The major challenge facing society in the 21st century is to improve the quality of life for all citizens in an egalitarian way, by providing sufficient food, shelter, energy and other resources for a healthy meaningful life, whilst at the same time decarbonizing anthropogenic activity to provide a safe global climate. This means limiting the temperature rise to below 2 C. Currently, spreading wealth and health across the globe is dependent on growing the GDP of all countries. This is driven by the use of energy, which until recently has mostly derived from fossil fuel, though a number of countries have shown a decoupling of GDP growth and greenhouse gas emissions from the energy sector through rapid increases in low carbon energy generation. Nevertheless, as low carbon energy technologies are implemented over the coming decades, fossil fuels will continue to have a vital role in providing energy to drive the global economy. Considering the current level of energy consumption and projected implementation rates of low carbon energy production, a considerable quantity of fossil fuels will still be used, and to avoid emissions of GHG, carbon capture and storage (CCS) on an industrial scale will be required. In addition, the IPCC estimate that large scale GHG removal from the atmosphere is required using technologies such as Bioenergy CCS to achieve climate safety. In this paper we estimate the amount of carbon dioxide that will have to be captured and stored, the storage volume and infrastructure required if we are to achieve both the energy consumption and GHG emission goals. By reference to the UK we conclude that the oil and gas production industry alone has the geological and engineering expertise and global reach to find the geological storage structures and build the facilities, pipelines and wells required. Here we consider why and how oil and gas companies will need to morph into hydrocarbon production and carbon dioxide storage enterprises, and thus be economically sustainable businesses in the long term, by diversifying in and developing this new industry.
Production optimization has become currently one of the most critical aspects for well/reservoir management. This course will cover the following aspects: Nodal Analysis, Formation Damage, Quantification of Formation Damage, Pressure Transient Analysis, Intervention Benefit, and Artificial Lifting (ESP). Every oil company, National, International or an independent company is working on achieving their economic goals by optimizing well deliverability. In this training participants will learn how to evaluate actual well performance and how to optimize well deliverability. Fabio Gonzalez is currently a Reservoir Engineering Advisor with BP on assignment in Kuwait.
The electromagnetic heating of oil wells and reservoirs refers to thermal processes for the improved production of oil from underground reservoirs. The source of the heat, generated either in the wells or in the volume of the reservoir, is the electrical energy supplied from the surface. This energy is then transmitted to the reservoir either by cables or through metal structures that reach the reservoir. The main effect, because of the electrical heating systems used in practice in enhanced oil recovery, has been the reduction of the viscosity of heavy and extra heavy crudes and bitumens, with the corresponding increase in production. Focus is centered on systems (and the models that describe their effects) that have been used for the electromagnetic heating in the production of extra heavy petroleum and bitumen.
Objectives/Scope: The continuous drive by the E&P industry to deliver additional value and performance improvements in unconventional reservoirs has created the need for innovative advances in technology to meet evolving challenges. Jweda et al. (2017) and Liu et al. (2017) developed a novel time-lapse geochemistry technology calibrated to core extracted oils to cost effectively ascertain vertical drainage, which is among the most critical parameters used in determining optimal field development strategies. Aqueous geochemistry, well-established in academic and environmental investigations, is another technology that can be used in conjunction with time-lapse hydrocarbon geochemistry to evaluate drainage behavior, vertical connectivity between stacked wells and to ascertain the efficacy of different stimulation designs. Methods/Procedures/Process: More than 300 produced water samples from approximately 60 different Eagle Ford wells have been collected across ConocoPhillips’ Eagle Ford acreage. Sampling campaigns have included collecting several long-term time-series and baseline samples from individual wells across the field. The analytical program consists of a suite of total ion chemistry (cations and anions), salinity, alkalinity, and isotopic geochemistry (δ18O, δD, 87Sr/86Sr, δ11B). Results/Observations/Conclusions: Produced waters, contain a robust arsenal of geochemical signals that can be analyzed to understand the provenance(s) and change(s) in composition with time of these produced waters. A combination of interpretative and multivariate statistical tools were used to gain a deeper understanding of water-rock interactions and mixing/diffusion processes in the subsurface. Stimulation water was differentiated from in-situ formation water, and the evolution of that process was tracked over time. Time-series water analyses were also used to evaluate differences between completion designs, determine the vertical drainage and/or communication between wells, and ultimately understand the drained rock volume through time. Applications/Significance/Novelty: We clearly demonstrate that produced waters are mixtures of stimulation and formation water and that long-term geochemical signals from different layers within the Eagle Ford can be differentiated using aqueous geochemistry. Furthermore, we show that the formation waters vary vertically, coincident with hydrocarbon indicators (oil biomarkers and gas isotopes). To our knowledge, this is among the first published studies of aqueous geochemical behavior of produced waters in the Eagle Ford and the first to establish that intra-formational waters can be discerned, which is particularly novel and important for evaluating completion designs and strategies within a stacked development.
Shale has been usually recognized as a transverse isotropic (TI) medium in conventional geomechanical log interpretation due to its laminated nature. However, when natural fractures (NFs) exist in the rock body, additional elastic anisotropy can be introduced, converting laminated Shale to an orthorhombic (OB) medium. Previous studies illustrate that treating the naturally fractured shale rock as a TI medium by ignoring the NF-induced anisotropy can cause the erroneous estimation of the geomechanical properties and in-situ stress. In this paper, the study is extended to quantify the impact of NF-induced elastic anisotropy on completion and fracturing designs in different actual shale reservoirs in U.S.
Published acoustic log data from five different shale formations (Bakken, Marcellus, Haynesville, Eagle Ford, and Niobrara) are collected and examined to determine their availability to generate the stiffness tensor of the representative TI background rock of each Shale reservoir. Natural fractures with different intensity values from 0 to 10 per foot, with shear wave splitting ranging from 0-5%, are introduced in the TI background rock to create the corresponding OB rock stiffness tensor. The OB stiffness tensors of different shale cases are finally converted back to the compressional and shear acoustic signals, which can be interpreted based on the TI or OB assumptions. The final output elastic moduli and in-situ stress results interpreted from different assumptions are compared, and the impact of NF-induced elastic anisotropy on completion and fracturing designs is quantified and fully understood for different shales.
The results show that introducing natural fractures into the TI background shale rock leads to a decrease of the in-situ stress and Young's modulus at the orientation perpendicular to the natural fracture plane. Such impact increases with increasing split of fast and slow shear wave slowness (SWS), while decreases with increasing ratio of the “soft mineral content” (i.e. clay and TOC) to the “hard mineral content” (i.e. quartz and calcite). In addition to that, different impacts on stress contrast (variation along the vertical depth) are observed for different shales, owing to the complex mineralogy/lithology sequences of different shale formations. As a result, ignoring the natural fracture induced elastic anisotropy in acoustic log interpretation can result in an overestimation of in-situ stress and Young's modulus as well as a misinterpretation of stress contrast, which further leads to the problematic or suboptimal completion/fracturing designs. The results have been also compared with the shale mineralogy/lithology log data to reveal how the natural fracture induced elastic anisotropy impact is associated with the natural fracture properties (compliance and intensity) and the mineralogy of TI background rocks.
The current study not only illustrates the importance of taking natural fracture induced anisotropy into account when performing geomechanical log interpretation, but also provides guidance to the operators of the five shale fields to better evaluate their current completion/fracturing design strategies and to determine if the natural fracture induced anisotropy impact should be corrected for their current designs or not based on the monitored splitting of fast and slow shear wave slowness.
The geochemical and petrophysical complexity of source-reservoirs in Liquid-Rich Unconventional plays (LRU) urges for the implementation of alternative analytical protocols for initial play assessment. In this study, samples from selected source-reservoirs in the USA and the UK were analyzed by high frequency-nuclear magnetic resonance (HF-NMR relaxometry), followed by hydrous pyrolysis, and modified Rock-Eval pyrolysis methods (multi-heating rate methods, MHR). The analytical protocol here presented attempts to better qualify and quantify different petroleum fractions (mobile, heavy hydrocarbons, viscous, solid bitumen), and thus provide valuable and refined information about producibility of target intervals during appraisal stages.
Modified Rock-Eval Pyrolysis (MHR). Briefly, the pyrolysis oven program had four temperature ramps (at 50 °C/min) and isothermal plateaus (maintained isothermal for 15 minutes) at 200°C, 250°C, 300°C and 350°C, with a fifth and last ramp of 25°C/minute to 650°C. HF-NMR Relaxometry Hydrogen NMR measurements were made with a special 22MHz spectrometer from MR Cores equipped with a 30-mm diameter probe. The T2 data were acquired using the CPMG sequence with an echo time spacing of TE=0.07 ms. The T1 data were acquired using an inversion-recovery sequence. Selected samples (Kimmeridge Clay, Green River Shale) were subjected to hydrous pyrolysis experiments. Crushed rock chips (2-4 g, 1-3mm top size) were loaded into mini-reactor vessels (25-35 mL internal volumes). Rock chips were covered with deionized water and the reactor was placed in a gas chromatograph oven at the chosen temperature, generally for 72h.
Initial results show how the hydrocarbon fractions interpreted from NMR regions are in good agreement with those from MHR pyrolysis analysis in terms of hydrocarbon mobility/producibility. Results from hydrous pyrolysis experiments show that an exception to this general agreement between NMR and MHR estimates occurs for the Kimmeridge Clay samples, where MHR shows an increase of > 90% in producible hydrocarbon yields vs. minimal to no presence of mobile hydrocarbons in NMR T1-T2 maps. Ongoing experiments will clarify the role of pore structure and networks in these discrepancies of producible oil estimates when comparing pyrolysis with NMR-based techniques. This multi-step, multidisciplinary approach provides an opportunity to use it as a screening analysis to identify zones of higher OIP and predict fluids mobility prior to drilling. The novelty of our study is the integration of laboratory-derived analytical data (HF H-NMR, MHR and Hydrous Pyrolysis, organic petrography) to assess the proportion of the OIP that is producible prior to drilling or completions.
Gas production from shale formations is growing, especially in the USA. However, the origin of shale gases remains poorly understood. The objective of this study is to interpret the origin of shale gases from around the world using recently revised gas genetic diagrams. We collected a large dataset of gas samples recovered from shale formations around the world and interpreted the origin of shale gases using recently revised gas genetic diagrams. The dataset includes >2000 gas samples from the USA, China, Canada, Saudi Arabia, Australia, Sweden, Poland, Argentina, United Kingdom and France. Both free gases collected at wellheads and desorbed gases from cores are included in the dataset. Shale gas samples come from >34 sedimentary basins and >65 different shale formations (plays) ranging in age from Proterozoic (Kyalla and Velkerri Formations, Australia) to Miocene (Monterey Formation, USA). The original data were presented in >80 publications and reports. We plotted molecular and isotopic properties of shale gases on the revised genetic diagrams and determined the origin of shale gases. Based on the distribution of shale gases within the genetic diagram of δ13C of methane (C1) versus C1/(C2+C3), most shale gases appear to have thermogenic origin. The majority of these thermogenic gases are late-mature (e.g., Marcellus Formation, USA and Wufeng-Longmaxi Formation, China) and mid-mature (associated with oil generation, e.g., Eagle Ford Formation, USA). Importantly, shales may contain early-mature thermogenic gases rarely found in conventional accumulations (e.g., T⊘yen Formation, Sweden and Colorado Formation, Canada). Some shale gases have secondary microbial origin, i.e., they originated from anaerobic biodegradation of oils. For example, gases from New Albany Formation and Antrim Formation (USA) have secondary microbial origin. Relatively few shale gases have primary microbial origin, and they often have some minor admixture of thermogenic gas (e.g., Nicolet Formation, Canada and Alum Formation, Sweden). Two other revised gas genetic plots based on δ2H and δ13C of methane and δ13C of CO2 support and enhance the above interpretation. Although shales that contain secondary microbial gas can be productive (e.g., New Albany Formation, USA), the resource-rich, highly productive and commercially successful shale plays contain thermogenic gas. Plays with late-mature thermogenic gas (e.g., Marcellus Formation, USA and Wufeng-Longmaxi Formation, China) appear to be most productive.
An optimized stimulation and flowback strategy was devised from formation structure and reservoir properties in the Powder River Basin (PRB) to keep fluid production rates and bottomhole flowing pressure (Pwf) inside a secure operating envelope (SOE) of operational parameters. Keeping operations within the SOE helps ensure
Well completion design and proppant placement are understood across the industry, but more recently long-term stimulation integrity has become more of a focus. A look-back analysis of offset wells showed considerable amounts of proppant produced during flowback. Traditional flowback approaches focus on surface rate control rather than differential pressure across the proppant pack. The pressure and flow rate are both drivers for proppant production risk.
A geomechanical earth model and stimulation design were used to establish an advanced flowback strategy to minimize risk of proppant flowback. Communication protocols between operations and engineering teams, a tailored SOE, and a flow simulator were then used to make on-time choke size decisions that maximized early-time production and minimized proppant flowback.
Using this advanced flowback strategy, an average of 30 pounds of proppant per well was estimated to be produced using hourly samples during the early production of the well compared with an average of 75,000 pounds of proppant per well recovered before the implementation of this strategy. The engineered flowback approach was implemented in a total of 15 wells with repetitive success that materially helped position these wells as top quartile producers within the PRB.
Based on the results of the implementation of this methodology, the engineered flowback approach was adopted as a standard operating practice within the production management organization of a major oilfield service provider in all assets in which wells are completed using hydraulic fracturing stimulation.