Some of the technologies, such as mechanical and control devices commonly used in subsea well and manifold systems, are well developed and can be considered off-the-shelf items. Many of the emerging products are well-proven surface components modified for subsea application. As in any integrated system, a shortcoming in any one of the links will impair the performance of the whole. A clear understanding of the process and all its parameters is the first step toward a successful design. As in surface facilities, knowledge of the produced fluid properties, rheology, and flow characteristics are critical. Luckily, whether the process is carried out on the surface or a thousand meters subsea, the process is the same. However, effects of the environmental conditions may be more dramatic and detrimental. Fluids with high foaming tendency will complicate the design and may require mechanical or chemical solutions. For subsea applications, a passive mechanical foam-breaking device (such as a low-shear inlet momentum breaker) is preferred over the more costly to install and operate chemical injection systems. For three-phase separation, the more complex oil/water emulsion/dispersion chemistry will come into play, along with the viscosities of the oil and water and changes in water cut with time. Whether an oil/water mixture will form a stable emulsion or a more manageable dispersion often depends on the small concentrations of surface-active impurities in the fluid.
Subsea processing using subsea separation and pumping technologies has the potential to revolutionize offshore oil and gas production. When combined with relatively mature subsea production technologies (see subsea chapter on well systems, manifold, pipeline, power and control umbilical, and so on), it can reduce development cost, enhance reservoir productivity, and improve subsea system reliability and operability. Over the period from 1970 to 2000, millions of dollars have been spent to develop subsea separation and pumping systems. But because of unresolved technical issues, along with a lack of confidence and clear understanding of the costs and benefits, industry has not rushed to deploy the technology on a commercial basis. However, as the industry moves into remote deep and ultradeep water, various degrees of subsea processing are becoming more common. In deep water, the technology can enable hydrocarbon recovery from small reservoirs that are subeconomic by conventional means, ...
Copyright 2019 held jointly by the Society of Petrophysicists and Well Log Analysts (SPWLA) and the submitting authors. ABSTRACT Today, many machine learning techniques are regularly employed in petrophysical modelling such as cluster analysis, neural networks, fuzzy logic, self-organising maps, genetic algorithm, principal component analysis etc. While each of these methods has its strengths and weaknesses, one of the challenges to most of the existing techniques is how to best handle the variety of dynamic ranges present in petrophysical input data. Mixing input data with logarithmic variation (such as resistivity) and linear variation (such as gamma ray) while effectively balancing the weight of each variable can be particularly difficult to manage. DTA is conceived based on extensive research conducted in the field of CFD (Computational Fluid Dynamics). This paper is focused on the application of DTA to petrophysics and its fundamental distinction from various other statistical methods adopted in the industry. Case studies are shown, predicting porosity and permeability for a variety of scenarios using the DTA method and other techniques. The results from the various methods are compared, and the robustness of DTA is illustrated. The example datasets are drawn from public databases within the Norwegian and Dutch sectors of the North Sea, and Western Australia, some of which have a rich set of input data including logs, core, and reservoir characterisation from which to build a model, while others have relatively sparse data available allowing for an analysis of the effectiveness of the method when both rich and poor training data are available. The paper concludes with recommendations on the best way to use DTA in real-time to predict porosity and permeability. INTRODUCTION The seismic shift in the data analytics landscape after the Macondo disaster has produced intensive focus on the accuracy and precision of prediction of pore pressure and petrophysical parameters.
The SWP project is located in a mature waterflood undergoing conversion to CO2-WAG operations at Farnsworth, Texas, USA. Utilized CO2 is anthropogenic, sourced from a fertilizer and an ethanol plant. Major project goals are optimizing the storage/production balance, ensuring storage permanence, and developing best practices for CCUS.
This paper provides a review of work performed toward development of a 3D coupled Mechanical Earth Model (MEM) for use in assessment of caprock integrity, fault reactivation potential, and evaluation of stress dependent permeability in reservoir forecasting. Mechanical property estimates computed from geophysical logs at selected wellbores were integrated with 3D seismic elastic inversion products to create a 3D "static" mechanical property model sharing the same geological framework as the existing reservoir simulation model including 3 major faults. Stresses in the MEM were initialized from wellbore stress estimates and reservoir simulation pore pressures. One way and two way coupled simulations were performed using a compositional hydrodynamic flow model and geomechanical solvers.
Coupled simulations were performed on history matched primary, secondary (waterflood), and tertiary (CO2 WAG) recovery periods, as well as an optimized WAG prediction period. These simulations suggest that the field has been operating at conditions which are not conducive to either caprock failure or fault reactivation. Two way coupled simulations were performed in which permeability was periodically updated as a function of volumetric strain using the Kozeny-Carmen porosity-permeability relationship. These simulations illustrate the importance of frequent permeability updating when recovery scenarios result in large pressure changes such as in field re-pressurization through waterflood after a long primary depletion recovery period. Conversely, production forecasting results are less sensitive to permeability update frequency when pressure cycles are short and shallow as in WAG cycles.
This paper describes initial work on development of a mechanical earth model for use in assessment of geomechanical risks associated with CCUS operations at FWU. The emphasis of this work is on integration of available geomechanical data for creation of the static mechanical property model. Preliminary coupled hydro-mechanical simulations are presented to illustrate some of the key diagnostic output from coupled simulations which will be used in later work for in depth evaluation of specific risk factors such as induced seismicity and caprock integrity.
Many gas reservoirs at the appraisal stage exhibit evidence of persistent gas saturations below free water levels (FWL's). The amounts of gas contained here may, under some situations, be a sizable fraction of the gas cap volumes. Many engineers appear poorly equipped to include, and model, paleo gas in simulation models. This often results in paleo gas being simply ignored when development plans are being considered. This is unfortunate because paleo gas upon pressure depletion can expand, displacing brine towards well completions. This means that while some additional gas production may occur from the paleo zone, the risk of water production may be significantly underestimated if paleo gas is simply omitted. This work discusses the evidence for paleo gas and shows that it may be described and incorporated in simple simulation models provided the user avoids some common misconceptions. It is demonstrated that under depletion conditions, paleo gas can be entirely visible to material balance pressure responses, while at the same time increasing the risk of produced water volumes. For higher pressure paleo gas reservoirs the common P on Z diagnostic plots can also provide early trends that are frequently misinterpreted. This work quantifies the curvature that can result in such systems, and shows that simulation models inherently predict the expected curvature in P on Z. The approach taken here is by design simplistic and is applicable to scoping evaluations where the paleo gas volumes could be a significant volumetric uncertainty. Where possible, we indicate where additional, or more rigorous, descriptions can be applied.
Penghui, Su (PetroChina Research Institute of Petroleum Explorationand and Development) | Zhaohui, Xia (PetroChina Research Institute of Petroleum Explorationand and Development) | Ping, Wang (PetroChina Research Institute of Petroleum Explorationand and Development) | Liangchao, Qu (PetroChina Research Institute of Petroleum Explorationand and Development) | xiangwen, Kong (PetroChina Research Institute of Petroleum Explorationand and Development) | Wenguang, Zhao (PetroChina Research Institute of Petroleum Explorationand and Development)
Interest has spread to potential unconventional shale reservoirs in the last decades, and they have become an increasingly important source of hydrocarbon. Importantly, pore structure of shale has considerable effects on the storage, seepage and output of the fluids in shale reservoirs so that reliable fractal characteristics are essential. To better understand the evolution characteristics of pore structure for a shale gas condensate reservoir and their influence on liquid hydrocarbon occurrences and reservoir physical properties, we conducted high-pressure mercury intrusion tests (HPMIs), field emission scanning electron microscopies (FESEM), total organic carbon (TOC), Rock-Eval pyrolysis and saturation measurements on samples from the Duvernay formation. Furthermore, the fractal theory is applied to calculate the fractal dimension of the capillary pressure curves, and three fractal dimensions D1, D2 and D3 are obtained. The relationships among the characteristics of the Duvernay shale (TOC, organic matter maturity, fluid saturation), the pore structure parameters (permeability, porosity, median pore size), and the fractal dimensions were investigated.
The results show that the fractal dimension D1 ranges from 2.44 to 2.85, D2 ranges from 2.09 to 2.15 and D3 ranges from 2.35 to 2.48. D2 and D3 have a good positive correlation. The pore system studied mainly consists of organic pores and microfractures, with the percentage of micropores being 50.38%. TOC has a positive relationship with porosity and D3 due to the development of organic pores. D3 has a positive correlation with gas saturation. With increased D3, median pore size shows a decreasing trend and an increase in permeability and porosity, demonstrating that D3 has a large effect on pore size distribution and the heterogeneity of pore size. In general, D3 has a better correlation with petrophysical and petrochemical parameters. Fractal theory can be applied to better understand the pore evolution, pore size distribution and fluid storage capacity of shale reservoirs.
The complete paper proposes an azimuthal plane-wave-destruction (AzPWD) seismic-diffraction-imaging work flow to efficiently emphasize small-scale features associated with subsurface discontinuities such as faults, channel edges, and fracture swarms. This paper contrasts the detailed perforating and flowback plan with the results of the operation where a number of planned, and some unplanned, contingencies were faced. A hybrid downhole microseismic and microdeformation array was deployed to monitor fracture stimulation of a vertical coal-seam-gas (CSG) exploration well in the Gloucester Basin in New South Wales, Australia, to provide more-accurate insight into overall fracture height. This paper outlines the key issues that must be addressed from a regulatory perspective in regard to the development of an onshore unconventional-gas industry in the Northern Territory. This paper provides an insight into the challenges encountered and overcome during installation of 20 subsea structures, some close to 1000 t in weight and in water depths of up to 1350 m, for the Gorgon project offshore Western Australia.
After a long cooling off period, this dry-gas shale play is once again red hot. The state-owned firm is looking within its home country, around Southeast Asia, and to the Americas—including shale—in an effort to maintain its forecast average yearly production of 1.7 million BOE/D over the next 5 years. Encana CEO Doug Suttles assures that shale executives are acutely aware of the parent-child well challenge, and he doesn’t think it’s “a big threat” to the sector. The US majors plan to produce around 1 million BOE/D each from the basin, which has become a primary focus of their upstream operations. This industry is one often considered reactive and overly tradition-bound.
The explorer has so far encountered 400 ft of reservoir pay zone in an area where it has three other producing fields. Murphy Oil to Buy Deepwater US Gulf Assets for up to $1.625 Billion The El Dorado, Arkansas-based Murphy has quickly found a home for some of the cash it will receive from the sale of its Malaysia business. The company has been rapidly expanding its US gulf footprint while simplifying its portfolio and targeting more oil. Petrobras and Shell have brought online the Lula field’s seventh FPSO as the firms continue to ramp up production from the pre-salt Santos Basin. The French major is racking up barrels of deepwater production as part of its large-scale West African push.