The entrepreneurial spirit is an increasingly valuable asset in today's economy. The same toolkit used to launch a business from scratch turns out to be quite applicable to larger, more established organizations as well. Mature energy companies and even nonprofit or government bodies have just as much need as startup companies for ambitious employees who have the ability to identify problems, listen to customers/stakeholders, marshal resources, and inspire teams to create efficient solutions. The George R. Brown School of Engineering, part of Rice University in Houston, Texas, is tasked with preparing the next generation of engineers for careers in academia or industry. In fact many of the students could spend the majority of their professional lives working in the energy industry.
More than half of all existing wells are estimated to require sand control or sand management throughout their lifetime, including unconsolidated sandstone in conventional reservoirs or flowback in unconventional reservoirs. The majority of recent major hydrocarbon discoveries, from Africa (Mozambique, Angola, and Tanzania), transcontinental countries (Egypt), North America (US and Canada), to Far East Asia (Malaysia), are offshore with high-permeability soft formation sands. Approximately half of them are gas-bearing reservoirs. High-flow-rate gas wells are particularly susceptible to sand production. High-velocity or turbulent fluid flow generates large drag forces, dislodging unconsolidated sand particles.
One of the primary energy sources, natural gas is widely used for power generation, industrial production, transportation, commercial buildings, and households. The industry is a capital intensive one for all stages from exploration to delivery. Two types of supplies: pipeline and Liquefied Natural Gas (LNG), recently have faced a direct intra-industrial competition. Physical nature of methane and associated transportation costs lead to domination of so-called "natural monopolies" or "national champions" and strict government regulation, which postponed the development of free trade and competition. After decades of technical innovations and cost curve improvement in LNG sector, shale boom in the USA, increasing global consumption, and demand for supply diversification reformulated the role of gas in the global energy balance. While the pipeline sector remains to be in the hands of large corporations and a subject of strategic interstate and international agreements, or LNG provides more diversity and flexibility of trade. However, even after a long history of LNG shipment since the late 1950s, LNG market is still regional with high spreads between countries and terms of delivery.
The paper presents the evolution of business models in the natural gas industry, focusing on the primary drivers as government regulation, production technologies, and regional markets trends on the way to liberalization and cointegration. Thus, our primary objective is to show relative influence power of these drivers. This analysis also defines the competitiveness of corporate business model under conditions of asymmetric information, regional gas markets, deregulation trends, fast-growing production technologies and downstream infrastructure (specifically in LNG sector). We also enclose the analysis of the most globally competitive gas projects. We analyze changes in value chain change and trading contracts. Our methodological approach poses model-based principles, including option and contract models, jointly with game theory elements.
Sourcing water for hydraulic fracturing and disposing of produced water are well-known constraints and significant cost items in the development of shale formations in the Permian Basin. Utilizing a water life-cycle approach, some of the produced water can be treated and reused. However, there is usually more produced water than needed and some must be disposed, typically by injection into a disposal well. Whether the water is to be reused or disposaed, it must be treated to some extent. Given the volumes of water involved, treatment technology must be robust and inexpensive. This suggests that the selected technology should be tailored to the characteristics of the water and the quality requirements of the final purpose (reuse or disposal).
This paper starts with characterization of produced water from a few Permian shale fields and proceeds to the selection of appropriate conventional, robust and low cost treatment systems. Using this approach, fit-for-purpose treatment systems have been implemented in the field. Impairment problems with reuse and disposal of this treated produced water have decreased.
A common pitfall in history matching is to falsely generalize the learning from local data to the entire field, which can lead to radical over-estimation of uncertainty reduction and bad reservoir management decisions. This problem is referred to as the local-global problem and in this paper a methodology is proposed to quantify and correct for the error arise from this problem.
Most performance metrics in an oil field, such as estimated ultimate recovery (EUR), are field-level ob jective functions that depend on properties (e.g., porosity) over the entire field. On the other hand, most measurement data (e.g., BHP) are sensitive only to a local area around the wells and are thus susceptible to local variation of geological properties. Calibrating field-level objective functions and multipliers of global properties (e.g., porosity) to local well data over-estimates the reduction of global uncertainties. In this paper, we derived the formula to quantify error in the calibrated posterior distribution (S-Curve) resulted from the local-global problem, as well as a correction factor to recover the true posterior S-Curve.
Through theoretical derivation, it is shown that the model error arise from the local-global problem is dependent on the magnitude of the global and local variation of the uncertain properties (e.g., porosity). The larger the local variation relative to the global variation, the larger the error is in the estimated posterior S-Curve. The error also depends on the variogram of the local variation, and the detection range of the data. The error is larger for case with long variogram for the local variation and short data detection range. In addition, this model error can be highly correlated for different measurement data points even when the measurement error for these data were independent. To address this local-global modeling error, a series of analytical and empirical formula is proposed, which has successfully corrected the error and greatly improve the posterior S-Curve for a series of cases.
To the best of our knowledge, this is the first time the error from the local-global problem is quantified and corrected. The methodology proposed could help improve the reliability of the result from probabilistic history matching.
The Ensco 107 rig was used to spud the Dorado-1 well offshore Western Australia. The Australian natural gas company Santos has acquired Quadrant Energy for $2.15 billion. The company said in a statement that the acquisition would be fully funded from existing cash resources and new committed debt facilities. Quadrant Energy holds natural gas and oil production, near- and medium-term development, appraisal, and exploration assets across more than 20,000 square miles of acreage, with most of it located in the Carnarvon Basin offshore Western Australia, the country’s largest offshore oil and gas province. In July, Quadrant made a large discovery at Dorado, located in the Bedout Basin near the Pilbara region in northern Western Australia.
Liu, Xiaodong (CNPC Boxing Co.of China National Petroleum Offshore Engineering Co.,Ltd.) | Xie, Binqiang (Yangtze University) | Gao, Yonghui (CNPC Boxing Co.of China National Petroleum Offshore Engineering Co., Ltd.) | Gu, Huiling (CNPC Boxing Co.of China National Petroleum Offshore Engineering Co., Ltd.) | Ma, Yongle (CNPC Boxing Co.of China National Petroleum Offshore Engineering Co., Ltd.) | Zhang, Yong (CNPC Boxing Co.of China National Petroleum Offshore Engineering Co., Ltd.) | Zhang, Ruxin (State Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum-Beijing) | Li, Qingyang (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University)
It brings severe challenges to drilling fluids when drilling high temperature deep well in environmentally sensitive sea area and facing strict environmental protection laws and regulation requirements meanwhile, the toxic value of drilling fluid must reach up the standard requirement of 30,000 mg/L.A new, environmentally safe water-based polymer system has been developed for drilling applications with temperatures resistance to 200°C and biological toxicity value LC50 more than 100,000 mg/L.
The new system consists of two basic polymeric components for high temperature rheology and filtration control, along with a special nano-plugging agent, glycol shale inhibitor, extreme pressure lubricant, and barite or formate weight material, providing superior performance for a variety of drilling environments. The system shows the base slurry is light colored and non-toxic to the marine environment, which can be discharged directly into the sea. The environmental friendly feature is a significant superiority over traditional high-temperature systems, such as sulfonated drilling fluid and oil-based drilling fluid which normally require the use of a large number of poisonous additives.
Experiments show that the new system has three important characteristics. Firstly, thermal stability time is more than 72h when aging at 200°C, HTHP filtrate loss is in the range of 12 to 25mL between temperature of 150 and 200°C, and sodium chloride and calcium chloride pollution resistance reach up to 200,000ppm and 5,000ppm, respectively. Secondly, the characteristic of excellent lubricity and inhibition can be comparable to oil based drilling fluids. Thirdly, the low biological toxicity also is one the most important characteristic, 96h LC50 semi lethal concentration of artemia is more than 100,000 mg/L, and EC50 median effective concentration of luminescent bacteria is more than 300,000 mg/L, which meet the biological toxicity discharge requirements for the first level sea area.
The extensive testing results of this new drilling fluid demonstrated its superiority characteristic and low biological toxicity to marine environment. Good results from field testing in Bohai offshore oil field are also presented, the deepest test well depth is 6066m, and the highest downhole temperature is 204°C.
Dashti, Jalal (Kuwait Oil Company) | Al-Awadi, Mashari (Kuwait Oil Company) | Moshref, Moustafa (Kuwait Oil Company) | Shoeibi, Ahmad (Geolog International) | Pozzi, Alessandro (Geolog International) | Estarabadi, Javad (Geolog International)
The Middle Jurassic strata of the NE Arabian Plate compose part of the largest world-class petroleum system, with more than 250 billion barrels of proven hydrocarbons. The Najmah Formation, one of those productive strata located in Kuwait, represents a transgressive deposition within a deep basinal settings and anoxic environments; with its black shales interbedded with bituminous limestones the Najmah Formation works as both reservoir and source rock. Due to its organic richness and maturity, the middle Jurassic formation can be considered the best potential conventional/unconventional play in the Kuwaiti Province.
Evaporates of Gotnia, a HPHT formation overlaying the Najmah reservoir, are dealt with high mud weight (19-21 ppg), to counter the high pressured patches. The identification of Najmah stratigraphic top is crucial for setting the casing point, then reducing the mud weight for the final drilling phase. Missing this critical casing point may lead to several rig NPT and related operational cost increments, such as cement jobs and, in extreme cases, may lead to missing and abandoning the well. When the standard investigation methods, as the optical microscopy, or Gamma Ray failed in identifying the Najmah top, due to the similarity between its limestones and those of Gotnia Formation, the ED X-ray fluorescence (XRF) and X-ray diffraction (XRD) established distinctive formations geochemical ‘fingerprints’, as well as their sedimentary patterns, providing absolute certainties about the casing point position despite a misleading stratigraphy.
The technique of Chemostratigraphy, applied in this study on five exploratory wells, can increase the value of such geochemical fingerprints, providing not only applications as critical casing points ID but also a means to unify stratigraphic schemes, i.e. develop stable reference stratigraphic frameworks: changes in rock geochemistry reflect changes in the relative sea level, thus sediment supply/accommodation, oxygenation and diagenetic conditions.
Once inside the Najmah Formation, the elemental and mineralogical patterns point out different formation sublayers, corroborating many sedimentological and stratigraphic evidences obtained from outcrops and cores analyses. Some redox-sensitive trace metals are delivered to the sediment in presence of organic matter (Ni, Mo, V and U) under anoxic-euxinic conditions and tend to exhibit covariation with TOC, highlighting the best pay zones in the Najmah Kerogen sublayers. Some other metals such as Mn, Fe and Zn, in carbonate sequences, can evaluate the amount of carbonate cement (sparite) among the microcrystalline matrix (micrite); such metals, correlated with mud gas concentration, reveal the most porous sections within calcareous sublayers.
Having access to more detailed rock properties allow for one time decisions making, such as the identification of casing/coring points and the characterization of a reservoir in all its sublayers. Chemostratigraphy has led the operational team to minimize NPT and related costs, the completion team to the right well profiles and the production team to a better overview of the reservoir.
ExxonMobil’s Eighth Discovery Off Guyana Adds Another Development Possibility
Matt Zborowski, Technology Writer
ExxonMobil said it has “encountered 78 m of high-quality, oil-bearing sandstone reservoir” near the Turbot discovery southeast of the Liza field offshore Guyana.
The supermajor’s eighth discovery in the burgeoning oil province could bring about a new development opportunity in the southeast portion of the 26,800-sq-km Stabroek Block. The first phase of development drilling on Liza field began in May.
The Longtail-1 discovery well was drilled to 5,504 m in 1,940 m of water by the Stena Carron drillship, which spudded the well on 25 May. It is the second discovery in that area after the Turbot discovery of late 2017. The two discoveries’ estimated recoverable resources total more than 500 million BOE, said ExxonMobil.
GE To Spin Off Baker Hughes
Pam Boschee, Senior Editor
GE is spinning off Baker Hughes (BHGE) in its strategic plan for growth and shareholder value creation. It plans to focus on aviation, power, and renewable energy.
GE CEO John Flannery said these areas share technologies, digital and additive strategies, and business models.
The separation from Baker Hughes will take place over the next 2 to 3 years as part of GE’s effort to “make its corporate structure leaner and substantially reduce debt,” the company said in a statement. GE Oil and Gas merged with Baker Hughes in July 2017, with GE holding a 62.5% stake. BHGE’s revenue on an annualized basis is $22 billion.
GE Healthcare will also be separated into a standalone company, which will begin immediately and progress over the next 12 to 18 months. The spinoffs of BHGE and GE Healthcare are part of GE’s efforts announced last fall to sell $20 billion worth of assets.
The Big Unknowns for World’s Balancing Act of Supply and Demand
Trent Jacobs, Digital Editor
Last year was a dynamic one for both oil producers and consumers. For much of 2017, oil prices headed north but consumption still outgrew daily production—even as those totals were rising too.
The net effect was seen as a positive for what has been a chaotic oil market in recent years. However, an annual report from BP’s economic group that studies market forces for the company has raised questions about what could disrupt this tenuous balance going forward.
Driven by rising but still relatively low prices, 2017 saw world oil demand increase by an impressive 1.7 million B/D. This 1.8% increase stands above the 10-year average of 1.2% and marks the third year in a row that these figures have seen an uptick.
Equinor Releases Subsurface and Production Data From NCS Field
Stephen Whitfield, Senior Staff Writer
For the first time, the general public will have complete access to the subsurface and production data from a field on the Norwegian continental shelf (NCS). Equinor announced that it will disclose the data from Volve, a shallow-water oil field located in the southern part of the Norwegian North Sea approximately 125 miles west of Stavanger.
Following its startup in February 2008, Volve’s production lasted for approximately 8 years. It was originally scheduled for 3 to 5 years of operation. At its peak, the field produced 56,000 BOPD, and a total of 63 million bbl of oil were produced before the field’s shutdown in September 2016. Equinor said that one of the goals of the data release is to allow students from relevant fields of study to train on real data sets.
Equinor, ExxonMobil Rack Up More Brazilian Pre-Salt Acreage
Matt Zborowski, Technology Writer
Equinor secured interests in two of three blocks awarded 7 June during Brazil’s 4th pre-salt bid round, further expanding its footprint in the growing offshore province alongside ExxonMobil, Shell, BP, and Chevron.
Three of four blocks were awarded overall, each of which will be operated by Petrobras. The state-owned firm has a right of first refusal to petition the government to operate all pre-salt blocks offered. The round received some $800 million in signing bonuses and $190 million in planned exploration investments.
The Norwegian firm took a stake in the highly coveted Uirapuru block in the Santos Basin with partners ExxonMobil and Petrogal Brasil. Petrobras exercised its right to enter the consortium and will be the operator with a 30% interest. Equinor and Exxon-Mobil will each have a 28% stake, with Petrogal Brasil holding the remaining 14%.
Natural fractures are present in the Permian Wolfcamp shales and have the potential to impact well completion operations and hydrocarbon production. In this paper, natural fractures are characterized with the latest borehole image technology, including both acoustic and micro-resistivity measurements. Whole core CT-Scan images are also made available to fully calibrated borehole image interpretation for better understanding of the many fracture attributes, i.e. fracture density, filling minerals, opening types, and termination, etc. Orienting whole core using image logs from the same wellbore was also made possible in this study.
This allowed interpretation of all visible fractures of any size with available fracture dip, strike, length, type and density as output. Litho-bounded, calcite-healed or partial-healed fractures are the dominant type within the formation. Open fractures, even though far less common, are also observed, with most of the being partially open. The interpretation concluded that the predominant set of fractures strike NE-SW, with a secondary NW-SE set, in the studied field area. However, fracture density showed considerable variability vertically and spatially among the studied wells.
The fracture facies analysis is first introduced in this study using borehole images, conventional open-hole logs and whole core data. Three basic types of fracture facies are proposed including fractured shale, non-fractured shale and limy beds. The fracture facies data has potential applications in understanding relative rock fracability in the studied Wolfcamp reservoir. The naturally fractured shales are expected to be the easier rock to hydraulically fracture compared to non-fractured shale and limy beds, because, in a sense, they were already fractured in geological history. The existence of abundant planes of weakness (even secondary mineral-cemented fractures) within the facies, takes far less energy to reactivate (or re-open) than to create new fractures during the hydraulic fracturing process. The fracture facies results of relative rock fracability can be used as part of the input for “sweet-spot” definition and/or landing zone decisions, along with available petrophysical & geomechanical properties. The various fracture attribute outputs and the interpreted in-situ maximum horizontal stress (SHmax) helps to understand the hydraulic fracture growth orientation and overall fracture network complexity.