|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Special Section: The Value and Future of Petroleum Engineering
In the JPT issue celebrating SPE’s 50th anniversary, John C. Calhoun addressed how distinctive petroleum engineering is from other engineering disciplines:
“During the past several decades, consolidation and integration of four major elements of petroleum engineering have occupied the profession. The following lists these elements.
Since that issue a little over a decade ago, petroleum engineering feats have expanded on the past and made towering breakthroughs in resource recovery. Those breakthroughs came about with added emphasis on decision and risk analysis as an essential project element; a step up from what was referred to as a coupling with business. Reviewing our technology history thus requires highlighting the tangible breakthroughs with the necessary intangibles that enabled faster transformations with commercial success (Fig. 1).
Tangible Breakthroughs Arguably the biggest breakthrough during the past 50 years was Mitchell Energy’s approach to making shale production viable. Well stimulation began in the mid-1800s with torpedoes used on Pennsylvania wells. It was the subject of the first JPT technology article published in 1949, “A Hydraulic Process for Increasing the Productivity of Wells,” by J.B. Clark.2 Mitchell’s approach was not so destructive as the torpedo approach and packed more energy per square nanometer to tip the scales of global supply sourcing. By leveraging the refinement of existing technologies, such as slickwater fracturing adopted from Union Pacific Resources Group, Mitchell’s engineering ushered in new sources of economic reserves, rebalancing top global supplier positions between North America and the Middle East.An equal contributor to shale success was horizontal drilling. While slant drilling was derisive in the 1920s, legal and more reliable horizontal drilling evolved with major advancement in the 1970s through the use of mud motors, “bent subs,” whipstocks, and measurement-while-drilling tools. The petroleum engineer’s ability to reduce trips, monitor, and course correct through tight lateral intervals advanced getting wells on production sooner, with lowered risks and better financial results. Direct public benefit from results such as this are exemplified by the number of sovereign wealth funds established using oil and gas proceeds: the Alaska Permanent Fund, Texas Permanent University Fund, and funds in Norway and the Middle East, to name a few.
In the JPT issue celebrating SPE’s 50th anniversary, John C. Calhoun addressed how distinctive petroleum engineering is from other engineering disciplines: Extending our capabilities to gain access to, to couple with, and to operate within a greater portion of the subsurface environment (e.g., offshore locations, over-pressured environments, marginal reservoirs, horizontal drilling, complex flow systems, acidizing, and hydrofracturing). Recovering a greater proportion of the petroleum within reservoirs that have been accessed and understanding the transfer operations that accompany the recovery (e.g., a broadened spectrum of injected fluids and fluid additives, phased fluid injection programs, extensions of reservoir flow paths, in-field drilling, and horizontal wellbores). Since that issue a little over a decade ago, petroleum engineering feats have expanded on the past and made towering breakthroughs in resource recovery. Reviewing our technology history thus requires highlighting the tangible breakthroughs with the necessary intangibles that enabled faster transformations with commercial success (Figure 1). Arguably the biggest breakthrough during the past 50 years was Mitchell Energy’s approach to making shale production viable.
Simon, Matthieu (Schlumberger) | Tkabladze, Avto (Schlumberger) | Beekman, Sicco (Schlumberger) | Atobatele, Timothy (Schlumberger) | De Looz, Marc-André (Schlumberger) | Grover, Rahul (Schlumberger) | Hamichi, Farid (Schlumberger) | Jundt, Jacques (Schlumberger) | McFarland, Kevin (Schlumberger) | Mlcak, Justin (Schlumberger) | Reijonen, Jani (Schlumberger) | Revol, Arnaud (Schlumberger) | Stewart, Ryan (Schlumberger) | Yeboah, Jonathan (Schlumberger) | Zhang, Yi (Schlumberger)
Formation bulk density is classically measured by irradiating the formation with gamma rays emitted by a 137Cs source, and counting the Compton scattered photons returning to the gamma-ray detectors in the well-logging instrument. Finding a suitable replacement for the 137Cs source has been difficult. The X-ray source described in this paper appears to be a robust replacement for this type of source.
The continued success of 137Cs sources in density logging shows that attempts at their replacement have been unsuccessful due to the insufficient measurement quality or lack of practicality of alternative logging instruments.
An X-ray density-pad sonde was engineered to measure bulk density without a radioisotopic source. The pad contains a rugged, compact X-ray generator with an endpoint energy larger than 300 keV. The core of the tool is the generator, which emits a controlled, focused, stable X-ray flux into the formation. The scattered X-rays are detected by strategically placed scintillation detectors. The pad-tool architecture significantly reduces the effects of standoff and borehole rugosity compared to a mandrel design.
Modeling and experimental data show that the physics of the formation density measurement using a sonde with an X-ray generator and scintillation detectors can be described in the same way as the traditional density measurement, which is based on a monoenergetic gammaray source. Although the 137Cs gamma-ray source density measurement and the X-ray density measurement differ in the relative magnitude of the responses to formation density and lithology (photoelectric factor, PEF), the fundamental physics is the same. An endpoint energy above 300 keV ensures that the transport and attenuation of X-rays in the formation are dominated by Compton scattering, like the attenuation of gamma rays from a 137Cs source. The contribution of the photoelectric absorption to the attenuation of the X-rays is increased, but remains much smaller than the effect of Compton scattering, making the corrections for lithology and borehole fluid straightforward.
A characterization database was acquired to probe the physics of the measurement and to derive robust density and PEF algorithms. Plots of near- and far-detector count rates for different mudcake thicknesses and mud types show spine-and-ribs behavior like 137Cs-based density tools. Field logs acquired with the new tool show improved precision and vertical resolution compared to the 137Cs source tools suggesting that this new tool may be a viable replacement for the older tools.
Qinghai, Yang (Research Institute of Petroleum Exploration & Development) | Siwei, Meng (Research Institute of Petroleum Exploration & Development) | Tao, Fu (Research Institute of Petroleum Exploration & Development) | Yongwei, Duan (Oil and Gas Engineering Research Institute) | Shi, Chen (Oil and Gas Engineering Research Institute)
CO2 waterless fracturing is a novel waterless fracturing technology. CO2 exists in the reservoir with supercritical state, and its fracturing stimulation mechanism is very different from that of water-based fracturing. This paper studies the physical and chemical properties of supercritical CO2 and reservoir adaptability of CO2 waterless fracturing.
Supercritical CO2 has the advantages of good fluidity and strong penetrability, which avail to form a complex network fractures. Through miscible phase with crude oil, absorption gas displacement, and reservoir energy enhancement, production and ultimate recovery are further improved. While the liquid CO2 has the disadvantages of poor proppant carrying capacity, high friction and low fracture opening. Based on CO2 waterless fracturing practices in Jilin oilfield, this paper summarizes physical parameters, operation effect and production situation of all wells, analyzes the main factors influencing productivity, and puts forward a set of well and layer selection methods of waterless CO2 fracturing.
Under the condition of existing CO2 thickening and resistance reducing technology, the selection of wells and layers is mainly carried out in 6 aspects. (1) Because the filtration of CO2 fracturing fluid is strong, the permeability of target reservoir should be lower than 5md in order to ensure stimulation effect of remote area. (2) CO2 can react with water and divalent metal ions to produce carbonate sediments to block existing pores and reduce reservoir permeability, so it is better for low water-bearing reservoirs. (3) Frictional resistance of CO2 is 1.9 times as that of conventional guar gum, so the target layer should be 3000m or shallower to reduce frictional pressure drop. (4) Energy increasing effectiveness of unit volume of CO2 is 1.9 times as that of slick-water, which is more suitable for stimulating undercompacted reservoirs. (5) There is no water phase in CO2 fracturing fluid, suitable for stimulating strong water-sensitive reservoirs. (6) CO2 is easy to dissolve in crude oil and greatly reduces its viscosity, which is suitable to stimulate heavy hydrocarbon reservoir.
Adopting above well and layer selection principles, CO2 waterless fracturing were implemented in 6 wells in 2017, and the key parameters, such as success ratio, sand adding amount, production capacity post-fracturing were comprehensively promoted, which effectively supported CO2 waterless fracturing development practices of unconventional reservoirs.
The CO2 waterless fracturing, just as its name implies, is a fracturing technique using CO2 as the fracturing fluid. During the operation, proppants are mixed with liquid CO2 under pressurized conditions, with the help of the customized blending apparatus, and the mixture is then injected into the wellbore to break the reservoir formation, create artificial fractures, and place proppants to avoid fracture closure after depressurization. The CO2 blending apparatus is a high-pressure sealed container, in which proppants are put inside prior to the fracturing operation. The blender connects the piping system, and is capable of mixing the proppant and CO2 liquid stream, and driving the mixture into the high-pressure fracturing pump.
Foamed acid fracturing is gaining importance in maximizing flowback recovery and is particularly applicable when reservoir energy is not sufficient to effectively flow back the well. Laboratory studies and field implementations during the 1980s showed application of foamed acid in addressing three fundamental issues of acid fracturing such as reactivity control, fluid loss control, and conductivity generation but it was evaluated at low temperature and in shallow wells. Recently, foamed acid has been successfully utilized to energize reservoirs to enhance flowback recovery and restore production after treatment. This paper summarizes literature reports from the last 30 years, showing improved use of foamed acid for acid fracturing.
Foamed acid offers additional benefits such as retardation, deeper conductivity generation, reduced water consumption, and improved acid diversion. Foamed acid laboratory studies from literature such as foam stability, rheology, reaction kinetics, fluid loss, diversion characteristics, and dynamic acid etching is reviewed. Comparison of CO2 and N2 foamed acid is documented in this paper to define fluid selection criteria for a typical foamed acid treatment. Foamed acid rheology at different quality is also summarized in this paper from previous studies.
The dissolution of carbonate rock is controlled by reactivity, which is greatly reduced after foaming for the same acid strength and temperature. Foamed acid having 50-60 quality could retard 60-70% acid reactivity. Excessive fluid loss is one of the challenges in acid fracturing. Conventionally, fluid loss is mitigated by using synthetic polymers to viscosify acid that controls leakoff by depositing a low permeability filter cake on the face of formation leading formation damage concerns. Foamed acid does not build filter cake and showed excellent leakoff control. Proper reactivity and fluid loss control regulates conductivity generation in acid fracturing. Conductivity generation depends on kinetic parameters — such as acid type/strength, temperature, reaction time, and flow regime. These parameters affect the amount of rock removed during the acidizing process. Case histories from different regions where recent application of foamed acid is documented show placement strategies and lessons learned. A horizontal well in one case study was treated with N2 foamed acid to achieve a 2.5 fold increase in production. N2 and CO2 foam was used as foam diverter in acid fracturing, and the productivity index increased to 38% with the use of N2 foam while in other fields the productivity index increased to 3.25 fold with the use of CO2 foam.
Laboratory studies available in the literature are not adequate to design foamed acid treatment for high- temperature, high-pressure wells. This paper summarizes published literature showing improved use of foamed acid for acid fracturing.
The objective of the research presented in this paper was to examine direct evidence of well conditions to determine wellbore integrity factors and mitigation for oil and gas wells exposed to carbon dioxide (CO 2) in the subsurface. This project involved identifying the nature and severity of well defects such as poor or permeable cement, microannulus occurrence, cracks, and mechanical defects, through a combination of sustained casing pressure testing and well history review. Two producing fields were used as case studies to explore wellbore integrity: a Michigan Basin site and an Appalachian Basin site. These sites contain wells that have been exposed to injected or naturally-occurring CO 2 over several decades and are therefore good candidates for researching wellbore integrity and sustained casing pressure. Gas sample analysis, field surveys of well conditions, cement bond logs, well records, and sustained casing pressure buildup tests were used to quantify wellbore integrity factors. This research improves understanding the viability of CO 2 injection projects and safe, reliable, and environmentally responsible operations. Growth in CO 2 -enhanced oil recovery (EOR) has led to an increased demand for information about operational safety and the integrity of wells that have been exposed to CO 2 due to injection or natural sources. Addressing this concern requires knowledge of the wellbore construction and local geology in relation to potential for corrosion of wellbore materials and migration of CO 2 . These aspects factor into site characterization, field management, and well plugging, especially in the Midwest U.S. where many legacy oil and gas wells are located.
Nikitin, Yu. I. (TNNC LLC, RF, Tyumen) | Astafyev, E. V. (TNNC LLC, RF, Tyumen) | Akhtyamova, I. R. (TNNC LLC, RF, Tyumen) | Shakirova, G. V. (TNNC LLC, RF, Tyumen) | Shirokovskich, O. A. (TNNC LLC, RF, Tyumen)
The PDF file of this paper is in Russian.
Regional criteria have been defined on the basis of world exploration experience analysis to substantiate by reef controlled oil-bearing zones. Presence of deep-water paleobasin with carbonate sedimentation and favorable paleoecology for reef development are main criteria to begin exploration for rich reef hydrocarbon deposits. The postdepositional inversional regional slope is an important criterion to look for large hydrocarbon deposits are controlled by barrier reefs. Application of the defined criteria to substantiate exploration development around the Orenburg region has resulted in confirmation of earlier forecasted new exploration play had to be controlled by the Upper Devonian reefs. 705 square kilometres of 3D seismic acquisition within the forecasted perspective zone were resulted in mapping of big groop of the Upper Frasnian isolated basinal reefs. Reef highs – 200-250 m, acreages – 0,7-1,7 km2. Due to drilling of successful exploration wells the rich oil-bearing zone has been revealed on reefs: oil deposits were discovered in reef bodies, in the Lower Famenian and Carboniferous layers in the above-reef compaction closures too. As a result of the regional criteria application new exploration play of Lower Famenian barrier reef has been revealed. The last was first delineated around the south-east of Volga-Ural Province. Together with Zavolzhian barrier reef the Lower Famenian barrier reef formed the Bobrov- Pokrov Swell of the Mukhano-Erokhov Trough’s southern margin in the Orenburg Oblast. Postdepositional inversional regional slope of the trough’s margin has provided a creation of above-reef closures, which are controlled large oil-bearing zone in the Carboniferous, Mid- Famenian and Upper Famenian layers. Oil deposits in the Famenian were placed along the Lower Famenian barrier reef and are the present- day perspective exploration play.
На основании анализа мирового опыта геолого-разведочных работ (ГРР) в зонах развития рифов определен комплекс региональных критериев поиска рифогенных зон нефтегазонакопления. Наличие глубоководного палеобассейна с карбонатной седиментацией и благоприятными для развития рифов палеоэкологическими условиями является одним из главных критериев для начала поиска в его пределах месторождений нефти и газа в рифогенных отложениях. Постседиментационный инверсионный региональный наклон является важным критерием поиска крупных залежей углеводородов, которые контролируются барьерными рифами.Комплекс критериев применен при обосновании развития ГРР на территории Оренбургской области. В пределах прогнозировавшейся перспективной зоны, на площади 705 км2, проведена сейсморазведка 3D. По ее результатам закартирована большая группа верхнефранских одиночных бассейновых рифов. Высота рифовых построек составляет 200-250 м, площадь – 0,7-1,7 км2. В результате бурения поисковых скважин обнаружена крупная зона нефтенакопления: залежи нефти открыты непосредственно в рифах, а также в нижнефаменских и каменноугольных отложениях в надрифовых структурах дифференциального уплотнения. В результате применения комплекса региональных критериев также обосновано новое направление ГРР, связанное с нижнефаменским барьерным рифом. Последний впервые выявлен на юго-востоке Волго-Уральской нефтегазоносной провинции. Совместно с заволжским барьерным рифом нижнефаменский барьерный риф в пределах Оренбургской области формирует Бобровско-Покровский вал южного борта Муханово-Ероховского прогиба. Постседиментационный инверсионный региональный наклон борта обеспечил образование надрифовых тектоно-седиментационных структур, контролирующих в каменноугольных, среднефаменских и нижнефаменских пластах крупную зону нефтенакопления.
Low temperature (60 and 100 °C) and long-term (6 months to 5 years) heating of pre-evacuated and sterilized shales and coals containing kerogen Types I (Mahogany Shale), II (Mowry Shale and New Albany Shale), and III (Springfield Coal and Wilcox Lignite) with low initial maturities (vitrinite reflectance Ro 0.39 to 0.62%) demonstrates that catalytically generated hydrocarbons may explain the occurrence of some non-biogenic natural gas plays where insufficient thermal maturity contradicts the conventional thermal cracking paradigm. Extrapolation of the observed rate of catalytic methanogenesis in the laboratory suggests that significant amounts of sedimentary organic carbon can be converted to relatively dry natural gas over tens of thousands of years in sedimentary basins at temperatures as low as 60 °C.
Our laboratory experiments utilized source rock chips sealed in gold and Pyrex® glass tubes in the presence of hydrogen-isotopically contrasting waters. Parallel heating experiments applied hydrostatic pressures from 0.1 to 300 MPa. Control experiments constrained the influence of pre-existing and residual methane in closed pores of rock chips that was unrelated to newly generated methane.
This study’s experimental methane yields at 60 and 100 °C are 5 to 11 orders of magnitude higher than the theoretically predicted yields from kinetic models of thermogenic methanogenesis, which strongly suggests a contribution of catalytic methanogenesis. Higher temperature, longer heating time, and lower hydrostatic pressure enhanced catalytic methanogenesis. No clear relationships were observed between kerogen type or total organic carbon content and methane yields via catalysis. Catalytic methanogenesis was strongest in Mowry Shale where methane yields at 60 °C amounted to ~2.5 μmol per gram of organic carbon after one year of hydrous heating at ambient pressure.
Future studies need to evaluate the possibility that clumped isotope characteristics of catalytically generated methane can diagnose the low-temperature regime of catalytic methanogenesis. Furthermore, testing of freshly cored anoxic rocks is needed to determine whether the use of archived, oxygen-exposed rocks in geochemical maturation/catalysis studies introduces artifacts in hydrocarbon yields.
ABSTRACT: Despite the significance of in situ stresses in geotechnical engineering, they are often not well defined due to (1) insufficient reliable stress data, which can be due to a lack of measurements and/or the uncertainties/errors associated with the measurement methods employed, and (2) natural variability in the in situ stresses due to the anisotropic and heterogeneous nature of the geology. This is especially true in the Coast Range Mountains of western British Columbia in Canada, where a number of tunnels have been planned for the coming years. This paper aims to provide guidance for the determination of in situ stress conditions in this complex environment through an assessment of the applicability of existing in situ stress methods and a review of previous project experience. The geological history of the area is presented to provide insight into the broad tectonic domain and allows general conclusions to be drawn regarding the state of stress in the region.
The in situ stress magnitude and orientation are critical engineering parameters for evaluating the short and long term behaviour of an underground excavation. These parameters not only define the induced stresses around the excavation, but also have a significant impact on rockmass characterization and establishing probable failure mechanisms (either structurally or stress controlled). By understanding the in situ stress conditions, the expected extent of failure can also be assessed through analytical or numerical analysis techniques, which plays an important role in selecting an appropriate excavation orientation, excavation method and ground support system.
Observations from existing tunnels in the Coast Range Mountains (shown in Figure 1) have illustrated the importance of considering in situ stress primarily for two design cases: (1) for assessing the effects of relatively high in situ stress on ground stabilization during excavation, and (2) for assessing the extent of steel lining for hydraulic pressure tunnels. Case 1 is dominated by high stresses while Case 2 is dominated by low stresses. This paper focuses on Case 1 although some insight into Case 2 is also provided.