Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Abstract: In the last decade, the petroleum industry became more and more aware of the determining role that fractures and faults play in the oil field production. The main reasons include an improved fracture detection from efficient logging tools and from an advanced interpretation of high-quality seismic data. Moreover, the increasing number of mature fields, in which are met unexpected production difficulties -such as breakthroughs-, raises suspicions as for the presence of fractures. At the same time, 3D modelling methodologies, implemented within powerful software, have been developed in order to integrate fracture-related information into consistent and reliable field-scale flow simulation models. This paper points out and illustrates the recent progress in the field of fracture modelling, which makes integrated fractured reservoir studies a reality. It also underlines the promising perspectives offered by advanced calibration, history matching and simulation techniques, which hopefully, will merge the so-called static and dynamic studies into a single multidisciplinary process. INTRODUCTION Although the specific flow behaviour of fractured reservoirs was identified and modelled a rather long time ago until recently no consistent methodology and software enabled to really integrate field information about natural fracturing in reservoir engineering studies. The availability of direct information about fractures, in particular borehole images, was an incentive for such integration. The unexpected production behaviour of many fields arising from an insufficient consideration of fracture effects on flow also emphasised the need for better characterising the distribution of fractures at various scales and transferring the meaningful part of this information to field simulation models. A recent example concerns a giant Middle East Carbonate field where sub-seismic fracture swarms and stratiform super-K intervals were found to establish preferential flow paths between injection and production wells. Therefore, the present trend in fractured field studies is toward the use of methodologies and software platforms to integrate all information about fractures into flow simulation models. The main features of those methodologies are described herein, on the basis of fracture modelling examples set up using our own workflow3 illustrated in Figure 1. This workflow involves the following steps:–constrained modelling of the geological fracture network based on the analysis, interpolation and extrapolation of fracture information acquired in wells and derived from seismic data, sometime completed by outcrop analogue data; –characterising the hydrodynamic properties of this natural network from flow-related data; –choosing a flow simulation model suited to the role played by fractures and faults at various scales and assigning to this model upscaled parameters derived from the flow-calibrated geological fracture model; –simulating the reservoir productivity and recovery on the basis of a physical assessment of the multiphase flow mechanisms prevailing in transfers within and between media. (Figure in full paper) In the following, those four steps are reviewed and illustrated from a representative synthetic field case. Emerging techniques to further capture the complexity and flow behaviour of fractured reservoirs are also identified
- Asia > Middle East (0.28)
- North America > United States > Kentucky > Butler County (0.24)
Abstract: A significant part of any field development planning exercise resides in adequately quantifying reservoir uncertainty, particularly when information availability is limited. For marginal fields, accurate appraisal of the downside of a project becomes even more crucial, as different development options carry a significant probability of negative net-present-value and project economic viability relies on reservoir risk minimization. It is then imperative to undertake a complete and detailed risk analysis, in order to identify key contributors to reservoir uncertainty, their combined effect and their impact on the final economic outcome. A thorough understanding of the risk setting can lead to resources being better focused, data acquired and creative solutions found, thereby mitigating the uncertainty and shifting the Gaussian distribution of recovery and net-present-value to the right. The evaluation and quantification of the impact of key uncertainty factors is exacerbated by the multiplicity of combinations in development options and can only be represented by a very high number of simulations. It is only with today's computing power and recent software developments, in stochastic data analysis and statistical optimization, that it is possible to quickly and exhaustively encompass all relevant uncertainty parameters. The following case of a marginal offshore field in Angola illustrates the successful application of a stochastic planning approach in defining the optimum field development strategy. A novel workflow in stochastic analysis was applied allowing proper identification and mitigation of all relevant risk factors. This resulted in the determination of optimum surface facilities dimensions, well locations, drilling plans, wellhead structure locations, coring programs and logging suites. This methodology was key in establishing an economically viable option in this high cost, high-risk area. INTRODUCTION The Morsa-West field was discovered in the early 80's, offshore Angola, and delineated four separate hydrocarbon-bearing accumulations with a total of eight exploratory and appraisal wells. The formation types vary from sand (S) to sandy dolomite (SD) to predominantly dolomite (D) with productivities ranging from fair to good depending on the different geological environment and the presence of tectonically created fractures. The original operator attempted to put forward a viable development plan but had to relinquish operatorship as no economic solution was reached. Sonangol P&P, the operating arm of Sonangol, took it upon itself to investigate the development of this potential and completed a subsurface evaluation of the area. This evaluation concluded that five of the eight wells drilled encountered oil and the four confirmed accumulations could potentially be developed economically. Simultaneously, oil-bearing exploratory prospects were identified in the area providing further need for project implementation. Following this work, Sonangol P&P approached the Concessionaire and was granted the right to review the information and propose a field development plan for the Morsa-West area. The following work is a culmination of the efforts, put forward by the Sonangol sub-surface Team, to develop what was previously labelled as a marginally economic field into a profitable venture for Sonangol P&P. Definition of Risk Two types of risk exist at the Field Development level, Market Risk and Project Risk.
Abstract: In naturally fractured reservoirs, there usually developed many scales of fractures, from multidarcy large fractures to hundreds of milli-darcy small fractures and even to milli-darcy matrix. This results in multi-scale flow in the subsurface and makes it tougher to analyze well productivity. In this paper, multi-rate well testing data were used to predict the well productivity at different pressure in naturally fractured reservoirs. This method is exemplified with a case reservoir in China. The predictions are very close to later field production data. We conclude that oil production rate in these kinds of reservoirs is not only impacted by both two-phase flow and non-Darcy flow as in the conventional reservoirs, but also impacted by the variation of fracture opening with reservoir pressure. This conclusion can be used to better define optimal rate with reservoir pressure decline in the naturally fractured reservoirs, thus further improve our forecast and enhance our reservoir development results. Introduction Many detailed studies have been done and lots of papers published on productivities of artificially fractured well. For example, McGuire, W.J. and Siora , V.J, Prats, M. and Levine, J.S ; van Poollen, H.K., Tkrsley, J.M. and Saunders, C.D. and Oberwinkler, C. et al have investigated the effect of fracture length and conductivity on post-fracture well productivity for vertically fractured reservoirs assuming pseudo steady-state or steady-state flow in the reservoir and fracture height equal to the reservoir thickness. Later, Tinsley et al investigated the relationship between fracture height and well productivity for cases assuming that the fracture height was equal to or less than the reservoir thickness. All of these works employed two-dimensional mathematical or physical analogy models to predict post thickness fracture well productivity. However, for naturally fractured wells, literatures on the well productivity are limited. The unique characterization of natural fractures makes its well productivity performance different with that of the artificially fractured well. Due to the decline of reservoir pressure, the fracture opening in the reservoir, especially that near the wellbore area, will decrease, which will result in the loss of permeability near wellbore. This permeability loss will impact the well productivity and should be taken into careful consideration when designing the field development. With the increase of oil and gas production from naturally fractured reservoir, the reservoir properties and production performance of this reservoir show a unique behaviour, which is different from the homogeneous reservoir. This uniqueness should be studied to ease our effort to predict later reservoir performance. In 2004, Joshi R described a field case study of Hunton Formation in West Carney Field in Oklahoma. The targeted formation is geologically complex with a large number of fractures. Some of the unique characteristics of the field include decreasing GOR at the beginning of production, increase in GOR after shut-in and sustained oil rates over long periods of time. The authors successfully used material balance and compositional flow simulation technique to reproduce the unique characteristics of the field.
- Asia (0.90)
- North America > United States > Oklahoma > Lincoln County (0.34)
- North America > United States > Oklahoma > Anadarko Basin > Carney Field (0.99)
- Asia > China > Hebei > Bohai Basin > Jizhong Basin > Renqiu Field (0.99)
- North America > United States > Texas > Anadarko Basin > Hunton Field > Hunton Limestone Formation (0.98)
- (2 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)