the challenges of large-diameter drilling with a design focus on improved stability, penetration rates, durability, and steerability.

Century Hole Opener as opposed to running two passes to open the hole to 30 in. Due to the unique design on the Hole Opener Bearings and Seals, the Century Hole Opener easily achieved 180 hours of operation in the hole. O T

The nozzle configuration is primarily focused on minimising the erosion of the borehole. This erosion is usually a major problem in large hole applications, where the nature of the lithologies drilled tends to create hole washouts.

Increases directional ability in large hole diameters.

Durability: more durable bit designs Bit wear and impact force prediction: proprietary

mathematical modelling ensures designs that resist external forces and formation abrasiveness.

Finite Element Analysis (FEA): advanced structural integrity simulations provide reliable bit body structure design to overcome the most demanding drilling situations.

Steerability: directionally compatible bit designs featuring the semi-active gauge

The TitanUltra designs can be run on bottomhole assemblies that include push or point the bit rotary steerable systems (RSS), as well as mud motors. Field testing has demonstrated its directional reliability response in all applications. TitanUltra is the first known 24 in. or larger PDC bit that has drilled more than a 15˚ inclination on an RSS through salt lithology in the Gulf of Mexico.

This new technology incorporates a new gauge configuration, the Semi-Active Gauge, which gives the bit ability to achieve moderate dog legs and maintain verticality. Overall, it has delivered superior borehole quality in these large diameter drilling applications.


Performance advantagesConventional thinking has held that an increase in blade count leads to a decrease in ROP. However the TitanUltra product line’s specially designed cutting structure layout provides performance advantages to increase ROP while using higher blade counts.

MAKING THE CUT

Varel International discusses recent advancements in PDC and Roller Cone drill bit technology.

Service companies in the oil and gas industry are constantly evolving through deployment of new technology to their customers and it is no more evident

than in the highly competitive drill bit industry. Companies work diligently to have a flow of constant technology development deployed to the field. Varel International continues to be a leader in the field, where rapid evolution of drill bit technology, drill bit applications and fierce competiveness keep things very interesting.

The company is in the forefront of drill bit and PDC cutter technology with research and design facilities both in the US and in Europe and is represented in all of the primary oil and gas basins worldwide.

In just the past year alone, Varel has made strides in both PDC and Roller Cone drill bit technology. Along with supporting its legacy lines, the company has been on the forefront of PDC cutter testing and cutter qualification, as well as delivering custom roller cone solutions for specific customer applications.

PDC cutter technology

Cutting edge testing technology cutter qualificationIn order to achieve success, the company has recently introduced its testing and qualification standards. Building upon already successful PDC product lines such as Diamond Edge™ bits, Navigator™ bits and the ToughDrill™ series, Varel has developed and deployed two patent pending PDC cutter testing technologies. These innovative tools measure cutter

toughness and abrasion resistance to enhance and improve the development and selection of PDC cutter technology for drilling applications.

Cutter toughnessCutter toughness is the ability to withstand the effects of drilling dynamics. Toughness is related to the strength of the diamond-to-diamond bonding created during the High Pressure High Temperature (HPHT) sintering of the PDC cutter. Historically, test methods in the industry have been qualitative and have fallen short of providing effective data for field cutter selection.

To better measure cutter toughness, Varel has developed its patent pending Acoustical Emissions Toughness Test (AETT). AETT quantitatively assesses the strength of the diamond-to-diamond bonding. With this test a load is applied to the cutters and increased at a constant rate while an acoustic sensor detects acoustic emissions from microcracking in the diamond table. Measuring the energy released during microcracking yields a concrete assessment of the PDC toughness.

Multiple types and grades of PDC cutters can be cross compared according to their resistance to load induced microcracking yielding a highly predictive valuation of impact toughness.

Abrasion resistance Abrasion resistance is the cutter’s ability to stay sharp as it drills. The primary drawback of traditional abrasion tests is

Figure 2. 26 in. TitanUltra World Record – ROP. Bit Dull Grading: 1-1-CT-N-X-I-NO-TD, Offshore Australia.

The TitanUltra product line has demonstrated great success in deepwater applications while drilling lithologies such as salt and sedimentary, interbedded formations. Extensive field testing over the past year led to three world records in some of the most important deepwater applications worldwide, such as the Gulf of Mexico, Russia and offshore Australia.

Proof of performance: The 17.5 in. TitanUltra bit set a single-bit run world record

in a section of the world’s longest well offshore Russia, drilling a total length of 14 603 ft at a rate 149.2 ft/hr.

In the Gulf of Mexico, a TitanUltra bit set a world record for the longest 24 in. PDC section, drilling 4645 ft at 107 ft/hr. This application was also the first known 24 in. or larger PDC run that drilled more than a 15˚ inclination on a rotary steerable system through salt lithology in the Gulf of Mexcio. Low vibration was registered and the bit was dull graded 1-1-WT-A-X-I-NO-TD.

The most recent world record was set in Australia, where a 26 in. TitanUltra bit set an ROP world record by drilling 3304 ft at the rate of 144.35 ft/hr, cutting 12 hours of drilling time and saving the customer approximately US$ 500 000 in rig costs alone, (Figure 2). O T


the lack of an accurate simulated geological environment. Current tests use a homogenous rock structure, which does not calibrate how moments of high impact energy affect a cutter’s abrasion resistance. Varel’s second patent pending test, the Bimodal Abrasive Rock Test (BART), is a laboratory abrasion resistance test which employs an engineered rock sample with highly abrasive cement cast around upright layers of high compressive strength granite to measure a cutter’s abrasion resistance. The two rock samples create a load/unload cycle to simulate interbedded formations and formation transitions. By recreating this environment, BART provides a more suitable measurement of abrasion resistance correlating to field performance and yields a quantification of a specific cutter’s applicability to transition drilling.

When used in combination, AETT and BART testing regimens promise to significantly accelerate cutter development by speeding the qualification of new cutters and by providing more accurate quantification of prototype cutter attributes. These processes aide in the development of new cutter technology and in the selection of the best existing technology.

These breakthough standards and testing technologies have led to the establishment of two classes of Varel qualified PDC cutters: Thor™ and Vulcan™ class cutters. The Thor class cutters are engineered to be more impact resistant than standard cutters to address the challenges specific to hard rock applications and interbedded formations. Conversely, highly resistant to abrasion and the heat of drilling, Varel’s Vulcan class cutters are applied in the hardest and most abrasive drilling applications.

Thor cuttersThe company deploys its Thor class cutters to meet the challenges associated with interbedded lithology and high impact drilling applications where cutter toughness is required. Drilling through transitional zones often produces significant drill string vibrations. With maximum diamond particle size distribution and optimal sintering, Thor cutters have increased toughness while maintaining thermal mechanical abrasion resistance. Before a cutter can enter this classification, it undergoes a battery of tests and evaluation techniques.

With Thor cutters, the foundation of the cutting structure is protected, leading to increased ROP and extended drill bit life in hard-to-drill applications.

Vulcan class cuttersVarel applies Vulcan class cutters when a high level of thermo-mechanical abrasion is anticipated. Highly abrasive formations generate elevated friction and heat during drilling, and industry standard cutters can crack and wear under these conditions.

This class of cutters is manufactured to resist these highly abrasive conditions. With a smaller diamond grain size and an enhanced thermal stability, the cutters resist abrasive wear while maintaining toughness. With Vulcan cutters, abrasion resistance is maximised, leading to longer bit life and higher ROP throughout the interval.

TestingBefore a cutter is qualified for Vulcan classification, it is subjected to a rigorous cutter testing methodology; key to entering this class is a high score in the thermal abrasion test.

Performance examplesIn a recent performance review for drilling in Offshore Southern Thailand, Varel designers delivered proof points of the effectiveness of Vulcan cutter equipped PDC drill bits. Overall these bits were able to withstand the highly abrasive formations they encountered, including formations with abundant dolomite stringers.

Specifically, two separate seven-bladed Navigator series drill bits earned top remarks from the drilling engineer in charge as “the best bit for the deeper section.” The first bit drilled through the hard and abrasive Benjarong Formation to TD of 12 215 ft, delivering superior footage and ROP when compared to closest offsets.

Due to the excellent post-run condition of the drill bit’s cutting structure, it was quickly rerun completing 1782 ft for a

Figure 1. 8.5 VRP 713PDGX Post Run: the second drill bit performance featured (the 8.5 in. VRP713PDGX bit) is shown here after two complete runs, the most recent to section TD in a formation consisted of hard and abrasive dolomitic cemented sandstone, dolomitic limestone and dolomite stringers with UCS up to 35 kpsi.

Figure 2. The Acoustical Emissions Toughness Test (AETT) quantitatively assesses the strength of the diamond-to-diamond bonding in PDC cutting elements.

OT_49-54_June2011.indd 53 08/06/2011 09:59


cumulative footage of 3261 ft spanning two runs and an ROP that was 122% higher than the closest competitive offset.

A second bit, used in hard and abrasive dolomite cemented sandstone, dolomitic limestone with multiple dolomite stringers, was also noted for its durability and longevity. While this 8 ½ in. VRP713PDGX delivered similar footage to its non-Vulcan equipped counterparts, the post-run condition and the estimated 79% increase in ROP, once again made this bit a success. A second run with this same bit in a separate section delivered a run to TD in the same unforgiving formation type.

Pushing the limits with 44 in. steel-tooth roller cone drill bit Varel has recently expanded the ‘Jumbo’ bit product offering to include additional sizes, cutting structures and bearing options for specific top hole requirements. The company has completed a massive 44 in. steel-toothed roller cone bit for the oil and gas industry.

The bit, which weighs in at more than 6000 lbs and is more than 22% larger in diameter than any previous roller cone bit, was requested specifically by an integrated global petroleum company in the Middle East.

David Harrington, Vice President of Varel’s roller cone technology group, explained how the ultra-large diameter bit will work to create efficiencies in current field operations by offering a single bit solution to top hole drilling which previously involved drilling a pilot hole and then re-drilling with a hole opening assembly.

Figure 3. 44.00 Roller Cone bit: the largest drill bit deployed in the oil and gas field, this 6000 lbs drill bit is designed to create efficiencies in the top hole drilling operations.

Figure 4. The Bimodal Abrasive Rock Test (BART), is a laboratory abrasion resistance test which employs an engineered rock sample with highly abrasive cement cast around upright layers of high compressive strength granite to measure a cutter’s abrasion resistance.


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Shale_End.indd 1 22/02/2011 15:02

“Drilling with this large diameter bit in the top hole section is a more efficient solution. The bit saves the operator time and money through a reduction of tripping to change bits and the need for hole enlargement tools,” said Harrington.

This bit features an advanced cutting structure with optimised row placement, tooth spacing and cutter geometry for increased drilling efficiency. These attributes also work to minimise tooth wear and prevent cutter tracking in a wide variety of formations and conditions.

The colossal bit was constructed following strict manufacturing processes that are designed to be robust and repeatable. These processes are constantly monitored and continuously reviewed to provide the drilling industry with ever-increasing value.

Harrington concluded, “The cutting structure on this bit was engineered for specifically for operator’s purpose. The inaugural run of this innovative product is scheduled for mid-2011.” O T

OT_49-54_June2011.indd 54 08/06/2011 09:59

THE MANY SHADES OF GREEN

Kelly Harris, BWA Water Additives, UK, takes a look at screening tests in order to find more environmentally friendly chemicals.

Since the 1972 Stockholm United Nations Conference on the Human Environment, environmental pollution has been considered as a major concern for all industries. Across the globe, a number of governments and regional economic integration organisations

have since established programmes for identifying and assessing substances that could cause long term harm. This ‘harm’ is defi ned as substances that are resistant to degradation and accumulate in living organisms where they produce undesirable effects above a certain level of concentration. These Persistent Organic Pollutants (POPs) or Persistent, Bio-accumulating, Toxic substances (PBTs) are classifi ed using a variety of tests and are subject to regulations concerning their use. These tests are dependent on the fi nal destination of the chemical, and knowledge of how the environment will be impacted by its presence is paramount. Once identifi ed, classifi cation depending on specifi c criteria can be achieved. For example:

The OSPAR (Oslo and Paris) Convention for the Protection of the Marine Environment of the North-East Atlantic, aims to prevent further pollution by continuously reducing discharges, emissions and losses of hazardous substances (identified by PBT criteria), with the ultimate aim of achieving concentrations in the marine environment near background values for naturally occurring substances, or close to zero for man-made substances.

The Environmental Protection Agency (EPA) in the USA defines two sets of criteria for PBTs. Fitting into one of which means emission must be controlled, and the other, for it to eventually be banned.

55


x The Canadian Government has a screening process that places substances that are persistent or bio-accumulating and inherently toxic into three categories depending on the outcome of further screening.

Unfortunately the hunt for ‘low harm’ (i.e. biodegradable) inhibitors has meant that less effective products are sometimes selected due to their perceived ‘green’ qualities. This is in spite of the fact that this lower efficacy may actually result in increased chemical discharge back to the environment. In an ideal world a very small amount of chemical would be used

Figure 1. Schematic demonstration of the differences between laboratory tests and field tests.

Figure 2. Calcium Carbonate Threshold Test - percentage inhibition at specified dose level.

Table 1. Inherent biodegradability of commonly used scale inhibitors and the new ‘green’ inhibitors

Inhibitor type Acronym Inherent biodegradability result*

Phosphonates PBTC 17% in 28 days

ATMP 23% in 28 days

HEDP 33% in 28 days

Polyacrylates PAA 10% in 35 days

Phosphinopolyacrylates PPCA 0% in 35 days

Polymaleic PMA 18% in 35 days

Terpolymaleic MAT 35% in 35 days

Sulphonic acid co-polymers SPOCA 7% in 28 days (OECD 306)

Polyaspartate PASP 83 - 87% in 28 days

Carboxy methyl inulin CMI >20% (OECD 306)

Polycarboxylic acid PCA 68.6% in 28 days (OECD 306)

Maleic acid polymer MAP 54.9% in 35 days

* OECD 302B test unless otherwise stated.

which would then disappear completely! A survey of the currently available products shows that although this target has not been met, some products are definitely moving in the right direction.

BiodegradationBiodegradation is a natural process by which organic substances are decomposed by micro-organisms (mainly aerobic bacteria) into simpler substances such as CO2, water and ammonia. At the moment, evidence of partial degradation is enough to meet most criteria and avoid categorisation as a PBT or POP.

For measuring biodegradability, the most recognised tests are the Organisation for Economic Co-operation and Development (OECD) series and include purely laboratory-based tests, as well as simulation and field-based tests.

The closer a test mimics the environment the less control there is in place and therefore the less reliable the data is. In the laboratory tests, every chance is given for degradation to occur utilising high levels of test substance or, a low ratio of test substance to biomass with a long adaptation period, and a simplified environment. Simulation tests are a good central point with external factors, such as temperature and pH, controlled but a more realistic environment.

Within OECD guidelines a series of tests can be undertaken as follows:

Ready/ultimate testsThese are rigid screening tests with a high level of test substance (2 to 100 mg/L). They are laboratory tests, however, a positive test means that ultimate biodegradation in the environment will occur. A failure does not mean that the chemical will not biodegrade at all, so instead inherent biodegradability tests may be performed.

Inherent testsThese tests have a high capacity for degradation with long exposure times and a high biomass to substance ratio, thus giving the substrate the best chance. Again, this is a laboratory test with a controlled and synthetic environment. A positive result will demonstrate the substrate is inherently biodegradable, but a negative result can still not rule out degradation in its final environment.

Simulation testsThese tests use a low concentration of the chemical and are performed in an environment that closely mimics the real world. A positive result here strongly suggests that a chemical will biodegrade in the natural environment. A negative result will give an indication that the chemical is likely to be persistent.

By following this process of beginning with the ready biodegradability tests and moving down the chain, a good understanding of how a substance will behave in the environment can be obtained. When this information is used in combination with the toxicity and bio-accumulation data, the impact of releasing this chemical into the environment can be assessed with a high degree of confidence. However, determining if a chemical biodegrades is only half the story,

OT_55-59_June2011.indd 56 08/06/2011 10:04

since all of this is futile if it does not do the job it was designed for.

Scale inhibitorsWater systems are ubiquitous with the chemical process industries (CPIs). The mixing, heating, concentrating or evaporating of water in these systems will form scale if they are left untreated.

Scale inhibitors are chemical substances, which when added at very low levels will reduce or prevent the formation of scale. There are a vast array available today including phosphate esters, phosphonates (PBTC, ATMP, HEDP), polyacrylates (PAA), phosphinopolyacrylates (PPCA), polymaleic acids (PMA), terpolymaleic acids (MAT), sulfonic acid copolymers (SPOCA), polyvinyl sulfonates, and more recently the so called ‘green’ inhibitors polyaspartic acid (PASP), carboxy methyl inulins (CMI), polycarboxylic acids (PCA) and maleic acid polymers (MAP).

The biodegradability of the current classes of inhibitors available in the market is shown in Table 1. Before the push for ‘green’ products very few were actually biodegradable. HEDP and MAT, being above 30%, are only just considered as inherently biodegradable. Looking at the new generation of ‘green’ inhibitors it is clear to see the difference with all four well above what is required to be considered as non-persistent. However, the question remains: are the new class of ‘green’ products effective scale inhibitors?

Scale formationScale is formed by the increasing concentration of scaling cations, such as calcium and barium with scaling anions, such as carbonate and sulphate. Once the concentration of ions exceeds super-saturation levels, nucleation will occur, which leads to precipitation. What happens at the surface of this crystal depends upon the rates of formation and dissolution of the scale. Generally the rate of formation is greater, thus leading to growth of the crystal. These crystals can then clump together to form larger crystals that will eventually block the system. There are three mechanisms by which inhibitors can work to prevent the catastrophic build up of scale; at the nucleation stage, at the growth stage and fi nally the deposition stage.

Threshhold inhibitorThe inhibitor binds with the scale forming ions, but unlike chelants the bound ions must be available to interact with their counter ions. This disrupts the ion cluster at the early equilibrium stages of crystal formation, thus disrupting them before they reach critical size for nucleation. As a result the ions dissociate releasing the inhibitor to repeat the process.

Growth inhibitorThis slows the growth of the scale by blocking the active edges of the crystal. Once the inhibitor has bound to the lattice, the crystal will form

much more slowly and be distorted. Often they are much more rounded in shape which makes them less likely to adhere to surfaces and more easily dispersed throughout the system.

DispersantPrevents the crystals coming together and forming a large body of scale. The inhibitor will interact with the surface and repulse other charged particles so that they do not bind.

Industrial Water Treatment (IWT)In the IWT area the most commonly encountered type of scale is calcium carbonate, which may occur in three possible crystal forms – aragonite, calcite and vaterite. When testing for the efficiency of a scale inhibitor against calcium carbonate scale the following tests can be performed:

Calcium Carbonate Jar TestThis is a 30 minute homogeneous test which demonstrates the threshold inhibitor ability of a product.


Pilot Cooling Tower Evaporative Unit Test This is designed to test both the threshold and dynamic inhibitor mechanisms against calcium carbonate under heat transfer conditions.

Calcium Carbonate Jar TestHere air bubbling is used to facilitate CO2 removal, which moves the equilibrium towards carbonate formation, thereby increasing the test severity by raising the pH of the test solution.

A solution containing calcium chloride and magnesium chloride is mixed with an equal volume of a solution containing sodium carbonate and sodium bicarbonate, which already contains the additive to be tested. The air bubbled solution is heated at 70 ˚C (158 ˚F) for 30 minutes, after which time the solution is filtered and the calcium remaining in solution determined by EDTA titration. The higher the amount of calcium retained in solution the greater the scale inhibition ability of the product.

The results expressed as percentage inhibiton against dose level are given in Figure 2. At 1 and 2 mg/L dose level HEDP and ATMP are clearly the most effective with PCA and MAP being the best amongst the ‘green’ scale inhibitors. Once a 4 mg/L dose level has been reached, a number of inhibitors are capable of 100% inhibition of calcium carbonate including PCA and MAP but PASP only reaches an 80% level. This may seem like quite a high figure but unless 100% is reached calcium carbonate will form and ultimately greatly reduce the efficiency of the plant.

Pilot Cooling Tower Evaporative Unit Test This dynamic test is designed to provide a realistic measure of an additive’s ability to control calcium carbonate deposition. The Pilot Cooling Tower Evaporative unit has constant make-up but has no blowdown, so the system water concentration increases with time as evaporation occurs. The system water is circulated over a 316 stainless steel heat exchanger. The heat exchanger is heated by passing hot water through the tube. The surface temperature of the heat exchanger is approximately 70 ˚C (158 ˚F). The evaporative region maintains bulk water temperature at 40 ˚C (104 ˚F), by passing air counter current to the water flow in the cooling tower. The higher the calcite saturation index (SI) that can be reached, the more efficient the inhibitor. A schematic diagram of the equipment used is given in Figure 3. Initial dose level of additives is 10 mg/L as solids.

In Figure 4, PBTC shows what level a good calcium carbonate inhibitor can achieve in this test. Its failure point occurs at a calcite SI of approximately 200.

Of the ‘green’ inhibitors, MAP exhibited the best calcium carbonate control, reaching a calcite SI of 285. PCA also fared well with a failure point at 240 calcite SI. Both of these results are a significant increase over that reached by PBTC. PASP however gave a rather poor result failing at a calcite SI of approximately 80. This is less than one third of the level reached by MAP and PCA.

Oil industryWhen considering application in oilfields, performing both the calcium carbonate and the barium sulphate dynamic scale

Table 2. Calcium Carbonate Dynamic Scale Loop Test water chemistry

Ion Concentration mg/L

Calcium 350

Magnesium 56

Sodium 10 077

Potassium 283

Barium 50

Strontium 50

Bicarbonate 1000

Chloride 16 058

Sulphate 0

TDS 27 924

pH 7.8

Table 3. Barium sulphate test water

Ion Concentration mg/L

Calcium 636

Magnesium 634

Sodium 14 760

Potassium 446

Barium 120

Strontium 190

Bicarbonate 0

Chloride 26 930

Sulphate 530

TDS 44 246

pH 5.5

Figure 4. Percentage calcium carbonate inhibition versus Calcite Saturation Index on an ICW rig.

Figure 3. Schematic diagram of PCT with conditions of operation.


loop tests is required to provide a good indication of inhibitor performance in the reservoir.

Calcium Carbonate Dynamic Scale Loop TestIn some ways the dynamic scale loop test is less severe than the threshold static jar test, the inhibitor is replenished therefore keeping it at a constant concentration. In the jar test when a crystal is formed some of the inhibitor is consumed as it binds onto the crystal surface. As inhibitor levels are not replenished, concentration will therefore drop over time. Having a constant inhibitor level throughout the dynamic test ensures that it is the growth inhibition mechanism that is being studied with metal surfaces acting as growth sites.

This test is conducted using synthetic Brent water, the water chemistry for which is given in Table 2. Separate solutions containing the anions and the cations are pumped through pre-heat coils at 90 ˚C (194 ˚F) and mixed in a T-piece prior to the 0.1 mm ID 1 m long 316 stainless steel test coil. A schematic representation of this apparatus is shown in Figure 5. During the test calcium carbonate deposition reduces the bore of the test coil causing an increase in pumping pressure. The rate of change in pressure across the coil is monitored with a pressure transducer and data captured for graphical representation later. The test is considered successful if the change in pressure remains below 1 psi (6.895 kPa) over a two hour period.

MAT, a commonly used inhibitor, demonstrates that a 2.5 mg/L dose level is sufficient to completely inhibit calcium carbonate scale formation (Figure 6). The ‘green’ inhibitors PCA and MAP also display excellent scale inhibition at 2.5 mg/L. PASP is unable to prevent scale formation at this dose, reaching 1 psi (6.895 kPa) in only 50 minutes.

Barium Sulphate Dynamic Scale Loop TestThe water chemistry for this dynmaic scale loop test is given in Table 3 and is equivalent to a 80:20 Troll:Seawater mixture. The anion and cation solutions, this time with with no inhibitor present, are pumped through preheat coils at 90 ˚C (194 ˚F) and mixed in a T-piece prior to the 0.1 mm ID 1 m long 316 stainless steel test coil. Barium sulphate deposition reduces the bore of the test coil causing an increase in pumping pressure. Once a 1 psi (6.895 kPa) change in pressure has been achieved, a third solution containing anions plus inhibitor replaces the anions solution. The test is run for 2 hours unless the additive fails to prevent further barium sulphate scale.

Figure 7 illustrates the data for MAT and the three ‘green’ inhibitors PASP, PCA and MAP. At a 4 mg/L dose level MAT was able to stop deposition completely thus leading to no further increase in pressure. PASP, PCA and MAP were equally efficient at this dose level. This demonstrates that in this test the ‘green’ inhibitors are as efficient as those already in common use.

ConclusionAll of these tests demonstrate that PCA and MAP offer a significant improvement over other biodegradable products such as PASP, and are also more efficient than their non-biodegradable counterparts, against calcium carbonate scale. A high result in a biodegradation test is a worthy aim, however it should not be at the sacrifice of overall

Figure 6. Calcium Carbonate Dynamic Scale Loop Test Results.

Figure 5. Dynamic Scale Loop Test Schematic.

Figure 7. Barium Sulphate Dynamic Scale Loop Test.

performance. A poor inhibitor could potentially do more damage in the long run as larger volumes of additive are required to control the scale and, therefore, much larger volumes are discharged into the environment. The focus of the water treatment industry has therefore never changed – to produce efficient products that prevent the formation of scale – now there is just an added caveat that they must do as little harm to the environment as possible. This study shows that although the problem has not been completely solved, we are certainly moving in the right direction. O T

Michael Hurd, Kasia Millan and

Dr. Mohan Nair, Kemira, USA,

offer a supplier’s view of

antiscalants in oil and gas markets.

Spotlight on:

ANTISCALANTS

60

There was a time not long ago when the needs for scale inhibitors were pretty well defi ned and the list was not all that long. Manufacturers and suppliers

had a basic sales relationship with the operators in order to understand the needs in the fi eld. Products were needed to stop barium sulfate and calcium carbonate scale development in ambient to hot, brackish to brine type produced waters. In recent years however, the list of conditions has grown in a surprising number of directions and also includes a wider range of scales. Previously ‘odd’ metal and mineral compositions like iron sulfi te or silica scales are now fairly common. Reservoirs with mixed waters from water injection for pressure maintenance, waterfl ood, or just disposal now create a world of scale headaches as the mix emerges from a producing well to fl ow along the seafl oor at near freezing temperatures or at near boiling temperatures from land production comingling with other production at an initial separation battery to further compound scaling tendencies. Throw in waxy deposits and H2S or CO2 from more complex completions and biofi lm, which becomes an active part of the scale itself from either the reservoir bacteria or surface contamination, and the market for scale inhibitors takes on a whole different meaning. And, of course, while being compatible with other chemicals being added into the fl ow stream, the scale inhibitor needs to be environmentally friendly or ‘green’, which often means different things to different people at different times. This article attempts to take a look at the issues in a broad sense and see what technology might be available to help solve, or at least better defi ne, the resulting needs that exist.

Being greenLet’s start at the end of the list with a discussion of what it means to be ‘green’. It is a buzzword that has become a part of our jargon overnight, being used by oilfi eld, environmental groups, media, and politicians alike, but unfortunately each have a slightly different understanding of what that means. To some it ideally means ‘nontoxic’, but then there are those who point out that even drinking water in excess can have the disastrous result of drowning! So use limits enter the picture with a debate of how much is acceptable with most recognising that minimum levels are desirable. In the oilfi eld we know that some of these chemistries we use can be harmful if misused or mishandled, and accidents and spills do occur, which cause the rest of us to be even more diligent in our use procedures. But we are also committed to producing needed oil and gas and that simply can’t be done without the use of scale inhibitors at some level in the process. The idea then is to minimise the amount that must be used against performance while continuing to develop scale inhibitor technology and other chemicals that are less toxic and provide equivalent or better performance.

However, there is still some debate over what determines toxicity. Testing in water represents a more sensitive environment to the dangers of a particular chemistry. Therefore, testing against certain fi sh and aquatic invertebrates determines a level of ‘aquatic toxicity’ and helps establish the minimum levels for discharge, particularly into a body of water. Biodegradation testing determines the time a particular chemistry will remain in, and be a potential threat to, the environment, with 28 days being a benchmark established initially in the North Sea as an acceptable time period in most regulations. Bioaccumulation determines the ability of a species, again usually aquatic, to accumulate the chemistry within its tissues. This test also taps into other work done to determine any other physical, neurological, or genetic disruption effects from these chemistries. The result is a set of data used most often by regulatory agencies to determine the parameters and use limits around which a chemical can be used in the fi eld. This data is also utilised by internal HS&E groups to establish working parameters and procedures for oilfi eld workers who handle the products on a regular basis and are far more likely to be exposed than the general public. Levels of acceptability usually emerge from the testing as some sort of ‘black’ to ‘green’ designations either in these areas individually or collectively according to a formula. Improvement in any area of the testing that moves from one level to another higher or better level without degrading results in another area is normally seen as a signifi cant improvement and rewarded in the ‘ratings’ awarded.

With that background then it is easier to understand that some aquatic toxicity is diffi cult to avoid with scale inhibitors. For most polymeric versions of scale inhibitor the molecule is too big to bioaccumulate in most species so biodegradation is where you look to improve the product in the short term. Kemira’s KemEguard™ scale control technology was developed to achieve the 60% biodegradability or higher guided by the Norway Sector of the North Sea regulations, (see Figure 1). One new product in particular, KemEGuard™ 2593 has a standard biodegradation rate of 60% over 28 days as compared with an average of 8 - 10% for typical polymeric scale inhibitors. Thus, the new technology offers a ‘greener’ option with similar performance for sulfate scale prevention compared with its parent technology.

With toxicity being such a concern though, there needs to be a way to keep track of the scale inhibitors in the system when squeeze treatments are used. Mass balance is one way of keeping track of the products that go in and are produced back out of a production well. The problem is that scale inhibitors are tough to measure, particularly at low levels near the Minimum Inhibition Concentration (MIC) after a squeeze job when timing and accuracy can be critical. This usually requires a sample to be caught,

61


transported, and analysed at a lab in a process that takes hours, if not days to complete. And getting a read on just how much is lost to the formation, how much is produced back quickly, and how much really does the job is particularly difficult when all you have is a snapshot in time.

TaggingTagging a molecule that is hard to find or measure with something you can easily monitor online is one way of keeping track of it quickly and efficiently. Using appropriately tagged scale inhibitors offers a number of benefits in addition to mass balance and tracking without interference in performance from the ‘tag’ addition. This isn’t a blend of scale inhibitors and something else. It’s an additional molecular structure that’s manufactured into the molecule, in one case into a sulfonated copolymer, in such a way that the two can’t be separated in the formation. Furthermore, the tag is incorporated so that it is uniformly distributed in the polymer backbone, and does not appreciably change the Mw and distribution of the original polymer, so that the polymer’s performance for scale prevention remains unchanged.

Blended products tend to adsorb at different rates with reservoir rock or react with reservoir fluids in ways that prevent accurate production of the ratio that was injected resulting in misleading data regarding the actual scale inhibitor. The same is the case with polymers with tags that are not uniformly incorporated into the polymer chain. A regimen of properly and uniquely tagged scale inhibitors allows for online detection, accurate trending of production levels, and better control of the overall treatment, increasing the time between treatments and allowing for better planning when a number of wells are treated together. It is particularly advantageous when several wells are comingled at a common production station.

Setting up online detection with unique tags in each well would allow for optimum planning for both the production facility shutdown and cost-effective group treatment of the individual wells by accurately reading the trends in each well and anticipating the most profitable treatment point in the future for all the common wells, all from a single point at the production station. Development work is continuing, specifically on the leading sulfonated copolymer chemistry offered, and products are now being used in field trials. In the future, the applications for this chemistry will be broadened beyond the offshore work where it is currently targeted.

Figure 1. % degradation (North Sea testing).

Figure 2. Iron contamination at 85 ˚C/pH 5.8.

Figure 3. Percent scale inhibition of BaSO4 at 250 ppm with a soluble iron contaminate.

Figure 4. Static barium sulfate inhibition efficiency 4C, pH 6.5, 50/50 Heidrun FW/seawater.

Figure 5. Barium sulfate inhibition at high temperature.

Performance issuesBeyond the convenience of tagging and the benefi t of an environmental product, a scale inhibitor still has to perform in the reservoir with the reservoir fl uids and additives into which it is injected. Additives and environmental conditions can play havoc with some standard products. Typical polymeric scale inhibitors can be precipitated by methanol; common antifreeze in the oilfi eld. Iron levels can affect a variety of scale inhibitors used. And while biofi lms can form with scales and complicate the treatment of both, the biocides used to treat the bacteria may also contribute to the consumption or interference of the scale inhibitor within the system. For this article we’ll focus on iron in the reservoir water, but pay attention to reactions of various kinds that might interfere with the performance of a scale inhibitor under reservoir conditions.

More often, dosage is pushed to bare minimum to minimise the environmental and economic footprint, and that makes detection and monitoring more diffi cult. The low dosage also creates an environment where the products are more susceptible to interferences from additives or contaminates. Iron happens to be one of those contaminates that has come up in recent years in part because of this change in dosage levels, particularly with phosphorous and polyacrylate based products. As dosage falls to minimum effective levels, iron appears to have a more signifi cant effect than fi rst thought. Note in Figure 2 the effect of iron at very low levels on a variety of chemistries. Figure 3 then shows that some of that effect is actually mitigated in phosphorous products with higher levels of iron. Those iron levels are likely to create other problems in the well however. Polyacrylates then tend to fall off in performance as that iron number continues to rise. Speciality formulations with a unique polymer can provide a synergistic effect in performance through offering lower dosage at improved performance, which, in the end, is the overall goal of product improvement.

Last, but certainly not least is the physical environment in which the antiscalant should work, looking specifi cally at temperature and brine. Kemira’s sulfonated copolymers chemistry worked well from 4 ˚C in a Scaled Solutions study to 175 ˚C at Rice University working with barium sulfate scales in brines that, in both studies, had moderate to severe scale indexes. A further variant of the

KemGuard 2705 is the KemGuard 2708, which has equivalent scale inhibition performance, is non-corrosive, is stable to 175 ˚C, and is approved for capillary injection applications. The Rice University study found the 2705 and 2708 to be particularly effective against calcium sulfate anhydrite scales. See Figures 4 and 5.

KemGuard scale control agent therefore offers a single product that works well across a wide range of temperature and brine conditions in comparison to phosphate-based and other common chemistries. For carbonate scales speciality formulations of organophosphates offer performance in similar temperature and/or brine condition ranges. While testing in specifi c brine compositions under specifi c moderate temperature conditions may pinpoint other chemistries that work similarly, brine compositions rarely remain constant, particularly in reservoirs with active water injection. Having fewer products in the warehouse that work over a wider range of conditions offers lower inventory costs and faster response time when (not if) conditions change.

SummaryThe issues presented here are by no means the defi nitive list, but are the ones where progress appears to be accomplished at this point in time. Additive interference will continue to be of increasing concern while reducing environmental footprint will be critical to future products. In the opening paragraph a basic sales relationship was mentioned between suppliers and operations, but now it is incumbent on manufacturers and suppliers to introduce new products, techniques, and applications in an effort to offer new solutions to the needs and issues in the fi eld in concert with operations and fi eld services. The growing complexity of the reservoirs, fl uids, and procedures in the fi eld demand a higher standard of involvement together at all levels of the supply chain in order to meet the need. Manufacturers often have a better understanding of the molecule itself and the ability to manipulate that molecule to achieve the desired effect. Therefore, effective working relationships or partnerships are an integral part of the development equation to make sure what is developed does the job. It is no longer ‘what do you have for me today’, but ‘what can we do together to solve this problem tomorrow!’ O T

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64

T he success of cesium formate brine as a well construction and

workover fluid1 has raised the question of whether there might be other cesium-based brines with equally useful properties. One candidate examined by the research department of Cabot Specialty Fluids (CSF) is cesium acetate brine. The results of CSF’s initial tests on cesium acetate brine are summarised below.

Solubility and density It was found that the solubility of cesium acetate in water is 89.95% wt at 20 ˚C (68 ˚F), making a brine with a fluid density of 2.336 g/cm3 measured at 15.6 ˚C (60 ˚F). The brine density as function of dissolved cesium acetate salt is shown in Figure 1.

Siv Howard and John Downs, Cabot Specialty Fluids, Scotland,

describe how cesium acetate brine could make a novel

high performance drilling, completion and workover fluid.

65


It is possible to blend cesium acetate brine with potassium acetate brine to make clear acetate fluids with densities between 1.40 g/cm3

and 2.30 g/cm3. It is also possible to blend cesium acetate

and cesium formate brines to make clear monovalent cesium brines with densities up to approximately 2.4 g/cm3. This is a higher density than can be reached with either of the two brines on their own.

Effect of pressure and temperature The effect of pressure and temperature on the density of a 2.246 g/cm3 cesium acetate brine is illustrated in Figure 2.

As with other brine systems, increasing temperature decreases the fluid density while increasing pressure increases the fluid density.

Water activityThe water activity of cesium acetate decreases with increasing brine density, dropping below 0.10 in brines with densities of > 2.25 g/cm3 brine (Figure 3).

Boiling pointThe boiling point of cesium acetate brine increases with increasing density, reaching over 175 ˚C at a brine density of 2.36 g/cm3 (see Figure 4).

Freezing and crystallisation temperatureThe freezing and crystallisation points of cesium acetate brine are less than -30 ˚C over the density range 1.45 - 2.20 g/cm3 (Figure 5), beyond the reach of Cabot’s laboratory refrigeration equipment.

Thermal stability Cesium acetate has been tested at temperatures up to 232 ˚C (450 ˚F) for periods up to 90 days. Fluid analyses, pH measurements, and density measurements show only small changes in properties at the highest test temperatures. It is known that the primary products of the thermal decomposition of acetate are methane gas and bicarbonate. It was found that at temperatures of < 200 ˚C (392 ˚F) no change in soluble bicarbonate content could be measured in the brine. At temperatures > 200 ˚C (392 ˚F) a slight increase in soluble bicarbonate content was measured in the brine, with a corresponding small drop in pH. This increase in bicarbonate content does not appear to affect the density of the brine.

Elastomer compatibilityFive commonly used elastomers and two plastics were tested for one and four weeks at 180 ˚C (356 ˚C) and 230 ˚C (446 ˚F) Figure 3. Water activity of cesium acetate brine as function of brine density.

Figure 1. Density at 15.6 ˚C (60 ˚F) of cesium acetate brine as function of concentration.

Figure 2. Density of a 2.246 g/cm3 cesium acetate brine as function of pressure for the temperatures 600, 450, 300, 200, 100, and 40 ˚F (315.6, 232.2, 148.9, 93.3, 37.8, and 4.4 ˚C).


in a 2.20 g/cm3 cesium acetate brine. The results of the test are shown in Tables 1 and 2. HNBR, VITON®ETP, and FFKM were not compatible with cesium acetate brine at 180 ˚C (356 ˚F) and higher. AFLAS, EPDM, PTFE, and PPS appeared to be entirely compatible with cesium acetate brine for four weeks at these very elevated test temperatures.

Compatibility with metals Modern well construction and workover fluids need to be compatible with the martensitic, duplex and high nickel alloy steels commonly used in well tubulars and packers. These metals are susceptible to Stress Corrosion Cracking (SCC), particularly at high temperatures and in the presence of acid gases (CO2 and H2S). Some are also susceptible to hydrogen charging in service.

A lot of corrosion testing has been conducted on cesium acetate brine:1. Six month SCC study at 170 ˚C (338 ˚F) with 145 psi N2

headspace. The metals that were tested were S13Cr -2Mo and alloy 718. SCC (C-ring and FPB and U-bend), hydrogen charging and weight loss tests were conducted on both materials. An ambient temperature SSRT test was conducted on S13Cr-2Mo after the fluid exposure.

The results of the testing are shown in Table 3. Neither of the metals showed any evidence of localised corrosion, SCC, hydrogen charging, or loss of ductility.

2. 30 day SCC study at 160 ˚C (320 ˚F) with a 145 psi CO2 headspace. Four commonly used corrosion resistant alloys (CRAs) were exposed to the buffered cesium acetate brine. These were S13Cr-2Mo, 22Cr Duplex stainless steel -110ksi, 25Cr Duplex stainless steel – 80 ksi, Alloy 718 nickel alloy. Analyses of the samples at the end of the test showed no evidence of SCC.

3. SCC tests on MSS at 177 ˚C (350 ˚F) for 90 days with 145 psi CO2 headspace. Triplicates of 13Cr-2Mo-110 and 13Cr-0.6Mo-110 were tested in buffered cesium acetate brine. Analyses of the samples showed no evidence of SCC or any other form for corrosion.

4. SCC tests on MSS at 177 ˚C (350 ˚F) for 90 days with 145 psi CO2 and 1.5 psi H2S headspace. Triplicates of 13Cr-2Mo-110 and 13Cr-0.6Mo-110 were tested in buffered cesium acetate brine. Analyses of the samples showed no failures but some evidence of minor pitting/fissuring and a small crack in one of the 13Cr0.5-Mo-110 samples. The samples were stressed to 100% AYS at room temperature rather than at test temperature, which could have affected the result.

Table 1. Results of elastomer testing for 1 – 4 weeks in a 2.20 g/cm3 cesium acetate brine

Elastomer typeTest material

type

Temperature Exposure

time [weeks]

Mass change

[%]

Volume change

[%]

Hardness [IRHD]

50% mod

TS EAB[°C] [°F]

FEPM (Aflas®)(TFE/P)

James Walker AF69/90

180 356

0 0.0 0.0 93 14.4 28.3 105

OK

1 0.4 0.2 93 13.1 25.9 108

4 0.2 0.3 91 13.3 27.3 115

230 446

0 0.0 0.0 93 14.4 28.3 105

1 -0.7 -0.9 94 12.1 21.0 97

4 -0.8 -1.7 95 13.2 19.9 85

FFKM (Kalrez® Chemraz®)

Parker V8588

180 356

0 0.0 0.0 92 14.7 22.9 84

Some degradation over time

1 2.0 -0.8 93 12.3 18.8 86

4 3.7 1.5 93 10.9 13.5 68

230 446

0 0.0 0.0 92 14.7 22.9 84

1 8.2 -- 88 -- 6.7 43

4 -7.3 -3.5 94 7.5 7.9 54

EPDMGulf Coast

Seals EO962

180 356

0 0.0 0.0 90 8.5 20.4 108

OK

1 0.7 1.2 90 8.8 20.5 106

4 0.6 0.7 91 9.3 20.9 100

230 446

0 0.0 0.0 90 8.5 20.4 108

1 -0.2 -0.3 92 8.8 20.7 99

4 0.5 -0.7 92 9.3 21.8 105

HNBRGulf Coast

Seals N4007

180 356

0 0.0 0.0 90 65 28.0 216

Fail

1 4.0 -1.0 94 13.1 30.8 200

4 27.4 5.8 98 -- 59.0 18

230 446 -- -- -- -- -- -- --

Base resistant FKM

(Viton® ETP)Parco 9130

180 356

0 0.0 0.0 90 8.3 21.8 138

Dissolving

1 3.3 2.0 92 -- 5.6 24

4 5.9 4.8 97 -- 8.7 9.9

230 446 -- -- -- -- -- -- --


5. SCC tests on high-nickel alloys at 232 ˚C (450 ˚F) for 90 days with 500 psi CO2 headspace. SM2550-125, Alloy 825, Alloy 718, Alloy 725, Alloy 935, Alloy 945-140, Alloy 925 were tested in a buffered cesium acetate brine. Analyses of the samples showed no evidence of SCC or any other form for corrosion.

6. SCC tests on high-nickel alloys at 232 ˚C (450 ˚F) and 30 days with 500 psi CO2 and 5 psi +H2S. SM2550-125, Alloy 825, Alloy 718, Alloy 725, Alloy 935, Alloy 945-140, Alloy 925 were tested in a buffered cesium acetate brine. Analyses of the samples showed no evidence of SCC or any other form for corrosion.

Conclusion Our preliminary investigations indicate that cesium acetate brine has the some desirable properties that could enable its use as the basis of well construction and workover fluids. Its compatibility with CRA, high nickel alloys and some elastomers is a particularly useful feature. Further testing is underway to complete the definition of the properties of this novel fluid. O T

References1. Downs, J.D, Turner, J.B. and Howard, S.: “A

Well Constructed Chemical”, Oilfield Technology magazine, September 2010.

Table 2. Results of PTFE plastic testing for 1 – 4 weeks in a 2.20 g/cm3 cesium acetate brine

Plastic typeTest material

type

Temperature Exposure time [weeks]

Mass change [%]

Volume change [%]

Hardness [Shore D]

Young’s mod (GPa)

TS (MPa) EAB[°C] [°F]

PTFEStandard unfiled

180 356

0 0.0 0.0 63 1.4 21.8 227 OK

1 0.0 0.2 60 1.2 26.1 274

4 0.0 -0.2 61 1.0 23.1 259

230 446

0 0.0 0.0 63 1.4 21.8 227

1 0.0 -0.2 63 1.0 23.5 270

4 0.0 -0.4 62 1.0 23.5 241

Table 3. Results of 4-point bend tests in cesium acetate at 170 ˚C (338 ˚F) for six months. N2 headspace

Specimen Test specimen descriptionCoupled / uncoupled

SCC Observations

Alloy 718 1 in. bar

~120 X 15 X 5 mmUncoupled NO Surface discolored, darken

Uncoupled NO Surface discolored, darken

S13Cr-2Mo 4.5 in. diameter pipe

~120 X 15 X 5 mmUncoupled NO Surface discolored, black surface film

Uncoupled NO Surface discolored, black surface film

Figure 4. Boiling point of cesium acetate as function of brine density.

Figure 5. Freezing and crystallisation points of cesium acetate as a function of brine density.

READ about the latest developments in unconventional resources on Energy Global


The industry’s recent forays into unconventional formations have presented challenges as never before in terms of dealing with extreme pressure

and temperature environments. These conditions have pushed fluids, designs, and equipment to the very edge of performance capability. This stress, however, has resulted in innovations that have made production from unconventional formations not only feasible but also economically attractive. This article will review developments related to efficiently producing hydrocarbons from shale, tight sand and heavy oil reservoirs.

Meeting HPHT challenges in shale formationsThe challenges in hydraulically fracturing high pressure, high temperature (HPHT) formations will inevitably increase globally as operators work to produce hydrocarbons from deeper unconventional reservoirs.

One region that has necessitated handling HPHT environments is the Haynesville and Bossier Shale plays in East Texas and North Louisiana. Dealing with frac gradients of 1.0 psi/ft (0.07 bar/ft) and bottomhole temperatures exceeding 320 ˚F (160 ˚C) has provided valuable lessons on how to best accommodate the extreme conditions of these horizontal completions. Applying the knowledge and experience gained from already-developed HPHT regions can help both operators and service companies take the steps necessary to achieve early success.

High pressure Probably the most evident change when transitioning to a high pressure reservoir focus is the increase in the hydraulic horsepower (HHp) needed to properly stimulate the reservoir (Figure 1). Since HHp is a direct function of pump rate and surface pressure, the same treatment design pumped under increased pressure

Addressing challenges

with innovation

Dave Allison, Neil Modeland, Bart Waltman and Kirk Trujillo, Halliburton, USA,

consider innovations in fluids, completion designs and equipment to address HPHT

stimulation challenges.

69


would necessitate a HHp increase proportional to the pressure; however, the HHp capability of the equipment needed to deliver the required treatment may be substantially more.

Pumping units designed to function at higher pumping pressures are typically more limited in pumping rate compared to their equivalent HHp counterparts designed to function at lower pressures. For these reasons, in the Haynesville Shale play, it is not uncommon for a treatment that requires 24 000 HHp for the fracture treatment to necessitate 40 000 HHp of equipment on location. Because of this situation, close collaboration and co-ordination by all disciplines involved is important. The amount of pumping equipment required impacts many facets of the project such as building the location, equipment and material logistics and, ultimately, the project budget and economics.

After addressing the requirement for sufficient HHp to place the treatment, the completion design can sometimes be finessed to enable performing the treatment at lower treating pressures. This can benefit the operator by lowering the risk of screenout as well as potentially reducing the pressure ratings needed for casing and well services equipment. The factors dictating the pressure observed at the wellhead include the following:

Bottomhole treating pressure (BHTP).

Entry friction through perforations and near-wellbore tortuosity.

Pipe friction.

Hydrostatic pressure created by the fluid.

Traditionally, hydrostatic pressure is one of the first components to be addressed by incorporating a weighted fluid system such as calcium bromide. Unfortunately, the typical fluid volumes needed to properly stimulate unconventional reservoirs are massive, often totaling over 1 million gal. (4000 m3). Weighting the fluid with agents in order to increase hydrostatic pressure becomes too costly and operationally too complex for the overall pressure benefit, making this solution impractical.

Other techniques to reduce BHTP and fluid friction have been successfully implemented by the completion teams. High pipe friction during stimulation treatments down the long horizontal wellbores of highly pressured reservoirs have made wellbore design more closely tied into completion success than ever before. Where completion treatments were previously designed around wellbore schematics provided by the drilling group, in these HPHT reservoirs the wellbore/casing layout is now being frequently designed around desired fracturing parameters. For example, increasing the casing ID in all or part of a well to reduce friction often comes at an increase of material costs; however, in some instances, the reduction in friction has been significant enough to enable using lower casing grades, providing additional value and savings to the overall project.

Another method of lowering pipe friction generated during these treatments is by reducing the treatment rate and compensating by increasing fluid viscosity to provide proppant transport and fracture growth. This approach must be evaluated closely since viscosifying agents and rate reductions can adversely affect the production from some reservoirs, depending on variables such as formation permeability, the possible need to enhance complexity, and the number of perforation clusters being treated per stage.

An emerging strategy used to further reduce treating pressures, especially in HPHT horizontal wells, is the design of perforation intervals called clusters and the spacing of the clusters being treated with each fracturing stage. Possibly contrary to traditional vertical well applications, by keeping perforation clusters in a horizontal well to 1 ft (0.3 m) of length or less, formation breakdown challenges and overall bottomhole treatment pressures have been shown to be significantly less in some reservoirs. This is attributed to the reduction in near-wellbore competing fractures stressing against each other during propagation, as these fractures are typically transverse to the lateral. This situation is more likely to occur with longer perforation intervals.

In occurrences of closely spaced competing fractures and high leakoff, it has become common practice to utilise 100 mesh proppant (or similar fluid leakoff control additive) used in small volumes (slugs) or even for several stages to seal off the competing fissures and further reduce treating pressures. Redesigning the perforating scheme can lead to lower treating pressures and reduce the amount of 100 mesh proppant needed.

When stimulating multiple perforation clusters during one treatment stage, maintaining high treatment rates per cluster has benefited production due to more effective limited entry

Figure 1. In the Haynesville Shale formation, the hydraulic horsepower capability of the equipment may have to significantly exceed the hydraulic horsepower required to fracture the well.

Figure 2. Comparative wellhead treating pressure for conventional crosslinked fluid vs the new high temperature high density crosslinked fluid.

fracturing. When designing treatment rates and volumes in conjunction with perforation cluster placement, many operators maintain high injection rates per perforation cluster with lowered friction pressure by reducing the number of clusters being fractured per treatment interval. More fracture stages will, however, have to be implemented under this strategy to maintain an equivalent degree of reservoir coverage.

High temperatureEven though the Haynesville reservoir has bottomhole static temperatures ranging from 280 to 380 ˚F (138 to 193 ˚C), the temperature of the wellbore environment during treating is dramatically reduced to 150 to 160 ˚F (65 to 71 ˚C) by the amounts of fluid required to properly treat the unconventional reservoir. Taking advantage of this ‘cool-down’ effect is a traditional engineering technique utilised by fracture designers. Often the fluid volume in the early part of the fracturing stage will be increased to intentionally lower the wellbore temperature to a level where standard fracturing fluid systems can perform adequately. When stimulating unconventional reservoirs like the Haynesville, completion design teams can take advantage of cool down so that the materials used to create the fracturing fluid system can be selected from materials originally intended for lower temperature environments. This provides greater confidence in the performance of the fluid while maintaining an acceptable cost for the fluid system.

Even after treating pressures are reduced as much as possible and bottomhole treating temperature is lowered, challenges continue in the HPHT unconventional reservoirs. Bottomhole temperatures exceed the limitations of many of the industry’s formation evaluation technologies. Those that are available are in high demand and command premium pricing. This technology and equipment shortfall can require operators to make assumptions about reservoir quality along the laterals and to work from estimates as to fracture placement and geometry without conclusive information. This has led to production logs, net pressure evaluation, and production comparisons across various completions becoming some of the primary evaluation tools of the stimulation treatment and for optimising the development of HPHT reservoirs.

Meeting HPHT challenges in tight gasAround the world, operators face a myriad of major tight gas challenges, but few rival a recent Saudi Arabia HPHT stimulation situation: how to perform a proppant frac in deep, tight gas sandstone formations at high bottomhole temperature.

In this case, well conditions of over 15 000 psi (1034 bar) bottomhole pressure and 375 °F (191 ˚C) reservoir temperature exceeded the operating limits of the fracturing equipment and fluid available. Halliburton experts quickly determined that the most cost-effective solution was not to incur the time and expense of bringing in specialised high pressure pumping equipment, but to instead develop a specific fracturing fluid that would work with existing equipment to successfully handle the extreme HPHT conditions. Lower surface treating pressures also translates into safer operating conditions.

Formulating a new solutionTo derive the necessary fluid chemistry and capabilities, Halliburton’s Saudi Arabia stimulation team collaborated with experts at Halliburton’s Duncan, Oklahoma, Technology Center.

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Working under extraordinarily tight time constraints, the strategy was to re-engineer Halliburton’s proven high density fracturing fluid system—specifically its thermal stability—to achieve the required bottomhole treating pressure by taking full advantage of the increased hydrostatic pressure of the weighted stimulation fluid system.

There were excellent reasons to base this solution on the proven high density fracturing fluid system. This fluid has been successfully used since 2004 on numerous high pressure deepwater Gulf of Mexico projects to perform some of the industry’s deepest fracpack treatments (SPE 11607).

While the fluid broke new ground in deepwater wells and possessed adequate density, it was not quite capable of handling the well’s high temperature threshold of 375 ˚F (191 ˚C). Working with the original high density fracturing fluid technology, experts overcame the temperature obstacle by ‘folding in’ chemistry from a separate proprietary high temperature fracture fluid, which utilises an optimised carboxymethyl-hydropropyl gel (CMHPG) loading and a tailored oxidiser breaker system.

The remaining challenge was how to cut pipe friction to further lower wellhead pressure. After fine tuning of the high density base fluid formulation to a density of 12.3 lb/gal. (1464 kg/m3), friction pressure was reduced by delaying crosslinking action during pipe transit time to the target zone. In addition, a microemulsion surfactant for improved fluid recovery in tight gas was added to the fluid system.

Finally, the new high temperature, high density fluid system was ready to run in the well. The graph in Figure 2 shows the expected fluid performance in reducing the surface treating pressure as compared to a conventional high temperature fracturing fluid.


Successful applicationThe result was flawless stimulation performance of Saudi Arabia’s—and the world’s—first high density, high temperature fracture fluid treatment. To stay within the downhole completion string pressure limitation, the pumping rate was held to a little over 16 bbls per minute. The ~11 000 psi (758 bar) surface treating pressure was only slightly higher than the predicted pressure. While the pump rate was lower than desired, it was not a limitation to successfully performing the treatment. As specified in the fracture design, Halliburton’s team pumped 80 000 gal. of the high temperature, high density gel system and placed more than 150 000 lbs of high strength proppant.

While solving the challenge of effectively and economically fracturing under extreme HPHT tight gas sandstone conditions, the new high temperature, high density fluid system met an even greater customer need: providing a proven, cost-effective way to fracture stimulate and validate the reserves of this significant Saudi Arabian tight gas formation. Indications are that this technology may well play an important role in solving similar tight gas challenges in other locations around the world.

Meeting HT challenges in heavy oil projectsFibre optic distributed-temperature-sensing (DTS) systems offer cost-effective methods for improving recovery in steam assisted gravity drainage (SAGD) oilfields producing heavy oil (Figure 3). One of the biggest challenges of a SAGD process is achieving uniform steam conformance along the horizontal wellbore. This is a result of reservoir heterogeneity, production and injection changes over time, and (typically) the limited control of steam placement along the wellbore. Consequently, uneven steam injection and heating can occur in the well and lead to development of a non-uniform steam chamber.

SAGD wells are usually operated under subcool control during which the production well is choked back if live steam reaches the producer. The proximity of live steam is monitored through the temperature difference between the injector and producer (subcool); however, this temperature difference is usually not uniform over the well length1. To prevent production of live steam and improve energy efficiency, it is necessary to limit the production rate based on controlling the subcool in the segment of the well most prone to steam breakthrough, i.e., steam breaking through to the producer.

Monitoring the temperature profile of a well over its entire producing zone via fibre optic DTS enables more cost-effective analytical methods versus other methods like thermocouples which do not provide a distributed temperature profile along then entire length. The fibre optic DTS measurement provides a much more representative profile of the subcool, reservoir heterogeneities and changing production and injection conditions over time that occur along the lateral.

Monitoring both temperature and pressureThe high temperature fibre optic cable can be combined with a fibre optic pressure gauge to obtain both the distributed temperature profile and pressure information with no requirement for downhole electronics. Fibre optic gauges offer the same accuracy and low drift capabilities as proven electronic gauge technology but provide pressure data capabilities in high temperature SAGD environments where electronic gauges cannot operate.

Monitoring and establishing a temperature profile with wellbore pressure information enables implementing a number of different technologies in SAGD projects that can influence the placement of steam along the horizontal wellbore. These can include the use of dual tubing strings, the relocation of a tubing string along the wellbore, the use of limited entry perforation and other more flexible solutions like interval control valves (ICV) technology that would enable some measure of zonal segmentation and control from surface.

Fibre optic system experienceFibre optic high temperature cable has been installed by Halliburton in nearly 200 steam injectors since 2001. Data from the fibre optic DTS have provided insight in fully understanding the completions equipment performance, steam movement results, and well response. Experience with the DTS has shown that multi-mode fibre typically gives superior performance over single-mode fibre in terms of accuracy and resolution under SAGD conditions. High temperature fibre pressure gauges have shown good stability and repeatability.

In one project installed by an operator in Canada utilising fibre optic DTS and pressure gauges, the observed uneven steam injection profile provided the opportunity to attempt to improve the injection performance. Steam was diverted to the heel zones to increase warming, improve injectivity and build a more uniform steam chamber. With initial indications of some warming of these zones, injectivity improved and steam-oil-ratio (SOR) performance improved about 20%. Evaluation of the ability to develop a more uniform chamber will take a longer time (CSUG/SPE 137133).

Other applicationsFibre optic systems have been discussed here relating to SAGD steam injectors; however, the applications extend to other thermal applications, e.g., cyclic steam stimulation (CSS), steam drive and variations, and non-thermal enhanced oil recovery (EOR) processes. The fibre optic systems can be used to observe behaviour over time and help optimise completions hardware and processes to improve performance and reduce operating costs. O T

References1. Gates and Leskiw, 2008.

Figure 3. A high temperature fibre optic system can provide temperature and pressure profiles along the entire wellbore to help better manage SAGD projects in heavy oil.

In 1998 an operator began drilling in a Pakistan fi eld, but a high pressure sequence forced them to stop. All available casing strings were consumed at a

measured depth (MD) of 3500 m; furthermore, managing the high levels of background gas and fl uid losses in the 6 in. hole proved impossible.

Ten years later, a different operator decided to target formations that had not previously been explored. They believed that managed pressure drilling (MPD) techniques coupled with the proprietary continuous circulating valves would enable drilling through the HPHT intervals to a deeper carbonate sequence.

The projected MD for the well was 5200 m. Drilling was originally to take place in two phases to overcome the limitations imposed by the pressure capacity (5200 psi) and certifi ed maximum drilling depth (5000 m) of the rig’s mud circulation system.

The formation consists of hydrocarbon-rich sandstone and a mixture of limestone and inter-bedded shale. The limestone is weak and vuggy, often leading to costly mud losses. Furthermore, pockets of high pressure gas can require days to circulate out, resulting in excessive non-productive time (NPT); a gas slug in the fi rst well precipitated six days of NPT.

The window between pore pressure and the fracture gradient in the formation is quite narrow (0.4 kg/cm2 equivalent mud weight). As such, a slight drop in equivalent circulating density (ECD) during pipe makeup can lead to kicks, well control issues and borehole instability. On the fl ip side, the use of overbalanced drilling techniques to prevent gas infl uxes tends to yield fractures, lost circulation, formation damage and a low ROP. The narrow gradient window has proven impossible to navigate using conventional drilling technology.

UNDER PRESSURE

ASAD MEHMOOD, WEATHERFORD INTERNATIONAL LTD, PAKISTAN, DISCUSSES THE USE OF DRILLING CONTROL

SYSTEMS TO NAVIGATE NARROW PRESSURE MARGINS AND ACCESS DEEP DRILLING TARGETS.

73


Operational detail Rig-up for the MPD operation entailed installing the RCD, adjustable choke manifold and control unit for the Microflux system, and topping the last set of stands with continuous circulation valves.

The platform incorporated a top-drive system. During drilling, mud flowed normally through the system and across the top of the continuous circulation sub. When the sub reached the table, a mud hose was connected to its side port; the side flapper valve opened to allow mud to enter and the flapper valve on the top of the sub closed so that the top drive could be disconnected.

Pumping continued through the sub’s side port until the next stand of pipe was connected. Mud flow was again routed through the top drive system from the top of the new stand. The auxiliary hose was disconnected from the bottom sub, the side port valve closed, and the sub was run in as part of the drillstring.

The Microflux system helped the operators in several ways during drilling. Combined with an auxiliary pump, it enabled them to maintain a constant level of annular backpressure, which ultimately contributed to increasing ROP. It also helped them manage transient conditions, such as pump-off, displacement of heavier mud pills, deployment of mud caps, circulation of high gas cut, plugging of nozzles at bit, and swab/surge. Furthermore, it detected two major partial loss events followed by influxes and allowed the influxes to be circulated out without impacting drilling activities.

Max drilling mud weight in the 8 in. section of the well was 2.07 kg/cm2. The max recorded circulating temperature was 121 ˚C (static temperature above 165 ˚C).

The technologies used on this operation supplanted conventional mud-logging based flow out monitoring and trip/active tank recordings.

ConclusionBenefits the two new technologies provided on the operation include minimised non-productive time, the ability to continue drilling while circulating out up to 50% gas cut and the prevention of kicks, other well-control issues, lost circulation and differential sticking. The operator reached TD under extremely challenging circumstances. O T

Beneath the formation lies pisolitic limestone; this formation had never been explored due to its depth and the difficulty of reaching it.

The operator overcame the obstacles to drilling the well using MPD techniques. One of the technologies used was Weatherford’s Microflux control system. The Microflux system monitors volume in versus out and controls annular backpressure. On the operation, the system proved capable of detecting and controlling an influx of less than 1.5 bbls within 2 minutes.

By maintaining continuous circulation and controlling annular and bottomhole pressure in the difficult section of the well, the operator and Weatherford were able to maintain an average ROP of 2.5 m/hr. The system effectively controlled background gas from the sandstone/limestone without causing lost circulation. Drilling continued even while circulating out as much as 50% gas cut.

System componentsThe Microflux system features a rotating control device (RCD), used to maintain a closed and pressurised annular environment. It is also equipped with sensors that monitor annular pressure and other drilling variables in real-time and an automated surface choke. During the operation, an auxiliary mud pump was used to increase back pressure, as needed.

Figure 1. This Microflux display shows an influx that is being circulated out of the well during the drilling of the 8 ½ in. section. The increase in the outward flow-rate (red) shows the influx. The annular backpressure has been increased to compensate, as has the standpipe pressure. The system allowed the operator to continue drilling while handling up to 50% gas cut in the annular flow.

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Petronas Carigali Sdn. Bhd operates 13 oil and gas fields in the South China Sea, located offshore the Malaysian state of Terengganu in water depths from 65 to 80 m. The area

has more than 30 platforms, most with small deck space areas and crane lifting capacity of only 5 t.

The fields began to experience increased sand production, high water cut and larger skin factor. Well interventions and treatments such as matrix stimulation, water shut-off and sand cleanout were required to sustain production rates. CT well intervention is the most effective method to perform the required treatments; however, when platform space is limited, it is often not practical to accommodate the required facilities onboard. In addition, crane capacity may be inadequate to safely handle the CT equipment. A solution is to deploy a minimal amount of equipment on the platform deck and use a suitable vessel to perform heavy lifting and other support for the CT operations.

Operations in the

Mohd Hairi Abd Razak and Fuad Mohd Noordin, Petronas, Malaysia, and Mohd Nur Afendy and Rahmat Wibisono, Schlumberger, Yemen and Malaysia, present an example of the planning

and execution of coil tubing (CT) operations on platforms too small to accommodate

all the required equipment.

South China

Sea

77


Pilot project Petronas selected two small platforms for a pilot CT intervention project. Platforms in its Penara field are of a lightweight design featuring a cable-guyed caisson monotower (Tarpon) and a topside deck with minimum facilities. First oil from the field was in May 2004, and peak production reached 12 000 bpd. The selected platform had just 180 m2 of main deck and its jib crane had a maximum capacity of 5 t.

The Malong field was completed in March 2000. The selected unmanned minimum-facilities platform was a lightweight optimised jacket structure that supports conductor slots for production and water injection wells and is suitable only for a jack-up drilling rig. The platform houses all the necessary production, well testing, water injection, pig launcher and gas lifting facilities, and is provided with a life support system. It has 650 m2 of main deck, but taking into account all the fixed surface facilities, the operations area is insufficient for conventional CT operations. In addition, the jib crane has a 5 t capacity, sufficient only for lightweight wireline equipment.

CT support vessel evaluationPetronas performed a detailed analysis to determine the type of vessel that would meet the technical requirements and be most cost-effective in supporting CT operations at the selected

platforms. Three options were considered: lift boat, work boat, and work barge. The evaluation was based on completing the CT pilot project within three months, chartering the vessel on a spot basis rather than a long term contract.

A lift boat is a self-propelled, self-elevating vessel with a relatively large open deck. Like a jackup rig, it is capable of raising its hull clear of the water on its own legs. This feature means that it does not require an anchor pattern for stability and to maintain a safe distance from the platform. This saves the cost of an anchor tug handling supply (ATHS) vessel and avoids the risk of anchors damaging seabed equipment if dragged by tides or currents. A disadvantage of the jackup system is the necessity to conduct a soil investigation prior to installation.

Work boats are commonly deployed to assist CT operations

in East Malaysia, and Petronas often uses them for workover operations. This option would require installation of an anchor pattern.

Work barges with the same specifications as work boats were available at lower daily charter rate (DCR) and shorter waiting times. Costs for the planned three month project were evaluated for each of the three technical options. These included ATHS vessel costs for the work boats and barges, crane costs if quoted separately from the DCR, fuel, manning and bunkering. The lift boat was the most expensive option. Due to lower DCR and faster availability, the work barge was the most cost-effective option for the project that met the essential technical and timing requirements.

Work barge assessmentThroughout the operations, only the coil tubing injector head, jacking frame and CT control cabin would be erected on the platform while the remaining equipment would stay on the barge. It was determined that the barge must have a minimum 500 m2 deck space without a crane, or 350 m2 with a crawler crane installed. The heaviest equipment that required lifting to the platform was the 12 t injector head and CT blowout preventer (BOP) assembly, which required a crane capable of lifting 15 t at 60˚ boom angle for safe operations. A 150 t capacity crawler

Figure 1. Map of PCSB concession with insert of Malong and Penara Platform.

Table 1. Vessel comparison

Lift boat Work boat Work barge

Anchor pattern Not required Required Required

Anchor handling tug Not required Required Required

Soil investigation Required Not required Not required

Deck space Yes Yes Yes

Crane Yes Yes Yes

Total project cost Most expensive Medium Least expensive

crane with 150 ft (45.72 m) boom was considered adequate to meet the requirements while minimising the required deck space. The barge needed an eight point mooring system to provide improved stability and facilitate faster disconnect in the event of emergency. Accommodations required sufficient workspace for at least 80 personnel.

Flowback handling system assessmentThe Penara work programme required a system to separate sand from the return fluid. A sand filter system and a cyclone sand separator were considered. Sands produced in Penara have fine (10 - 40 micron) grain size. Filter systems cannot separate such fine sand and were not a viable option; however, a centrifugal cyclone system would be able to handle them effectively.

The sand separator was hooked directly into the well, so the platform shutdown system and surface safety valve (SSV) had to be bypassed. To enable the flowback handling system to override the existing emergency shutdown device (ESD) and SSV, a dedicated SSV in the return line and separate ESD control panel were required.

To improve cleanup efficiency, water-based gelling fluid was used to raise the viscosity of the injected fluid. However, sand separation is more efficient with low viscosity fluids, requiring a breaker solution to be injected before the separator, which is capable of destroying the polymer structure of the gel. Facilities were also required to store sand and liquid effluent.

Health, safety, and environment (HSE) assessment The monsoon season in the South China Sea area is between October and March when there are often strong winds and swells in excess of 6 m. It is usual to avoid operating during this season; however, due to other commitments, the work barge was only available in February. The HSE assessment determined that operations should only start in less than 3 m swell and 20 knot winds. Weather forecasts were updated hourly to maximise the time available for crews to stop operations and perform the necessary steps to move away from the platform. A special device in the CT reel was deployed during the project to allow emergency disconnect and immediate pull-away from the platform if forecasts indicated dangerous conditions within 3 hours.

Figure 2. Equipment layout on the barge.


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Results: Penara Well 1Previous bullheading operations unsuccessfully removed wax from this wellbore, and another treatment to bullhead solvent also proved to be ineffective. A high pressure jetting tool was used to pump different solvent fluids, and was able to reach plug back total depth (PBTD). A final slickline gauge ring run indicated that the wax had been successfully removed, and the well had returned to oil production with encouraging results.

Results: Penara Well 2Bailer runs in October 2007 became hung at 2073 m and upon retrieval to surface, the bailer recovered traces of sands. The CT intervention programme of this well required sand cleanout from hung-up depth to PBTD—an interval of approximately 935 m. Bipolymer gel was conveyed by a special nozzle. In the event of hard sediment that was not removed by this nozzle, acid could be conveyed by a high pressure jetting tool. The programme was executed as planned, with a CT rate of penetration between 1 - 3 ft/min. The separator worked effectively to capture produced sands from the wellbore. A small pill of acid had to be pumped to enable the CT to reach final cleanout depth. Rough weather led to one emergency disconnect, in which planned procedures were successfully implemented.

Results: Malong WellThe production and intervention history of this well indicated that it required water shutoff treatment to block water production

from the lower reservoir; however, leaks in the completion tubing complicated these operations. The only way to effectively squeeze water shutoff chemical was by conveying it with a CT multi-set mechanical packer. After setting the packer, the leak could be isolated, enabling the chemical to be squeezed into the lower operation.

CT operations in this well proved unsuccessful. Prior to reaching target depth, a sequence packer activation procedure was performed to test its functionality and integrity. The setting sequence showed that pressure was holding during injection; however, the unsetting sequence showed that the packer could not be released from its position. High pulling force and multiple packer manipulation were attempted, but after two days of trying, it was decided to release from the packer by activating an emergency disconnecting tool. The upper portion of the disconnecting tool was retrieved to surface. Subsequent attempts to fish the packer were unsuccessful, and it remains in the hole.

ConclusionsThis case study confirms that CT operations can be cost-effectively performed with the support of a work barge on platforms that cannot accommodate all of the necessary equipment. Thorough planning is required to ensure that the technical requirements of multiple types of CT intervention can be effectively delivered and that operations can proceed safely in potentially adverse conditions. O T

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“ High pressures and temps nolonger translateinto more NPT.”

Oilfield Technology June 2011

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