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Relative permeability and capillary pressure defined capillary pressure as the difference in pressure across the interface between two phases. Similarly, it has been defined as the pressure differential between two immiscible fluid phases occupying the same pores caused by interfacial tension between the two phases that must be overcome to initiate flow. With Laplace's equation, the capillary pressure Pcow between adjacent oil and water phases can be related to the principal radii of curvature R1 and R2 of the shared interface and the interfacial tension σow for the oil/water interface: The relationship between capillary pressure and fluid saturation could be computed in principle, but this is rarely attempted except for very idealized models of porous media. Methods for measuring the relationship are discussed in Measurement of capillary pressure and relative permeability. Figure 1 shows a sketch of a typical capillary pressure relationship for gas invading a porous medium that is initially saturated with water; the gas/water capillary pressure is defined as Pcgw pg-pw.
Reservoir engineers use relative permeability and capillary pressure relationships for estimating the amount of oil and gas in a reservoir and for predicting the capacity for flow of oil, water, and gas throughout the life of the reservoir. Relative permeabilities and capillary pressure are complex functions of the structure and chemistry of the fluids and solids in a producing reservoir. As a result, they can vary from place to place in a reservoir. Most often, these relationships are obtained by measurements, but network models are emerging as viable routes for estimating capillary pressure and relative permeability functions. Before defining relative permeability and capillary pressure, let us briefly review the definition of permeability. Permeability represents the capacity for flow through porous material. It is defined by Darcy's law (without gravitational effects) as ....................(15.1) Darcy's law relates the flow rate q to the permeability k, cross-sectional area A, viscosity μ, pressure drop ΔP, and length L of the material. High permeability corresponds to increased capacity for flow. The dimensions of permeability are length squared, often expressed as darcies (1 darcy 0.987 10–8 cm2), millidarcies, or micrometers squared.
Drought conditions rated as "moderate or worse" affected 31 US states as of 8 June, as reported by the US National Integrated Drought Information System. Particularly dry are the West and Upper Midwest regions, relevant to the Permian and Bakken, respectively. While not a record-level drought, attention is turning to the Missouri River in North Dakota where streamflow levels are at low levels for this time of year--about 48% below the seasonal average. In the extreme drought, water restrictions could come into play. Throughout the industry, recycling and reuse of frac and produced water have been studied, and where the chemical makeup of the frac or produced water is suitable for optimal and economical treatment, it has been implemented.
Recently, global climate change and air quality have become increasingly important environmental concerns. Consequently, there has been a rise in collaborative international efforts to reduce the concentration of greenhouse gases and criteria pollutants. Greenhouse gases include carbon dioxide (CO2), methane (CH4) and nitrous oxide (N2O), occurring naturally and as the result of human activity. In addition, criteria pollutants (1970 amendments to the Clean Air Act required EPA to set National Ambient Air Quality Standards for certain pollutants known to be hazardous to human health) include emissions of nitrogen oxide, sulfur dioxide, carbon monoxide, and total unburned hydrocarbons. International and national governments are implementing more regulations on air emissions.
Equinor recently offered another possible future for engineers in oil and gas exploration and production (E&P) during the transition. By the end of the decade, the Norwegian energy company plans to be producing about as much oil as it did in 2020 but with a lot smaller global footprint. That is part of its plan to maximize its cash flow to support the growth of carbon-emission-lowering ventures, such as offshore wind power and long-term carbon storage. "Early on, oil and gas will mostly contribute to that return. As we move to 2030, it will be more and more renewables," Anders Opedal, Equinor's chief executive officer, said during the company's recent Capital Market Day with investor analysts.
Introduction Petroleum data analytics is a solid engineering application of data science in petroleum-engineering-related problems. The engineering application of data science is defined as the use of artificial intelligence and machine learning to model physical phenomena purely based on facts (e.g., field measurements and data). The main objective of this technology is the complete avoidance of assumptions, simplifications, preconceived notions, and biases. One of the major characteristics of petroleum data analytics is its incorporation of explainable artificial intelligence (XAI). While using actual field measurements as the main building blocks of modeling physical phenomena, petroleum data analytics incorporates several types of machine-learning algorithms, including artificial neural networks, fuzzy set theory, and evolutionary computing.
Yi, Ming (CNPC Xibu Drilling Engineering Company Ltd) | Liu, Ling (CNPC Xibu Drilling Engineering Company Ltd) | Wei, Qiang (CNPC Xibu Drilling Engineering Company Ltd) | Chen, Liang (CNPC Xibu Drilling Engineering Company Ltd) | Li, Binging (CNPC Xibu Drilling Engineering Company Ltd) | Guo, Zhiqi (CNPC Xibu Drilling Engineering Company Ltd) | Xu, Yangyang (CNPC Xibu Drilling Engineering Company Ltd) | Huang, Xingning (CNPC Xibu Drilling Engineering Company Ltd)
Abstract Exploration focus is moving into deeper targets of high pressure and high temperature (HPHT) regime due to the ever-increasing energy demand of China. Overpressure and wellbore instability related problems in such setting are mainly associated with narrow drilling margin resulting in severe well control incidents and increased drilling cost. In order to reduce drilling risks and operation costs, an accurate geomechanical model is necessary. The model provides technical support for drilling process and minimum reservoir damage due to optimal mud weight program. Well-scale (1D) Mechanical Earth Model (MEM) is constructed on the offset wells which consist of rock strength properties and stress profile by incorporating all available data including open hole log data, geomechanical core lab results, LOT/FIT, direct pore pressure measurements and drilling events. Furthermore, 3D geomechanics model is generated using available well-scale MEM data in the field and distributed throughout the field which guided by seismic interpretation data as distribution control. The 3D geomechanical model is used to design mud weight and casing program for the upcoming well. The offset wells in the study areas were drilled through complex geological settings with high overpressure (13500 psi) and high temperature (200-220 deg C). Therefore, drilling operations is also risky with different types of drilling events encountered frequently including stuck pipe, inflow, losses and connection gas etc. With 3D geomechanical model as the foundation, the integrated approach helps ultra-deep wells to reduce serious wellbore instability caused by abnormal formation pressure, wellbore collapse and other complex drilling problems. The implementation of systematic and holistic workflow has proven to be extremely successful in supporting the drilling of HPHT wells in China. The integrated solution has been applied in the ultra-deep well, recorded an improvement in ROP by 35.3% and decrease no-productive time (NPT) by 25.3% compared with offset well. The geomechanical approach provides a convenient means to assist field engineers in the optimization of mud weight, risk assessment, and evaluation of HPHT wells drilling performance. The findings will provide reference and guideline for de-risk and performance improvement in HPHT wells drilling.
Wang, Xindong (CNPC Xibu Drilling Engineering Company Ltd) | Ke, Xue (CNPC Xibu Drilling Engineering Company Ltd) | Zhang, Shuxia (CNPC Xibu Drilling Engineering Company Ltd) | Zhang, Cheng (CNPC Xibu Drilling Engineering Company Ltd) | Li, Hui (CNPC Xibu Drilling Engineering Company Ltd) | Li, Pengfei (CNPC Xibu Drilling Engineering Company Ltd) | Li, Zhenchuan (CNPC Xibu Drilling Engineering Company Ltd) | Huang, Xingning (CNPC Xibu Drilling Engineering Company Ltd, formerly)
Abstract Drilling operations is risky due to narrow mud weight windows in deep wells. Different type of drilling events and wellbore instability have encountered frequently including inflow, drilling induced tensile fractures (DITF), losses and connection gas etc. As such to mitigate the problems, a robust pore pressure prediction is necessary with requires an understanding of the origins and distribution of overpressures in the area. The technical research process is divided into three steps: pre-drill pore pressure predication (PPP) modelling, real-time monitoring and post-drill validation. Efforts were made to understand the geological settings and temperature model. A pore pressure predication (PPP) model was built by integrating fully coupled geomechanical with thermodynamics modeling. Real-time monitoring information provides references and guidelines for PPP model optimization. During the post-drill stage, the updated PPP model was used to design a mud weight and casing program for the upcoming wells. The study area is located northwestern China, the deep formations that more than 7000 meters are ultra-high temperature (200-220 deg C). Thermal-related secondary pore pressure generating mechanism may become active leading to higher overpressure and difficulties in prediction. For the case study, an empirical relationship of overpressure impact factors versus temperature of sandstone and mudstone was proposed. An accurate PPP model is generated using available well-scale geomechanical model and overpressure impact factors. With an integrating fully coupled PPP model as foundation, the integrated approach helps to reduce serious wellbore instability caused by abnormal formation pressure, wellbore collapse and other complex drilling problems deep wells. A1 well was safely drilled guided by the study result and has no significant wellbore instability issues and has minimum reservoir damage due to optimal mud weight program. These findings will provide reference for overpressure mechanics study of deep wells. The multidisciplinary study results have created value by improving drilling performance and well delivery efficiency. It can also help operator reduce drilling costs and make development plan decisions.
US shale producers Cabot Oil & Gas and Cimarex Energy are the latest to declare a "merger of equals" in a deal valued at around $17 billion, based on recent equity prices. Announced today, the terms of the deal will result in Cimarex shareholders owning about 50.5% of the combined company and Cabot shareholders owning approximately 49.5%. The deal brings together Houston-based Cabot's gas-rich portfolio, comprising almost 173,000 acres in the Marcellus Shale, with Cimarex's oil-dominated 560,000 net acres in the Permian Basin and Anadarko Basin. On a pro forma basis, the merged company will produce around 600,000 BOE/D from the three basins. The companies expect $100 million in savings to materialize within 2 years of the deal closing and to generate around $4.7 billion in free cash flow from 2022 to 2024.
Abstract Legacy crushed rock analysis, as applied to unconventional formations, has shown great success in evaluating total porosity and water saturation over the previous three decades. The procedure of crushing rock into small particles improves the efficiency of fluid recovery and grain volume measurements in a laboratory environment. However, a caveat to crushed rock analysis is that water and volatile hydrocarbon evaporate from the rock during the preparatory crushing process, causing significant uncertainty in water saturation assessment. A modified crushed rock analysis incorporates nuclear magnetic resonance (NMR) measurements before and after the crushing process to quantify the volume of fluid loss. The advancements improve the overall total saturation quantification. However, challenges remain in the quantification of partitioned water and hydrocarbon loss currently derived from NMR spectrum along with its uncertainty. Furthermore, pressure decay permeability from crushed rock analysis has been reported to have two to three orders of magnitude difference between different labs. The calculated pressure decay permeability of the same rock could even vary several orders of magnitude difference with different crushed size, which questions the quality of the crushed pressure decay permeability. In this paper, we introduce an intact rock analysis workflow on unconventional cores for improved assessment of water saturation and enhanced quantification of fast pressure decay matrix permeability from intact rock. The workflow starts with acquisition of NMR T2 and bulk density measurements on the as-received state intact rock. Instead of crushing the rock, the intact rock is directly transferred to a retort chamber and heated to 300 °C for thermal extraction. The volumes of thermally-recovered fluids are quantified through an image-based process. The grain volume measurement and a second NMR T2 measurement are performed on post retort intact rock. The pressure decay curve during grain volume measurement is then used for calculating pressure decay matrix permeability. Total porosity is calculated using bulk volume and grain volume of the rock. Water saturation is quantified using total volume of recovered water. In addition, the twin as-received state rocks are processed through the crushed rock analysis workflow for an apple-to-apple comparison. Meanwhile, pressure decay permeability is cross-validated against the steady state permeability of the same sample. The introduced workflow has been successfully tested on different formations, including Bakken, Bone Spring, Eagle Ford, Cotton Valley, and Niobrara. The results show that total porosities calculated from intact rock analysis are consistent with total porosities from crushed rock analysis, while water saturations from the new workflow are average 8%SU (0.2–0.7%PU of bulk volume water) higher than those from the prior crushed rock workflow. The study also indicated that for some formations (e.g., Bone Spring) the fluid loss during crushing process is dominated by water, however, for some other formations (e.g., Bakken), hydrocarbon loss is significant. Pressure decay permeability quantified using intact rock analysis is also confirmed within an order of magnitude of steady state matrix permeability.