Cubic Feet Of Gas Research Articles

Chevron Applies Some Unconventional Thinking To Try To Make Shale EOR a Standard Treatment

In the shale business, the closest thing now to enhanced oil recovery (EOR) is improved techniques. During an earnings call last November an analyst asked EOG Resources executives about their enhanced completion technique which EOG reported was adding 20% to first-year well production in the Permian. Improved completions have allowed operators to significantly increase early production year after year, but after that, steep declines are a given. Back in 2016, EOG was talking about how it was increasing oil production significantly by injecting millions of cubic feet of gas a day into wells in the Eagle Ford. It triggered an EOR field-testing boom by competitors hoping to match reported reserve increases of “30 to 70%.” In a 2017 JPT story, Deepak Devegowda, a petroleum engineering professor at the University of Oklahoma, said, “This is the name of the game. Everybody is talking about EOR and pumping money into trials of EOR.” Now the only mention of the acronym EOR on EOG’s website is an item in its corporate history timeline for 2016: “We commercialized the first enhanced oil recovery process, or EOR, in shale.” In recent years, reported shale EOR work has been mostly in the form of occasional papers describing production uplift by companies selling ways to increase production by injecting gas or chemicals. EOR effectiveness isn’t the issue, according to Todd Hoffman, a petroleum engineering professor at Montana Tech University who wrote two papers evaluating EOG’s methods cited in two Chevron papers. “The EOG field work showed us that these projects can produce significant additional oil and be economically positive,” he said. The problem is that drilling and fracturing wells delivers “higher economic returns than the EOG-style EOR projects with the huge compressors, high gas rates, and high injection pressures.” Last year in the middle of this EOR drought, Chevron did something different. It delivered two papers revealing a major company-scale effort to find ways to use chemical and gas injections to economically produce more oil. The papers presented at the 2023 Unconventional Resources Technology Conference (URTeC) reported on field tests of surfactants and natural gas injection on Permian Basin wells which delivered sufficiently encouraging results to justify an expanded testing program. (URTeC 3870505 and URTeC 3871386). Chevron described a systematic effort by its corporate technical unit and its Mid-Continent business unit to rethink shale EOR methods based on the unconventional nature of flow through fractured reservoirs and the economic realities in a business where new EOR technology is competing with the profitable status quo. Its methods challenge accepted notions about the role of EOR. In SPE’s disciplines, EOR normally falls under the production topic, “marginal aging fields.” What Chevron tested is better described by the topic, “well interventions.” Rather than looking at these techniques as a way to eke out the last barrels from old wells, the papers describe methods that can be deployed earlier in the life of these short-lived wells.

Local Coal for Power Generation in Pakistan

PREFACE
 Coal contributes significantly to global energy supplies. In 2021, coal was the second-largest energy source consumed globally (Chart 1). Over the years, coal demand has increased substantially from 2.6 billion tons in 1980 to 5.5 billion tons in 2021 (Chart 2). Because of environmental concerns and the increasing trend towards renewables, its share declined in the United States and many European countries, decreasing global consumption in 2014 and onwards. But the trend reversed in 2020. It is because of the Russia-Ukraine war leading to the worldwide energy crisis that the demand for coal has increased.
 According to the International Energy Agency (IEA) forecast, coal demand is expected to exceed the previous coal demand record of 2014 in the next few years. The United States and many European countries are shifting back to coal as it is still one of the cheapest energy sources.
 The primary coal-consuming sector is electricity generation. High natural gas prices have increased reliance on coal for generating power. Coal consumption in electricity generation is expected to grow by more than 2%. If the gas prices continue to increase in 2023 or onwards, dependence on coal will remain, and demand will surge further. Besides gas prices, coal prospects will depend on the transition speed towards renewable energy sources.
 PAKISTAN COAL POTENTIAL
 Pakistan has 186 billion tons of coal reserves, primarily located in the province of Sindh (Chart 4). Only Thar desert (10,000 sq. km) contains the world’s 7th largest coal reserves of about 175 billion tons (Chart 5), equivalent to 50 billion tons of oil equivalent (more than Saudi Arabia and Iran’s oil reserves) and 2000 trillion cubic feet of gas (68 times more than Pakistan’s total gas reserves). Thar Block-II alone contains 2 billion tons of lignite reserves, of which 1.57 billion tons are exploitable. This Thar Block-II can produce 5,000MW of electricity for 50 years, while the total Thar reserves can sustain 100,000MW for over two centuries . Most of the coal in Pakistan is lignite (with more moisture content, up to 50%).

Petrophysical properties and volume estimation of hydrocarbon resources in x field, onshore niger delta: A reservoir characterization study

A reservoir characterization study was conducted on three wells located in X Field, situated in the Onshore region of the Niger Delta. A suite of conventional digital well logs was utilized to identify hydrocarbon-bearing reservoirs, determine reservoir petrophysical parameters, and infer the depositional environment. The study delineated four hydrocarbon-bearing reservoirs, labeled A, B, C, and D, with porosity estimates ranging from 25% to 27%, and permeability values varying from 1863.22md to 2759.78md. These results suggest that the reservoirs have good storage capacity and permit free flow of fluids, consistent with prior research in the Niger Delta. The water saturation values, ranging from 43% to 70% for Well X and 53% to 94% for Well Y, indicate the presence of significant hydrocarbon in reservoir C, while Well Z did not contain any hydrocarbon. The estimation of oil and gas resources indicated that Well X contains 1.11 X 105 barrels/acre of oil and 5.16 X 107 cubic feet/acre of gas, while Well Y contains 4.43 X 106 cubic feet of gas. The analysis of the volume of shale (0.15-0.19) revealed that the reservoirs range from slightly shaly sand to shaly sand. Based on the log motifs, the study suggests that the reservoirs are mainly fluvial channel deposits, and the rapid alternation of thin beds of sand and shale indicates deposits of delta progradation and river floodplain deposits.

Data-driven workflow for the preemptive detection of excess water producing wells drilled in unconventional shales

The continuous rise in global energy demand requires the production of oil and gas from unconventional shale resources. One major concern for oil and gas producers has been the large volumes of produced water associated with the production of hydrocarbon from the shale resources. Yet, to the level of our knowledge, the source/s of the excess water produced in unconventional shale reservoirs has not been presented in a scientific publication. In this work, we developed a data-driven workflow for identifying potentially high water-producing wells drilled in unconventional shale formation and we identified geophysical signatures that explain the source of excess water production from the wells drilled in unconventional shale reservoirs. To that end, we applied unsupervised learning followed by supervised learning to process five conventional well logs, namely shallow and deep resistivity logs, density porosity logs, neutron porosity logs, and gamma ray logs, from wells drilled in two unconventional shale formations – Gulf Coast and Fort Worth. A novelty of our study is the use of clustering methods to generate pseudo-lithology prior to applying classification techniques for determining excess water producing wells. The data-driven workflow built using 23 wells in Gulf coast basin and 29 wells in Fort Worth basin. Fort Worth (FW) and Gulf Coast (GC) basins in the U.S. are highly productive shale basins that produce 380 million cubic feet of gas and 1.74 million barrels of crude oil every day. Additionally, based on permutation feature ranking and Kendall Tau's associated test, we identified the sources of excess water – highly water-wet and low thermally matured shale present at deep depths in Fort Worth basin, and absence of bituminous, pyrite-bearing shales at deep depths in Gulf Coast basin.

Made in New York

Abstract The eight digester towers at New York City's Newtown Creek Wastewater Treatment Plant seamlessly convert sewage into biogas and a dirt-like output, similar to how Mother Nature would do it. At 145 feet high and 80 feet in diameter, each egg holds about 3 million gallons of sludge, converting it into 2 million cubic feet of gas every day.

Life cycle greenhouse gas emissions of crude oil and natural gas from the Delaware Basin

Development of the Permian Basin in recent years has disrupted the global trade of oil and gas. As of January 2020, it was producing more than five million barrels of oil and 20 billion cubic feet of gas per day, with the greatest growth coming from the Delaware Basin sub-play. In this investigation, we report the results of a novel process-based life cycle assessment (LCA) of the greenhouse gas (GHG) emissions associated with oil and gas products from the Delaware Basin, employing extensive operational data including direct measurements of methane emissions. We find that if 1% of the gross gas produced is flared, then the upstream carbon intensity of crude oil is 19.5 kg CO2eq per barrel of crude oil - substantially lower than “global average” intensities reported in the literature. Moreover, the carbon intensities of gasoline, diesel and jet fuel refined from Delaware Basin crudes are approximately 10% less than the U.S. EPA and Department of Energy baselines when a 1% flaring rate is achieved. The life cycle GHG reductions are also a consequence of the physical and chemical properties of Delaware Basin crudes relative to the average crude blend for the U.S., resulting in reduced refinery GHG emissions. We also find that life cycle GHG emissions associated with natural gas from the Delaware Basin are similar to those reported for U.S. shale gas.

Twelve years of unconventional oil and gas development: production performance and economic analysis

Unconventional formations have been actively developed in the US since 2008. However, it is challenging to quantify the impact of technological advancement and geology on production. In addition, the economics of unconventionals is not well-understood. In this paper, we studied five major unconventional formations in the US: the Bakken, Eagleford, Haynesville, Marcellus, and Wolfcamp formations. We used historical data to quantify the impact of technological and geological variations on production. To accomplish this, we identified four phases of unconventional development over the past 12 years during which drilling and completion technology, initial investment, and commodity prices were similar: Phases 1–4. Using statistical analysis, we compared well performance of each phase. Then, we generated type curves for each phase for economic studies. Initial analysis shows that between January 2008 and December 2019, 60,611 horizontal wells were completed in these formations, producing about 8.185 billion barrels of oil, 90 trillion cubic feet of gas, and generating an estimated $816 billion in gross revenue. For the statistical analysis, the level of uncertainty ( $${P}_{10}/{P}_{90}$$ ratio) reduced from Phase 1 to Phase 4 across all formations, suggesting consistent improvements in well productivity over time while county-level analysis shows spatial disparity in well performance. We infer that technology drives temporal changes while geology drives spatial differences in well performance. From economic analysis, Phase 4 type wells had the best production performance, partly, due to improved drilling and completion efficiency. It was also because operators targeted their best acreage to maximize their asset’s potential.

Brittleness evaluation of Naparima Hill mudstones

The brittleness of unconventional source rock reservoirs is an essential parameter that controls the effectiveness of hydraulic fracturing operation. Brittleness can vary with effective pressure (equivalent to burial depth) and can be influenced by fluid saturation. Therefore, a detailed evaluation of rock brittleness is necessary prior to field applications. The late Cretaceous Naparima Hill Formation is the primary source for most of the 4 billion barrels of oil and 10 trillion cubic feet of gas produced in the last hundred years from conventional reservoirs in Trinidad, West Indies. This Formation is now being considered an unconventional reservoir in order to prolong and increase current productions. However, despite being a prolific Formation, there are no available geomechanical data, including brittleness. Brittleness index (BI) is often used to measure rock brittleness. In this study, we determined elastic-based BI from P- and S-wave velocity measurements, at effective pressures up to 130 MPa, for dry and water saturated outcrop mudstones from four lithofacies within the Naparima Hill Formation. The experimental results show that the BI for all four lithofacies, is independent of effective pressures in both dry and water saturated conditions. All four lithofacies can be considered brittle under dry conditions. However, when saturated, the BI reduces, which proves significant for softer lithofacies (siliceous calcareous mudstones and siliceous mudstones). In this saturated state, the harder lithofacies (calcareous mudstone interbedded with black chert and carbonate rich mudstone with nodular chert) are considered marginally brittle and the softer ones, are considered ductile. The results highlight that porosity is the main factor that controls the magnitude of reduction in the BI when the mudstones are fully saturated.

Integrated reservoir management in a Niger Delta oil rim field

Several hundred million barrels of oil and trillions standard cubic feet of gas are enclosed within the oil rim reservoirs in the Niger Delta. The low recovery from these reservoirs can be attribut...

Controls on Petroleum Resources for the Devonian Marcellus Shale in the Appalachian Basin Province, Kentucky, West Virginia, Ohio, Pennsylvania, and New York

Greater than 33 trillion cubic feet of gas, 68 million barrels of natural gas liquids (NGL), and 192 million barrels of water have been produced from the Middle Devonian Marcellus Shale of the Hamilton Group in the Appalachian Basin. These volumes are from more than 11,700 non-commingled wells. Areas of greatest production and future potential for gas and NGL from the Marcellus Shale are within and near the northeast-trending Rome trough in northern West Virginia and Pennsylvania. Southernmost New York, eastern Ohio, western Virginia, and Maryland also contain petroleum potential and (or) reserves. A confluence of factors enhances gas and NGL reserves and resources in the Marcellus Shale. These include (1) brittleness based on lithofacies composition; (2) thickness and distribution of brittle and organic-rich shale; (3) measured thermal maturity of 1% vitrinite reflectance and greater; (4) at least 2 weight percent total organic carbon; (5) dense and complex fracturing and faulting; (6) presence of evaporite beds in the underlying Silurian Salina Group; (7) potential overpressure; (8) current depths of 1,370 m (4,500 ft) and greater, and (9) predominately horizontal wells with laterals that are oriented to the northwest or southeast, or roughly perpendicular to the direction of maximum horizontal stress, and that cross major fault and fracture sets.

Reservoir Geometry Determination and Volumetric Reserve Estimation of an Offshore, Niger Delta Basin Nigeria

Volumetric reserve estimation had been carried out as well as deducing the reservoir geometry of Idje field. Idje field is an 8.4 km2 area between latitudes 4°31’49”N and 4°33’23” N and longitudes 4°34’43”E and 4°36'17"E offshore Niger Delta in a water depth of approximately 1000 m on the continental slope. Well logs suites from ten wells comprising gamma-ray, resistivity, neutron and density were obtained and analyzed. From the result, it was observed that the reservoir was a sedimentary dome possibly resulting from an underlying shale diaper. The volumetric reserve estimate for the D-3 reservoir shows that it contains 15.8 million barrels of oil and 32 billion cubic feet of gas. If the field is produced at the rate of 10,000 barrels per day, it would yield production for approximately 4 years before subsequent secondary and tertiary recovery measures would be employed.

OIL AND GAS POTENTIAL OF THE EUPHRATES GRABEN IN SYRIA

Syria is an important oil producer in the Middle East region with estimated hydrocarbon reserves of 2.5 billion barrels of oil and 8.5 trillion cubic feet of gas. Prospective areas of Syria with proven industrial oil and gas potential are the northeastern part of the Mesopotamia basin, the Euphrates graben, complicated by the Tual-abba-Sinjar uplifts system, the southern part of the Aleppo plateau and the Palmyra region. The Euphrates graben is located in Southeastern Syria with an area of about 90 x 160 km and is part of the fault system that arose in the Late Cretaceous. It is of great economic importance as one of the largest oil fields in Syria and contains the most important oil fields in Syria, where the estimated production reserves about 1 billion barrels of light oil with less quantities of natural gas. The Euphrates rift system can be divided into several structural elements: it is the deepest lower central element and an adjacent group of grabens surrounding the central depression of the Euphrates, and stable relatively elevated blocks. The main part of the gas and oil fields are located in the fields of Taym, Al-Ward, Teshreen and Al-Jibsa. In terms of oil and gas prospects in Syria, it is possible to distinguish the following areas: promising with proven industrial oil and gas potential; promising with direct signs of oil and gas; promising, but little studied; studied, but unpromising; unexplored. In the Euphrates graben there is a sufficiently large number of oil and gas source rocks and productive reservoirs, which indicates the presence of favorable geological factors that determine the prospects of oil and gas sedimentary cover in the Euphrates basin. The oil and gas potential of the Euphrates graben is associated with deposits of the Poleozoic, Triassic, Cretaceous, Paleogene and Neogene. The set of studies performed shows a favorable prospect for the discovery of new hydrocarbon deposits in the continental part of Syria.

Resource Growth Through Petroleum Exploration in PNG

Mesozoic and Tertiary clastic and carbonate reservoirs are prolific producers of high quality liquid-rich gas onshore PNG. LNG projects are among the lowest cost and most profitable globally. Accordingly there has been a recent resurgence of petroleum exploration in PNG.In 2015 Oil Search undertook a country-wide petroleum Common Risk Segment analysis that highlighted potential for giant new oil and gas fields of sufficient scale to support future LNG projects. It also concluded that 40 trillion cubic feet of gas plus 550 million barrels of oil resources remain to be found (representing approximately 60% of PNG’s total petroleum resource).In 2016 Oil Search completed an ambitious integrated structural, stratigraphic, burial, maturation, migration, uplift and erosion model of PNG’s total petroleum system to quantify the locations for highly prospective under-explored regions.Tectonic events at plate and basin scales were re-assessed and correlated within a new country-wide PNG Chrono-stratigraphy of regionally mappable sequences and flooding events, some of Global extent.A Base Tertiary Mega-Sequence Boundary is mappable over the entire onshore to deepwater regions. 130 1D burial models combined with restored 2D structural and stratigraphic cross sections, have contributed to a new regional petroleum charge model of the Foldbelts, Foreland and Offshore regions.It is concluded that petroleum was generated pre- foldbelt during Late Cretaceous times in interior PNG while petroleum is currently being generated at the present day mountain front.A holistic 4D charge model explains why very young foldbelt traps are petroleum charged.

Associated natural gas flare in the integrated market of the southern cone

Reducing greenhouse gas is a major challenge. The oil and gas industry must contribute to this goal, primarily by controlling natural gas flaring and venting, which is a multibillion revenue loss. More than 4000 billion cubic feet of gas is flared every year in the world, leading to almost 400 million tonnes of greenhouse gases. In Latin America, 7.4% of the total gas produced in the region is flared or vented. This article evaluates the status of the flaring and venting of gas in Latin America, focusing on the southern cone countries (Argentina, Bolivia, Brazil and Chile). It also develops a long-term perspective analysis for the region, using an integrated optimization model. Findings indicate that, when transport infrastructure is limited or there is no domestic demand to absorb the associated gas, flaring becomes the least-cost solution in the optimization model. This can be critical in the next decade, due to the excess gas supply or the lack of gas demand to absorb it. Particularly, the natural gas demand associated with the electricity generation in Brazil is reduced by the hydroelectric expansion and a sluggish economy. Therefore, policies must promote options to monetize the stranded gas.

Thermodynamic and Environmental Assessment of Gas Flaring in the Niger Delta Region of Nigeria

This paper discusses the thermodynamic and environmental assessment of flared gases in an oil field. The oil field for the case study is located in the Niger Delta region of Nigeria. The data required for this report were obtained during a nine-year period (2008-2016), which revealed production volumes, flared volumes, operating temperatures and pressures, gas compositions, gas density, and flow rates. With the data and the aid of fundamental thermodynamic equations and MATLAB program codes, analysis was carried out on combustion to ascertain the amount of flue gases. Analyses revealed that a total of 1.99175 × 1011 standard cubic feet of gas was flared during the said period, generating anthropogenics estimated at 582,319,618.1825 m3 (≈1.046 Mt) of CO2, 1,077,510,054.31 m3 (≈2.0 Mt) of water vapour, 14,960,560.91 m3 of methane emitted and contaminated the atmosphere creating serious environmental concerns. Further analyses also showed that the approximate adiabatic flame temperature is about 1965&degC for the field under investigation. Exergy analyses carried out also revealed that a total of 3.6099 × 1013 kJ (36.099 TJ) of exergy was available which would have translated to 1.0189 × 1010 kWh of electrical energy for the period under investigation. Conclusively, some measures that can be taken to prevent gas flaring are that every new project on oil and gas should incorporate technical details of gas gathering and utilization plan at the conceptual and design phases of projects for gas commercialization, establishment of more gas-to-power project for gas utilization. Also Carbon capture technology should be enhanced, although the best option is flaring out based on the astronomical amount of carbon (IV) oxide and other greenhouse gases depicted by the results. The entire work and results showed that gas flaring is undesired and pernicious because it has thermal, environmental and economic consequences.

Applying modern interpretation techniques to old hydrocarbon fields to find new reserves: A case study in the onshore Gulf of Mexico, USA

This study shows how the use of current geological investigative techniques, such as sequence stratigraphy and modern seismic interpretation methods, can potentially discover additional hydrocarbons in old fields that were previously considered depleted. Specifically, we examine the White Castle Field in South Louisiana, which has produced over 84.1 million barrels of oil and 63.1 billion cubic feet of gas but retains additional recoverable hydrocarbons. The field has pay sections ranging from late Oligocene to late Miocene. The upper Oligocene to early Miocene package, which was underexploited and understudied during the previous exploitation phase, contains three primary reservoirs (Cib Haz, MW, and MR). During most of the late Oligocene, the White Castle Salt Dome was located in a minibasin on the continental slope. The Cib Haz and MW reservoirs were deposited in this minibasin and offer great exploitation potential. The Cib Haz interval is an amalgamation of slumped shelfal limestones, sandstones, and shales interpreted to represent a lowstand systems tract (LST). The MW comprises a shelf-edge delta deposit that is also interpreted as part of a LST. The MR reservoir is interpreted as an incised valley fill located in the continental shelf that was deposited during a lowstand of sea level after the minibasin was filled. Finally, it appears that the minibasin acted as a self-contained hydrocarbon system during the late Oligocene, suggesting the possibility of a shale play. In this study, several new areas of interest are revealed that could contain economical amounts of hydrocarbons.

In the Warming Arctic Seas

In the Warming Arctic Seas

E&P Emphasis Is Now on the P

Unconventional E&P The focus in unconventional exploration and production is shifting to maximizing production. “The next big play is getting more out of what you have,” said Jay Ottoson, president and chief operating officer for SM Energy, at the recent Unconventional Resources Technology Conference in Denver. The math is simple. Adding one percentage point to recoveries from the top unconventional formations for oil and gas in the United States will add billions of billions of barrels of oil production and tens of trillions of cubic feet of gas, he said. There is plenty of room for improvement. The examples offered by Ottoson would increase the ultimate recovery rate in the biggest US oil plays from 5% to 6%. Comments by others during the conference, a joint project of SPE, AAPG, and SEG, indicated that range is not uncommon as companies look for ways to do better. Even at those levels, the growing flow of oil and gas from these extensive formations has pushed the US up toward the top of the list of the world’s producers. Scott Key, chief executive officer of IHS, said that in a few years, the United States will again emerge as the world’s largest producer of oil and gas. The production increase has been enough to boost the growth rate of the US economy, turning it into the low-cost producer in refining and chemical making and soon an exporter of liquefied natural gas, Key said. Rick Bott Jr., president and chief operating officer of Continental Re - sources, described the company’s approach as “we have a simple sort of strategy, we drill a lot of horizontal wells.” Anadarko is drilling about one well a day in the Wattenburg field in Colorado, said Brad Holly, vice president for the Rockies at Anadarko Petroleum. While the pace is steady, methods are constantly changing. Improvement is in the details. To begin with, the particulars include more precise drilling of clusters of wells that are spaced and fractured based on a growing understanding of how best to efficiently drain a formation. Continental, which was a pioneer in the Bakken in North Dakota, and SM reported pilot projects on what Bott called “down spacing,” that is, seeking gains by drilling wells on a single pad site to varying depths. “The technology is changing monthly,” he said. Coming are projects to enhance the output of older wells, such as installing downhole pumps and refracturing older wells. “We have not really started working on production enhancements,” Bott said. Anadarko is drilling horizontal wells to revive a formation where new wells must be carefully drilled around many old ones. “We are operating among 17,000 vertical wells. We need to minimize interference with existing wells that are as little as 15 ft away,” Holly said. Products displayed at the conference helped define the challenges of this sort of development. They promised information that could be used to make better development decisions, deliver it fast enough to keep up with rapid field work, and at a price that is in line with price-conscious mass production operations. Unconventional exploration and production is a bit like farming, said Don Westacott, chief adviser for global unconventional reservoirs at Halliburton, who grew up on a farm in western Canada. Both can be profitable enterprises, but they require expensive inputs, the cooperation of nature, skill, and persistence. And both farmers and oil companies can be so productive that they glut the market, driving down prices. Schlumberger offered a reminder of the challenges of this business during a display at its booth. At the bottom of the screen during a video on its TelePacer drilling platform, which is designed to help drillers drill wells according to plan, was a constant reminder that 40% of wells are subeconomic and 35% of all fracture stages do not contribute.

Emerging Frontiers: Collaboration

President's column One of the personal objectives I took as president was to increase the extent in which SPE collaborates with other professional societies and other industries. This is important for two reasons. First, I think we all will agree that meeting the world’s increasing energy demand is becoming more challenging. Reservoirs are becoming more difficult to find and produce. They are generally smaller, more complex, and exist in increasingly challenging environments, whether in the Arctic, beneath 10,000 ft of water, or at very high pressures and temperatures. We need all the help we can get from experts in other domains, other industries, and nascent technologies being developed for different uses. Second, project costs are increasing at a much higher rate than new production; it is taking more technology, effort, and capital expenditure (Capex) to produce another barrel of oil and another thousand cubic feet of gas. Over the past 10 years, exploration and production (E&P) Capex spend has grown approximately by 400% while global oil production is up by only 15%. In just the past 3 years, the upstream E&P industry has spent on average USD 600 billion per year, and the only part of the oil production base that has grown significantly is the liquids production from North American unconventional resource plays (Kibsgaard 2014). The relatively easy oil - the first trillion barrels or so we have already produced - has been developed and the next trillion will be much more costly and require more sophisticated, integrated technologies and processes. This is why we must reach out to other industries and societies to identify new processes, different ideas, and innovative technologies.

Walking the Wall

Walking the Wall