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Wednesday, March 30, 2011

Simulator CMG (Computer Modelling Group)

CMG (Computer Modelling Group) 2002.10 adalah program simulasi reservoir yang dibuat oleh Computer Modelling Group Ltd., Calgary, Canada. Program simulasi ini digunakan untuk melakukan simulasi reservoir. Program ini dapat digunakan untuk reservoir satu fasa, dua atau multi fasa dan juga dapat digunakan untuk membuat simulasi dengan dua dimensi atau tiga dimensi. CMG memiliki tiga jenis simulator yaitu IMEX, GEM, dan STARS
Simulator IMEX digunakan untuk kondisi isothermal, aliran simultan dari minyak, gas dan air yang berhubungan dengan viskositas, gaya gravitasi dan gaya kapiler. Istilah Black Oil melambangkan bahwa fasa hidrokarbon dipandang sebagai satu jenis cairan homogen dan tidak ditinjau dari komposisi kimianya. Komposisi fasa dianggap konstan walaupun kelarutan gas dalam minyak dan air diperhitungkan.
Simulator GEM digunakan untuk simulasi reservoir dengan jenis compositional dimana komposisi cairan atau gas diperhitungkan terhadap perubahan tekanan. Simulasi jenis ini banyak digunakan untuk studi perilaku reservoir yang berisi volatile-oil dan gas condensate.
Simulator STARS digunakan untuk studi aliran fluida, perpindahan panas maupun reaksi kimia. Simulasi ini juga banyak digunakan untuk studi injeksi uap panas (steam flood) dan pada proses perolehan minyak tahap lanjut dengan metode in-situ combution.
Pada simulator CMG juga terdapat simulator WINPROP yaitu equation of state untuk multifasa. WINPROP dapat digunakan untuk menganalisa kelakuan fasa fluida reservoir pada sistem gas dan juga minyak, dan digunakan untuk membuat properti komponen untuk simulator komposisional GEM, simulator Black Oil IMEX, dan simulator thermal STARS. WINPROP biasanya digunakan dalam pembuatan properti komponen yang akan digunakan sebagai data input pada simulator komposisional GEM.
Secara garis besar program simulasi pada CMG terdiri dari tujuh bagian utama, yaitu : Technologies Launcher, ModelBuilder, GridBuilder, Simulator (IMEX, GEM, STARS), Results Graph dan Results 3D. Berikut ini akan dijelaskan secara ringkas tentang fungsi dari masing-masing bagian simulator.

selanjutnya download disini...

Tuesday, March 29, 2011

Pencegahan Korosi dan Scale Pada Proses Produksi Minyak Bumi



Minyak bumi adalah suatu senyawa hidrokarbon yang terdiri dari karbon (83-87%), hidrogen (11-14%), nitrogen (0,2-0,5%), sulfur (0-6%), dan oksigen (0-3,5%). Proses produksi minyak dari formasi tersebut mempunyai kandungan air yang sangat besar, bahkan bisa mencapai kadar lebih dari 90%. Selain air, juga terdapat komponen-komponen lain berupa pasir, garam-garam mineral, aspal, gas CO2 dan H2S. Komponen-komponen yang terbawa bersama minyak ini menimbulkan permasalahan tersendiri pada proses produksi minyak bumi.

Air yang terdapat dalam jumlah besar sebagian dapat menimbulkan emulsi dengan minyak akibat adanya emulsifying agent dan pengadukan. Selain itu hal yang tak kalah penting ialah adanya gas CO2 dan H2S yang dapat menyebabkan korosi dan dapat mengakibatkan kerusakan pada casing, tubing, sistem perpipaan dan surface fasilities.
Sedangkan ion-ion yang larut dalam air seperti kalsium, karbonat, dan sulfat dapat membentuk kerak (scale). Scale dapat menyebabkan pressure drop karena terjadinya penyempitan pada sistem perpipaan, tubing, dan casing sehingga dapat menurunkan produksi. 

Korosi adalah suatu proses elektrokimia dimana atom-atom akan bereaksi dengan zat asam dan membentuk ion-ion positif (kation). Hal ini akan menyebabkan timbulnya aliran-aliran elektron dari suatu tempat ke tempat yang lain pada permukaan metal.
Istilah scale dipergunakan secara luas untuk deposit keras yang terbentuk pada peralatan yang kontak atau berada dalam air.

Dalam operasi produksi minyak bumi sering ditemui mineral scale seperti CaSO4, FeCO3, CaCO3, dan MgSO4. Senyawa-senyawa ini dapat larut dalam air.
Scale CaCO3 paling sering ditemui pada operasi produksi minyak bumi. Akibat dari pembentukan scale pada operasi produksi minyak bumi adalah berkurangnya produktivitas sumur akibat tersumbatnya penorasi, pompa, valve, dan fitting serta aliran. Penyebab terbentuknya deposit scale adalah terdapatnya senyawa-senyawa tersebut dalam air dengan jumlah yang melebihi kelarutannya pada keadaan kesetimbangan. Faktor utama yang berpengaruh besar pada kelarutan senyawa-senyawa pembentuk scale ini adalah kondisi fisik (tekanan, temperatur, konsentrasi ion-ion lain dan gas terlarut).
 

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Problem Utama Directional Drilling Serta Penanggulangannya


Sasaran pemboran horizontal adalah membuat lubang horizontal dengan pertambahan sudut tertentu dari titik belok pertama. Masalah utama timbul karena adanya bagian pertambahan sudut dari bagian horizontal, yang berhubungan dengan efek gravitasi, friksi dan pengendapan partikel (cutting) pemboran. Masalah-masalah dalam pemboran horizontal diantaranya :
1)   Problem terhadap rangkaian, yaitu torsi, drag, buckling dan tension.
2) Problem lumpur dan hidrolika, yaitu pengendapan cutting dan gugurnya dinding lubang sumur.
3)   Kecenderungan penyimpangan sudut.
4)   Rendahnya laju penembusan.
5)   Differential pipe sticking.

Perencanaan rangkaian pipa bor yang akan dipergunakan harus mempertimbangkan beban drag, beban torsi, buckling, dan tension. Dalam hal ini yang akan kita bicarakan adalah masalah kekuatan dan beban dari rangkaian pipa bor.


Pembelokan lubang bor dalam pemboran horizontal dilakukan dengan besar sudut kemiringan dan arah tertentu sesuai dengan type pemboran horizontal yang dipilih. Pembelokan lubang bor dimulai dari KOP hingga target arah yang diinginkan (EOC/End Of Curvature), pembelokan arah diusahakan agar tidak mengalami penyimpangan terhadap rencana/ target, yang saat ini dikontrol melalui peralatan Measurement While Drilling (MWD).




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Wednesday, March 23, 2011

Best Practice in Understanding and Managing Lost Circulation Challenges




Lost circulation has been one of the major challenges that cause much nonproductive rig time each year. With recent advances, curing lost circulation has migrated from “plugging a hole” to “borehole strengthening” that involves more rock mechanics and engineering. These advances have improved the industry’s understanding of mechanisms that can eventually be translated into better solutions and higher success rates. This paper provides a review of the current status of the approaches and a further understanding on some controversial points.
There are two general approaches to lost circulation solutions : proactive and corrective, based on whether lost circulation has occurred or not at the time of the application. This paper provides a review of both approaches and discusses the pros and cons related to different methods—from an understanding of rock mechanics and operational challenges.
Introduction
Lost circulation (LC) is defined as the loss of whole mud (e.g.,solids and liquids) into the formation (Messenger 1981). There are two distinguishable categories of losses derived from its leakoff flowpath: Natural and Artificial. Natural lost circulation occurs when drilling operations penetrate formations with large pores, vugs, leaky faults, natural fractures, etc. Artificial lost circulation occurs when pressure exerted at the wellbore exceeds the maximum the wellbore can contain. In this case, hydraulic fractures are
generally created.
During the last century, lost circulation presented great challenges to the petroleum industry, causing significant expenditure of cash and time in fighting the problem. Trouble costs have continued into this century for mud losses, wasted rig time, and ineffective remediation materials and techniques. In worst cases, these losses can also include costs for lost holes, sidetracks, bypassed reserves, abandoned wells, relief wells, and lost petroleum reserves.
The risk of drilling wells in areas known to contain these problematic formations is a key factor in decisions to approve or cancel exploration and development projects.

selanjutnya download disini file PDF...



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Flow Regulator



Reservoir memberikan tekanan fluida dengan mengendalikan tenaga untuk mendorong fluida menuju lubang bor, dalam aliran sumur natural, mengimbangi tubing produksi ke permukaan. Untuk memaksimalkan kapasitas produksi dari sumur terpisah, memastikan dengan tepat ada pembatasan minimal di flowline. Bagaimanapun, dalam kasus yang serupa, dari sistem kapasitas produksi akan terus-menerus menyesuaikan dalam line dengan gangguan aliran lainnya atau ketidakstabilan dalam sumur. Jadi, sebagian besar sumur produksi menggunakan choke atau pembatasan flowline downstream dari kepala sumur ke tekanan balik dari sumur.

Pelaksanaan menutup tekanan balik dari flowline ke kepala sumur mungkin perlu untuk beberapa alasan berikut :
·      Mempertahankan aliran stabil/keadaan tekanan downstream dari choke.
·      Mengendalikan drawdown di sumur dan karena itu kejadian terbatas dari cusping gas atau water coning sampai lubang bor atau kegagalan sekitar formasi di lubang bor.
·      Mengurangi turunnya fluktuasi di sumur yang berubah-ubah oleh tekanan balik dari sistem yang diterapkan.
·      Memisahkan fluktuasi tekanan dari sumur yang di buat dalam sistem proses, gathering dan transportasi.


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Tuesday, March 22, 2011

Drill String Component


A drill string on an drilling rig is a column, or string, of drill pipe that transmits drilling fluid (via the mud pumps) and rotational power (via the kelly drive or top drive) to the drill bit. The term is loosely applied as the assembled collection of the drill pipe, drill collars, tools and drill bit. The drill string is hollow so that drilling fluid can be pumped down through it and circulated back up the annulus (void between the drill string and the formation).
Drill string components
The drill string is typically made up of 4 sections:
  • Bottom hole assembly (BHA)
  • Transition pipe, which is often heavyweight drill pipe (HWDP)
  • Drill pipe
  • Drill stem subs
Each section is made up of several components, joined together using special threaded connections known as tool joints.
Bottom hole assembly (BHA)
The BHA is made up of a drill bit which is used to break-up the rock formations, drill collars which are heavy, thick-walled tubulars used to apply weight to the drill bit, and stabilizers which keep the drilling assembly centered in the hole. The BHA may also contain other components such as a downhole motor, Rotary Steerable System, measurement while drilling (MWD), and logging while drilling (LWD) tools.
Transition pipe
Heavyweight drill pipe (HWDP) is used to make the transition between the drill collars and drill pipe. The function of the HWDP is to provide a flexible transition between the drill collars and the drill pipe. This helps to reduce the number of fatigue failures seen directly above the BHA. A secondary use of HWDP is to add additional weight to the drill bit.
Drill pipe
Drill pipe makes up the majority of a drill string. A drill string is typically about 15,000 feet (4.6 km) long for an oil or gas well vertically drilled onshore in the United States and may extend to over 30,000 feet (9.1 km) for an offshore deviated (non-vertical) well.
Drill stem subs
Drill stem subs are used to connect drill string elements.
Running a drill string
Most components in a drill string are manufactured in 31 foot lengths (range 2) although they can also be manufactured in 45 foot lengths (range 3). Each 31 foot component is referred to as a joint. Typically 2, 3 or 4 joints are joined together to make a stand.
Pulling the drill string out of or running the drill string into the hole is referred to as tripping. Drill pipe, HWDP and collars are typically tripped in stands to save time.
Stuck drill string
A stuck drill string can be caused by many situations.
  • Packing-off due to cuttings settling back into the wellbore when circulation is stopped.
  • Differentially when the formation pressure is too low, the wellbore pressure is too high or both, essentially pushing the pipe onto the wall of the wellbore.
  • Keyhole sticking occurs mechanically as a result of pulling up into doglegs when tripping.
  • Adhesion due to not moving it for a significant amount of time.
Once the tubular member is stuck, there are many techniques used to extract the pipe. The tools and expertise are normally supplied by an oilfield service company. Two popular tools and techniques are the oilfield jar and the surface resonant vibrator. Below is a history of these tools along with how they operate.
History of Jars
The mechanical success of cable tool drilling has greatly depended on a device called jars, invented by a spring pole driller, William Morris, in the salt well days of the 1830's. Little is known about Morris except for his invention and that he listed Kanawha County (now in West Virginia) as his address. Morris patented this unique tool in 1841 for artesian well drilling. Later, using jars, the cable tool system was able to efficiently meet the demands of drilling wells for oil.
The jars were improved over time, especially at the hands of the oil drillers, and reached the most useful and workable design by the 1870's, due to another patent in 1868 by Edward Guillod of Titusville, Pennsylvania, which addressed the use of steel on the jars' surfaces that were subject to the greatest wear. Many years later, in the 1930's, very strong steel alloy jars were made.
A set of jars consisted of two interlocking links which could telescope. In 1880 they had a play of about 13 inches such that the upper link could be lifted 13 inches before the lower link was engaged. This engagement occurred when the cross-heads came together.Today, there are two primary types, hydraulic and mechanical jars. While their respective designs are quite different, their operation is similar. Energy is stored in the drillstring and suddenly released by the jar when it fires. Jars can be designed to strike up, down, or both. In the case of jarring up above a stuck bottomhole assembly, the driller slowly pulls up on the drillstring but the BHA does not move. Since the top of the drillstring is moving up, this means that the drillstring itself is stretching and storing energy. When the jars reach their firing point, they suddenly allow one section of the jar to move axially relative to a second, being pulled up rapidly in much the same way that one end of a stretched spring moves when released. After a few inches of movement, this moving section slams into a steel shoulder, imparting an impact load.
In addition to the mechanical and hydraulic versions, jars are classified as drilling jars or fishing jars. The operation of the two types is similar, and both deliver approximately the same impact blow, but the drilling jar is built such that it can better withstand the rotary and vibrational loading associated with drilling. Jars are designed to be reset by simple string manipulation and are capable of repeated operation or firing before being recovered from the well. Jarring effectiveness is determined by how rapidly you can impact weight into the jars. When jarring without a compounder or accelerator you rely only on pipe stretch to lift the drill collars upwards after the jar releases to create the upwards impact in the jar. This accelerated upward movement will often be reduced by the friction of the working string along the sides of the well bore, reducing the speed of upwards movement of the drill collars which impact into the jar. At shallow depths jar impact is not achieved because of lack of pipe stretch in the working string.
When pipe stretch alone cannot provide enough energy to free a fish, compounders or accelerators are used. Compounders or accelerators are energized when you over pull on the working string and compress a compressible fluid through a few feet of stroke distance and at the same time activate the fishing jar. When the fishing jar releases the stored energy in the compounder/acclerator lifts the drill collars upwards at a high rate of speed creating a high impact in the jar.
System Dynamics of Jars
Jars rely on the principle of stretching a pipe to build elastic potential energy such that when the jar trips it relies on the masses of the drill pipe and collars to gain velocity and subsequently strike the anvil section of jar. This impact results in a force, or blow, which is converted into energy.
History of Surface Resonant Vibrators
The concept of using vibration to free stuck objects from a wellbore originated in the 1940's, and probably stemmed from the 1930's use of vibration to drive piling in the Soviet Union. The early use of vibration for driving and extracting piles was confined to low frequency operation; that is, frequencies less than the fundamental resonant frequency of the system and consequently, although effective, the process was only an improvement on conventional hammer equipment. Early patents and teaching attempted to explain the process and mechanism involved, but lacked a certain degree of sophistication. In 1961, A. G. Bodine obtained United States Patent 2,972,3801[1] that was to become the "mother patent" for oil field tubular extraction using sonic techniques. Mr. Bodine introduced the concept of resonant vibration that effectively eliminated the reactance portion of mechanical impedance, thus leading to the means of efficient sonic power transmission. Subsequently, Mr. Bodine obtained additional patents directed to more focused applications of the technology.
The first published work on this technique was outlined in a 1987 Society of Petroleum Engineers (SPE) paper presented at the International Association of Drilling Contractors in Dallas, Texas [2] detailing the nature of the work and the operational results that were achieved. The cited work involving liner, tubing, and drill pipe extraction and was very successful. Reference Two[3] presented at the Society of Petroleum Engineers Annual Technical Conference and Exhibition in Aneheim, Ca, November, 2007 explains the resonant vibration theory in more detail as well as its use in extracting long lengths of mud stuck tubulars. The Figure 1 below shows the components of a typical surface resonant vibrator.
System Dynamics of Surface Resonant Vibrators
Surface Resonant Vibrators rely on the principle of counter rotating eccentric weights to impart a sinusoidal harmonic motion from the surface into the work string at the surface. Reference Three (above) provides a full explanation of this technology. The frequency of rotation, and hence vibration of the pipe string, is tuned to the resonant frequency of the system. The system is defined as the surface resonant vibrator, pipe string, fish and retaining media. The resultant forces imparted to the fish is based on the following logic:
  • The delivery forces from the surface are a result of the static overpull force from the rig, plus the dynamic force component of the rotating eccentric weights
  • Depending on the static overpull force component, the resultant force at the fish can be either tension or compression due to the sinusoidal force wave component from the oscillator
  • Initially during startup of a vibrator, some force is necessary to lift and lower the entire load mass of the system. When the vibrator tunes to the resonant frequency of the system, the reactive load impedance cancels out to zero by virtue of the inductance reactance (mass of the system) equalling the compliance or stiffness reactance (elasticity of the tubular). The remaining impedance of the system, known as the resistive load impedance, is what is retaining the stuck pipe.
  • During resonant vibration, a longitudinal sine wave travels down the pipe to the fish with an attendant pipe mass that is equal to a quarter wavelength of the resonant vibrating frequency.
  • A phenomenon known as fluidization of soil grains takes place during resonant vibration whereby the granular material constraining the stuck pipe is transformed into a fluidic state that offers little resistance to movement of bodies through the media. In effect, it takes on the characteristics and properties of a liquid.
  • During pipe vibration, Dilation and Contraction of the pipe body, known as Poisson’s ratio, takes place such that that when the stuck pipe is subjected to axial strain due to stretching, its diameter will contract. Similarly, when the length of pipe is compressed, its diameter will expand. Since a length of pipe undergoing vibration experiences alternate tensile and compressive forces as waves along its longitudinal axis (and therefore longitudinal strains), its diameter will expand and contract in unison with the applied tensile and compressive waves. This means that for alternate moments during a vibration cycle the pipe may actually be physically free of its bond.
  •  
re-post : http://top-topics.thefullwiki.org/Petroleum_geology

    Blowout (well drilling)




    A blowout is the uncontrolled release of formation fluid from a well, typically for petroleum production, after pressure control systems have failed.[1]
    Cause of blowouts
    A blowout is caused when a combination of well control systems fail – primarily drilling mud hydrostatics and blow-out preventers (BOPs) – and formation pore pressure is greater than the wellbore pressure at depth.
    When such an incident occurs, formation fluids begin to flow into the wellbore and up the annulus and/or inside the drill pipe, and is commonly called a kick. If the well is not shut in, a kick can quickly escalate into a blowout when the formation fluids reach the surface, especially when the fluid is a gas which rapidly expands as it flows up the wellbore and accelerates to near the speed of sound. Blowouts can cause significant damage to drilling rigs, injuries or fatalities to rig personnel, and significant damage to the environment if hydrocarbons are spilled.
    Prior to the development of blow-out preventers, blowouts were common during drilling operations, and were referred to as gushers.
    Formation kick
    A kick can be the result of improper mud density control, an unexpected overpressured (shallow) gas pocket, or may be a result of the loss of drilling fluids to a formation called a thief zone. If the well is a development well (and not a wildcat), these thief zones should already be known to the driller and the proper loss control materials would have been used. However, unexpected fluid losses can occur if a formation is fractured somewhere in the open-hole section, causing rapid loss of hydrostatic pressure and possibly allowing flow of formation fluids into the wellbore. (See "Underground Blowout" discussion in next section.) Shallow overpressured gas pockets are generally unpredictable and usually cause the more violent kicks because of rapid gas expansion almost immediately.

    The primary means of detecting a kick is a relative change in the circulation rate back up to the surface into the mud pits. The drilling crew or mud engineer keeps track of the level in the mud pits, and a increase in this level would indicate that a higher pressure zone has been encountered at the bit. Conversely, a drop in this level would indicate lost circulation to a formation (which might allow influx of formation fluids from other zones if the hydrostatic head at depth is reduced from less than a full column of mud). The rate of mud returns also can be closely monitored to match the rate that it is being pumped down the drill pipe. If the rate of returns is slower than expected, it means that a certain amount of the mud is being lost to a thief zone, but this is not necessarily yet a kick (and may never become one). In the case of a higher pressure zone, an increase in mud returns would be noticed as the formation influx pushes the drilling mud toward the surface at a higher rate.

    The first response to detecting a kick would be to isolate the wellbore from the surface by activating the BOPs and closing in the well. Then the drilling crew would attempt to circulate in a heavier kill fluid to increase the hydrostatic pressure (sometimes with the assistance of a well control company). In the process, the influx fluids will be slowly circulated out in a controlled manner, taking care not to allow any gas to accelerate up the wellbore too quickly by controlling casing pressure with chokes on a predetermined schedule. In a simple kill, once the kill-weight mud has reached the bit the casing pressure is manipulated to keep drill pipe pressure constant (assuming a constant pumping rate); this will ensure holding a constant adequate bottomhole pressure. The casing pressure will gradually increase as the contaminant slug approaches the surface if the influx is gas, which will be expanding as it moves up the annulus and overall pressure at its depth is gradually decreasing. This effect will be minor if the influx fluid is mainly salt water. And with an oil-based drilling fluid it can be masked in the early stages of controlling a kick because gas influx may dissolve into the oil under pressure at depth, only to come out of solution and expand rather rapidly as the influx nears the surface. Once all the contaminant has been circulated out, the casing pressure should have reached zero.

    Sometimes, however, companies drill underbalanced for better, faster penetration rates and thus they "drill for kicks" as it is economically sounder to take time to kill a kick than to drill overbalanced (which causes slower penetration rates). Under these circumstances, always with qualified personnel on the rig, calling in a "well control" specialist may not be necessary.
    Blowout
    When all the controls described above fail, a blowout occurs. Blowouts are dangerous since they can eject the drill string out of the well, and the force of the escaping fluid can be strong enough to damage the drilling rig. Blowouts often ignite due to the presence of an ignition source, from sparks from rocks being ejected along with flammable fluids, or simply from heat generated by friction. (Rarely the flowing gas will contain poisonous hydrogen sulfide and the oil operator might decide to ignite the stream to convert this to less hazardous substances.) A well control company will then need to extinguish the well fire and/or cap the well, and replace the casing head and hangars.
    Sometimes, blowouts can be so forceful that they cannot be directly brought under control from the surface, particularly if there is so much energy in the flowing zone that it does not deplete significantly over the course of a blowout. In such cases, other wells (called relief wells) may be drilled to intersect the well or pocket, in order to allow kill-weight fluids to be introduced at depth. (Contrary to what might be inferred from the term, such wells generally are not used to help relieve pressure using multiple outlets from the blowout zone.)
    An "underground blowout" is a special situation where fluids from high pressure zones flow uncontrolled to lower pressure zones within the open-hole portion of the wellbore. Usually they come up the wellbore to shallower formations (typically near the last casing shoe) that have been fractured from the overall effect of hydrostatic mud head plus casing pressure imposed at the time of the initial kick. Underground blowouts can be very difficult to bring under control although there is no outward flow at the drill site itself. However, if left unchecked, in time the fluids may find their way to the surface elsewhere in the vicinity (possibly "cratering" the rig), or may pressurize other zones, leading to problems when drilling subsequent wells.

    re post : http://www.thefullwiki.org/Blowout_%28well_drilling%29

    Oil Sand




    Oil sands, also known as tar sands, or extra heavy oil, are a type of bitumen deposit. The sands are naturally occurring mixtures of sand or clay, water and an extremely denseviscous form of petroleum called bitumen. They are found in large amounts in many countries throughout the world, but are found in extremely large quantities in Canada and Venezuela. and
    Oil sands reserves have only recently been considered to be part of the world's oil reserves, as higher oil prices and new technology enable them to be profitably extracted and upgraded to usable products. Oil sands are often referred to as unconventional oil or crude bitumen, in order to distinguish the bitumen extracted from oil sands from the free-flowing hydrocarbon mixtures known as crude oil traditionally produced from oil wells.
    Making liquid fuels from tar sands requires huge amounts of energy for steam injection and refining. This process generates two to four times the amount of greenhouse gases per barrel of final product as the production of conventional oil
    History
    The exploitation of bituminous sands dates back to paleolithic times. The earliest known use of bitumen was by Neanderthals, some 40,000 years ago. Bitumen has been found adhering to stone tools used by Neanderthals at sites in Syria. After the arrival of Homo sapiens, humans used bitumen for construction of buildings and water proofing of reed boats, among other uses. In ancient Egypt, the use of bitumen was important in creating Egyptian mummies - in fact the word mummy is derived from the Arab word ‘mÅ«miyyah’, which means bitumen.
    In ancient times, bitumen was primarily a Mesopotamian commodity used by the Sumerians and Babylonians, although it was also found in the Levant and Persia. Along the Tigris and Euphrates rivers, the area was littered with hundreds of pure bitumen seepages. The Mesopotamians used the bitumen for waterproofing boats and buildings. In North America, the early European fur traders found Canadian First Nations using bitumen from the vast Athabasca oil sands to waterproof their birch bark canoes.[4] In Europe, they were extensively mined near the European city of Pechelbronn, where the vapor separation process was in use in 1742.
    The name tar sands was applied to bituminous sands in the late 19th and early 20th century. People who saw the bituminous sands during this period were familiar with the large amounts of tar residue produced in urban areas as a by-product of the manufacture of coal gas for urban heating and lighting.[6] The word tar to describe these natural bitumen deposits is really a misnomer, since, chemically speaking, tar is a man-made substance produced by the destructive distillation of organic material, usually coal. Since then, coal gas has almost completely been replaced by natural gas as a fuel, and coal tar as a material for paving roads has been replaced by the petroleum product asphalt. Naturally occurring bitumen is chemically more similar to asphalt than to tar, and oil sands (or oilsands) is more commonly used in the producing areas than tar sands because synthetic oil is what is manufactured from the bitumen.
    Oil sands are now considered a serious alternative to conventional crude oil, since crude oil is becoming scarce. Oil sands and oil shale have the potential to generate oil for centuries.
    Reserves
    Many countries in the world have large deposits of oil sands, including the United States, Russia, and various countries in the Middle East. However, the world's largest deposits occur in two countries: Canada and Venezuela, each of which has oil sand reserves approximately equal to the world's total reserves of conventional crude oil. As a result of the development of Canadian oil sands reserves, 44% of Canadian oil production in 2007 was from oil sands, with an additional 18% being heavy crude oil, while light oil and condensate had declined to 38% of the total.[9] Because growth of oil sands production has exceeded declines in conventional crude oil production, Canada has become the largest supplier of oil and refined products to the United States, ahead of Saudi Arabia and Mexico. Venezuelan production is also very large, but due to political problems within its national oil company,[10] estimates of its production data are not reliable. Outside analysts believe Venezuela's oil production has declined in recent years,[11] though there is much debate on whether this decline is depletion-related or not.
    Oil sands may represent as much as two-thirds of the world's total petroleum resource, with at least 1.7 trillion barrels (270×109 m3) in the Canadian Athabasca Oil Sands.^
    In October 2009, the USGS updated the Orinoco tar sands (Venezuela) mean estimated recoverable value to 513 billion barrels (8.16×1010 m3), making it "one of the world's largest recoverable" oil deposits.[12]
    Between them, the Canadian and Venezuelan deposits contain about 3.6 trillion barrels (570×109 m3) of oil in place, compared to 1.75 trillion barrels (280×109 m3) of conventional oil worldwide, most of it in Saudi Arabia and other Middle-Eastern countries.^^
    Production
    Bituminous sands are a major source of unconventional oil. Conventional crude oil is normally extracted from the ground by drilling oil wells into a petroleum reservoir, allowing oil to flow into them under natural reservoir pressures, although artificial lift and techniques such as water flooding and gas injection are usually required to maintain production as reservoir pressure drops toward the end of a field's life. Because extra-heavy oil and bitumen flow very slowly, if at all, toward producing wells under normal reservoir conditions, the sands must be extracted by strip mining or the oil made to flow into wells by in situ techniques which reduce the viscosity by injecting steam, solvents, and/or hot air into the sands. These processes can use more water and require larger amounts of energy than conventional oil extraction, although many conventional oil fields also require large amounts of water and energy to achieve good rates of production.
    This is because heavy crude feedstock needs pre-processing before it is fit for conventional refineries. This pre-processing is called 'upgrading', the key components of which are as follows:
    1. removal of water, sand, physical waste and lighter products
    2. catalytic purification by hydrodemetallisation (HDM), hydrodesulfurization (HDS) and hydrodenitrogenation (HDN)
    3. hydrogenation through carbon rejection or catalytic hydrocracking (HCR)
    As carbon rejection is very inefficient and wasteful in most cases, catalytic hydrocracking is preferred in most cases. All these processes take large amounts of energy and water, while emitting carbon dioxide.
    Catalytic purification and hydrocracking are together known as hydroprocessing. The big challenge in hydroprocessing is to deal with the impurities found in heavy crude, as they poison the catalysts over time. Many efforts have been made to deal with this to ensure high activity and long life of a catalyst. Catalyst materials and pore size distributions are key parameters that need to be optimized to deal with these challenge and this varies from place to place depending on the kind of feedstock present.[13]
    At the present time, only Canada has a large-scale commercial oil sands industry, though a small amount of oil from oil sands is produced in Venezuela. Because of increasing oil sands production Canada has become the largest single supplier of oil and products to the United States. Oil sands now are the source of almost half of Canada's oil production, although due to the 2008 economic downturn work on new projects has been deferred, while Venezuelan production has been declining in recent years. Oil is not produced from oil sands on a significant level in other countries.[14]
    Transportation and refining
    The heavy crude oil or crude bitumen extracted from oil sands is a viscous, solid or semisolid form that does not easily flow at normal oil pipeline temperatures, making it difficult to transport to market and expensive to process into gasoline, diesel fuel, and other products. Despite the difficulty and cost, oil sands are now being mined by energy companies on a vast scale to extract the bitumen, which is then converted into synthetic oilpetroleum products by specialized refineries.[15] (syncrude) by bitumen upgraders, or refined directly into
    As oil source, by location
    Canada
    Canada is the largest supplier of crude oil and refined products to the United States, supplying about 20% of total U.S. imports, and exports more oil and products to the U.S. than it consumes itself.[16] In 2006, bitumen production averaged 1.25 million barrels per day (200,000 m3/d) through 81 oil sands projects, representing 47% of total Canadian petroleum production. This proportion is expected to increase in coming decades as bitumen production grows while conventional oil production declines.[1]
    Most of the oil sands of Canada are located in three major deposits in northern Alberta. These are the Athabasca-Wabiskaw oil sands of north northeastern Alberta, the Cold LakePeace River deposits of northwestern Alberta. Between them they cover over 140,000 square kilometres (54,000 sq mi) - an area larger than England - and hold proven reserves of 1.75 trillion barrels (280×109 m3) of bitumen in place. About 10% of this, or 173 billion barrels (27.5×109 m3), is estimated by the government of Alberta to be recoverable at current prices using current technology, which amounts to 97% of Canadian oil reserves and 75% of total North American petroleum reserves.[1] The Cold Lake deposits extend across the Alberta's eastern border into Saskatchewan. In addition to the Alberta oil sands, there are major oil sands deposits on Melville Island in the Canadian Arctic islands which are unlikely to see commercial production in the foreseeable future. deposits of east northeastern Alberta, and the ^^
    The Alberta oil sand deposits contain at least 85% of the world's reserves of natural bitumen (representing 40% of the combined crude bitumen and extra-heavy crude oil reserves in the world), but are the only bitumen deposits concentrated enough to be economically recoverable for conversion to synthetic crude oil at current prices. The largest bitumen deposit, containing about 80% of the Alberta total, and the only one suitable for surface mining, is the Athabasca Oil Sands along the Athabasca River. The mineable area (as defined by the Alberta government) includes 37 townships covering about 3,400 square kilometres (1,300 sq mi) near Fort McMurray. The smaller Cold Lake deposits are important because some of the oil is fluid enough to be extracted by conventional methods. All three Alberta areas are suitable for production using in-situ methods such as cyclic steam stimulation (CSS) and steam assisted gravity drainage (SAGD).
    The Alberta oil sands have been in commercial production since the original Great Canadian Oil Sands (now Suncor) mine began operation in 1967. A second mine, operated by the Syncrude consortium, began operation in 1978 and is the biggest mine of any type in the world. The third mine in the Athabasca Oil Sands, the Albian Sands consortium of Shell Canada, Chevron Corporation and Western Oil Sands Inc. [purchased by Marathon Oil Corporation in 2007] began operation in 2003. Petro-Canada was also developing a $33 billion Fort Hills Project, in partnership with UTS Energy Corporation and Teck Cominco, which lost momentum after the 2009 merger of Petro-Canada into Suncor. If approved, Fort Hills Oilsands upgraders were slated to begin output in 4-5 years.
    With the development of new in-situ production techniques such as steam assisted gravity drainage, and with the oil price increases since 2003, there were several dozen companies planning nearly 100 oil sands projects in Canada, totaling nearly $100 billion in capital investment. With 2007 crude oil prices significantly in excess of the current average cost of production of $28 per barrel of bitumen,[17] all of these projects appear likely to be profitable. However, bitumen production costs are rising rapidly, with production cost increases of 55% since 2005, due to shortages of labor and materials.[17]
    The minority Conservative government of Canada, pressured to do more on the environment, announced in its 2007 budget that it would phase out some oil sands tax incentives over coming years. The provision allowing accelerated write-off of oil sands investments will be phased out gradually so projects that had relied on them can proceed. For new projects the provision will be phased out between 2011 and 2015.[18]
    With oil prices setting new highs in 2007, tax incentives were no longer necessary to encourage oil sands projects in Canada. In July of that year Royal Dutch Shell released its 2006 annual report and announced that its Canadian oil sands unit made an after tax profit of $21.75 per barrel, nearly double its worldwide profit of $12.41 per barrel on conventional crude oil.[19] A few days later Shell announced it had filed for regulatory approval to build a $27 billion oil sands refinery in Alberta, one of $38 billion in new oil sands projects announced that week.[20]
    Venezuela
    Located in eastern Venezuela, north of the Orinoco River, the Orinoco oil belt vies with the Canadian oil sand for largest known accumulation of bitumen in the world. Venezuela prefers to call its oil sands "extra heavy oil", and although the distinction is somewhat academic, the extra heavy crude oil deposit of the Orinoco Belt represent nearly 90% of the known global reserves of extra heavy crude oil, and nearly 45% of the combined crude bitumen and extra-heavy crude oil reserves in the world.
    Bitumen and extra-heavy oil are closely related types of petroleum, differing only in the degree by which they have been degraded from the original crude oil by bacteria and erosion. The Venezuelan deposits are less degraded than the Canadian deposits and are at a higher temperature (over 50 degrees Celsius versus freezing for northern Canada), making them easier to extract by conventional techniques.
    Although Venezuela's extra-heavy oil is easier to produce than Canada's bitumen, it is still too heavy to transport by pipeline or process in normal refineries. Lacking access to first-world capital and technological prowess, Venezuela has not been able to design and build the kind of upgraders and heavy oil refineries that Canada has. In the early 1980s the state oil company, PDVSA, developed a method of using the extra-heavy oil resources by emulsifying it with water (70% extra-heavy oil, 30% water) to allow it to flow in pipelines. The resulting product, called Orimulsion, can be burned in boilers as a replacement for coal and heavy fuel oil with only minor modifications. Unfortunately, the fuel’s high sulphur content and emission of particulates make it difficult to meet increasingly strict international environmental regulations.
    Further development of the Venezuelan resources has been impeded by political unrest. Venezuela is less politically stable than a country such as Canada, and a two-month strike in 2002-2003 by employees of the state oil company was followed by the dismissal of most of its staff. As tensions resolved, strike leaders pointed to the reduction in Venezuela's domestic crude output as an argument that Venezuela's oil production had fallen. However, Venezuela's oil sands crude production, which sometimes wasn't counted in its total, has increased from 125,000 bbl/d (19,900 m3/d) to 500,000 bbl/d (79,000 m3/d) between 2001 and 2006 (Venezuela's figures; IAEA says 300,000 bpd).[21][22][23]
    USA
    In the United States, oil sands resources are primarily concentrated in Eastern Utah. With a total of 32 billion barrels of oil(known and potential) in eight major deposits[24] in the Utah counties of Carbon, Garfield, Grand, Uintah and Wayne. Currently, oil is not produced from oil sands on a significant commercial level in the United States, although the U.S. imports twenty percent of its oil and refined products from Canada, and over fifty percent of Canadian oil production is from oil sands. In addition to being much smaller than the Alberta Canada oil sands deposits, the U. S. oil sands are hydrocarbon wet, whereas the Canadian oil sands are water wet. As a result of this difference, extraction techniques for the Utah oil sands will be different than those used for the Alberta oil sands. A considerable amount of research has been done in the quest for commercially viable production technology to be employed in the development of the Utah oil sands. A special concern is the relatively arid climate of eastern Utah, as a large amount of water may be required by some processing techniques.[14] Section 526 of the Energy Independence And Security Act[25][26] prohibits United States government agencies from buying oil produced by processes that produce more greenhouse gas emissions than would traditional petroleum including oil sands.
    Other countries
    Several other countries hold oil sands deposits which are smaller by orders of magnitude. Russia holds oil sands in two main regions[27]. The Volga-Urals basins (in and around Tatarstan), which is an important but very mature province in terms of conventional oil, holds large amounts of oil sands in a shallow permian formation. Exploitation has not gone beyond pilot stage yet. Other, less known, deposits are located in eastern Siberia.
    In the Republic of the Congo the Italian oil company Eni have announced in May 2008 a project to develop the small oil sands deposit in order to produce 40,000 barrels per day in 2014.[28] Reserves are estimated between 0.5 and 2.5 billion barrels.
    In Madagascar, Tsimiroro and Bemolanga are two heavy oil sands deposits with a pilot well already producing small amounts of oil in Tsimiroro[29] and larger scale exploitation in the early planning phase.[30]
    Extraction process
    Surface mining
    Since Great Canadian Oil Sands (now Suncor) started operation of its mine in 1967, bitumen has been extracted on a commercial scale from the Athabasca Oil Sands by surface mining. In the Athabasca sands there are very large amounts of bitumen covered by little overburden, making surface mining the most efficient method of extracting it. The overburden consists of water-laden muskeg (peat bog) over top of clay and barren sand. The oil sands themselves are typically 40 to 60 metres deep, sitting on top of flat limestonedraglines and bucket-wheel excavators and moved to the processing plants by conveyor belts. In recent years companies such as Syncrude and Suncor have switched to much cheaper shovel-and-truck operations using the biggest power shovels (100 or more tons)[31] and dump trucks (400 tons) in the world. This has held production costs to around $27 per barrel of synthetic crude oil despite rising energy and labour costs.[32] rock. Originally, the sands were mined with
    After excavation, hot water and caustic soda (NaOH) is added to the sand, and the resulting slurry is piped to the extraction plant where it is agitated and the oil skimmed from the top.[33] Provided that the water chemistry is appropriate to allow bitumen to separate from sand and clay, the combination of hot water and agitation releases bitumen from the oil sand, and allows small air bubbles to attach to the bitumen droplets. The bitumen froth floats to the top of separation vessels, and is further treated to remove residual water and fine solids. Bitumen is much thicker than traditional crude oil, so it must be either mixed with lighter petroleum (either liquid or gas) or chemically split before it can be transported by pipeline for upgrading into synthetic crude oil.
    The bitumen is then transported and eventually upgraded into synthetic crude oil. About two tons of oil sands are required to produce one barrel (roughly 1/8 of a ton) of oil. Originally, roughly 75% of the bitumen was recovered from the sand. However, recent enhancements to this method include Tailings Oil Recovery (TOR) units which recover oil from the tailings, Diluent Recovery Units to recover naptha from the froth, Inclined Plate Settlers (IPS) and disc centrifuges. These allow the extraction plants to recover well over 90% of the bitumen in the sand. After oil extraction, the spent sand and other materials are then returned to the mine, which is eventually reclaimed.
    Alberta Taciuk Process technology extracts bitumen from oil sands through a dry-retorting. During this process, oil sand is moved through a rotating drum, cracking the bitumen with heat and producing lighter hydrocarbons. Although tested, this technology is not in commercial use yet.[34]
    Four oil sands mines are currently in operation and two more (Jackpine and Kearl) are in the initial stages of development. The original Suncor mine opened in 1967, while the Syncrude mine started in 1978, Shell Canada opened its Muskeg River mine (Albian Sands)Shell Canada's Jackpine mine, Imperial Oil's Kearl Oil Sands Project, Synenco Energy's Northern Lights mine, and Suncor's Fort Hills mine. in 2003 and Canadian Natural Resources Ltd opened its Horizon Project in 2009. New mines under construction or undergoing approval include
    It is estimated that approximately 90% of the Alberta oil sands and nearly all of Venezuelan sands are too far below the surface to use open-pit mining. Several in-situ techniques have been developed to extract this oil.[35]
    Cold flow
    In this technique, also known as cold heavy oil production with sand (CHOPS), the oil is simply pumped out of the sands, often using progressive cavity pumps. This only works well in areas where the oil is fluid enough. It is commonly used in Venezuela (where the extra-heavy oil is at 50 degrees Celsius), and also in the Wabasca, Alberta Oil Sands, the southern part of the Cold Lake, Alberta Oil Sands and the Peace River Oil Sands. It has the advantage of being cheap and the disadvantage that it recovers only 5-6% of the oil in place.
    Some years ago Canadian oil companies discovered that if they removed the sand filters from the wells and produced as much sand as possible with the oil, production rates improved remarkably. This technique became known as Cold Heavy Oil Production with Sand (CHOPS). Further research disclosed that pumping out sand opened "wormholes" in the sand formation which allowed more oil to reach the wellbore. The advantage of this method is better production rates and recovery (around 10%) and the disadvantage that disposing of the produced sand is a problem. A novel way to do this was spreading it on rural roads, which rural governments liked because the oily sand reduced dust and the oil companies did their road maintenance for them. However, governments have become concerned about the large volume and composition of oil spread on roads,[37] so in recent years disposing of oily sand in underground salt caverns has become more common.
    Cyclic Steam Stimulation (CSS)
    The use of steam injection to recover heavy oil has been in use in the oil fields of California since the 1950s. The Cyclic Steam Stimulation or "huff-and-puff" method has been in use by Imperial Oil at Cold Lake since 1985 and is also used by Canadian Natural Resources at Primrose and Wolf Lake and by Shell Canada at Peace River. In this method, the well is put through cycles of steam injection, soak, and oil production. First, steam is injected into a well at a temperature of 300 to 340 degrees Celsius for a period of weeks to months; then, the well is allowed to sit for days to weeks to allow heat to soak into the formation; and, later, the hot oil is pumped out of the well for a period of weeks or months. Once the production rate falls off, the well is put through another cycle of injection, soak and production. This process is repeated until the cost of injecting steam becomes higher than the money made from producing oil. The CSS method has the advantage that recovery factors are around 20 to 25% and the disadvantage that the cost to inject steam is high.
    Steam Assisted Gravity Drainage (SAGD)
    Steam assisted gravity drainage was developed in the 1980s by the Alberta Oil Sands Technology and Research Authority and fortuitously coincided with improvements in directional drilling technology that made it quick and inexpensive to do by the mid 1990s. In SAGD, two horizontal wells are drilled in the oil sands, one at the bottom of the formation and another about 5 metres above it. These wells are typically drilled in groups off central pads and can extend for miles in all directions. In each well pair, steam is injected into the upper well, the heat melts the bitumen, which allows it to flow into the lower well, where it is pumped to the surface. SAGD has proved to be a major breakthrough in production technology since it is cheaper than CSS, allows very high oil production rates, and recovers up to 60% of the oil in place. Because of its very favorable economics and applicability to a vast area of oil sands, this method alone quadrupled North American oil reserves and allowed Canada to move to second place in world oil reserves after Saudi Arabia. Most major Canadian oil companies now have SAGD projects in production or under construction in Alberta's oil sands areas and in Wyoming. Examples include Japan Canada Oil Sands Ltd's (JACOS) project, Suncor’s Firebag project, Nexen's Long Lake project, Suncor's (formerly Petro-Canada's) MacKay River project, Husky Energy's Tucker Lake and Sunrise projects, Shell Canada's Peace River project, Encana's Foster CreekConocoPhillips' Surmont project, Devon Canada's Jackfish project, and Derek Oil & Gas's LAK Ranch project. Alberta's OSUM Corp has combined proven underground mining technology with SAGD to enable higher recovery rates by running wells underground from within the oil sands deposit, thus also reducing energy requirements compared to traditional SAGD. This particular technology application is in its testing phase. development,
    Vapor Extraction Process (VAPEX)
    VAPEX is similar to SAGD but instead of steam, hydrocarbon solvents are injected into the upper well to dilute the bitumen and allow it to flow into the lower well. It has the advantage of much better energy efficiency than steam injection and it does some partial upgrading of bitumen to oil right in the formation. It is very new but has attracted much attention from oil companies, who are beginning to experiment with it.
    The above three methods are not mutually exclusive. It is becoming common for wells to be put through one CSS injection-soak-production cycle to condition the formation prior to going to SAGD production, and companies are experimenting with combining VAPEX with SAGD to improve recovery rates and lower energy costs.[citation needed]
    Toe to Heel Air Injection (THAI)
    This is a very new and experimental method that combines a vertical air injection well with a horizontal production well. The process ignites oil in the reservoir and creates a vertical wall of fire moving from the "toe" of the horizontal well toward the "heel", which burns the heavier oil components and upgrades some of the heavy bitumen into lighter oil right in the formation. Historically fireflood projects have not worked out well because of difficulty in controlling the flame front and a propensity to set the producing wells on fire. However, some oil companies feel the THAI method will be more controllable and practical, and have the advantage of not requiring energy to create steam.[38]
    Advocates of this method of extraction state that it uses less freshwater, produces 50% less greenhouse gases, and has a smaller footprint than other production techniques.[39]
    Petrobank Energy and Resources Ltd. has reported encouraging results from their test wells in Alberta, with production rates of up to 400 barrels per day per well, and the oil upgraded from 8 to 12 API degrees. The company hopes to get a further 7-degree upgrade from its CAPRI (controlled atmospheric pressure resin infusion)[40] system, which pulls the oil through a catalyst lining the lower pipe.[41][42][43]
    Environmental issues
    Like all mining and non-renewable resource development projects, oil sands operations have an effect on the environment. Oil sands projects affect: the land when the bitumen is initially mined and with large deposits of toxic chemicals; the water during the separation process and through the drainage of rivers; and the air due to the release of carbon dioxide and other emissions, as well as deforestation. Additional indirect environmental effects are that the petroleum products produced are mostly burned, releasing carbon dioxide into the atmosphere.
    Air
    The Wood Buffalo Environmental Association (WBEA) monitors the air in the Regional Municipality of Wood Buffalo continuously. This is done through a variety of air, land and human monitoring programs. The information collected is openly shared with stakeholders and the public.
    Since 1995, monitoring in the oil sands region shows improved or no change in long term air quality for the five key air quality pollutants — carbon monoxide, nitrogen dioxide, ozone, fine particulate matter (PM2.5) and sulphur dioxide — used to calculate the Air Quality Index[44]. Air monitoring has shown significant increases in exceedances of hydrogen sulfide (H2S) both in the Fort McMurray area and near the oil sands upgraders.
    Hydrogen sulfide is the chemical compound with the formula H2S. This colorless, toxicgas is responsible for the foul odour of rotten eggs. Hydrogen sulfide gas occurs naturally in crude petroleum, natural gas, volcanic gases and hot springs. It also can result from bacterial breakdown of organic matter and be produced by human and animal wastes. and flammable
    In 2007, the Alberta government issued an Environmental Protection Order to Suncor Energy Inc. The order comes in response to numerous occasions when ground level concentration (GLC) for H2S exceeded acceptable standards.[45] Environmental Protection Orders are issued under the authority of Alberta’s Environmental Protection and Enhancement Act. Alberta Environment can issue Environmental Protection Orders to remedy environmental problems where there has been a release of a substance that has caused or may cause an adverse effect to the environment.
    Land
    A large part of oil sands mining operations involves clearing trees and brush from a site and removing the "overburden" — the topsoil, muskeg, sand, clay and gravel — that sits atop the oil sands deposit.[46] Approximately two tons of oil sands are needed to produce one barrel of oil (roughly 1/8 of a ton).[47] As a condition of licensing, projects are required to implement a reclamation plan.[48] The mining industry asserts that the boreal forest will eventually colonize the reclaimed lands, but that their operations are massive and work on long-term timeframes. As of 2006/2007 (the most recent data available), about 420 km22 (25 sq mi) of that land is under reclamation.[49] In March 2008, Alberta issued the first-ever oil sands land reclamation certificate to Syncrude Canada Ltd. for the 1.04 km2 (0.40 sq mi) parcel of land known as Gateway Hill approximately 35 km (22 mi) north of Fort McMurray.[50][51] (160 sq mi) of land in the oil sands region have been disturbed, and 65 km Several reclamation certificate applications for oil sands projects are expected within the next 10 years.
    Water
    Between 2 to 4.5 volume units of water are used to produce each volume unit of synthetic crude oil (SCO) in an ex-situ mining operation. Despite recycling, almost all of it ends up in tailings ponds, which, as of 2007, covered an area of approximately 50 km2 (19 sq mi). In SAGD operations, 90 to 95 percent of the water is recycled and only about 0.2 volume units of water is used per volume unit of bitumen produced.[52] Large amounts of water are used for oil sands operations – Greenpeace gives the number as 349 million cubic metres per year, twice the amount of water used by the city of Calgary. It is unclear if this is the amount of water they are licensed to remove from the Athabasca or the actual use and how up to date the statistic is. The Athabasca River is also much larger than Bow and Elbow rivers that flow through Calgary.[53]
    The Athabasca River is the ninth longest river in Canada running 1,231 km (765 mi) from the Athabasca Glacier in west-central Alberta to Lake Athabasca in northeastern Alberta.[54] The average annual flow just downstream of Fort McMurray is 633 cubic metres per second[55] with its highest daily average measuring 1200 cubic metres per second.[56]
    Current water license allocations totals about 1.8 percent of the Athabasca river flow. Actual use in 2006 was about 0.4 percent.[57] In addition, the Alberta government sets strict limits on how much water oil sands companies can remove from the Athabasca River. According to the Water Management Framework for the Lower Athabasca River, during periods of low river flow water consumption from the Athabasca River is limited to 1.3 per cent of annual average flow.[58] The province of Alberta is also looking into cooperative withdrawal agreements between oil sands operators.[59]
    In October 2009, Suncor Energy announced it was seeking government approval for a new process to recover tailings called Tailings Reduction Operations (TRO), which accelerates the settling of fine clay, sand, water, and residual bitumen in ponds after oil sands extraction. The technology involves dredging mature tailings from a pond bottom, mixing the suspension with a polymer flocculent, and spreading the sludge-like mixture over a “beach” with a shallow grade. According to the company, the process could reduce the time for water reclamation from tailings to weeks rather than years, with the recovered water being recycled into the oil sands plant. In addition to reducing the number of tailing ponds, Suncor claims TRO could reduce the time to reclaim a tailing pond from 40 years at present to 7-10 years, with land rehabilitation continuously following 7 to 10 years behind the mining operations.[60]
    Climate change
    The production of bitumen and synthetic crude oil emits more greenhouse gas (GHG) than the production of conventional crude oil, and has been identified as the largest contributor to GHG emissions growth in Canada, as it accounts for 40 million tonnes of CO2 emissions per year.[61] Environment Canada claims the oil sands make up 5% of Canada's greenhouse gas emissions, or 0.1% of global greenhouse gas emissions. It predicts the oil sands will grow to make up 8% of Canada's greenhouse gas emissions by 2015.[62]2. Environmentalists argue that the availability of more oil for the world made possible by oil sands production in itself raises global emissions of CO
    While the emissions per barrel of bitumen produced decreased 26% over the decade 1992–2002[63], total emissions were expected to increase due to higher production levels.[64] As of 2006, to produce one barrel of oil from the oil sands released almost 75 kg (170 lb) of GHG with total emissions estimated to be 67 megatonnes (66,000,000 LT; 74,000,000 ST) per year by 2015.[65]
    In January 2008, the Alberta government released Alberta’s 2008 Climate Change Strategy.[66] Alberta’s emissions are projected to grow to 400 megatonnes (Mt) by 2050, largely due to forecast growth in the oil sands sector.[66] The new plan aims to cut the projected 400 Mt in half by 2050, with a 139 Mt reduction coming from carbon capture and storage — the bulk of those reductions (100 Mt) will come from activities related to oil sands production.[66]
    A federal court of Canada ruling on March 6, 2008, found the approval of Imperial Oilclimate change and greenhouse gas emissions. Proposals in the regulatory system at that date included mines by Total SA of France, by Anglo-Dutch Royal Dutch Shell and by Petro-Canada, as well as steam-injection projects by EnCana of Calgary.[67] Ltd.'s $8-billion oil sands mine insufficient on
    Carbon dioxide sequestration
    To offset greenhouse gas emissions from the oil sands and elsewhere in Alberta, sequestering carbon dioxide emissions inside depleted oil and gas reservoirs has been proposed. This technology is inherited from Enhanced oil recovery methods, which have been in use for several decades.[68] In July 2008, the Alberta government announced a C$2 billion fund to support sequestration projects in Alberta power plants (largely coal) and oil sands extraction and upgrading facilities.[69][70][71]
    Concerns of environmentalists
    The environmental impact caused by oil sand extraction is frequently criticized by environmental groups such as Greenpeace.[72][73] Environmentalists state that their main concerns with oil sands are land damage, including the substantial degradation in the land's ability to support forestry and farming[citation needed], greenhouse gas emissions, and water use. Oil sands extraction is generally held to be more environmentally damaging than conventional crude oilcarbon dioxide "well-to-pump" emissions, for example, are estimated to be about 1.3-1.7 times that of conventional crude.[62]
    Input energy
    Approximately 1.0 – 1.25 gigajoule of energy is needed to extract a barrel of bitumen and upgrade it to synthetic crude. As of 2006, most of this is produced by burning natural gas.[74] Since a barrel of oil equivalent is about 6.117 gigajoules, this produces about 5 or 6 times as much energy as is consumed. Energy efficiency is expected to improve to 0.7 gigajoules of energy per barrel by 2015,[75] giving an EROEI of about 9. However, since natural gas production in Alberta peaked in 2001 and has been static ever since, it is likely oil sands requirements will be met by cutting back natural gas exports to the U.S.[76]
    Alternatives to natural gas exist and are available in the oil sands area. Bitumen can itself be used as the fuel, consuming about 30-35% of the raw bitumen per produced unit of synthetic crude. Nexen's Long Lake project will use a proprietary deasphalting technology to upgrade the bitumen, using asphaltene residue fed to a gasifier whose syngas will be used by a cogeneration turbine and a hydrogen producing unit, providing all the energy needs of the project: steam, hydrogen, and electricity.[77] Thus, it will produce syncrude without consuming natural gas, but the capital cost is very high.
    Coal is widely available in Alberta and is inexpensive, but produces large amounts of greenhouse gases. Nuclear power is another option which has been proposed, but did not appear to be economic as of 2005.[78] In early 2007 the Canadian House of Commons2 emissions and help Canada meet its Kyoto commitments, as it would require nearly 12 GW to meet production growth to 2015, but the implications of building reactors in northern Alberta were not yet well understood.[79][80][81] Energy Alberta Corporation announced in 2007 that they had applied for a license to build a new nuclear plant at Lac Cardinal, 30 km west of the town of Peace River. The application would see an initial twin AECL Advanced CANDU ReactorGW (electric).[82][83] At 6.117 GJ/barrel, this is equivalent to conserving 31,074 barrels per day (4,940.4 m3/d). On November 30, 2007 Bruce Power, which owns eight CANDU reactors in Ontario, signed a letter of intent to acquire Energy Alberta and take over the project. Standing Committee on Natural Resources considered that the use of nuclear power to process oil sands could reduce CO ACR-1000 plant go online in 2017, producing 2.2

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