Wednesday, January 15, 2014

Fraccing giant to set up in Broome - Yahoo!7

Fraccing giant to set up in Broome - Yahoo!7

Port Drive, OTS site  Photo: Redhanded Jan 2014

Schlumberger, the oil services giant which has become a major benefactor of the US shale boom, has unveiled plans for a $12.5 million supply base in Broome to service a likely frenzy of fraccing activity in the Canning Basin.
It is the first concrete sign of the boom that could sweep across the Kimberley, based on much-hyped expectations the region east and south of Broome could hold some of the world's richest untapped shale reservoirs.
Schlumberger yesterday would not comment on its proposal for Broome, which remains subject to regulatory approval. Its subsidiary M-I Australia has submitted plans with the Shire of Broome for a drilling fluids facility at the town's port.
One of the biggest challenges facing explorers, led by Buru Energy and New Standard Energy, in their quest for Canning Basin riches has been the lack of infrastructure and a dearth of support services. Backed by Mitsubishi, Apache, ConocoPhillips and PetroChina, this year is set to be groundbreaking for the explorers as they embark on big drilling programs.
Houston-based Schlumberger has been riding the US shale boom, sparked by oil and gas companies' need for hydraulic fracturing to break up the shales to release the oil and gas.
The process requires the injection of sand and chemicals-laced fluids, usually at least 1000m beneath the surface. It is a service provided by the likes of Schlumberger, which has more than a dozen specialised trucks on site at some of the bigger shale well operations in the US.
Fraccing has caused widespread concern among environmental groups, which claim the fluids can poison ground water supplies. They are also worried about the disposal of the fluids once fraccing is complete.


  1. On ABC Radio this morning Campbell said himself and Poelina had asked them if the mud would be used for fracking and they were told "no".The mud plant was to supply offshore rigs and Schlumberger did not supply the fracking industry in WA.

    However when pressed on the Shires position on fracking he spat the dummy and told the interviewer the ABC bias was showing again and he had already received an apology over a previous interview - why not talk about this or that suicide etc.?

    He then said rejoice because the mud plant would contribute over $100,000 toward public art.

    Also "being quite blunt" the boating facility was cancelled because "Barnett had got himself a bloody nose" from previous dealings with Broome and "doing business in Broome" was seen to be too hard by some.

    So having the project cancelled in that way was some payback for JPP being too expensive - hardly Broomes fault.
    After all when questioned early on in the JPP saga - "had he ever been to JPP?" Barnett said "I flew over it once."
    And Voelte once admitted he (Woodside) had no idea having good relations with Aboriginals was important.

    But the ego maniac has to blame someone else for his failures of course.

    The fact that the mud plant at that site would be an abominable eyesore was not raised.

    1. Its true you cannot frack with mud but you can drill very very deep holes, that you can then pour vast amounts of chemicals down and other devices that can do the fracking. They want to build this on the pinan foreshore on ®roebuck Bay. Gampbell has very little understanding about fracking he is just trying really hard to stay in good with the telly toddies gang. Red

    2. Haha - I like that "the telly toddies gang".
      How much of the wasted $8 million JPP money went into their pockets?
      The "oil and gas consultancy" must have been charging SERCO rates - just like their poofy mate and the $4 million to find Chinatown.

      One thing for sure a fracking crew will be easy to spot.

      Heres a couple of articles on mud and onshore/offshore fracking.

    3. How Do Drilling Fluids Work?

      Drilling deeper, longer and more challenging wells has been made possible by improvements in drilling technologies, including more efficient and effective drilling fluids. Drilling fluids, also referred to as drilling mud, are added to the wellbore to facilitate the drilling process by suspending cuttings, controlling pressure, stabilizing exposed rock, providing buoyancy, and cooling and lubricating.

      As early as the third century BC, the Chinese were using drilling fluids, in the form of water, to help permeate the ground when drilling for hydrocarbons. The term "mud" was coined when at Spindletop in the US, drillers ran a herd of cattle through a watered-down field and used the resulting mud to lubricate the drill.

      While the technology and chemistry of drilling fluids have become much more complex, the concept has remained the same. Drilling fluids are essential to drilling success, both maximizing recovery and minimizing the amount of time it takes to achieve first oil.

      Purposes of Drilling Fluid

      During drilling, cuttings are obviously created, but they do not usually pose a problem until drilling stops because a drillbit requires replacement or another problem. When this happens, and drilling fluids are not used, the cuttings then fill the hole again. Drilling fluids are used as a suspension tool to keep this from happening. The viscosity of the drilling fluid increases when movement decreases, allowing the fluid to have a liquid consistency when drilling is occurring and then turn into a more solid substance when drilling has stopped. Cuttings are then suspended in the well until the drill is again inserted. This gel-like substance then transforms again into a liquid when drilling starts back up.

      Drilling fluids also help to control pressure in a well by offsetting the pressure of the hydrocarbons and the rock formations. Weighing agents are added to the drilling fluids to increase its density and, therefore, its pressure on the walls of the well.

      Another important function of drilling fluids is rock stabilization. Special additives are used to ensure that the drilling fluid is not absorbed by the rock formation in the well and that the pores of the rock formation are not clogged.

      The longer the well, the more drill pipe is needed to drill the well. This amount of drill pipe gets heavy, and the drilling fluid adds buoyancy, reducing stress. Additionally, drilling fluid helps to reduce friction with the rock formation, reducing heat. This lubrication and cooling helps to prolong the life of the drillbit.

      Types of Drilling Fluids

      Drilling fluids are water-, oil- or synthetic-based, and each composition provides different solutions in the well. If rock formation is composed of salt or clay, proper action must be taken for the drilling fluids to be effective. In fact, a drilling fluid engineer oversees the drilling, adding drilling fluid additives throughout the process to achieve more buoyancy or minimize friction, whatever the need may be.

      In addition to considering the chemical composition and properties of the well, a drilling fluid engineer must also take environmental impact into account when prescribing the type of drilling fluid necessary in a well. Oil-based drilling fluids may work better with a saltier rock. Water-based drilling fluids are generally considered to affect the environment less during offshore drilling.

      Disposal of drilling fluids after they are used can also be a challenge. Recent technological advances have established methods for recycling drilling fluids.

    4. Fracking 101: Breaking down the most important part of today’s oil, gas drilling

      Glossary of terms

      » Blender: The equipment used to prepare the slurries and gels commonly used in stimulation treatments. Modern blenders are computer controlled, enabling the flow of chemicals and ingredients to be efficiently metered and requiring a relatively small residence volume to achieve good control over the blend quality and delivery rate.

      » Casing: Steel pipe cemented in place during the construction process to stabilize the wellbore. The casing forms a major structural component of the wellbore and serves several important functions: preventing the formation wall from caving into the wellbore, isolating the different formations to prevent the flow or crossflow of formation fluid, and providing a means of maintaining control of formation fluids and pressure as the well is drilled. The casing string provides a means of securing surface pressure control equipment and downhole production equipment, such as the drilling blowout preventer (BOP) or production packer. Casing is available in a range of sizes and material grades.

      » Completion: A generic term used to describe the events and equipment necessary to bring a wellbore into production once drilling operations have been concluded, including but not limited to the assembly of downhole tubulars and equipment required to enable safe and efficient production from an oil or gas well. Completion quality can significantly affect production from shale reservoirs.

      » Drilling rig: The machine used to drill a wellbore. It includes virtually everything except living quarters. Major components of the rig include the mud tanks, the mud pumps, the derrick or mast, the drawworks, the rotary table or topdrive, the drillstring, the power generation equipment and auxiliary equipment.

      » Hydration unit: This unit mixes the water and chemical additives to make the frac fluid. Usually the blending process takes a few minutes for the water to gel to the right consistency.

      » Missile: The missile is comprised of a low-pressure side and a high pressure side, and is the manifold through which the frac fluid flows to the pressurization trucks, and into the wellbore to frac the rock.

      » Roughneck: A floor hand, or member of the drilling crew, who works under the direction of the driller to make or break connections as drillpipe is tripped in or out of the hole. On most drilling rigs, roughnecks are also responsible for maintaining and repairing much of the equipment found on the drill floor and derrick.

      » Roustabout: Any unskilled manual laborer on the rigsite. Roustabouts are commonly hired to ensure that the skilled personnel that run an expensive drilling rig are not distracted by peripheral tasks, ranging from cleaning up the location to cleaning threads to digging trenches to scraping and painting rig components.

      » Shale: A fine-grained sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers. It is the most abundant sedimentary rock. Shale can include relatively large amounts of organic material compared with other rock types and thus has potential to become a rich hydrocarbon source rock, even though a typical shale contains just 1 percent organic matter.

      » Tank battery: A group of tanks that are connected to receive crude oil production from a well or a producing lease. A tank battery is also called a battery. In the tank battery, the oil volume is measured and tested before pumping the oil into the pipeline system.

      » Wellbore: The drilled hole or borehole, including the openhole or uncased portion of the well. Borehole may refer to the inside diameter of the wellbore wall, the rock face that bounds the drilled hole.

    5. Glossary of terms

      » Vapor Recovery Unit: A system at a drilling site to recover vapors formed inside completely sealed crude oil or condensate tanks. The vapors are sucked through a scrubber, where the liquid trapped is returned to the liquid pipeline system or to the tanks, and the vapor recovered is pumped into gas lines.

      Source: Tribune research and Schlumberger, a global supplier of oil field technology and equipment

    6. Fracking 101: Breaking down the most important part of today’s oil, gas drilling

      Starting a well

      Companies start the drilling process on about a 3-acre pad of land, which allows for the many trucks that become part of an oil and gas drilling process.

      The process begins with vertical drilling. A drilling rig is brought on site to drill the well, which will go to depths of up to 10,000 feet below the surface. This process can take from a week to 10 days, depending on the site.

      Drilling stops initially below the water table so the well can be encased in cement to prevent anything from the well leaking into the water table. Once the casing is completed, a 7-inch drill bit will drill more than a mile to get to the formation in which to frac, usually the Niobrara or Codell formations, both stacked beneath several impermeable rock formations. Once the drill bit hits bottom, or the “pay zone,” the company will drill what is called the “bend,” which is the curve the well takes to get into the horizontal portion of the zone. The bend alone could take up to two days to drill.

      Throughout the drilling process, drilling mud is pumped in to cool the drill bit and act as a means for the resulting debris to leave the well.

      The horizontal portion of the well then is drilled for an additional 4,000 feet to 10,000 feet, then encased in cement, with a 4-inch metal pipe in the center to allow for the oil and gas to flow to the surface. At this point, the well is just a hole drilled into the ground, with a cement barrier between the pipe, the formations and water table.

      The rig is packed up and activity stops until fracking is scheduled. Sometimes it can wait for weeks before a fracking crew is able to get there. Sometimes it takes a couple of days.

    7. Fracking 101


      The actual fracking process uses a lot of machinery capable of driving the fluid down more than a mile, and a lot of science to calculate the exact mixtures of everything from chemicals and water and sand to the pressure it takes to crack tiny little fissures into rocks, more than a mile beneath the surface.

      Sand, water and chemical additives are pumped into the well at high pressures, so as to crack the rock in different stages in the horizontal (parallel to the surface) portion of the well.

      “To open fractures at bottom-hole pressures in the Niobrara, you probably need downhole pressures of 10,000 psi or so to open the rocks,” Weijers said.

      The chemicals do not erode the rock to create the cracks or fracs — it’s the high pressure of the water that opens them up. The chemicals, such as guar gum, which also are in many foods we eat, are added to help the water to gel, allowing the sand an easier vehicle in which to move.

      “When it’s thicker, it does a better job of carrying sand downhole,” Weijers said. “If you think about a handful of sand at a lake, and you put it in water, the sand will settle quickly to the bottom of the lake. We don’t want that to happen in factures.”

      Those cracks, now held open by the tiny kernels of sand, release the trapped oil and gas inside, which flow back to the surface after the downward pressure from fluids is released from the well.

      Soap ingredients also can be added to the gel to prevent bacterial growth in the well. If bacteria forms, it could release deadly gases.

      “You put a lot worse stuff in your food, your yard, or your garden,” Richardson said. “A lot of the chemicals are used to clean your counters, and put in your make-up.”

      Many involved in the process describe frac fluid as “slime,” like the stuff kids play with from the local toy store.

    8. Fracking 101

      The Layout

      To handle the sand, water, chemicals and production that comes out of the well during the fracking of the well (commonly called flowback), the site needs have the basics: Trucks, trucks and more trucks to carry the water, the sand, and the chemicals to mix them all together, and more truck horsepower to combine it all to shoot down through a pipe into an 8-inch hole in the ground.

      To prep the area, several 500-barrel tanks for water storage or a massive, 40,000-barrel pool to store water is erected on the periphery of the site. Sand storage tanks arrive, then are filled. A typical frac job will utilize from 1.5 million to 6 million pounds of sand.

      Iron trucks carry massive amounts of pipe that will be used to keep the well opened and separate from the well.

      “When the rest of the crew arrives on location, they’ll typically rig up to the well head with a missile,” Weijers said.

      The missile is a manifold around which most of the activity centers, to ultimately pump fracking fluid downhole. Crews will line on each side of the missile five to six semi trucks, which contain the horsepower to create enough pressure to pump the fluid downhole at the proper rate.

      In addition to the horsepower trucks, there are sand trucks and trucks containing the chemical additives to thicken the water to keep the sand moving in the well.

      A hydration truck, through which the chemicals are added to the water to “gel,” and a blender, which mixes that fluid with the sand, are nearby. All surround the missile in a horseshoe shape.

      “The blender sends the mixture of sand water to the low-pressure side of the missile,” Weijers said. “From that missile, we have 10-12 connections to the individual horsepower units, which really pressurize the mixture of sand and fluids so the (missile) can send it (through its high-pressure side) downhole at pressures that can crack the rock open.”

      That one process is good for one frac, or stage, at which the horizontal well is cracked from being hit at such high pressures.

      A typical well can have 20 fracs, each necessitating this procedure of blending, pressurizing and cracking. A typical frac job can last up to 20 hours — one frac stage per hour — from start to finish.

      At the open end, or the top of the horseshoe, is a data center, or a trailer containing about five to six people controlling the science of the job. There’s usually a representative or two from the oil and gas company, a frac job supervisor and an engineer to do the calculations.

      “Typically, there’s an engineer who makes the readings of the pressure,” Weijers said. “There’s hundreds of parameters being tracked, all the chemicals, the proppant (sand) being pumped, pressures during the job. The engineer makes it possible to track that and do scientific calculations of the data.”

      Here, employees track every aspect of the job, from pressures of the frac fluid to the diesel engine’s fuel gauges.

      At various other open areas, there will be containers in which the used sand and production waters are placed into once they fulfill their purpose in the wells to be hauled off later for recycling, injection or disposal.

      On jobs where crews utilize a large pool of water, the water is usually being heated to temperatures of about 70 degrees to provide the perfect chemical combination with the additives and sand.

      At some point in the drilling and completion process, crews will build oil and gas storage tanks, vapor recovery units to control air emissions, and oil and gas separators for the eventual well production. All will be strategically located around the wellhead.

    9. Fracking 101


      Once all the fracs are created, the downward pressure is removed from the well. Within a couple of days, the release of that pressure will reverse, allowing the oil and gas to flow from the rocks and up the well.

      “At end of the frac job, the flow stream is reversed,” Wiejers said. “Instead of pumping things downhole, due to the pressure we created, we have almost no pressure at the surface, then the flow reverts and oil and gas and some of the water find their way back from downhole to the surface.”

      All the equipment is removed from the site, leaving only the wellhead, the storage tanks, separators and emissions control. Production can last for years.

    10. OFFSHORE

      Baker Hughes Incorporated, announced that its subsidiary has chartered a new state-of-the-art pressure pumping vessel that will provide offshore stimulation services to Maersk Oil in the North Sea. Upon completion, scheduled for late 2013, the Blue Orca(TM) will become the eighth vessel in the Baker Hughes fleet.

      “We are pleased to be working with Maersk Oil as we expand our current fleet into the North Sea,” said Art Soucy, Baker Hughes’ President of Global Products & Services. “Our full cadre of world-class stimulation vessels offers customers the capacity, performance and redundancy for round-the-clock operations that are needed in today’s offshore plays. We are committed to operating safely and efficiently while continuing to build on our pressure pumping market leadership and the challenging offshore environments where operators need us to be.”

      The Blue Orca will be rated to 15,000 psi and will offer among the largest fluid and proppant carrying capacities in the world. It will provide 15,000 hydraulic horsepower pumping capacity and the ability to pump at rates well in excess of 60 bpm. Engineering work on the marine and stimulation systems has already begun.

      “Stimulation of long horizontal wells is one of Maersk Oil’s key technologies and vital for economic development of our tight chalk reservoirs,” said Mary Van Domelen, Maersk Oil’s Stimulation Team Leader. “We appreciate the opportunity to work with Baker Hughes to deliver a new state-of-the-art stimulation vessel and look forward to welcoming the Blue Orca to the North Sea.”

      The Blue Orca will join Baker Hughes’ other stimulation vessels – including the company’s newest additions to the Gulf of Mexico: Blue Tarpon and the Blue Dolphin. The vessels support offshore completion operations and will be equipped to support high-rate and high-volume multi-zone fracturing operations.

      “Our pressure pumping vessels offer enhanced safety systems with redundant back-up blending and pumping capabilities,” said Lindsay Link, Baker Hughes’ President of Pressure Pumping. “When it comes to performing multi-zone, high-rate, high-pressure completions, our vessels are reliable, efficient and minimize delays in high-cost offshore environments, where time is of the essence for the operators on behalf of whom we are working.”



      Impacts of Offshore Drilling

      Offshore drilling operations create various forms of pollution that have considerable negative effects on marine and other wildlife.

      These include drilling muds, brine wastes, deck runoff water and flowline and pipeline leaks. Catastrophic spills and blowouts are also a threat from offshore drilling operations. These operations also pose a threat to human health, especially to oil platform workers themselves.

      Drilling muds and produced water are disposed of daily by offshore rigs. Offshore rigs can dump tons of drilling fluid, metal cuttings, including toxic metals, such as lead chromium and mercury, as well as carcinogens, such as benzene, into the ocean.

      Effects of Drilling Muds

      Drilling muds are used for the lubrication and cooling of the drill bit and pipe. The muds also remove the cuttings that come from the bottom of the oil well and help prevent blowouts by acting as a sealant. There are different types of drilling muds used in oil drilling operations, but all release toxic chemicals that can affect marine life. One drilling platform normally drills between seventy and one hundred wells and discharges more than 90,000 metric tons of drilling fluids and metal cuttings into the ocean.

      Effects of Produced Water

      Produced water is fluid trapped underground and brought up with oil and gas. It makes up about 20 percent of the waste associated with offshore drilling. Produced waters usually have an oil content of 30 to 40 parts per million. As a result, the nearly 2 billion gallons of produced water released into the Cook Inlet in Alaska each year contain about 70,000 gallons of oil.

      Effects of Exploration

      Factors other than pollutants can affect marine wildlife as well. Exploration for offshore oil involves firing air guns which send a strong shock across the seabed that can decrease fish catch, damage the hearing capacity of various marine species and may lead to marine mammal strandings.

      More drilling muds and fluids are discharged into the ocean during exploratory drilling than in developmental drilling because exploratory wells are generally deeper, drilled slower and are larger in diameter. The drilling waste, including metal cuttings, from exploratory drilling are generally dumped in the ocean, rather than being brought back up to the platform.

      Effects of Offshore Oil Rigs

      Offshore oil rigs may also attract seabirds at night due to their lighting and flaring and because fish aggregate near them. Bird mortality has been associated with physical collisions with the rigs, as well as incineration by the flare and oil from leaks. This process of flaring involves the burning off of fossil fuels which produces black carbon.

      Black carbon contributes to climate change as it is a potent warmer both in the atmosphere and when deposited on snow and ice. Drilling activity around oil rigs is suspected of contributing to elevated levels of mercury in Gulf of Mexico fish.


      Terminology and the Obfuscating Euphemism

      So - we are not allowed to know what, exactly, is in the waste dumped over the side of thousands of drilling rigs, production platforms and drillships. The terminology used to describe the main classes of drilling fluids can also be confusing because it has changed over the years, to keep up with changes in mud technology. These are the terms used by the Oslo-Paris Commission (OSPAR) and the UK Department of Trade and Industry, as of March 2000:

      a. Water-based muds or fluids (WBM);
      b. Organic-phase drilling fluids (OPF), which is the newly-coined collective term (and euphemism) for:

      i. Oil-based muds (OBM), including Low-toxicity Oil-based Muds (LTOM) and
      ii. Synthetic-based drilling fluid/mud (SBF or SBM) - formerly known as Pseudo Oil-based Mud (POBM) and also including Emulsion-based Mud.

      As discussed below in more detail, the term WBM conceals the fact that the water base may contain hydrocarbons in concentrations of parts-per-thousand (Reddy, S., et al. 1995. op. cit.), some from additives and some from crude petroleum with which the mud has been in contact down the hole (Patin, S. A. 1999. Environmental Impact of the Offshore Oil & Gas Industry. Eco Monitor Publishing, East Northport, New York. ISBN 0-967 1836-0-X.)

      Whatever the base fluid used, nearly all muds contain at least some of the additives in the List of Notified Chemicals and the Fluids Tables mentioned above. These materials come back up the well to the drilling floor (The deck of the drilling rig or platforms where the drilling turntable and drilling crews are located) in a slurry with drill cuttings (rock fragments), crude oil, gas, natural gas liquids, produced water, traces of heavy metals, biocides, surfactants and other, mostly organic, substances. The mixtures entering and leaving a well can be so complicated that the OCNS has a special reporting category called UCMs: "unresolvable complex mixtures" (CEFAS. 2000a. op. cit. p.20). In the early years of offshore drilling, all this material was dumped into the sea.

      Pollution problems caused by oil and other contaminants in waste drilling fluids were recognised over 40 years ago in the Gulf of Mexico and, since the development of the North Sea oil and gas fields in the 1970s, have become a major political issue in Western Europe.

      Oil-based muds were developed for situations where WBMs could not provide enough lubrication or other desired characteristics. Usually, this would be when a job required directional, or deviated, drilling. In this precision drilling technique, now so essential to the industry, the drill bit can be "steered" downhole so that the well deviates from the vertical by a known and controlled angle.


      When wells are drilled many thousands of feet below the seabed, the drill bit can end up cutting horizontally through the strata, making accessible isolated pockets of oil and gas that were previously not economic to extract. Such deviated drilling has revolutionised the economics of offshore oil and gas drilling and has become standard procedure on such fields as the Atlantic Margin, off the west coast of Shetland, where many small, discrete reservoirs can now be penetrated with a single well. Although the radii of such curved wells are very large, deviated drilling still requires drilling mud with higher lubrication qualities than the ordinary, water-based mud traditionally used for spudding in and drilling vertical wells - particularly when cutting through layers of very hard rock or when drilling smaller radius holes a long way down. Until the mid-1980s, OBM was routinely used for this kind of difficult drilling.

      The realisation that relatively large areas of seabed around hundreds of offshore installations had been smothered, sterilised and/or poisoned, by OBM-contaminated drill cuttings and the crude oil sticking to them, led to a number of international agreements which, by 1996, had outlawed the discharge of oil-based drilling muds containing diesel or mineral oils (OSPAR. 1992a. PARCOM Decision 92/2 on the Use of Oil-based Muds. See also: OSPAR. 1996. PARCOM Decision 96/3 on a Harmonized Mandatory Control System for the Use and Reduction of the Discharge of Offshore Chemicals; OSPAR. 1997. PARCOM Decision 97/1 on Substances/Preparations Used and Discharged Offshore; OSPAR. 1999a. List of Substances / Preparations Used and Discharged Offshore Which Are Considered to Pose Little or No Risk to the Environment (PLONOR)). How far this has been put into effect is the subject of some debate.

      Low-toxicity OBMs can be and still are used (See the list of "Z-muds" on the CEFAS website: Group Z Base Fluids), but only in formulations designed for zero-discharge, where all the used mud is either recycled (usually onshore) or re-injected with cuttings into the rocks below the seabed.

      Changing the terminology is a technique sometimes used by industries seeking to delay or weaken regulation. Giving something a new, neutral-sounding name can confuse and soothe lawmakers, government officials and the general public. A classic example of the obfuscating euphemism, originating in the US, is the recent re-naming of drilling muds.



      ##Water-based mud (WBM): Most basic water-based mud systems begin with water, then clays and other chemicals are incorporated into the water to create a homogenous blend resembling something between chocolate milk and a malt (depending on viscosity). The clay (called "shale" in its rock form) is usually a combination of native clays that are suspended in the fluid while drilling, or specific types of clay that are processed and sold as additives for the WBM system. The most common of these is bentonite, frequently referred to in the oilfield as "gel". Gel likely makes reference to the fact that while the fluid is being pumped, it can be very thin and free-flowing (like chocolate milk), though when pumping is stopped, the static fluid builds a "gel" structure that resists flow. When an adequate pumping force is applied to "break the gel", flow resumes and the fluid returns to its previously free-flowing state. Many other chemicals (e.g. potassium formate) are added to a WBM system to achieve various effects, including: viscosity control, shale stability, enhance drilling rate of penetration, cooling and lubricating of equipment.

      ##Oil-based mud (OBM): Oil-based mud can be a mud where the base fluid is a petroleum product such as diesel fuel. Oil-based muds are used for many reasons, some being increased lubricity, enhanced shale inhibition, and greater cleaning abilities with less viscosity. Oil-based muds also withstand greater heat without breaking down. The use of oil-based muds has special considerations. These include cost, environmental considerations such as disposal of cuttings in an appropriate place to isolate possible environmental contamination and the exploratory disadvantages of using oil based mud, especially in wildcat wells due inability to analyze oil shows in cuttings, because the oil based mud has fluorescence confusing with the original oil of formation. Therefore induces contamination of cuttings samples, cores, sidewall cores for geochemical analysis of TOC and masks the real determination of API gravity due to this contamination.

      ##Synthetic-based fluid (SBM) (Otherwise known as Low Toxicity Oil Based Mud or LTOBM): Synthetic-based fluid is a mud where the base fluid is a synthetic oil. This is most often used on offshore rigs because it has the properties of an oil-based mud, but the toxicity of the fluid fumes are much less than an oil-based fluid. This is important when men work with the fluid in an enclosed space such as an offshore drilling rig. The same environmental problems and contamination for analysis of rock samples occurs using Synthetic-based fluid.

      On a drilling rig, mud is pumped from the mud pits through the drill string where it sprays out of nozzles on the drill bit, cleaning and cooling the drill bit in the process. The mud then carries the crushed or cut rock ("cuttings") up the annular space ("annulus") between the drill string and the sides of the hole being drilled, up through the surface casing, where it emerges back at the surface. Cuttings are then filtered out with either a shale shaker, or the newer shale conveyor technology, and the mud returns to the mud pits. The mud pits let the drilled "fines" settle; the pits are also where the fluid is treated by adding chemicals and other substances.

      Fluid Pit
      The returning mud can contain natural gases or other flammable materials which will collect in and around the shale shaker / conveyor area or in other work areas. Because of the risk of a fire or an explosion if they ignite, special monitoring sensors and explosion-proof certified equipment is commonly installed, and workers are advised to take safety precautions. The mud is then pumped back down the hole and further re-circulated. After testing, the mud is treated periodically in the mud pits to ensure properties which optimize and improve drilling efficiency, borehole stability, and other requirements listed below.


      Drilling fluid environmental considerations

      Health, safety and environment policies

      The health, safety, and environmental (HSE) policies of many companies are more stringent than those required by national governments and the various agencies charged with overseeing drilling operations. All personnel who take part in the well-construction process must comply with these standards to ensure their own safety and that of others. On most locations, a “zero-tolerance” policy is in effect concerning behaviors that might endanger workers, the environment, or the safe progress of the operation. Additionally, all personnel are encouraged to report potentially hazardous activities or circumstances through a variety of observational safety programs.

      The packaging, transport, and storage of drilling-fluid additives and/or premixed fluid systems are closely scrutinized regarding HSE issues. Personnel who handle drilling fluid and its components are required to wear personal protective equipment (PPE) to prevent inhalation or other direct contact with potentially hazardous materials. Risk-assessed ergonomic programs have been established to reduce the potential for injuries related to lifting sacks and other materials, and operating mud-mixing equipment.

      Transportation and management

      When possible, drilling-fluid additives, base fluids, and whole mud are transported in bulk-tote tanks or are containerized. These transport methods help reduce packaging-related waste, and minimize the risk of harming personnel, polluting the environment, and impairing operations. High-volume materials such as barite, bentonite, salt, and base fluids almost always are provided in bulk to offshore installations. Onshore locations might use both bulk and packaged-unit materials, depending on the well depth and complexity.

      The drilling-fluids specialist and operator representative at each location are responsible for ensuring that the available volume and properties of the drilling fluid will meet the immediate demands of a well-control situation, for example:
      ◾ A loss of circulation
      ◾ A tripping of a wet string
      ◾ A material-delivery delay caused by adverse transport conditions
      ◾ The need to mix additional volumes of drilling fluid with the appropriate properties at the rigsite
      ◾ The need to obtain additional volumes of drilling fluid with the appropriate properties in a timely manner

      Published well-control guidelines recommend storing a riser volume plus 200 bbl (for pumping and line losses) in water depths ≥ 1,000 ft.[1] Many deepwater-drilling operations take place in water depths exceeding this and approaching 10,000 ft. Nonsettling, ballast-storable drilling fluids have been used offshore to eliminate the risk of disruptions to supply created by inclement weather, and to prepare for drilling through SWFzones

    16. Drilling fluid environmental considerations

      Sources of contamination

      Land and offshore drilling locations are regulated regarding:
      ◾ Disposal of whole mud
      ◾ Drilled cuttings and other solids
      ◾ Runoff generated by rainfall
      ◾ Wave action
      ◾ Water used at the rigsite

      Industrywide efforts to eliminate environmental hazards resulting from accidents or the negligent handling of drilling fluids and/or drilled cuttings encompass several contamination issues related to drilling fluids:
      ◾ Formulation (chlorides, base oils, heavy metals, and corrosion inhibitors)
      ◾ Natural sources (crude oil, salt water, or salt formation)
      ◾ Rigsite materials (pipe dope, lubricants, and fuel)

      In some cases, reformulating drilling-fluid systems makes them environmentally more benign. For example, chrome lignosulfonate water-based fluid (WBF) is available in a chrome-free formulation. The development of SBFs stemmed from the need to replace diesel- and mineral-oil-based fluids (OBFs) because of environmental restrictions.

      The discharge of conventional OBFs and drilled cuttings effectively was prohibited in the North Sea in 2000. According to the Convention (OSPAR) Commission for the Protection of the Marine Environment of the North-East Atlantic, 98% of the total hydrocarbon discharge volume consists of produced water and drilled cuttings generated with SBFs.[6]

      Cuttings that are generated by drilling with certain compliant SBFs may be discharged overboard in the western Gulf of Mexico if they comply with the retention-on-cuttings (ROC) limits introduced in 2002 by the Environmental Protection Agency (EPA). Neither traditional OBFs nor the drilled cuttings produced while using them can be discharged in the Gulf of Mexico. The rare offshore operation that uses a diesel- or mineral-based fluid must include a closed-loop process for continuously capturing all drilled cuttings and returning them to shore for regulated disposal.

  2. Buru-Mitsubishi JV Spuds Ungani 3 Appraisal Well in Western Australia

    Australia's oil and gas company Buru Energy Limited disclosed that drilling operations on the Ungani 3 well in exploration permit (EP) 391 in Western Australia commenced at 17:30hrs Jan. 14 (AWST) using the Advanced Energy Services Crusader 405 drilling rig. As at 06:00hrs Jan. 15 (AWST) the well was drilling ahead at 337 feet (103 meters). Ungani 3 is the first well in the Buru – Mitsubishi Corporation (MC) 2014 drilling program. Buru and MC each have a 50 percent equity and contributing interest in the well and the Ungani Field.

    The Ungani 3 well is located in production application STP-PRA-0004 in EP 391 some 62 miles (100 kilometers) to the east of Broome. The well location is some 31 miles (50 kilometers) from the Great Northern Highway along the Ungani access road. The well has a programmed total depth of 7,677 feet (2,340 meters) and is expected to take some 35 days to drill and suspend.

    The well is located in the Ungani Field area on a separate pad to the Ungani Production Facilities (UPF) and is some 3,280 feet (1,000 meters) to the east of the Ungani 1 and 2 wells. The planned production from the well will be transferred to the UPF via a pipeline from the Ungani 3 pad.

    The primary objective of the well is the oil producing Ungani Dolomite reservoir of the Ungani Field, the well also has a secondary target in the overlying Grant Formation in which oil shows were encountered in the Ungani 1 well, and where a potentially significant structural closure has been identified on the Ungani 3D seismic data.

    1. Future Activities and
      AEG is committed to working
      closely with Western Australian
      operators to continuously improve
      well construction efficiency; raise
      health, safety and environmental
      standards; and reduce overall well
      construction costs. As our clients
      achieve exploration and appraisal
      success, their focus will shift
      from remote exploration wells to
      enhanced efficiency of development
      drilling, as well as minimisation
      of the environmental impact of
      remote operations.

      By working closely with its business
      partners, AEG will provide enhanced
      capabilities that are aligned to our
      client’s objectives. These services and
      technologies are likely to include:
      • Closed-loop drilling fluid management
      systems enabling fluid conditioning
      and recycling with greatly reduced
      environmental impact;
      • Directional casing drilling technology
      enabling efficient construction of
      horizontal development wells,
      significantly reducing overall well
      construction time and cost;
      • Underbalanced drilling capabilities
      enabling optimisation of reservoir
      performance for development wells
      and a reduction in overall well
      numbers; and
      • New rig (such as the design shown in
      Figure 1) which enable extremely
      efficient rig moves at multi-well
      pads (‘walking rig’) and between
      fields and basins.

      It is clear that a step-change is
      required in the onshore drilling
      services sector, a change that will
      reduce overall well construction
      costs, reduce our environmental
      impact and greatly improve the health
      and safety of well-site personnel.
      AEG believes that these changes
      can only be delivered by the
      embracing new technologies and
      adopting a management philosophy
      that enables closer collaboration and
      alignment between operators and
      service providers.
      This will not be an easy change
      to realise, however it is crucial to
      improving productivity and reducing
      overall well construction costs
      within the onshore oil and gas
      sector. If this can be achieved it
      will deliver significant value to
      exploration and production
      companies, service providers and
      the Western Australian community.


      Posted as a guide as to what they are up to in trying to get costs down for CB operations.

    2. How Does a Top Drive Work?

      Used to rotate the drill string during the drilling process, the top drive is a motor that is suspended from the derrick, or mast, of the rig. These power swivels boast at least 1,000 horsepower that turn a shaft to which the drill string is screwed. Replacing the traditional Kelly or rotary table, the top drive lessens the manual labor involved in drilling, as well as many associated risks.

      A top drive is comprised of one or more electric or hydraulic motors, which is connected to the drill string via a short section of pipe known as the quill. Suspended from a hook below the traveling block, the top drive is able to move up and down the derrick. Many times, slips are still employed on a rotary table to ensure the drill string does not fall down the well.

      Chosen both for increased safety and efficiency, top drives provide several key benefits:
      •A top drive is capable of drilling with three joints stands, instead of just one pipe at a time.
      •Top drives typically decrease the frequency of stuck pipe, which contributes to cost savings.
      •A top drive allows drillers to more quickly engage and disengage pumps or the rotary while removing or restringing the pipe.
      •Top drives are also preferable for challenging extended-reach and directional wells.

      Reducing risk and increasing safety during the drilling process, top drives remove much of the manual labor that was previously required to drill wells. Many times, top drives are completely automated, offering rotational control and maximum torque, as well as control over the weight on the bit.

      Top drives can be used in all environments and on all types of rigs, from truck-mounted units to the largest offshore rig. Although top drives can be used on both onshore and offshore rigs, there are some differences between the two. For example, on an offshore rig, the top drive travels up and down the vertical rails to avoid the mechanism from swaying with the waves of the ocean.

    3. Drilling With Casing
      Weatherford's drilling-with-casing (DwC™) system eliminates the need to trip pipe and bottomhole assemblies (BHAs), increasing drilling speed and reducing risk exposure by always having casing on or near the bottom. The DwC system simplifies well architecture by potentially reducing the surface casing size as well as contingency casing strings or liners. A casing string or liner can be eliminated by successfully drilling into or through a pressure transition or lost zone.

      As reservoirs age, drilling hazards ranging from depleted zones with pressure transitions and hole stability problems become more prevalent. These issues add to an estimated 10 to 20 percent or more to drilling time. Additionally, conventional methods used to control lost circulation such as mud additives, pumping cement plugs, cementing, and resins can be time consuming, costly, and often ineffective.


      Casing Drilling Services

      TDDirect technology eliminates dedicated casing runs

      TDDirect casing-drilling and liner-drilling technology delivers a high-quality wellbore by casing and isolating the formation while drilling. Each foot of borehole is drilled and cased off simultaneously, eliminating the need for separate casing or liner runs. When TD is reached, the borehole is ready for cementing. Compared with the performance of conventional drilling systems, TDDirect technology has recorded equal or better on-bottom ROPs and has reduced the time spent on drilling and casing operations by more than 30%.


      Canrig Drilling Technology Ltd. Introduces New Casing Running Tool

      Magnolia, Texas (April 26, 2010) – Today Canrig Drilling Technology Ltd. launches an automated casing running tool that decreases drilling costs while helping to overcome complex well conditions, all while leaving casing in better condition than traditional die slips. The SureGrip™ CRT was strategically designed to address many of operators’ major concerns, including drilling efficiency, operational safety, pipe condition and equipment integration.

      “Our new SureGrip technology does the work of an entire casing crew with the touch of a button from the driller or certified Canrig technician,” said Chris Papouras, President of Canrig. “It allows rig personnel to focus on landing casing down-hole instead of the handling process of getting casing ready to trip in. SureGrip reduces the manual handling, equipment and personnel needed to run casing, resulting in enhanced operating efficiency and drill floor safety.”

      SureGrip™ automates the process of picking up single joints of casing and stabbing them into the string, which reduces manual handling requirements – the number one cause of rig safety incidents. It utilizes the top drive to apply torque and simultaneously rotate, reciprocate and circulate, crucial for overcoming troublesome hole conditions and yielding better cement jobs, preventing the need for costly remedial actions. SureGrip extends the top drive’s capabilities downhole.

      “When running casing, operators need to reduce costs by improving the efficiency and safety of landing casing,” said Papouras. ”Canrig’s SureGrip CRT delivers a process that is more cost effective, seamlessly integrates with your existing equipment and is less damaging to your casing. Running casing has never been more efficient or safer.”

    4. The LOC-400 drilling rig, known as
      Crusader 405, is the most advanced
      deep gas drilling rig currently available
      in Australia. Key features of Crusader
      405 include:
      • Small footprint – reducing site
      preparation requirements;
      • Highly mobile – modular and
      containerised design improves
      mobility and reduces intra and
      inter basin transportation costs;
      • Highly automated – automated rig
      floor reduces manual handling
      operations and improves crew health
      and safety;
      • Cyber drilling – cyber control
      station in air conditioned control
      room centralises all primary rig
      functions and provides a
      comfortable working environment;
      • Enhanced reliability – high degree
      of redundancy on power generation
      and control functions enhances the
      reliability and safety of the rig and
      the well;
      • Casing drilling – integrated casing
      drilling capabilities enable a
      step-change reduction in well
      construction time and cost;
      • Small crew – smaller rig crews
      (including removal of some third
      party well-site services) reduces
      the number of personnel at site
      thereby lowering overall well
      construction costs.
      These key features make Crusader
      405 attractive to operators seeking
      to conduct exploration and appraisal
      programmes in the more remote
      basins of Western Australia and the
      Northern Territory.


      Senior crew members will also
      undertake comprehensive training on
      a purpose-built LOC-400 simulator
      located in Houston, Texas.


      Crusader 405
      is contracted to Buru Energy Limited
      for an initial four well campaign in
      the Canning Basin. This will involve
      a 2600 kilometre journey to the
      Canning Basin.


      U.S. Shale-Oil Boom May Not Last as Fracking Wells Lack Staying Power

      Chesapeake Energy’s (CHK) Serenity 1-3H well near Oklahoma City came in as a gusher in 2009, pumping more than 1,200 barrels of oil a day and kicking off a rush to drill that extended into Kansas. Now the well produces less than 100 barrels a day, state records show. Serenity’s swift decline sheds light on a dirty secret of the oil boom: It may not last. Shale wells start strong and fade fast, and producers are drilling at a breakneck pace to hold output steady. In the fields, this incessant need to drill is known as the Red Queen, after the character in Through the Looking-Glass who tells Alice, “It takes all the running you can do, to keep in the same place.”

      The U.S. is producing 7.8 million barrels of oil a day, more than it has in a quarter-century. Crude from shale formations has cut reliance on imports and put the U.S. closer to energy independence than it’s been since 1989. The International Energy Agency predicted last year that the U.S. would overtake Saudi Arabia by 2020 as the world’s largest producer.

      Whether current production can hold up is the subject of debate. David Hughes, a geoscientist and president of Global Sustainability Research, has examined the life span of shale wells. “The Red Queen syndrome just gets worse and worse and worse,” he says. “The higher production goes, the more wells you need to offset the decline.”


      Global Sustainability’s Hughes estimates the U.S. needs to drill 6,000 new wells per year at a cost of $35 billion to maintain current production. His research also shows that the newest wells aren’t as productive as those drilled in the first years of the boom, a sign that oil companies have already tapped the best spots, making it that much harder to keep breaking records. Hughes has predicted that production will peak in 2017 and fall to 2012 levels within two years.

      “The hype about U.S. energy independence and ‘Saudi America’ is deafening if you look at the mainstream media,” Hughes says. “We need to have a much more in-depth and intelligent discussion about this.” On Oct. 7, Abdalla Salem el-Badri, OPEC’s secretary general, said at a conference in Kuwait that U.S. shale producers are “running out of sweet spots” and that output will peak in 2018.




    Tremendous Investment, Astute Project Management Needed for US Shale

    Oil and gas companies will require significant investment and astute project management to successfully execute large capital projects in North America and worldwide at a time when skilled workers are increasingly in short supply, according to a recent report by the Deloitte Center for Energy Solutions.

    Horizontal drilling and hydraulic fracturing and multi-stage hydraulic fracturing, along with advances in deepwater drilling technology and growing Canadian oil sands production, have unlocked previously inaccessible shale and deepwater resources and have bolstered North America onshore and offshore oil and gas production, Deloitte noted in “The Challenge of Renaissance: Managing an unprecedented wave of oil and gas investment”.

    Thanks to this production growth, the United States could become the world’s largest oil producer by early 2020, with peak production of 11 million barrels of oil per day (MMbopd) overtaking Saudi Arabia’s projected production of 10.5 MMbopd, according to International Energy Agency (IEA) estimates.

    Total U.S. natural gas production, including shale gas and tight oil, is expected to rise to 75 billion cubic feet per day (Bcf/d) in 2020 from production in 2005 of 49 Bcf/d. However, this production target will require sustained levels of onshore unconventional well activity across many North America shale basins over the next 20 to 30 years.

    According to IEA estimates, nearly $5 trillion in oil and gas investment will be needed in North America through 2035 to maintain current production and meet future demand growth.

    The U.S. Energy Information Administration estimates that over 630,000 new wells will be needed to bring available U.S. shale gas and tight oil resources into production.

    The number of wells substantially raises the capital requirements for resource development, and companies will need experienced project managers to efficiently bring these wells online. “One of the key challenges operators face to bring these wells online is their ability to acquire experienced project managers and skilled talent,” Deloitte said in the report.

    “Once online, these wells will ultimately require recompletion, artificial lift, and eventually, enhanced recovery to keep them producing.”

    The number of North America megaprojects with a capital investment value of $1 billion or greater also is expected to grow due to infrastructure development for deepwater, midstream and liquefied natural gas (LNG) export capacity, as well as expansion of U.S. petrochemical capacity and possible gas-to-liquids facilities.


    Surge in Megaproject Poses Challenges for Oil, Gas Industry

    The investment surge in North America reflects a growing trend worldwide of significant investment in oil and gas capital projects.

    Worldwide, the oil and gas industry will invest up to $700 billion over the next two to four years in capital projects, said Alan Richard, director at Deloitte Financial Advisory Services LLP, at the Deloitte Oil & Gas Conference in Houston in November. North American megaprojects will have to compete for investment dollars with international oil and gas megaprojects for large, technically complex oil and gas deepwater and frontier resources. The size and unprecedented number of concurrent megaprojects present a significant challenge for the oil and gas industry.

    Deloitte noted in the report that oil majors are undertaking this year three to five megaprojects at the same time, which account for 24 to 35 percent of their annual cash flows.

    Many of these projects are valued at $1 billion or greater, and the size of the projects means companies are outspending their cash flows.

    “Even some of the larger independents in 2013 are undertaking between two and four megaprojects concurrently, which account for between 12 and 115 percent of their annual cash flows,” Deloitte said.

    1. The LOC-400 drilling rig, known as
      Crusader 405, is the most advanced
      deep gas drilling rig currently available
      in Australia. Key features of Crusader
      405 include:
      • Small footprint – reducing site
      preparation requirements;
      • Highly mobile – modular and
      containerised design improves
      mobility and reduces intra and
      inter basin transportation costs;
      • Highly automated – automated rig
      floor reduces manual handling
      operations and improves crew health
      and safety;
      • Cyber drilling – cyber control
      station in air conditioned control
      room centralises all primary rig
      functions and provides a
      comfortable working environment;
      • Enhanced reliability – high degree
      of redundancy on power generation
      and control functions enhances the
      reliability and safety of the rig and
      the well;
      • Casing drilling – integrated casing
      drilling capabilities enable a
      step-change reduction in well
      construction time and cost;
      • Small crew – smaller rig crews
      (including removal of some third
      party well-site services) reduces
      the number of personnel at site
      thereby lowering overall well
      construction costs.
      These key features make Crusader
      405 attractive to operators seeking
      to conduct exploration and appraisal
      programmes in the more remote
      basins of Western Australia and the
      Northern Territory.


      Senior crew members will also
      undertake comprehensive training on
      a purpose-built LOC-400 simulator
      located in Houston, Texas.


      Crusader 405
      is contracted to Buru Energy Limited
      for an initial four well campaign in
      the Canning Basin. This will involve
      a 2600 kilometre journey to the
      Canning Basin.

    2. Sorry - BlogSpot gone silly again

  4. US Chamber Proposes Energy Reforms to Reflect New Energy Revolution

    The U.S. Chamber of Commerce’s Institute for 21st Century Energy revealed Wednesday its new Energy Works for U.S. platform, an update of its 2008 Blueprint for Securing America’s Energy Future, to reflect the current boom in unconventional oil and gas exploration in the United States

    . The plan, which includes 64 specific recommendations in nine key areas, will form the basis for the U.S. Chamber’s energy advocacy across the United States this year and in the future.

    These recommendations, which institute officials say will create millions of jobs and generate billions in revenue and trillions in private investment, and reduce U.S. public debt, include:

    Removing barriers to increased oil and gas production and fuel manufacturing

    Maintain coal’s role as a vital part of a diverse energy portfolio

    Expand nuclear energy use and commit to a nuclear waste solution

    Enhance the competitiveness of renewable sources of energy

    Promote 21st century energy efficiency and advanced technologies

    Modernize the permitting process for our nation’s energy infrastructure

    Protect our energy infrastructure from physical disruptions and cyber attacks

    Reform the regulatory process for balance, predictability and transparency

    Ensure a competitive energy workforce

    In its recommendations, the institute called for the Department of the Interior (DOI) to propose a new plan for the Outer Continental Shelf (OCS) that would open the eastern Gulf of Mexico, Atlantic and Pacific oceans to leasing and exploration and make significantly more onshore federal lands available for energy development.

    The U.S. Congress should also provide a 37.5 percent share of royalty revenues from all new production on the OCS to the states adjacent to development areas.

    The Bureau of Land Management (BLM) also should delay finalizing a proposed rule for hydraulic fracturing on federal lands until BLM works with state and industry officials to ensure a future rule addresses an existing regulatory gap, and not just to demonstrate its ability to regulate.

    Additionally, the U.S. Environmental Protection Agency should also end its efforts to regulate fracking by circumventing the rulemaking process and unlawfully issuing de facto regulations as guidance documents.

    - See more at:

  5. East coast demand to soar as oil giants hog gas for export projects

    OIL giants Shell and PetroChina have refused to offer new domestic gas supply from their vast Queensland coal-seam gas reserves, warehousing all the gas for an LNG export project that is yet to be approved due to high Australian construction costs.

    Amid concerns of a looming east coast gas shortage, it is understood the pair's Brisbane-based Arrow Energy joint venture has been approached by at least two domestic major east coast gas buyers but has been unwilling to take part in the tender process.


    BP Releases Energy Outlook 2035

    ........................The Outlook reveals that global energy consumption is expected to rise by 41 per cent from 2012 to 2035 – compared to 55 per cent over the last 23 years (52 per cent over the last twenty) and 30% over the last ten. Ninety five per cent of that growth in demand is expected to come from the emerging economies, while energy use in the advanced economies of North America, Europe and Asia as a group is expected to grow only very slowly – and begin to decline in the later years of the forecast period.

    Shares of the major fossil fuels are converging with oil, natural gas and coal each expected to make up around 27% of the total mix by 2035 and the remaining share coming from nuclear, hydroelectricity and renewables. Among fossil fuels, gas is growing fastest, increasingly being used as a cleaner alternative to coal for power generation as well as in other sectors.


    ..................While the fuel mix is evolving, fossil fuels will continue to be dominant. Oil, gas and coal are expected to converge on market shares of around 26-27% each by 2035, and non-fossil fuels – nuclear, hydro and renewables – on a share of around 5-7% each.


    Natural gas is expected to be the fastest growing of the fossil fuels – with demand rising at an average of 1.9% a year. Non-OECD countries are expected to generate 78% of demand growth. Industry and power generation account for the largest increments to demand by sector. LNG exports are expected to grow more than twice as fast as gas consumption, at an average of 3.9% per year, and accounting for 26% of the growth in global gas supply to 2035.

    Shale gas supplies are expected to meet 46% of the growth in gas demand and account for 21% of world gas and 68% of US gas production by 2035. North American shale gas production growth is expected to slow after 2020 and production from other regions to increase, but in 2035 North America is still expected to account for 71% of world shale gas production.


    PIRA: Asian Near Term Spot Demand Climate Looking Bearish

    PIRA Energy Group believes Asian near term spot demand climate is looking bearish. In the U.S., EIA changes its methodology for assessing associated gas production. In Europe, the peak period is upon us for seasonal gas demand over the next four weeks in a normal weather environment.

    Specifically, PIRA’s analysis of natural gas market fundamentals has revealed the following:

    Asian Near Term Spot Demand Climate Looking Bearish

    In Asia, near term spot demand is looking much more bearish over the balance of 1Q14 and beyond owing to the nascent return to normal operation of Korea’s 23 scandal-plagued nuclear power units. PIRA forecasts a 9-mmcm/d year-on-year average drop in gas demand for power generation through June. This is the equivalent of some 3 standard cargos per month, and the forecasted decrease is on the conservative side.

  6. Alaska Inks MoU with Largest Financier of LNG Projects

    Alaska ‘s Natural Resources Commissioner Dan Sullivan traveled to Japan this week to sign an agreement with one of the world’s largest financiers of LNG projects, speak at a global LNG conference, and engage in bilateral meetings with business and government officials.

    “The goal of this trip was to build upon the extensive engagement that the Parnell Administration has undertaken in the past few years to develop strong relationships with the world’s leading LNG buyers, their governments, and consumers,” Sullivan said.

    A key element of the trip was the signing of a Memorandum of Understanding (MOU) between the Department of Natural Resources and the Japan Bank for International Cooperation (JBIC). JBIC is a financial institution that plays a critical role in financing and securing Japan’s LNG imports. Sullivan and JBIC Managing Director Koichi Yajima signed the MOU in Tokyo.


    Dominion Appoints Two Officers to Cove Point LNG Team

    Dominion has named two officers to its Cove Point LNG Terminal team as it awaits necessary federal and state permits to begin construction of a facility to liquefy natural gas for export.


    FERC Releases Cameron LNG DEIS

    The Federal Energy Regulatory Commission (FERC) has prepared a draft environmental impact statement (DEIS) for the Cameron liquefaction project proposed by Cameron LNG and Cameron Interstate Pipeline.

    Cameron is requesting authorization to export 12 million tons of LNG per year from its terminal in Cameron and Calcasieu Parishes, Louisiana.

    The draft EIS assesses the potential environmental effects of the construction and operation of the Cameron Liquefaction Project in accordance with the requirements of the National Environmental Policy Act (NEPA).

    “The FERC staff concludes that approval of the proposed Project, with the mitigation measures recommended in the EIS, would ensure that impacts in the Project area would be avoided or minimized and would not be significant,” FERC said in a statement.

  7. Mozambique Minister Optimistic about Early LNG Deals with India

    In a meeting between Indian petroleum Minister, Veerappa Moily, and his Mozambique counterpart, Esperanca Bias, during Petrotech 2014, the Mozambique Minister for Mineral Resources showed optimism that the deals relating the LNG project will fructify soon, and the first LNG trains may start moving by 2019.

    This was one of the 11 bilateral meetings lined up during the Petrotech-2014, organized by ONGC.

    In the context of Indian companies ONGC Videsh Limited (OVL), OIL and BPCL having committed significant investments in this Mozambique LNG project, Moliy urged the Mozambique minister to expedite the consortium related issues and also fast-track the development of the discovered assets. The Indian companies hold 30 per cent of the project costing around 60 billion US dollars, the operatorship of which lies with Anadarco.


    India has finalized a demand of up to 8 trains of LNG, starting with 4 trains. The pricing aspects were also discussed between the Ministers during the bilateral meeting, which was represented by ONGC CMD, OVL MD and other corporate honchos.


    VINCI Scores Contract for Yamal LNG Storage Tanks

    Entrepose Contracting and VINCI Construction Grands Projets, both subsidiaries of VINCI, have been awarded a contract with JSC Yamal LNG, owned by NOVATEK (80 %) and TOTAL (20 %), to perform an engineering, procurement, supply, construction and commissioning of four cryogenic full-containment LNG storage tanks.

    Each LNG tank will be composed of a 9% nickel stainless steel interior container and a pre-stressed concrete external container, with a capacity of 160,000 cubic meters each.

    These tanks will form part of a 16.5 million tons per annum natural gas liquefaction project, which will utilise the resources of the South Tambey Gas Condensate Field situated in the Yamal Peninsula in the Russian Federation.


    Novatek Sells 20 Pct Share in Yamal LNG to CNODC


    Fluor, JGC Secure EPC Contract for Kitimat LNG

    Fluor Corporation announced that its joint venture with JGC was awarded an engineering, procurement and construction contract by Chevron Canada for the proposed Kitimat LNG project in Bish Cove, British Columbia, Canada.

    Chevron and Apache Canada each hold a 50 percent interest in the proposed project.


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