Lv, Zuobin (Tianjin Branch of CNOOC Ltd.) | Huo, Chunliang (Tianjin Branch of CNOOC Ltd.) | Ge, Lizhen (Tianjin Branch of CNOOC Ltd.) | Xu, Jing (Tianjin Branch of CNOOC Ltd.) | Zhu, Zhiqiang (Tianjin Branch of CNOOC Ltd.)
JZS oilfield is an offshore metamorphic rock fractured buried hill oilfield. It was put into development in July 2010. The overall production situation of the oilfield is good, but some problems have been exposed. The main performance is as follows: It is difficult to accurately characterize the heterogeneity of fracture space distribution; In the numerical simulation of fractured reservoir, it is impossible to accurately describe and predict the fracture flow of fluid channeling in corner point grid system.
In order to solve the above problems, this study presents a new integrated fractured reservoir geological modeling and numerical simulation research method based on unstructured grid. There are three key aspects to this method. (1) The multi-scale (large, middle and small) discrete fracture system is established by combining outcrop measurement data with well point information and seismic attributes. On the basis of post-stack 3D seismic data, ants attributes are extracted, then the ant body results are transformed into large scale fractures; Using azimuth anisotropy attribute based on pre-stack inversion and combining the distribution orientation of large-scale fractures, the middle-scale fractures are established; According to the power law distribution relation between the cumulative frequency and the fracture length of large scale and small scale which based on outcrop observation, the imaging logging data and pre-stack inversion azimuth anisotropy attribute, small scale fractures are constructed by DFN technology.(2) For multi-scale fractures, the unstructured grid division technique is used to build a 3D model that conforms to the heterogeneity of dual media. In this study, a layered triangular prism grid generation technique is proposed. It is used to establish model of multi-scale fractures based on unstructured grid. Using large-scale fractures as a constraint, full 3D unstructured grid model is set up, and the discrete fracture model can accurately describe the fracture system and the coupling relationship between matrix and the fracture;(3)The triple-medium numerical simulation of the reservoir in the study area is carried out by using the automatic history fitting technology of ensemble kalman filter (EnKF). After several parameter adjustments, both the coincidence rate of the index and the fitting precision are higher than before.
Multi-scale discrete fracture model based on the large-scale fractures discretization processing, equivalent medium processing to middle and small scale fractures, keeps the seepage characteristic of the large-scale discrete fractures model and ensures the calculation efficiency. The results show that the new method has obvious advantages in computing speed and that the fitting effect is closer to the actual production performance.
Lopez, Ramiro Gabriel (YPF. S.A.) | Flores Montilla, Gustavo (YPF. S.A.) | Hryb, Damian (YPF. S.A.) | Periale, Santiago (YPF. S.A.) | Fantin, Julian (YPF. S.A.) | Perez, Gustavo (YPF. S.A.) | Simonetto, L. (YPF. S.A.) | Manceda, René (Y-Tec)
ABSTRACT: Due to the complexity in reservoir development of a Naturally Fractured Carbonate, a static model, combining matrix and natural fractures properties was carried out and then dynamically simulated in order to evaluate different scenarios both for vertical and horizontal wells. DFN model included in the static model was constrained by Drill core description, Borehole image analysis and 3D Seismic structural interpretation. From this data a Geomecanically based Tectonic evolution model was carried out in order generate Natural Fractures Orientation and Intensity drivers which were used to guide DFN population. All properties were then upscaled for dynamic modeling. During this modeling, several parameters where evaluated with the aim of reduce reservoir uncertainty. This process allows recognizing the relative importance of parameters as quantity of perforation meters, fracture porosity, fracture permeability and Oil-water contact. At the end of this simulation it was recognized that a horizontal well could produce 2.5 times more than a vertical well.
Hydrocarbon production is usually restricted by excess water production in naturally fractured reservoirs. Polymer gel injection is an efficient method to shut-off fracture conduits in water bearing zones. Efficiency of water shut-off may decrease in time due to several reasons. Well diagnostic methods such as recovery plot, production history plot and decline curve analysis can be used to identify necessity to re-gel the well. Both of the surveillance methods require some sort of analytical modeling and may not identify performance loss in due time. In this study, we propose the use of pressure build up test analysis as diagnostic tool to optimize re-treatment time. To achieve this goal a highly fractured heavy oil reservoir going through polymer injection is modeled using discrete fracture network (DFN) modelling approach where it is used as a tool for providing fracture properties to the dual-porosity fluid flow simulator. DFN model is created by using available fracture parameters. The model is then calibrated by conditioning it to well test data obtained from a heavily fractured field located in South East Turkey. A CMG STARS single well/dualporosity numerical model whose fracture properties are populated by the DFN model results is used to model polymer injection. Once the matches obtained with DFN populated dual porosity model were obtained, several synthetic pressure build up tests were conducted to estimate skin factor as well as permeability which are markers used for regel treatment performance. It was concluded that well test analysis is an efficient tool to estimate the time of re-gel operation.
ABSTRACT: We model the geomechanical, flow, and thermal effects associated with the cold-water-injection process into a fractured reservoir. This problem is pertinent to the prediction of well injectivity and productivity changes in geothermal as well as fractured oil and gas reservoirs. The injected fluid can dramatically alter the formation temperature and pressure, which impact the stresses on natural fractures and their hydraulic properties. We demonstrate the use of a coupled thermo-hydro-mechanical simulation framework to analyze the observed bottom-hole-pressure measurement from an actual waterflooding pilot for a fractured carbonate reservoir. We employ unstructured grids that represent natural fractures explicitly as discrete polygonal planes containing fluid and the matrix rock as conforming polyhedral cells. Finite- volume and finite-element discretization schemes are employed for the flow/thermal and mechanical problems respectively. We show that the well-pressure data can be explained by the evolution of fracture hydraulic properties predicted by our framework and that thermal effects only become important over the longer term in this case. The results indicate that it is important to account for geomechanical, flow, and thermal effects for the successful long-term development of such reservoirs.
In this study, we consider the simulation of a cold- water-injection process of a real fractured carbonate reservoir and evaluate the associated geomechanical, flow, and thermal effects. As the injected fluid flows through the fracture network and penetrates the formation, it can cause significant changes in rock temperature, pore pressure, and stresses acting on the natural fractures, which in turn lead to the alteration of fracture hydraulic properties. This phenomenon can manifest itself in pressure measurements at injection wells. For typical values of thermal, flow, and mechanical properties of rocks, the propagation of temperature changes is slower than that of pressure. However, thermal effects can be important if the time scale is long or the temperature contrast between the injected fluid and reservoir is large. For example, Nakao and Ishido (1998) described the unexpected decline in well bottom-hole-pressures during the constant-flow-rate injection of cold water into a geothermal reservoir, which was attributed to nearwell, injection-induced cooling.
ABSTRACT: Simulating pressure changes and production processes in natural fractured formations has been commonly performed by the classic dual-porosity model. Geomechanics can be crucial for pressure change and production as both formation deformation and locally induced stresses may contribute to skeleton deformation and the pressure change thus production significantly, particularly in low-permeability and fractured formations. Multiphase flow in both the matrix and fractured system can significantly affect the production and pressure results, particularly near a wellbore or a hydraulic fracture. The key parts on developing this model are to come up an efficient algorithm and to define the parameters characterizing the geomechanics coupling to the flow on top of the explicit coupling to the saturation, where upstream weighting normally is applied. The proposed algorithm coupled the pressures from both system with the corresponding volumetric strain and subsequently explicitly coupled to the saturation. Both a generalized Galerkin and Petrov-Galerkin finite methods are used in which mixed quadratic and linear shape functions are implemented respectively for the displacement and pressures, yet only quadratic weighting function is used in the calculation of saturation and for the entire weighting function. A unique weighting function with different P-G coefficient is also proposed and tested for saturation calculation. Results for saturation and pore pressure near a wellbore during a pressurization are generated and discussed, simulating fracturing process in naturally fractured reservoirs.
Flow in naturally fractured reservoirs is normally characterized and modeled by the well-known sugar cubic model proposed by Barenblatt et al.,  and Warren and Root, . Extensive studies follow by mixture theory focusing on stress-sensitivity and loosely geomechanics coupling [Wilson and Aifantis, 1982, Beskos and Aifantis, 1986, Huyakorn and Pinder, 1983, Elworth and Bai, 1992, Bai et al 1993] and by an alternatively conventional reservoir-geomechanics coupling model following Biot’s theory [Biot, 1941, Duguid and Lee, 1977, Vallianppan and Khalili-Naghadeh, 1990, Khalili-Naghadh and Valianppan, 1996, 1996, Chen and Teufel, 1997]. Following Vallianppan and Khalili-Naghadeh, 1996, Chen and Teufel , an extended Biot theory coupled the fluid flow to deformation is proposed and implemented. Those critical parameters between stresses and pore pressure and the deformation coupled between pore volume, bulk volume, porous matrix, solid particle, and fractured volume are highlighted. Studies on dual porosity model have been extended into two phase flows [Nair et al., 2005, Bai et al., 1999] by a mixture theory. Following Wang and Chen  in which only a single poroelastic model is proposed, a two phase flow model with extended Biot formulation will be the focus in this paper. Two phase flow during hydraulic fracturing in a fractured formation is of great interest to engineers in petroleum engineering and hydrogeology. Both the over-all production and flow back fluid after a fracturing job are heavily depending on the saturation change near a hydraulic fracture or in the vicinity of a wellbore. Coupling to geomechanics is another important aspect of the issues in the naturally fractured reservoirs. A generalized finite element approach with an extended Galerkin method in which the weighting function consistent with the shape function in pore pressures are used is implemented. A general formulation with four pore pressures and one bulk displacement as the primary variables are presented. Results from an approximated formulation in which an average pore pressure in each medium is used by adding two mass balance equations for different phase, i.e. water and oil are presented. Saturation calculation is validated by an analytical solution.
In this paper, geomechanics is coupled with reservoir flow for modeling the depletion and deformation in fractured vuggy carbonate reservoir. Different from the dual- and triple-porosity models or the coupled approaches in which the vugs are considered as a continuous porosity, the vugs are treated as virtual volumes in this study. For each vug, the fluid exchange at the vug-matrix interface is dynamically calculated with time evolution and the pore pressure in the vugs is updated through considering both the fluid material balance and the volume change due to the mechanical deformation of vug. The fluid-mechanical interaction in the rock matrix and natural fractures is calculated based on the framework of Biot's poroelstic theory. The mechanical and hydraulic interactions between vugs and matrix are preserved and the stress evolution due to the depletion can be dynamically updated. The results in this study show that, the depletion process is mainly controlled by the fluid storage of the vugs. Fluid modulus is thus a more sensitive parameter than the rock/fracture modulus in terms of the depletion. However, the rock/fracture modulus can also affect the deformation of the system and thus affect the volume and pressure changes of the vugs.
Padra field, discovered in 1977, is located in the eastern margin of Ankleshwar-Broach tectonic block of Cambay basin. Padra basement is overlain by thick sedimentary succession of clastic reservoir rocks and shale barriers including Cambay shale (major source rock). The characterization, modelling and flow simulation of fractured basements is complex and entirely different from conventional reservoirs. The paper aims to introduce a unique approach for study of basement reservoirs.
A Discrete Fracture Network (DFN) model is made to represent two fracture set explicitly, based on spatial and non-spatial parameters. Fracture orientation is distributed using statistical model of Fisher. Simulation exercises are carried out wherein; fractures are not explicitly represented but an equivalent virtual medium is created with effective properties (porosity and permeability) representing the dynamic properties of the flowing domain (fractures). Being a type I basement reservoirs, single medium model (single porosity and permeability) is used for flow simulation with effective properties calculated by Oda's method of numerical flow.
This work paves the way to establish workflows that benefit from the merits of complementary methods, which will allow us to characterise the uncertainty in naturally fractured reservoirs more accurately. The case study elucidates the experiences gathered during simulation study of 112 wells, out of which 48 wells have been found to be hydrocarbon bearing. Pressure and water cut trend indicate active aquifer support. Early cessation of structurally higher wells in same as well as different fault blocks has been found to be a prominent anomaly. Also, strong contrast in reservoir performance of nearby wells has been found in a few cases. This indicates a great level of heterogeneity in fracture distribution in reservoir. Ten zones of alternate high and low fracture intensity have been created based on interpretation of 6 FMI logs. The fracture counts (P10, count per length) in wells with FMI should have been used as indicator for fracture intensity (fractures area in a unit volume). Sensitivities on interaction forces and roughness of fracture planes is carried out as a key part of dynamic modeling. The DFN approach allows us to generate multiple realisations of fracture models and condition these to the field observations.
Characterizing fractured reservoirs using borehole core and image logs provides the static description of fracture properties. However, some fracture properties (3D fracture-density) are highly uncertain when they are evaluated using static characterization methods only. Hence, dynamic calibration methods are required to condition geological fracture models and to increase confidence in the adopted conceptual model. Pressure transient analysis integrated with log/core information must be used to characterize the reservoir's flow capacity and for the dynamic calibration.
He, Jie (Texas A&M University) | Killough, John E. (Texas A&M University) | Gao, Sunhua (Texas A&M University) | Fadlelmula, Mohamed M. (Texas A&M University At Qatar) | Fraim, F. Michael (Texas A&M University At Qatar)
Flow simulation in carbonate reservoirs presents many challenges due to the frequent occurrence of vugs and natural fractures therein. In conventional reservoir simulation practices, fluid flow in vugs and fractures is usually assumed as Darcy flow, and permeability values are estimated for vuggy regions and fractures. Although such estimations are often accomplished in reasonable ways, no physical or mathematical basis exists for them, and even the assumption of Darcy flow itself is questionable.
In this paper, we propose a novel workflow for the simulation of fluid flow in naturally fractured carbonate karst reservoirs. The workflow is based on simulation results of a single-phase transient Brinkman model, which provides the correct and complete description of the coupled flow in vuggy and fractured reservoirs by unifying Stokes flow in vugs and fractures with Darcy flow in the rock matrix. The new workflow proceeds through an iterative procedure by increasing the permeability values of vugs and fractures without the disadvantages of accurately estimating them, and attains the final simulation results when a convergence pattern is observed.
The novel workflow is implemented and compared with the conventional approaches in commercial reservoir simulators. The workflow is first applied to single-phase flow simulations in a fine-scale 3D geological model which is generated using the multiple-point geostatistical modeling technique, and then extended to immiscible two-phase flow and other multi-phase cases. Simulation results show that in most cases our new workflow yields higher production rate predictions than conventional approaches. This is due to the fact that the permeability values of vugs and fractures estimated by conventional methods are usually lower than the permeability values required for the iterative convergence of the new workflow. The results also have further implications on the history matching process that more focus should be put on fracture geometry, i.e. fracture width and half-length, since the use of fracture permeability alone has lost its physical meaning in the novel workflow according to the Brinkman equation.
Naturally fractured reservoirs (NFRs) always have flow networks that are more or less irregular, discontinuous, or clustered. NFR with such spatially non-uniform distribution of fractures is called partially naturally fractured reservoir (PNFR). An improved understanding of pressure response is required to characterize PNFR. This paper presents a better understanding of well test pressure response of PNFR.
Stochastic modeling was used to generate various geological models with different fracture intensities. Single phase liquid flow through stochastically generated reservoirs is simulated by a numerical reservoir simulator. Dual-porosity / dual-permeability model was selected to simulate PNFR. A vast database of pressure transient responses of the reservoirs with varying fracture intensity, matrix permeability and fracture porosity is presented in this paper. Pressure derivative was used to analyze the pressure transient responses.
Pressure derivative analysis indicates multiple V-shapes representing various sets of fracture intensities. It is observed that with the increase of fracture porosity V-shape become more pronounced. It is also observed that with the increase of matrix permeability, the duration of composit radial flow is prolonged. The shapes of pressure drawdown plots indicate the level of fracture connectivity of the reservoir. Whereas the fracture connectivity is related to the fracture intensity (FI). The critical value of fracture intensity is observed around 60 percent which results in the formation of connected fracture network.
The interpretation of pressure responses of PNFR becomes very difficult and challenging because the available simplified models do not relate to reality of reservoirs. This paper quantifies the fracture intensity for a broad range of PNFR with the use of pressure transient responses. This quantification is a major contribution to the present literature.