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Systems analysis has been used for many years to analyze the performance of systems composed of multiple interacting components. Gilbert was perhaps the first to introduce the approach to oil and gas wells but Mach, Proano, and Brown and Brown popularized the concept, which is typically referred to as Nodal Analysis within the oil and gas industry. The objective of systems analysis is to combine the various components of the production system for an individual well to estimate production rates and optimize the components of the production system. The flow of reservoir fluids from the subsurface reservoir to the stock tank or sales line requires an understanding of the principles of fluid flow through porous media and well tubulars. As the fluid moves through the production system, there will be an associated pressure drop to accompany the fluid flow.
The characterization of naturally and hydraulically fractured reservoirs, where many scales of heterogeneity are involved, is extremely challenging. Representing fractures explicitly using discrete fractures network models (DFN) faces important applicability issues, such as the prohibitive computational cost of the resulting systems and the under-determination of the characterization problem. Alternative approaches (ex: homogenization via dual porosity / dual permeability models, embedded DFN models…) can reduce the simulation cost, but they do not ensure that the equivalent matrix-fracture transfers are accurately captured. In particular, the transient processes, which are of primary importance in low-permeability formations, are usually lost. Consequently, the flow regimes are not correctly reproduced, and simulated cumulative volumes are impacted. This prevents such upscaled models from being used reliably for PTA and RTA. The issue is even worse in multiphase contexts, where PVT changes occur in the vicinity of the fractures. A new numerical upscaling approach is proposed, that preserves transient flows for accurate coarse-scale results.
In order to accurately capture the matrix-fracture transfers, a Voronoi grid is built, which is rigorously constrained to all the fracture segments and connections. Cell faces are locally aligned with the fractures, and orthogonal connections ensure accurate transmissibilities. The grid is iteratively refined locally, so that cell sizes decrease continuously with the proximity to fractures. Each cell is assigned a "refinement rank" stored for upscaling purposes. The resulting reference grid can be very large, but it is not used for simulation. Instead, all the corresponding control volumes are aggregated into a much smaller number of groups, directly in the computational domain. The procedure is such that created groups can aggregate cells of the same rank only. This ensures that transient processes are preserved, while the size of the simulation system is drastically reduced. Coarse transmissibilities between aggregated control volumes are calibrated rigorously via numerical upscaling from a fast single-step pressure resolution on the reference system.
We show that even when rigorous coarse scale transmissibilities are used on simulation grids, the transient processes are lost when the permeability is low, with important consequences on the flow signatures and volume predictions. The advantage of the proposed approach is that it preserves transient processes and ensures much better predictions, especially in the presence of multiphase effects.
The proposed approach allows to incorporate the fractures explicitly at a fraction of the CPU cost required for standard DFN simulations - hence enabling the practical use of DFN models in transient simulations and PTA/RTA applications.
A novel approach that considers the three-dimensional flow effects while designing kill well strategies has been developed. This type of analysis helps to accurately model the flow behaviour downhole at the interception point and offers game-changing safety and environmental benefits for well kill design and operations.
In planning a relief well contingency, the current industry standard is the 1-D multiphase model which is used to determine the requirement of pump rate and mud weight to kill the blowout well. Using 3-D Computational Fluid Dynamics (CFD) helps to capture the physics of the flow better and provides more accurate representation of the mixing and multiphase interaction occurring.
Both 1-D and CFD modeling were compared to analyze well kill design conditions. In one field case, the 1-D analysis returned results where even with a 19.0 ppg mud pumped at 100 bpm, the worst-case discharge rate from the well (680 MMSCF/D) could not be killed. Another case using the 1-D analysis showed that planning a relief well kill for a 1.0 BCF/D gas blowout rate, required three to four relief wells with a kill rate of 200 bpm simultaneously to kill the well.
CFD modeling was used to model the same two conditions, in addition, the CFD model also captured the jetting effect from the relief well. CFD model also iterated on a design that included pumping down a smaller string to analyze/understand the detailed fluid flow behavior at the intercept. This allowed for two successful designs of a kill with lighter muds for the 680 MMSCF/D case. For the 1.0 BCF/D rate case, the CFD analysis indicated that the well could be killed at a much lower pump rate compared to the 1-D model.
A test apparatus was designed and created to verify which of the two methods was more accurate. Physical experiments indicate that results from the proposed method match the test results closer than the standard approach.
This approach can reduce the equipment required and the time to drill a relief well (which can take two to three months to drill) and more effectively terminate a blowout event earlier, thereby minimizing the negative impact on environment, economics and human life.
Bazyrov, I. Sh. (Gazpromneft NTC LLC) | Gunkin, A. S. (Saint-Petersburg mining university) | Ovcharenko, Yu. V. (Gazpromneft NTC LLC) | Lukin, S. V. (Gazpromneft NTC LLC) | Alchibaev, D. V. (Gazpromneft NTC LLC) | Shapovalova, A. A. (Gazpromneft NTC LLC) | Bolgov, I. P. (Peter the Great Saint-Petersburg Polytechnic University)
The PDF file of this paper is in Russian.
The developed analytical model for fracture initiation pressure estimation is described. The model is based on solving the problems of stress tensor transformation, estimation of stress distributions around the boreholes, direction cosines estimation, transforming stress tensor between cylindrical and Cartesian coordinate systems. In the work, the stress state of natural fractures only intersecting the well trajectory is calculated. As criteria for crack initiation, the shear fracture criterion and the tensile fracture criterion are used. The calculation results showed that when the well pressure changes, the stress state at the point of intersection of the fracture and the well changes, including the fracture initiation criterion. A study was made to estimate the influence of the following factors on the magnitude of the fracture initiation pressure: the orientation of the wellbore relative to the main stresses and fracture geometry. Combinations of fracture initiation parameters are determined. The developed technique allows to determine the bottomhole pressure boundaries to prevent fracture initiation near the wellbore. The technique allows to determine the necessary pressure during the drilling or wellkilling operations. On the other hand, it is possible to estimate the bottomhole pressure at which natural fractures will be initiated to assess the risks of hydraulic fracturing, as well as to prevent early water breakthroughs from water-injection wells. Further steps to improve the technique include a more detailed sensitivity analysis of the developed analytical model, estimation of the fracture initiation pressure located at a small distance from the well (without well and fracture intersection), estimation of the fracture initiation pressure in the case of perforation, verification of the results in the field using hydrodynamic tests, as well as geophysical studies.
В статье рассмотрена аналитическая модель для определения давления инициации трещины. Модель основана на решении задач трансформации тензора напряжений при переходе в систему координат, связанную со скважиной, перераспределения региональных напряжений на кольцевое пространство рассматриваемой скважины, расчета направляющих косинусов площадки трещины в трансформированной системе координат и перевода тензора напряжений из цилиндрической системы координат в декартову. Рассчитывалось напряженное состояние только естественных трещин, пересекающих траекторию скважины. В качестве критериев для инициации трещины использованы сдвиговый критерий разрушения и критерий разрушения при растяжении. Результаты расчетов показали, что при изменении внутрискважинного давления напряженное состояние на контуре пересечения трещины и скважины изменяется, в том числе меняется локализация инициированной зоны трещины. Проведено исследование степени влияния следующих факторов на давление инициации трещины: направление главного напряжения, ориентация ствола скважины относительно главных напряжений и геометрия трещины. Определены комбинации параметров инициации трещин. Разработанная методика позволила определить границы забойного давления для предотвращения инициации трещины вблизи ствола скважины. Предложенная методика дает возможность подобрать рабочие давления при операциях бурения или глушения. С другой стороны, можно рассчитать забойное давление, при котором будет инициирована естественная трещина, для оценки рисков при проведении гидроразрыва пласта, а также при работе нагнетательной скважины для предотвращения ранних прорывов воды. Дальнейшие совершенствование методики предполагает более детальный анализ чувствительности разработанной аналитической модели, оценку давления инициации трещины, находящейся на небольшом удалении от скважины (не пересекающейся с траекторией скважины), оценку давления инициации трещины в случае наличия перфорации, проверку результатов аналитической модели в полевых условиях с помощью гидродинамических тестов, а также геофизических исследований.
A new Protocol ("DMX") is presented for 3d DFFN (Discrete Fault and Fracture Network) modelling, a numerical code developed over the last 20 years in order to converge towards a more realistic Discontinuity (fault and fracture) Network representation in space. The protocol introduces the following new features: Fracture interaction, truncation, termination and cross cutting in 3d space based on newly designed collision algorithms and fracture propagation principles; Modelling at any scale range of unlimited basic 3d fracture shapes, specific 3d fracture morphology, and 3d fracture aperture types; A complete integration between classical geological/geomechanical drivers such as stress ellipse, fault zones with 3d slip vectors, and different fold models (axial plane, fold axis and bedding orientation conditioning), geological assembly modelling such as joint spacing and set dependency, offset/faulting, and probabilistic conditioning of any of the parameters and drivers. Examples of the application of the protocol are presented to illustrate few of the unlimited amount of combinations that can be generated in 3d space. Furthermore, an example of the complete flow chart of a calibration to real observed cases is provided. The protocol constitutes a complete game change and opens a range of technological challenges for the future applications in Mining, Civil Engineering and Conventional and Unconventional Oil and Gas Exploration and Production.
Abdelkarim, Islam (ADNOC Offshore) | Jadallah, Haitham (ADNOC Offshore) | Ness, Knut (ADNOC Offshore) | AL ALI, Salim (ADNOC Offshore) | Alzaabi, Mohamed (ADNOC Offshore) | Amer, Reem (BHGE) | Diaz, Nerwing (BHGE) | Gjertsen, Morten (BHGE)
After completing the drilling phase of the 8½″ section for a well in a giant mature field offshore Abu Dhabi, due to geomechanical challenges it was not possible to run the 7″ liner in a shale formation which was open for a long period of time due to rig repairs (top drive failure in open hole), exposing all reservoirs and compromising the field development strategy. After several unsuccessful attempts to run the liner and leaving a drilling BHA in the hole during one of the cleanout runs, it was decided to sidetrack around the fish to intersect the original 8½″ open hole section in order to recover the original hole and isolate the reservoir flow units from each other, which was critical for the field development since more than five reservoir layers were opened with water and oil bearings increasing the risk of damaging the reservoir integrity due to potential cross flow.
Detailed measurement-while-drilling (MWD) survey analysis was conducted for the original hole in order to enhance surveys accuracy and minimize positional uncertainty. Typical survey management practices were implemented for Sag and Drilling String Interference; other techniques such as Dual Inclination, In-Field Referencing, and Multi Station Analysis were also applied. The implementation of these different survey management practices and their respective results are covered in detailed in the current article. Comprehensive planning was carried out, the sidetrack was accomplished and the original hole was successfully intersected at the first attempt.
The advanced applied survey management techniques were crucial, particularly in the absence of magnetic ranging as the interval to intersect was open hole. The outcome of these corrections resulted in a shift of 8ft to the final well position, ensuring the correct direction and position for a successful attempt to intersect the well. This intersection was particularly challenging as the original hole had a 3D profile, thus it was critical to minimize both vertical and azimuthal uncertainties. Intersection was achieved with an RSS BHA, and the success of this intersection without magnetic ranging capability was only based on following a planned well trajectory that intersected the original hole surveys, clear validation of the accuracy of the surveys for both original and sidetrack holes. Achieving this challenging directional drilling goal allowed the completion of the well as per original plan, which was critical for the field development plan of these reservoirs.
Based on the fact that there is very limited existing literature covering similar cases to the one presented, this current case represents a solid successful reference to be replicated in similar cases in the future covering these challenging applications of advanced survey management techniques.
John Saiz is a Principal Industrial Fellow at the University of Cambridge Institute for Manufacturing (IfM) responsible for collaborating with technology-intensive organizations worldwide with support from the staff at the IfM Centre for Technology Management. In this capacity, Saiz has worked with a number of multinational commercial organizations, industry consortia, and universities. Saiz was previously the chief technology officer at the National Aeronautics and Space Administration (NASA). While at NASA, he directed a number of technology and flight development projects that included efforts spanning the full spectrum of "technology readiness levels," from initial proof-of-concept laboratory demonstration through long-term spaceflight operations on the Space Shuttle, Russian Mir, and the International Space Station. During his tenure at NASA, he managed a portfolio of nearly 200 internal research and technology development activities. Saiz holds degrees in petroleum engineering and mechanical engineering, and his industry experience includes a brief stint as a mud logger with Integrated Drilling and Logging in the Texas and Louisiana oil fields, and engineering and technology management roles at Honeywell Defense Systems, Oceaneering Space Systems, and Halliburton. How can the energy and aerospace industries benefit from collaboration? Do you see any game-changing innovations on the horizon for either industry?
Hydrocarbon recovery from shale subformations has greatly contributed to the global energy supply and has been constantly reshaping the energy sector. Oil production from shale is a complex process in which multicomponent-fluid mixtures experience multiphase transitions in multiscale volumes (i.e., nanoscale pores are connected to fractures/macropores). Understanding such complicated phenomena plays a critical role in the estimation of ultimate oil recovery, well productivity, and reserves estimation, and ultimately in policy making. In this work, we use density-functional theory (DFT) to explicitly consider fluid/surface interactions, inhomogeneous-density distributions in nanopores, volume partitioning in nanopores, and connected macropores/natural fractures to study the complex multiphase transitions of multicomponent fluids in multiscale volumes. We found that vapor-like and liquid-like phases can coexist in nanopores when pressure is between the bubblepoint and dewpoint pressures of nanoconfined fluids, both of which are much lower than those of the originally injected hydrocarbon mixtures. As the volume ratio of the bulk at the initial conditions to pores decreases, both the bubblepoint and the dewpoint in nanopores increase and the pore two-phase region expands. Within the pore two-phase region, both C1 and C3 are released from the nanopores to the bulk phase as pressure declines. Meanwhile, both liquid and vapor phases become denser as pressure drops. By further decreasing pressure below the dewpoint of confined fluids, C3 in the nanopore can be recovered. Throughout the process, the bulk-phase composition varies, which is in line with the field observation. Collectively, this work captures the coupled complexity of multicomponent and multiphase fluids in mutliscale geometries that is inherent to shale reservoirs and provides a theoretical foundation for reservoir simulation, which is significant for the accurate prediction of well productivity and ultimate oil recovery in shale reservoirs.
In 2017 the excavation of 5 large rock caverns including an access tunnel started in Oslo, Norway. The caverns are 15-25 m wide, 18-20 m high and 127-198 m long. In total 300.000 m3 rock are excavated. This paper describes the planning and execution of pre-grouting at this site.
The rock caverns are located in the Oslo Field. The rock mass consists mainly of syenite (nordmarkite) with several intrusions of diabase and rhomb-porphyry including presence of swelling clay of variable thicknesses. Generally, the syenite is moderately jointed and has a low permeability. The properties of the diabase and rhomb-porphyry intrusions varies greatly between moderate to densely jointed with moderate to high permeability. A major weakness zone consisting of diabase and rhomb-porphyry is crossing four of the five rock caverns. The caverns are situated below the ground water level, and the main concern was lowering of the water level in nearby ponds and wet-area. Originally, a total leakage of 100 l/min was considered acceptable and a systematic pre-grouting of the largest caverns was planned. Later on, early on in the construction period, hydrogeological modelling was carried out. The modelling indicated little hydrological communication between the ponds/wet-area and the caverns and the level of acceptable leakage was increased to 300 l/min. Hence, systematic probe drilling ahead of tunnel face was performed in order to determine if pre-grouting should be executed.
Pre-grouting in the project has proved to be challenging for several reasons. The geology varied greatly and was hard to predict from MWD-data (Measurement While Drilling). Moreover, the geometry was complex with large cross-sections and several tunnel intersections. At times the contractor was working at 5 tunnel-faces at once which demanded frequent adaption of the pre-grouting design. In addition, the site is located near existing rock caverns, which have not been pre-grouted. The possibility of increased leakages here had to be considered when planning the pre-grouting in the new caverns.
This study examines the levels of vehicular Carbon (IV) oxide (CO 2) emissions in nine (9) selected locations characterised by high traffic congestion in Benin City Metropolis, Edo State, Nigeria. The contributory effects of these emission levels on climate change and air pollution were also assessed based on global standards. CO 2 concentration measurements were conducted twice a day, four times a week, for a period of sixteen (16) weeks. Results showed that the highest average mean values were recorded at Ring Road, New Benin and Third East Circular Junctions with 1421 ppm, 1417ppm and 1171ppm respectively in the morning hours and 1767ppm, 1417ppm, 1217ppm respectively in the afternoon hours. Diurnal variations revealed significant statistical differences (P 0.05) for CO 2 emissions generated at different times of the day. Spatial variations in the CO 2 data were also statistically significant (P 0.05), with the highest mean concentrations of 1594ppm reported for Ring Road sampling station while New Benin and Five Junction sampling sites recorded mean CO 2 emissions rates of 1417ppm and 745.8ppm respectively. The results showed that CO 2 emission levels at these selected high traffic areas in Benin are approximately five times more than the internationally accepted safe limits of 350ppm for atmospheric CO 2 . However, these levels are less than the Occupational Safety and Health Administration (OSHA) permissible exposure limits of 5,000ppm. High vehicular exhaust emission which is the primary source of CO 2 in the Benin city metropolis can be attributed to poor traffic handling and discipline; and low dilution and dispersion of the emitted CO 2 due to prevalent low wind speeds in these study locations.