Recoverable Oil Reserves Research Articles

Do Shale Pore Throats Have a Threshold Diameter for Oil Storage?

In this work, a nanoporous template with a controllable channel diameter was used to simulate the oil storage ability of shale pore throats. On the basis of the wetting behaviours at the nanoscale solid-liquid interfaces, the seepage of oil in nano-channels of different diameters was examined to accurately and systematically determine the effect of the pore diameter on the oil storage capacity. The results indicated that the lower threshold for oil storage was a pore throat of 20 nm, under certain conditions. This proposed pore size threshold provides novel, evidence-based criteria for estimating the geological reserves, recoverable reserves and economically recoverable reserves of shale oil. This new understanding of shale oil processes could revolutionize the related industries.

Oil Production, Refining and Transportation in Canada

The article deals with fuel and energy complex of Canada as one of the largest manufacturers of primary energy in the world, which provides up to 6 percent of the world energy supply. Only the Russian Federation, PRC, the United States of America and the Kingdom of Saudi Arabia have larger production volumes. However, oil plays the most significant role in Canada's energy exports. It is estimated that its proven reserves are sufficient to meet the demand for 140 years at current production rate. The relevance of the study, including the analysis of fuel and energy complex of Canada, is due to the fact that such comparison and synthesis of data on the amount of recoverable oil reserves, the volume of its production, imports, exports and transit of oil and oil products, the distribution of oil for transportation (via pipelines, rail, sea, road), strategic oil field, refining and transportation of oil and oil products development projects, as well as implementation of Canada's best practices in the Russian Federation, is being developed for the first time. In addition, the data given in previously published articles on the subject, due to the dynamic development of the industry, are obsolete and do not reflect the real situation.

Rift that will Host Important Deposits of Hydrocarbons: A Review of the Petrologic Constraints Recorded by the Mantle Peridotites from Ophiolite Massifs

Rift formation has long been the focus of attention for researchers, and numerous studies have been carried out in order to understand causes and modes of whole lithospheric extension. The process of lithospheric rifting is classically considered to be a product of “active rifting” or “passive rifting”, depending upon which forces are involved at the inception of rifting. Continental rifting is conventionally described as a thinning process of the whole lithosphere, ultimately leading to rupture of the continent, onset of sea-floor spreading and the consequent formation of a mid-oceanic ridge. Rifting is the initial and fundamental process by which the separation of a continent into two tectonic plates takes place. Active rifting or mantle-activated rifting has been classically ascribed to the ascent of a mantle plume impinging upon the base of the lithosphere, with consequent heating and thinning of the lithosphere. Passive rifting has been classically considered the result of horizontal stretching of the continental lithosphere, in which far-field tectonic stresses, generated at the boundaries of the lithospheric plates, result in lithosphere extension. Continental rifts are the sites of significant oil and gas accumulations, such as the Viking Graben and the Gulf of Suez Rift. Thirty percent of giant oil and gas fields are found within such a setting. In 1999 it was estimated that there were 200 billion barrels of recoverable oil reserves hosted in rifts.

Oil and gas cooperation between China and Central Asia in an environment of political and resource competition

This paper investigates Central Asia’s oil and gas resources, special geopolitics and energy competition, and approaches, challenges and prospects in cooperation between China and Central Asia. The objective is to propose measures for oil and gas cooperation between China and Central Asia. Central Asia is rich in oil and gas resources. Its remaining recoverable reserves of crude oil and natural gas account for 1.9% and 10.6 %, respectively, of the world’s total reserves. Moreover, there is great exploration and development potential. As a strategic channel connecting Eurasia, Central Asia has a prominent geopolitical status. Many powerful countries such as the United States, Russia and China, as well as Europe, have an intense energy competition in Central Asia. In the oil and gas cooperation with Central Asia, the China National Petroleum Corporation (CNPC) focuses on establishing a coordination group, promoting overall oil and gas business opportunities and sustainable development, innovating and applying specialty engineering technology and improving project economic benefits. Through its efforts over the last nearly two decades, the China National Petroleum Corporation has completed a 50-million-tonne a year oil and gas production centre in Central Asia and oil and gas pipelines passing through multiple countries, becoming an important channel for securing China’s energy imports. If appropriate measures are taken in the ‘Thirteenth Five-Year Plan’ period or later, the China National Petroleum Corporation will develop a 100-million-tonne p.a. oil and gas production centre in Central Asia and a strategic oil and gas import channel exceeding this amount of production. This cooperation between China and Central Asia is however faced with the following challenges: increasing multinational competition uncertainty, potential risks in the political systems of Central Asian countries, frequently occurring violence and also resource policy tightening in Central Asia. To further oil and gas cooperation with Central Asia, it is recommended that China should develop an energy acquisition strategy, assign a regional energy ambassador, enhance oil and gas supply by mergers and acquisitions, establish regional multinational subsidiaries and improve its risk prevention system.

Definition of facies conditions by granulometric analysis on the example of horizons JK2-5 in Em-Egovskoe field (Western Siberia)

The significance increase of recoverable oil reserves in reservoirs of deep horizons requires more detailed study of their formation conditions. Granulometric and mineralogical investigations of terrigenous sediments allow obtaining the basic ideas on their sedimentation conditions. In this case the combination of the existing methods enables to address some issues of facies analysis. The integrated investigations of the horizons JK2-5 of Tumensk formation in Em-Egovskoe area, Krasnoleninskoe field (208 samples) have been performed. Based on granulometric and mineralogical studies, the authors made the conclusion that the sediments studied had been formed within the estuary. The results of the study show that the sedimentation conditions may be different under the same dynamic accumulation conditions and similar particle granulometric distributions. The efficiency of facies prediction can be enhanced only through the integrated analysis.

A feasibility study on in-situ heating of oil shale with injection fluid in China

The reserves of oil shale are over 5 times as many as the current natural proven recoverable oil reserves in the world. It has huge potential but it is hard to obtain economic efficiency because of its low oil length and exploration difficulty. This research combines theory and experiment, evaluates the exploitation of in-situ heating of oil shale with injection fluid, which have the characteristics of high oil length, large productivity and short production cycle. For the oil shale layer with high oil length (>18%), the oil price shall at least reach 105 $/bbl (18% oil length) to maintain 10% of the internal rate of return; for the oil shale with low oil length (3.5–18%), the oil price shall at least reach 377 $/bbl (5% oil length) to maintain 10% of the internal rate of return. At present, only the oil shale with high oil length (>18%) can be exploited for in-situ heating of oil shale with injection fluid in China.

Predicted new large oil pools in the main petroliferous belt of the Lena-Tunguska province

Almost all the gas-oil and oil-gas fields in the Lena-Tunguska province (Siberian Platform) were discovered in the Baikit, Katanga, and Nepa-Botuobiya petroliferous regions, which form an E-W-striking band. The latter, named “the main petroliferous belt,” includes one giant and 11 large fields (by recoverable oil reserves).New large oil pools are predicted within the main belt. The prediction is based on the analysis of geological data and the quantitative estimation of hydrocarbon resources. Promising areas with large fields in the Baikit, Katanga, and Nepa-Botuobiya petroleum regions are substantiated.

Comments: Global Shale Prospects

Editor's column Several years into the “shale revolution,” progress remains confined largely to North America. It is a viable question whether the shale oil and gas business will take off outside North America at all, or just at a slower pace. The reasons for slow growth vary from country to country but center around lack of infrastructure, ownership rights, government and public support, an active service sector that can support the activity, and whether such production makes sense economically. The growth in shale oil over the past few years has been impressive. Unconventional oil production in the Permian Basin, Eagle Ford, and other areas has lifted output in the state of Texas to 2.7 million BOPD. North Dakota’s production, thanks to the Bakken, has doubled to almost 1 million BOPD. Total US production reached 7.5 million BOPD last year, a yearly increase of 1 million BOPD and, according to a US Department of Energy forecast, could hit 9.3 million BOPD by the end of next year, which would make the US among the top producers in the world. With oil prices for WTI and Brent still around USD 100/bbl, economics would appear right for continued growth in unconventional E&P. And several countries have unconventional resources rivaling that of North America. Commercially recoverable reserves of tight oil could be double or more those of North America and the geology of many of those prospects is better, according to a study released last year by IHS. Russian’s Bazhenov shale in Siberia has been called the “next Bakken” and initial estimates suggest it could be the largest shale oil deposit in the world. Shell and Gazprom have begun drilling the first of five horizontal wells there after several years of assessment. Rosneft and ExxonMobil agreed in 2012 to jointly develop the shale and will be undertaking a study to determine the commercial potential of the resources. The Asia Pacific region holds 74 billion bbl of technically recoverable tight oil resources, according to the International Energy Agency’s World Energy Outlook 2013. The most promising prospects are in China, Australia, and Indonesia. Most forecasts are optimistic about China’s prospects. It is estimated to hold the world’s third-largest technically recoverable tight oil resources, 32 billion bbl across the Junggar, Tarim, and Songliao basins. Growing oil demand in the country and a supportive government should encourage production. And the country is adept at using hydraulic fracturing and horizontal well drilling because of its abundance of low-permeability fields. Advanced studies and preliminary drilling by PetroChina, Sinopec Hess, and Shell have already taken place. A state intervention model for shale oil advancement will help countries such as China develop infrastructure needed for development. Also boosting the country’s chances are the experience that several Chinese firms have gained working in unconventional projects in North America. JPT

International Transport of Captured $$\hbox {CO}_2$$ CO 2 : Who Can Gain and How Much?

If carbon capture and storage (CCS) is to become a viable option for low-carbon power generation, its deployment will require the construction of dedicated CO2 transport infrastructure. In a scenario of large-scale deployment of CCS in Europe by 2050, the optimal (cost-minimising) CO2 transport network would consist of large international bulk pipelines from the main CO2 source regions to the CO2 sinks in hydrocarbon fields and saline aquifers, which are mostly located in the North Sea. In this paper, we use a Shapley value approach to analyse the multilateral negotiation process that would be required to develop such jointly optimised CO2 infrastructure. First, we find that countries with excess storage capacity capture 38–45 % of the benefits of multilateral coordination, implying that the resource rent of a depleted hydrocarbon field (when used for CO2 storage) is roughly \({\$}1\) per barrel of original recoverable oil reserves, or \({\$}2\) per boe (barrel of oil equivalent) of original recoverable gas reserves. This adds 25–600 % to current estimates of CO2 storage cost. Second, countries with a strategic transit location capture 19 % of the rent in the case of national pipeline monopolies. Liberalisation of CO2 pipeline construction at EU level could eliminate the transit rent and is shown to reduce by two-thirds the differences between countries in terms of cost per tonne of CO2 exported. Reaching agreement on such liberalisation may be politically challenging, since the payoffs are shown to be strongly divergent across countries.

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.

Shale 2.0: From Efficient to Effective Shale Development

Guest editorial Hydrocarbons from shale were first produced commercially as long ago as 1821, and from the 1860s through the 1920s gas was produced from shallow, low-pressure, naturally fractured shales in the eastern US. However, today’s shale “revolution” did not really begin until 1985. That was when George Mitchell started developing a model for economically viable exploitation of the Barnett Shale. It took almost 20 years and literally hundreds of wells to find the right formula, based on two transformative technologies: horizontal drilling and multistage hydraulic fracturing. Shale 1.0: The Quest for Operational Efficiency Since roughly 2005—the beginning of what I call Shale 1.0—we have successfully revived old shale plays and developed new ones. Every year, North American companies complete thousands of wells in shale reservoirs. However, even in mature plays like the Barnett, where productivity per well has doubled or tripled over the past decade, as many as 30% of all perforation clusters contribute absolutely nothing to production. That is the same as drilling 30 totally nonproductive wells out of every 100. To improve shale economics, operators and oilfield service companies have focused considerable brainpower and technical resources on reducing the unit cost of production through greater operational efficiency. In many cases, we have brought drilling and completion costs down 50%, largely through application of new technologies, efficient project management, and supply chain negotiations. In some cases, advanced drilling technologies, automation, and real-time data have slashed average time to total depth from 48 days to just 8. Not all new technologies are exotic. For example, installation of rupture disk valves—which replace coiled tubing or drillpipe-conveyed perforations for the first stage in horizontal wells—reduced completion costs in 15 Eagle Ford wells by more than USD 100,000 per well. The shale revolution has yielded many economic and social benefits, including growth in jobs and local businesses across the US, lower domestic energy costs, reduced CO2 emissions, and—perhaps most important—access to a new national resource that holds enormous potential for long-term energy security. According to the Institute for Energy Research, the US has more than 200 years’ capacity of technically recoverable oil reserves and 110 years’ worth of natural gas at current rates of consumption, much of those from unconventional plays. In fact, shale oil is leading the current growth in US crude production. The US Energy Information Administration conservatively predicts global shale oil production will reach more than 4 million BOPD by 2030. Other analysts double that estimate.

An Evaluation Model of the Recoverable Reserves at Risk for Exploration and Development Projects of International Petroleum

In this study, we propose an evaluation model of the recoverable reserves for exploration and development projects of international petroleum. Due to the greater of the Exploration and Development Projects of International Petroleum (EDPIP) and defects of traditional methods, the study introduced the ideas of at risk into the evaluated methods of recoverable reserves of oil and gas and explored the Recoverable Reserves Risk (RRsaR) of petroleum for the EDPIP. The model can effectively deal with the dilemma of traditional methods and make the evaluated results combined with the risk. And it can present the petroleum recoverable reserves under the conditions of different (namely different probabilities) for the investors.

First Barents Sea Oilfield Development Emphasizes Oil Spill Preparedness

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 156773, ’Implementation of the Oil Spill Preparedness for the Goliat Offshore Oilfield Development—The First Oilfield Development in the Barents Sea,’ by Erik Bjornbom and Ole Hansen, Eni Norge; Frode Engen, Statoil; and Sjur W. Knudsen, Norwegian Clean Seas Association for Operating Companies, prepared for the 2012 SPE/APPEA International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Perth, Australia, 11-13 September. The paper has not been peer reviewed. The Goliat field will be the first offshore oil field in the Barents Sea and the world’s northernmost offshore oil field. The field is in the southwestern part of the Barents Sea, close to the coastline in an environmentally sensitive area. The implementation of the Goliat oil spill preparedness plan will introduce new technologies and methods, the results of projects and initiatives developed in cooperation with the Norwegian Clean Seas Association for Operating Companies (NOFO). This will give an increased oil spill response capability, especially for the coastal zone. Goliat Field Development The Goliat field is an oil and gas discovery in the southwestern Barents Sea. Goliat contains two main oil-bearing reservoirs (Realgrunnen and Kobbe) with 28×106 std m3 of recoverable oil reserves. In addition, the field contains 8.8×109 std m3 of gas. The field is approximately 85 km from the city of Hammerfest in the county of Finnmark and approximately 50 km southeast of the Snøhvit offshore gas field (Fig. 1). The water depth in the license area is between 248 and 436 m. The Goliat field is to be developed by 22 subsea wells drilled from eight tem-plates linked to a circular floating production, storage, and offloading (FPSO) facility (Fig. 2). The Goliat development represents one of the largest industrial projects ever undertaken in northern Norway. The well stream will be processed on the FPSO, and the oil will be exported to market using tankers. During the first phase, produced gas will be reinjected to provide pressure drive. This will, in addition to the injection of seawater, attain the total pressure drive necessary to achieve optimal production of the resources. The facility will run on power supplied from land combined with an onboard power-generation system. In 2009, the Norwegian parliament approved the plan for development and operation for the Goliat field, with seven specific conditions that the project needs to fulfill. For the first time in Norway, one of the specific conditions was related to oil spill preparedness: “In the light of the particular challenges in the northern areas and the Goliat field’s proximity to the coast, oil spill contingency strategies must be assigned very high priority. The operator shall carry out a detailed evaluation of the infrastructure within the area of influence of potential polluting emissions and discharges from the Goliat field. The operator shall implement measures designed to consolidate the oil spill contingency strategies in the affected municipalities … .”

Выделение категории энергетически обоснованных извлекаемых запасов нефти

Выделение категории энергетически обоснованных извлекаемых запасов нефти

Quantitative Models of Development Laws for Heterogeneous Sandstone Reservoirs by Water Flooding

The Lorenz curve is used to estimate the heterogeneity of an oil reservoir. The corresponding permeability distributions in a series of concept reservoir models with a uniform average permeability but different heterogeneities are obtained and characterized by inverse calculation of the Lorenz curve. Then the development laws of a reservoir in relation to its heterogeneity are studied in method of numerical simulation. The results show that reservoirs with a Vk (permeability variation coefficient is defined in appendix) which characterizes the heterogeneity less than 0.2 have almost the same development rule. It is also found that the permeability profile is consistent with the water-cut profile in both positive and reverse rhythm reservoirs where injected water channels in high permeable layers. Furthermore, the water-cut profile of a reverse rhythm reservoir is more uniform than that of a positive rhythm reservoir. In addition, results also show an exponential relation between water-free recovery and variation coefficients in positive rhythm heterogeneous reservoirs. From the simulation results of reservoir models with different oil-water viscosity ratios, it is found that during the development process, the water-free recovery firstly decreases rapidly with an increasing oil/water viscosity ratio less than 30:1 before it decreases slightly. Besides, a modified logistic function is built to present the relation between ultimate recovery and variation coefficient for positive rhythm reservoirs. The ultimate recovery firstly decreases slightly before the permeability variation coefficient increases up to 0.4, and then decreases sharply. However, the inflexion of variation coefficient in a reverse rhythm one is 0.6. An algebraic equation is also built to describe the water cut change with the recovery factor of recoverable oil reserves. The water-free recovery is higher in a reverse rhythm reservoir than that in a positive rhythm reservoir especially in a reservoir with a relative small oil/water viscosity. However, the ultimate recovery of a reverse rhythm reservoir is higher than that of a positive rhythm reservoir. Also, during development process, the water-cut increases faster in a positive rhythm reservoir than in a reverse rhythm reservoir especially for medium heterogeneous reservoirs.

A new method to optimize the fracture geometry of a frac-packed well in unconsolidated sandstone heavy oil reservoirs

The worldwide proven recoverable reserves of conventional oil are less than the amount of the heavy oil. Owing to weakly consolidated formation, sand production is an important problem encountered during oil production in heavy oil reservoirs, for which frac-pack technique is one of the most common treatments. Hence, how to obtain the optimal fracture geometry is the key to increasing well production and preventing sand. Due to the faultiness that current optimization of the fracture geometry only depends on well productivity, fracture-flow fraction was used to describe the contribution of the fracture collecting and conducting fluids from the reservoir. The higher the fracture-flow fraction, the more likely bilinear flow pattern occurs, thus leading to smaller flow resistance and better results in oil productivity and sand prevention. A reservoir numerical simulation model was established to simulate the long-term production dynamic of a fractured well in rectangular drainage areas. In order to reach the aim of increasing productivity meanwhile preventing sand, a new method based on Unified Fracture Design was developed to optimize the fracture geometry. For a specific reservoir and a certain amount of proppant injected to the target layer, there exits an optimal dimensionless fracture conductivity which corresponds to the maximum fracture-flow fraction, accordingly we can get the optimal fracture geometry. The formulas of the optimal fracture geometry were presented on square drainage area conditions, which are very convenient to apply. Equivalent Proppant Number was used to eliminate the impact of aspect ratios of rectangular drainage area, then, the same method to optimize the fracture geometry as mentioned for square drainage areas could be adopted too.

An integrated approach to energy prospects for North America and the rest of the world

Many international organizations and research institutions have released recently unequivocal scenarios on energy's future prospects. The peak in global oil production is likely to happen in the next ten to fifteen years, if it hasn't already happened, and decisions to be made in the near future are likely to have large impacts on our quality of life in the coming decades. This study presents an integrated tool for national energy planning customized to North America. The authors analyzed the impact of world oil production on economic, social and environmental indicators. Two cases of global ultimate recoverable oil reserves are considered, a low and medium estimate within current research. Three sets of policy directions were chosen: Business As Usual (Market Based), Maximum Push for Renewables, and Low Carbon Emissions. Results of the simulations show that without restrictions on emissions coal becomes the dominant energy in the longer term. On the other hand, if US policymakers are able to effectively implement the necessary polices, such as a 20% RPS by 2020 and increased CAFE Standards, along with increased energy conservation and efficiency, the medium to longer-term economic impacts of a global peak in oil production can be mitigated, while a sustained reduction in emissions would require a larger effort.

Greenhouse-gas emission targets for limiting global warming to 2 °C

More than 100 countries have adopted a global warming limit of 2 degrees C or below (relative to pre-industrial levels) as a guiding principle for mitigation efforts to reduce climate change risks, impacts and damages. However, the greenhouse gas (GHG) emissions corresponding to a specified maximum warming are poorly known owing to uncertainties in the carbon cycle and the climate response. Here we provide a comprehensive probabilistic analysis aimed at quantifying GHG emission budgets for the 2000-50 period that would limit warming throughout the twenty-first century to below 2 degrees C, based on a combination of published distributions of climate system properties and observational constraints. We show that, for the chosen class of emission scenarios, both cumulative emissions up to 2050 and emission levels in 2050 are robust indicators of the probability that twenty-first century warming will not exceed 2 degrees C relative to pre-industrial temperatures. Limiting cumulative CO(2) emissions over 2000-50 to 1,000 Gt CO(2) yields a 25% probability of warming exceeding 2 degrees C-and a limit of 1,440 Gt CO(2) yields a 50% probability-given a representative estimate of the distribution of climate system properties. As known 2000-06 CO(2) emissions were approximately 234 Gt CO(2), less than half the proven economically recoverable oil, gas and coal reserves can still be emitted up to 2050 to achieve such a goal. Recent G8 Communiques envisage halved global GHG emissions by 2050, for which we estimate a 12-45% probability of exceeding 2 degrees C-assuming 1990 as emission base year and a range of published climate sensitivity distributions. Emissions levels in 2020 are a less robust indicator, but for the scenarios considered, the probability of exceeding 2 degrees C rises to 53-87% if global GHG emissions are still more than 25% above 2000 levels in 2020.

Too much of a bad thing

There are various — and confusing — targets to limit global warming due to emissions of greenhouse gases. Estimates based on the total slug of carbon emitted are possibly the most robust, and are worrisome. How quickly greenhouse-gas emissions need to be reduced in order to avoid what has been termed dangerous climate change is of fundamental importance. Two papers in this issue tackle the question from different standpoints, yet come to broadly similar conclusions. Meinshausen et al. relate the cumulative emission of greenhouse gasses by 2050 to the probability of exceeding the 2 °C of global warming above pre-industrial temperatures adopted by more than 100 countries as the threshold of dangerous climate change. They find that only about a third of economically recoverable oil, gas and coal reserves can be burned if global warming of 2 °C is to be avoided by 2100, an amount of fossil fuel that would be burned by 2029 if consumption remains at today's levels. Allen et al. use a combined climate and carbon cycle model to produce simulations spanning a range of climate futures consistent with the changes already observed. The 500 billionth tonne of anthropogenic carbon since 1750 was recently released into the atmosphere, and Allen et al. find that releasing a trillion tonnes of carbon in total is likely to cause a peak warming exceeding the 'acceptable' 2 °C temperature increase. Every tonne released thereafter increases the committed maximum warming in a predictable way, regardless of when it is released. Any effective climate mitigation regime must therefore achieve a cap on cumulative carbon dioxide emissions — one trillion tonnes would be a possible though optimistic target. In News and Views, Gavin Schmidt and David Archer consider these papers and other recent work focusing on establishing achievable emissions targets.

Using Spoolable Composite Pipe in a Large CO2 Enhanced Oil Recovery Project to Reduce Flowline Installation and Lifecycle Costs

Abstract Historically, steel pipe has been the primary material used in oil and gas production gathering applications. More than 25 years ago, glass fiber-reinforced epoxy (ORE) pipe was introduced to the oil and gas industry, and this material has been used in applications where internal or external corrosion was causing high failure rates and maintenance costs in steel pipelines. ORE pipe (commonly called stick fiberglass) is produced in joints typically just over 9 m (30 ft) in length, which are mechanically joined together during installation. Overall construction costs for steel and ORE pipe are similar. In both steel and ORE, the underlying pipe and construction technologies are mature, and thus it is difficult to reduce total installed costs beyond small increments. More recently, spoolable composite pipe has become a widely accepted alternative to these materials demonstrating lower capital and operating costs for infield gathering and injection applications, as well as improved pipe integrity and field performance. This paper describes a major operator's experience using Fiberspar ® spoolable composite pipe in place of steel and stick fiberglass in one of Canada's most highly visible CO2 enhanced oil recovery (EOR) projects. Fiberspar LinePipe ™ enabled this operator to reduce flowline costs while eliminating corrosion related failures and problems with joint integrity in this hostile producing environment. This paper summarizes actual field experience showing how LinePipe can substantially reduce costs and improve pipe integrity over the producing life of a field. Weyburn Project Overview The Weyburn Oil Field is operated by EnCana and lies on the northwestern rim of the Williston Basin. It is 16 km (10 mi) southeast of Weyburn in southern Saskatchewan. Production began in 1954, and currently there are approximately 990 production and water injection wells in operation. The average daily crude oil production is 2,900 m3/d (c. 18,200 bbl/d). Over its lifetime, the field has produced roughly 55 million m3 (c. 346 million bbl) of oil from primary and waterflood production. The field is currently in production decline, having produced approximately 25% of the estimated recoverable oil reserves. EnCana announced in 1997 that it would develop an EOR project to extend the life of the Weyburn Field by more than 25 years. The project involves a CO2 miscible flood, which is expected to extract an additional 19 million m3 (122 million bbl) or more of oil from the field. Waterflood injection is used to increase reservoir pressure, while pushing oil to producing wells to improve recovery. A miscible flood is an enhanced oil recovery technique where a fluid (CO2) is injected into the reservoir to expand and sweep the oil to the producing wells, increasing recovery rates beyond waterflooding. The Weyburn project is highly significant for three reasons:Apart from giving new life to an old field, the use of CO2 as a miscible flood agent makes Weyburn Canada's largest greenhouse gas sequestration project. For this reason, the Weyburn project is the site of a world-scale research initiative operated under the auspices of the International Energy Agency, which is studying the sequestering of CO2 in an oil reservoir.