Billion Barrels Of Oil Research Articles

An overview of the energy efficiency potential

The global economy is not particularly energy-efficient. At current levels of consumption the U.S. economy, for example, is an anemic 14% efficient – which means that the United States wastes about 86% of the energy now burned to maintain its economy. Most recently, Laitner et al. (2012) documented an array of untapped cost-effective energy efficiency resources roughly equivalent to 250 billion barrels of oil. That is a sufficient scale that would enable the U.S. to cut total energy needs in half compared to business-as-usual projections for the year 2050, and still maintain a robust economy.

Oil production optimization without natural gas constraints: The harvesting of upstream natural gas

Almost always oil production is accompanied by the surface production of associated gas. In the case of under-saturated reservoirs where the gas–oil-ratio (GOR) is expected to be relatively constant, the gas production rate from the field is expected to increase according to any increase in oil production rate. For saturated reservoirs the gas production rate over time increases because the solution gas–oil ratio is a function of pressure. More gas is released from the oil as the pressure drops.With the above phenomena in mind, it means that any plan to maximize reservoir oil production must be followed by a plan to handle the associated gas. In the case where gas production rate is at maximum capacity as dictated by surface facility limits, it can be inferred that oil production rate may have to be held below a certain level.If gas is “harvested” at its raw state, i.e., out of the primary separator and before it is treated, the benefits would be far more than the obvious saving of the costs from treating the gas. Compressed natural gas (CNG) en route to onshore or to a centralized LNG facility for example becomes then a tool of primary gas management.In a study performed on a theoretical reservoir and modeled after a West African deep-water field which has approximately 2 billion barrels of oil in place, twenty (20) producers, six (6) gas injectors and twelve (12) water injectors, it was determined that an additional 193.5 million barrels of oil could have been produced over ten years had there not been a limit to the gas production rate to be handled. The maximum field gas production rate per day in this study was 1060 MMSCF/d, of which 415 MMSCF/d was re-injected daily into the reservoir. The maximum field oil production rate was 250,000 STB/d and the maximum field water production rate was 80,000 STB/d. This work shows the advantages of eliminating production constraints imposed by natural gas production. With gas harvesting, the field oil rate can be optimized to ensure that the reservoir is producing at its true potential.

Drilling and Completing Cascade and Chinook Wells: A Case History

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24179, ’Drilling and Completing Cascade and Chinook Wells: A Design and Execution Case History,’ by Flavio Dias De Moraes, Petrobras; Oswaldo Moreira, Petrobras America; Ziad Haddad, FOI Technologies; Scott Ogier and Jonathan Shipley, SPE, Cherokee Offshore Engineering; Mauricio Rebelo, Petrobras; and Fernando Gama, Petrobras America, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed. During the design, implementation, and operation of the Cascade and Chinook (C&C) field development project in ultradeep water in the Lower Tertiary play of the Gulf of Mexico (GOM), the technical limits of single-trip multizone (STMZ) frac-pack systems were pushed to depths greater than 27,000 ft using high fracture rates and high-strength proppants; knowledge was gained from ultrahigh-pressure (greater than 20,000 psi) tubing-conveyed perforating systems; and well-design criteria suitable for high-drawdown (more than 12,000 psi) production operations were demonstrated. Introduction The C&C development plan in the GOM is one of the most technologically challenging and complex projects ever implemented by Petrobras. This project uses the first floating production, storage, and offloading vessel in operation in US waters at a water depth of 8,200 ft. The C&C subsea infrastructure considers the use of subsea manifolds, rigid flowlines, pipe-in-pipe pipelines, and freestanding hybrid risers. These two fields are 15 miles apart and share several characteristics such as depth, lithology, and reservoir similarities. The Wilcox 1 (Eocene) and 2 (Paleocene) sands belong to the Lower Tertiary geologic period and are part of the latest exploratory frontier in the GOM. At least 12 discoveries have been made in the Lower Tertiary, holding a potentially recoverable volume of several billion bbl of oil, highlighting the importance of this technology development for the industry. These reservoirs are characterized by a considerable thickness of intercalated sandstones and shales. The reservoirs show low horizontal permeability (less than 100 md) and poor vertical communication between sand layers. Other characteristics include a very high static formation pressure, a maximum temperature of 256°F, and a low gas/oil ratio. The produced oil has carbon dioxide concentration in the gaseous phase of less than 1.5%, and there is no evidence of hydrogen sulfide contamination. Drilling Design The casing design was based on delivering an 8½-in.-internal-diameter casing at total depth (TD) to accommodate the completion design. In this design, each string is run to its approximate design limit to maximize leakoff-test (LOT) values. One of the most important strategies of the C&C wells was the elimination of the 11⅞-in. liner, which prevents achieving adequate circulation rates for a successful primary cement job on the 10⅛-in. production casing.

Saudi Aramco Oil and Gas Production Hits Historic Levels

Production Record Saudi Arabian state oil company Saudi Aramco released its annual report in July, noting that it produced more oil and gas last year than ever before, and also raised its technical capabilities to new heights as part of it 2020 strategy to be a fully integrated energy and chemicals company. The company’s annual production exceeded 3.4 billion bbl of oil, equal to an average of 9.5 million BOPD. “In 2012, we produced 3.479 billion bbl of oil, about one in every eight bbl of the world’s crude oil production and the most we have produced in a single year in our history,” Saudi Aramco said in its annual report. “During 2012 at Saudi Aramco, we responded to market conditions by producing crude oil at the highest level in our company’s history,” said Khalid Al-Falih, president and chief executive officer of Saudi Aramco. The company’s recoverable crude oil and condensate reserves have reached 260.2 billion bbl, while gas reserves reached 284.8 Tcf. “Our maximum daily sustainable crude oil production capacity remained at 12 million BOPD during the year. Our gas plants now have a gas processing capacity of 13.23 Bscf/D,” the report said. Gas production has also reached historic levels, as the company reported an 8.3% increase in output in 2012 com-pared with 2011 at about 3.924 Tcf/yr, the highest in Saudi Aramco’s history. The company also said that it produced 482 million bbl of natural gas liquids including 82 million bbl of condensates. Crude oil exports increased 100 million bbl in 2012 to 2.52 billion bbl, with 53.2% exported to the Asia Pacific region followed by 16.5% to the United States, 7.4% to the Mediterranean region, and 5% to Europe. In 2012, Saudi Aramco focused on exploring frontier areas in the Red Sea and complex reservoirs onshore and offshore. Discoveries included one oil field—Aslaf—and two gas fields—Sha’ur and Umm Ramil—bringing its total oil and gas field discoveries throughout its history to 116. Sha’ur was its first discovery in the marine portion of the Red Sea.

Advancements in Completion Technology Increase Production in the Williston Basin

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 159586, ’Advancements in Openhole-Completion Technology Increase Efficiencies and Production in the Williston Basin,’ by John Paneitz, Whiting Petroleum, and C. Christopher Johnson, Matthew White, and George Gentry, Baker Hughes, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8-10 October. The paper has not been peer reviewed. Over the years, hybrid systems have been installed in horizontal wellbores to increase the number of compartmental sections for hydraulic fracturing because of the limitations of ball-actuated fracture sleeves. Experimenting with hybrid systems provides operators with the ability to optimize spacing of fracture stages along the horizontal section when sleeve technology alone does not allow for the desired number of stages. The costs are higher for operators to perform a hybrid-type completion, however, and this has driven enhanced sleeve technology to allow for all-sleeve completions. Introduction The Bakken shale located in the Williston basin covers an area that includes portions of North Dakota and Montana in the US and Manitoba and Saskatchewan in Canada (Fig. 1). An unconventional reservoir, the Bakken formation is one of the last giants to be discovered in North America. The US Geological Service estimates that the undiscovered US portion of the Bakken formation holds 3.65 billion bbl of oil, 1.85 Tcf of associated gas, and 148 million bbl of natural-gas liquids. Advances in horizontal drilling of extended-reach wells and in completion techniques have increased the amount of recoverable oil and gas. Wells drilled in the Bakken are typically drilled horizontally across two 640-acre sections, with laterals that can extend more than 9,000 ft. Two completion methods known for cost-effectiveness and high well efficiency that are used in these wells are the openhole-packer system and the sleeve one-trip system. Openhole-Packer and Sleeve Completions Openhole completions performed in the Bakken are commonly run as a one-trip system on drillpipe containing the following equipment: a hydraulic or mechanical running tool, liner-top packer or liner-hanger system, openhole packers, fracture sleeves, and float equipment. Once the system is in position, the appropriate fluid is displaced, and the liner-top-packer is set; the running tool is dis-connected from the system and removed from the well. The openhole packers pro-vide compartmental isolation along the horizontal wellbore with fracture sleeves placed at each stage, forming a pathway for stimulation fluid and the production of hydrocarbons.

Environmental Impact Asessment of 3D Seismic Acquisition in The Badra Oilfield , Iraq

This study represents the Environmental Impact Assessment (EIA) of 3D Seismic Acquisition in the Badra oilfield, Wasit province, Iraq. Seismic acquisition is part of works under the contract for the development of the Badra oilfield, with a planned capacity of 2 billion barrels of oil, and its associated linear facilities to be located in Wasit, 160 km southeast of Baghdad, Iraq. The study was prepared for the Company – Gazprom Neft Badrah B.V. (GPN) in 2010.
 An Environmental Impact Assessment (EIA) study was prepared to identify and assess the potential environmental effects of seismic operations, and in order to accomplish that goal, a baseline environment study was conducted first to illustrate the climate, geology, topography, natural resources, industrial activities, social and natural environment ( flora and fauna) of the region based on field visit and desktop history.
 Based on the baseline study, mitigation measures forming Environmental Management Plan was proposed aiming to minimize environmental and socio-economic adverse effects such as waste water, solid wastes, air pollution and to maximize positive ones.
 The study also illustrated all related national and international laws and regulations to force the company to oblige them during work on the Iraqi land. It also detailed the national and international limits of air emission and liquid effluent quality not to be exceeded.

Seismic Unwired: Going Wireless in Difficult Terrain

Seismic Unwired The Cook Inlet has a long history of oil production, with more than 1.3 billion bbl produced and the potential for more. But ever since production peaked at 230,000 b/d in the 1970s, there has been little exploration as it dwindled to around 12,000 b/d. Stories about the decline point out that the Cook Inlet was eclipsed by far larger finds on Alaska’s North Slope, such as Prudhoe Bay. Still it does offer the potential for significant conventional oil finds onshore and in shallow waters offshore. A 2011 assessment by the US Geological Survey (USGS) covering the entire inlet estimated there could be up to 1.3 billion bbl of oil to discover—its mean estimate was nearly 600 mm bbl of oil plus 13.7 Tcf of natural gas from conventional formations. Plus significantly more gas from unconventional ones. Unlike the North Slope, there is a ready market for natural gas. The nearby city of Anchorage depends on the inlet for natural gas and is concerned about dwindling local supplies, and the location offers transport links not available in the far north. Past exploration suggested the underground structures likely to hold hydrocarbons could readily be identified using 3D seismic. But there have been few surveys using advanced seismic technology and they generally covered small areas. That is not surprising considering the inlet’s treacherous tides, punishing winter weather, endangered Beluga whales, and the brown bears thriving in the wildlife preserves on its shores. Not to mention the permitting process. That all changed when Apache Corp. began an aggressive leasing program a few years ago, gaining rights to explore more than 1 million acres. The big independent exploration company saw the potential for discoveries, particularly in unexplored deeper horizons, and based on its experience elsewhere it believed it could deal with the problems associated with doing a large-scale seismic survey. Obtaining permits to shoot seismic in the inlet required creating a monitoring program, with specially trained and equipped observers making sure the operation followed regulations that can shut down seismic work if certain endangered mammals are within a 6-mile radius, and where sounds could affect animals. Putting out the sensors needed to record those echoes presented another set of natural challenges in waters where tides can change the water level by as much as 35 ft. Currents up to 7 mph (6 knots) rule out towing streamers that move with the current, which also has presented problems for strings of seafloor receivers wired together using cables. “There were horror stories in the past of cables drifting in the currents. Currents are a big problem,” said Mike Yates, senior staff geophysicist for Apache, which also experienced electrical problems with a cabled system, caused by the salt water. On land, laying out long lines of receivers connected by cables was a problem because the permits banned cutting through the brush to create the relatively straight paths needed for cables, and forced detours around protected areas, such as bear dens.

Unconventional Exploration Reaches: Alaska's North Slope

North Slope Shale On the day last February that the US Geological Survey (USGS) came out with a report saying up to 2 billion bbl of oil could be produced from shale formations on the North Slope of Alaska, a company was already planning to drill on its 500,000-acre lease. That was a striking change at the agency where years separated the release of assessments and exploration in plays such as the Marcellus said David Houseknecht, a research geologist for the USGS and the lead author of the North Slope assessment. The explorers and the government geologists drew on similar sources to conclude the North Slope could be a likely spot for the next US shale exploration boom. While the USGS was working on its North Slope evaluation, geologists like Ed Duncan were looking for signs the rocks that were the source of oil that migrated over long periods into huge conventional reservoirs, such as the Prudhoe Bay, Kuparuk, and Alpine, could also be rich sources of oil. Using what he’d learned early in his career working the North Slope and later as a consultant for companies seeking new shale plays, Duncan and his wife Karen Duncan, formed a company called Great Bear Petroleum and put in a surprise bid at the December 2010 Alaska state lease sale. “I was stunned by the potential, with three of the most prolific oil source rocks and nobody was doing anything with them,” said Duncan, who is president and chief executive officer at Great Bear. At the time he told the story of how he came to explore the North Slope, Duncan was in Golden, Colorado, at a Weatherford lab studying the core samples collected from Great Bear’s test wells, the Alcor and the Merak, drilled in the summer of 2012. The wells near the gravel road that parallels the Trans-Alaska Pipeline penetrated all three source rock formations. The early evaluations were all in line with expectations but in late December he was just beginning to see the results of the tests of formations so rarely seen that a USGS geologist came out to examine them. Duncan hopes to drill a horizontal well, fracture it, and do a production test next, but: “As much as I would love to say here is the result, let’s go ahead with a fracture-flow test, that is not the case,” he said. “We are learning a tremendous amount every day,” Duncan said after 2 days in Golden. But critical tests on the rock properties indicating whether it could be effectively fractured would not come in until February. “My father would say there is plenty of wood to chop here,” he said.

Nationalism and Domestic Politics as Drivers of Maritime Conflict

Nationalism and Domestic Politics as Drivers of Maritime Conflict Meghan Kleinsteiber (bio) Drivers of Maritime Disputes In her essay, “Oceans of Conflict: Determining Potential Areas of Maritime Disputes, ” Elizabeth Nyman examines five main factors that drive maritime disputes: the pursuit of nonliving resources, the pursuit of living resources, conflicting claims to sovereignty over uninhabited rocks or islands, pollution, and the future role of climate change in driving future conflicts. Nyman notes that uncertainty over sovereignty of rocks and islands is the driving force behind Japan and China’s dispute over the Senkaku/Diaoyu Islands in the East China Sea, as well as conflicts between China and members of the Association of Southeast Asian Nations (ASEAN) over the Spratly Islands and Paracel Islands in the South China Sea. Nyman suggests that states desire sovereignty of a region because they desire the right to resources in that region, and in doing so, she neglects a non-economic explanation for the escalation of these disputes. I argue that the fundamental drivers behind the disputes in the East and South China Seas are not potential or claimed natural resources, but rather domestic politics, rising nationalism, and irredentism. Resource Claims First, I contradict the claim that disputes in the East and South China Seas are purely driven by resources, because the actual quantity of resources in the seas is unknown, and resource extraction is currently too costly for regional actors. Many of the world’s fisheries resources are found in the East and South China Seas. It is well documented that the fisheries stocks in the East and South China Seas are bountiful, but rapidly depleting. On the other hand, the extent of hydrocarbon wealth in the region is uncertain. The United States Energy Information Administration (EIA) estimates that the South China Sea could hold up to 11 billion barrels of oil and 190 trillion [End Page 15] cubic feet of natural gas, and that the East China Sea may contain between 60 and 100 million barrels of oil. In contrast, a report published by Chinese National Offshore Oil Company (CNOOC) provided significantly higher estimates of 125 billion barrels of oil and 500 trillion cubic feet of natural gas in the South China Sea, and another Chinese source claimed resources in the East China Sea to be anywhere between 70 and 160 billion barrels.1 Both the EIA and Chinese estimates include proven and probable ranges of reserves. However, given the technological capacity of the littoral states involved, resource extraction is not economically viable at present. Thus, the amount of hydrocarbons that could feasibly be extracted from the East and South China Seas is highly debatable, calling into question the assertion that potential resources are the primary factor that has reinvigorated the maritime disputes in recent years. Even if resources are an important component in heightened activity in the East and South China Seas, conflicts over sovereignty appear to be counterproductive to gaining access to the available resources. As Nyman notes, increased aggression and uncertainty scare away private firms, and a calmer environment is more conducive to joint development. A recent CSIS report by Gregory Poling illustrates what he calls an “area of maximum dispute,” the overlap of each country’s maximum claim assuming that all contested features are considered islands (as opposed to rocks), and are thus awarded a full exclusive economic zone (EEZ) of 200 nautical miles, instead of a 12 nautical mile territorial sea.2 Poling argues that, as all parties are bound by their UNCLOS obligations, they should accept this area as being in dispute. By clearly defining the area of dispute, the potential for joint exploitation and the development of resources becomes much greater. In fact, joint development projects have already led to the extraction of resources in parts of both the East and South China Seas. In 2009, Brunei and Malaysia established a “Commercial Arrangement Area” for the joint development and exploitation of petroleum resources off of Borneo after resolving a contested maritime area between the two countries.3 Although questions of resource ownership have existed for decades, conflict has only been sporadic. Not long ago, the disputes in the East and South China Sea had been relatively dormant...

Assessment of Alaska’s North Slope Oil Field Capacity to Sequester CO2

The capacity of 21 major fields containing more than 95% of the North Slope of Alaska’s oil were investigated for CO2 storage by injecting CO2 as an enhanced oil recovery (EOR) agent. These fields meet the criteria for the application of miscible and immiscible CO2-EOR methods and contain about 40 billion barrels of oil after primary and secondary recovery. Volumetric calculations from this study indicate that these fields have a static storage capacity of 3 billion metric tons of CO2, assuming 100% oil recovery, re-pressurizing the fields to pre-fracturing pressure and applying a 50% capacity reduction to compensate for heterogeneity and for water invasion from the underlying aquifer. A ranking produced from this study, mainly controlled by field size and fracture gradient, identifies Prudhoe, Kuparuk, and West Sak as possessing the largest storage capacities under a 20% safety factor on pressures applied during storage to avoid over-pressurization, fracturing, and gas leakage. Simulation studies were conducted using CO2 Prophet to determine the amount of oil technically recoverable and CO2 gas storage possible during this process. Fields were categorized as miscible, partially miscible, and immiscible based on the miscibility of CO2 with their oil. Seven sample fields were selected across these categories for simulation studies comparing pure CO2 and water-alternating-gas injection. Results showed that the top two fields in each category for recovery and CO2 storage were Alpine and Point McIntyre (miscible), Prudhoe and Kuparuk (partially miscible), and West Sak and Lisburne (immiscible). The study concludes that 5 billion metric tons of CO2 can be stored while recovering 14.2 billion barrels of the remaining oil.

Coiled Tubing Advances Improve Extended Reach Drilling Operations

Coiled Tubing Fast setup and depth specific capabilities make coiled tubing (CT) the fastest growing technology in the oilfield services sector. Small diameter tubing spooled on a reel make for easy transportation, especially in remote areas. The main driver for CT usage stems from its ability to operate without a rig, which reduces an operator’s time and cost extensively. Because of its flexibility, the use of CT in horizontal and extended reach drilling operations has increased dramatically over the past few years. While CT can achieve efficient results at lower costs in less time, it is not a perfect solution. Small tubing size increases the chances of lockup during intervention. CT also suffers from a reduction in stiffness. In horizontal and highly deviated wells, tubing is exposed to high frictional forces as it is dragged against the wellbore and this can lead to buckling. The extended reach capabilities of CT have been extended by several methods including tractor technology and rollers, which add force at the end of the tubing, pulling it deeper into the hole. Designed in the planning phase, tapered strings can improve the efficiency of an operation, but may limit its use in subsequent intervention projects. Improved friction reduction is one of the key features to ensure against early lockup. Whether done chemically, lubricating the drillstring and the wellbore, or through buoyancy reduction, new technology is achieving results in extended reach CT applications. Horizontal Application The Bakken play in North America covers a 200,000 square mile region from Montana and North Dakota in the United States to southern Saskatchewan in Canada. Second only to Texas in oil production, the play has an estimated ultimate recovery of 24 billion bbl of oil, according to Continental Resources. The company has been active in the North Dakota Bakken since it completed the first commercially successful horizontal well, the Robert Heuer 1-17R, in March 2004. Since 2008, Continental and Sanjel have successfully performed more than 200 CT mill outs in the Bakken with more than 3,000 plugs milled. Traditionally, completion technology has drastically increased the number of fracture stages per well. Early this year, a Bakken record was set of 39 plugs in a single trip while reaching out to 10,024 ft in a lateral. Mill outs in the Bakken routinely reach more than 19,000 ft using downhole water hammer tools (WHT) and different CT string designs. As CT depths approach 20,000 ft, friction reducers are among several other technologies being sought by operators in the region.

The Enemy Within: Oil in the Niger Delta

The Enemy Within: Oil in the Niger Delta

Offshore Exploration in the Arctic: Can Shell’s Oil-Spill Response Plans Keep Up?

All around the world, oil and gas companies are being forced by resource declines to drill in less accessible areas, and the Arctic is their newest frontier. The geology above the Arctic Circle—that is, everything above latitude 66.56°N—holds an estimated 90 billion barrels of oil and 1,669 trillion cubic feet of natural gas, or 22% of the world’s undiscovered1 conventional resources, according to the U.S. Energy Information Administration.2 It’s thought that these resources lie predominantly under Arctic seas, which have recently become easier to reach due to significant reductions in seasonal ice cover associated with global climate change.3 Norway, Russia, Canada, Denmark, and other northern countries are in various stages of developing offshore Arctic programs, and diplomatic squabbles have broken out over territorial rights extending all the way to the North Pole. Between 1980 and 2000 Alaska accounted for an average one-fifth of U.S. oil production.4 But with oil flowing through the Trans-Alaska Pipeline falling by more than two-thirds since a peak in 1988,4 the recent pressure to drill in the Outer Continental Shelf (OCS) off the state’s north coast has been relentless. Alaska derives at least 90% of its revenues from oil,5 so law makers in that state—supported by much of the state’s population—have pushed hard for offshore authorization. The federal government has also indicated its support, in 2011 expressing a commitment to facilitate development in the OCS region and to expedite offshore permitting in Alaska, assuming that “safety, health, and environmental standards are fully met.”6 Now the United States has taken a big step toward opening the seas off Alaska to a new round of oil and gas exploration. In a major breakthrough for the petroleum industry and loss for drilling opponents, the U.S. Department of the Interior (DOI) in February 2012 approved Shell Gulf of Mexico, Inc.’s oil-spill response plan for the Chukchi Sea, which provides habitat for polar bears, walruses, and other wildlife, and a hunting ground for Alaska Natives who still go whaling in seal-skin boats.7 Six weeks later the company’s spill-response plan for the adjoining Beaufort Sea also was approved.8 Shell must cease drilling well before the water freezes over lest a late-season blowout cause oil to accumulate under the ice through the winter. Shell Alaska spokesman Curtis Smith says DOI approval of the plans puts the company on track to launch exploration in the region this summer (final permits to drill must still be obtained). But many critics contend it’s not possible to drill safely in the region, given the isolation and harsh weather, and they question how well the plans will protect Arctic health in the event of a spill.

Opportunity, Challenge Meet on Arctic Horizon

On the stark expanse of the Milne Point field on the Alaska North Slope, the BP Mount Elbert well tests the reservoir productivity of methane hydrate in a joint project with the National Energy Technology Laboratory of the US Department of Energy during 2007. The Arctic represents a large expanse of opportunity for discovery and development of oil and gas resources, but one matched equally with technical challenges that test the limits of the industry. In the 2008 Circum-Arctic Resource Appraisal (CARA), covering 33 geologic provinces considered prospective for petroleum, the United States Geological Survey (USGS) calculated that the sum of the mean estimates for each province indicated that 90 billion bbl of oil, 1,669 Tcf of gas, and 44 billion bbl of natural gas liquids (NGL) remain to be found in the Arctic, of which 84% was expected to lie in offshore areas. The study included only resources that are technically recoverable, that is, those considered recoverable using existing technology. The obstacles of ice, the most severe weather conditions, seasonal constraints, minimal infrastructure, daunting and uncertain logistics, and the high cost of operations begin but do not end the list of challenges to Arctic exploration and production. “The extensive Arctic continental shelves may constitute the geographically largest unexplored prospective area for petroleum remaining on Earth,” the study said. The challenges may explain exactly why that is so and cause some to conclude that these areas will always be underexplored, with many of these estimated resources never developed. Yet the matter can be viewed quite the opposite way. As the area is so underexplored, will we someday find these estimates low if we answer the challenge to explore and develop the Arctic? Unconventional resources, such as coalbed methane, methane hydrate, oil shale, and tar sand, were explicitly excluded from the 2008 study. Perhaps that is just a footnote. But considering what has happened in only the past few years with the tremendous growth of shale resource estimates, perhaps it is not. It is questions like that, and always knowing that there is so much we do not know, that keep the Arctic on the horizon of opportunity for the oil and gas industry.

The application and value of AVO and spectral decomposition for derisking Palaeogene prospects in the UK North Sea

Perhaps over a billion barrels of oil, distributed over dozens of mostly small prospects, remain trapped in Palaeogene reservoirs in the UK sector of the North Sea Basin. Here we consider whether traditional amplitude versus offset (AVO) analysis, augmented by spectral decomposition, can provide a useful tool in helping to evaluate which of these prospects are worthwhile targets for drilling. In recent years, exploration drilling in the Palaeogene play fairway of the UK Northern North Sea has had mixed results. Eighty percent of wells drilled since 2000 have failed to encounter hydrocarbons, for reasons that include poor interpretation and evaluation of prospects, lack of AVO analysis, and positioning of wells on poor quality seismic data. Our analysis suggests that AVO analysis and spectral decomposition can be very useful and powerful tools for predicting the presence or absence of hydrocarbons in undrilled Palaeogene prospects in the North Sea. However, the validity of the results depends upon the availability of good quality seismic data with broad frequency content that have been acquired with cable lengths greater than 3 km.

Assessment finds more natural gas resources but less oil

The latest report on undiscovered conventional oil and gas resources outside the United States estimates that there are more undiscovered and technically recoverable natural gas and natural gas liquids (NGLs) but less oil than had previously been thought. The 18 April report, issued by the U.S. Geological Survey (USGS) as part of its World Petroleum Resource Project, estimates that there are 5606 trillion cubic feet of natural gas, compared with 4669 trillion cubic feet in the previous assessment, in 2000, and 167 billion barrels of NGLs compared with an earlier 207 billion barrels. The assessment also estimates that there are 565 billion barrels of oil compared with an earlier 649 billion. About 75% of those resources outside the United States are located in four regions: South America and the Caribbean, sub‐Saharan Africa, the Middle East and North Africa, and the Arctic provinces portion of North America, according to the new assessment.

Interwell Tracer Tests To Optimize Operating Conditions for a Surfactant Field Trial: Design, Evaluation, and Implications

Summary Enhanced oil recovery (EOR) by surfactant flooding is the key to unlocking the next billion barrels of oil for Minas, one of the world's largest waterflood fields. An interwell tracer test (ITT-1) was performed before a surfactant field trial (SFT) to ensure well injectivity, demonstrate pattern confinement, quantitatively describe interwell connectivity and sweep efficiency, and provide sufficient data for reservoir evaluation. The tracer test was designed by numerical simulation. The test started in November 2009 and was terminated in February 2010. Analytical interpretation based on moment analysis and numerical reservoir simulations was conducted to evaluate ITT-1 results. Interpretation of the test results indicated various operational and reservoir properties that would have likely led to failure of the surfactant pilot. Hydraulic control of the SFT pattern was not achieved; in fact, less than 20% of one tracer was recovered. Many small-scale heterogeneities were identified that led to a lower-than-expected reservoir volume contacted. Unexpected communication between the target sand and the underlying sands outside the pattern also contributed to low tracer recovery and low swept volume. The tracer test was history matched, and additional features were incorporated in the reservoir model, and a new tracer design (ITT-2) was optimized to correct low sweep efficiency and poor hydraulic control. New information from ITT-2 will be used to further optimize operating conditions for SFTs. Failure to conduct the tracer tests would have likely revealed these unfavorable reservoir and operational conditions during the SFT. Had oil recovery been poor (because of low swept volume), it would have erroneously been attributed to a poor SFT rather than to the true causes. ITT-1 is considered successful because it allowed us to redesign injection/hydraulic control during the relatively inexpensive tracer test and thus evaluate the surfactant trial without bias.

Coping with an Ecological Disaster: The Role of Perceived Meaning in Life and Self-Efficacy Following the Gulf Oil Spill

On April 20, 2010, the Deepwater Horizon oil platform exploded, releasing five billion barrels of oil into the Gulf of Mexico over five months (referred to as the Gulf Oil Spill). This oil spill affected Gulf Coast communities, harming both sea and land wildlife, damaging the fishing industry, and destroying natural resources. In the wake of such a disaster, many people experience decreases in their quality of life. However, coping mechanisms such as developing meaning or purpose in life and creating a sense of self-efficacy can allow people to recover. The present study evaluates the effect of the Gulf Oil Spill on 361 individuals seeking clinical services on the Mississippi Gulf Coast following the spill. Regression analyses revealed that the perceived effects of the spill were only weakly related to life satisfaction. Perceived meaning in life and self-efficacy were much more predictive of satisfaction with life, with perceived meaning in life serving as the most important predictor. These data provide initial support for models that emphasize the role of coping mechanisms in the wake of ecological disasters. Future research should evaluate the effects of such mechanisms using longitudinal and other designs that allow for stronger causal inferences. Clinical implications include the use of therapies that foster a sense of perceived meaning in life (e.g., logotherapy) and self-efficacy (e.g., cognitive behavioral therapy), as well as consideration of the specific ecological nature of disasters such as the Gulf Oil Spill.

Niobrara Ramps Up To Hot Play For Liquids

The Niobrara Shale in the United States has ramped up into a hot play that could soon bring an explosion of horizontal drilling in Colorado and Wyoming. The combination of horizontal drilling and multistage hydraulic fracturing is transforming the Niobrara from a target that has been drilled vertically and primarily for gas for nearly 100 years into a liquids-rich play that is capturing considerable attention. Speaking at the 2011 SPE Annual Technical Conference and Exhibition in Denver, John Ford, general manager of Colorado’s Wattenberg field at Anadarko, described the growing Niobrara activity as “really the next big thing.” That optimism was understandable. In November, Anadarko announced that its leases at Wattenberg may hold more than a billion barrels of recoverable oil and natural gas. The statement noted company drilling success in 11 recent wells at the field, including the Dolph 27-1HZ horizontal well that showed initial production of more than 1,100 B/D of oil and 2.4 MMcf/D of natural gas. These latest wells have given the company confidence that it can drill between 1,200 and 2,700 wells in northeast Colorado, with approximately 160 wells planned for this year. Based on results so far, the company expects ultimate recovery of between 500 million and 1.5 billion bbl of oil, natural gas liquids, and natural gas on an equivalent basis. Anadarko is not alone. Chesapeake Energy, Noble, Encana, and EOG Resources are among the largest acreage holders and the most active drillers of many companies—including numerous small independents—probing the Niobrara. Majors such as Shell and Marathon Oil have significant acreage. There are more than 50 operators in or near the Wattenberg field alone. Situated north/northeast of the Denver area, Wattenberg is the largest producing field in the Denver-Julesburg (D-J) Basin and one of the largest onshore oil and gas fields in the US. Reservoir Rock and Producing Regions Although the Niobrara is usually referred to as a shale, its reservoir rock consists primarily of limestone or chalk intervals, said Steve Sonnenberg, professor of petroleum geology at Colorado School of Mines in a recent edition of the AAPG Explorer (published by the American Association of Petroleum Geologists). “The formation demonstrates facies changes that range from limestone and chalk in the eastern end to calcareous shale in the middle and eventually transitioning to sandstone farther west,” said Sonnenberg, a past president of AAPG. “Depth and thickness are highly variable.”

The Arctic Is Now: Economic and National Security in the Last Frontier

ABSTRACT With an estimated 30 billion barrels of oil, 220 trillion cubic feet of natural gas, rare earth minerals, and massive renewable wind, tidal, and geothermal energy resources, the economic potential of the Alaskan Arctic can be measured in the trillions of dollars. Although the other Arctic nations are parties to the Law of the Sea Convention and are already developing their nations’ Arctic resources, the United States has failed to ratify the convention or develop a plan for the region. Now is the time for the Obama administration to advance a comprehensive Arctic strategy that addresses both governance and acquisition requirements, or it risks further harm to the nation's economic and national security.