Karam, Pierre (Baker Hughes, a GE Company) | Yang, Junjie (Baker Hughes, a GE Company) | Cozyris, Kristian (Baker Hughes, a GE Company) | Stephenson, Tim (Baker Hughes, a GE Company) | An, Xiaoxuan (Baker Hughes, a GE Company) | Jung, Chimok (SK E&P Operations America) | Jun, Jongyoung (SK E&P Operations America) | Lee, Hyungseok (SK E&P Operations America)
Sooner Trend Anadarko Canadian Kingfisher, also known as STACK, is a booming unconventional oil play in North America. As one of the main features that makes the asset profitable, multiple targeting benches raise a challenge of optimization. Well-developed natural fracture system brings in another level of complexity to estimate well spacing. This study introduces an integrated workflow to better understand the fluid flow mechanism in the reservoir and optimize development strategy.
From borehole image log, natural fracture orientation and density was interpreted and statistically populated into geologic model along with petrophysical properties. To account for productivity enhancement due to natural fractures, enhanced permeability was embedded into the simulation model according to the distribution of discrete fracture network. After being history matched, the reservoir model was used to test the sensitivity on well spacing, landing zone and hydraulic fracturing pump schedule. Both infill drilling program and green field development scenarios were tested and compared to optimize our field development study.
Production history match indicates that natural fractures serve as fluid flow conduit and contribute significantly to the production in Osage. Pressure transient observation shows a similar reservoir behavior in the Osage as opposed to the Woodford. Multiple wells experience productivity reduction over longer production history, indicating near-field damage (such as scaling) and/or far-field damage (such as fracture closure). Introduction of skin factor and pressure dependent permeability captured the trend on productivity behavior in the history match. In addition, the simulation study shed light on the hydraulic fracture geometry that provides direct insight on well spacing and landing zone analyses. Results from the infill drilling program show that staggered design with 3 Osage and 4 Woodford wells per section yields the higher oil recovery. However, using the greenfield sensitivities, and depending on the pumping schedule, hydraulic fractures from Woodford wells show upward growth, draining both formations effectively even without Osage wells.
This study provides valuable information about the development strategy in STACK unconventional resources, particularly for scenarios with natural fracture system and multiple targeting zones. The simulation workflow considers well interference in both horizontal and vertical directions simultaneously to optimize oil recovery and reduce operational cost.
A challenge in oil-reservoir studies is evaluating the ability of geomechanical, statistical, and geophysical methods to predict discrete geological features. This problem arises frequently with fracture corridors, which are discrete, tabular subvertical fracture clusters. Fracture corridors can be inferred from well data such as horizontal-borehole-image logs. Unfortunately, well data, and especially borehole image logs, are sparse, and predictive methods are needed to fill in the gap between wells. One way to evaluate such methods is to compare predicted and inferred fracture corridors statistically, using chi-squared and contingency tables.
In this article, we propose a modified contingency table to validate fracture-corridor-prediction techniques. We introduce two important modifications to capture special aspects of fracture corridors. The first modification is the incorporation of exclusion zones where no fracture corridors can exist, and the second modification is taking into consideration the fuzzy nature of fracture-corridor indicators from wells such as circulation losses. An indicator is fuzzy when it has more than one possible interpretation. The reliability of an indicator is the probability that it correctly suggests a fracture corridor. The indicators with reliability of unity are hard indicators, and “soft” and “fuzzy” indicators are those with reliability that is less than unity.
A structural grid is overlaid on the reservoir top in an oil field. Each cell of the grid is examined for the presence and reliability of inferred fracture corridors and exclusion zones and the confidence level of predicted fracture corridors. The results are summarized in a contingency table and are used to calculate chi-squared and conditional probability of having an actual fracture corridor given a predicted fracture corridor.
Three actual case studies are included to demonstrate how single or joint predictive methods can be statistically evaluated and how conditional probabilities are calculated using the modified contingency tables. The first example tests seismic faults as indicators of fracture corridors. The other examples test fracture corridors predicted by a simple geomechanical method.
This paper describes the application and testing of innovative dual porosity flow diagnostics to quantitatively rank large ensembles of fractured reservoir models. Flow diagnostics can approximate the dynamic response of multi-million cell models in seconds on standard hardware. The need for new faster screening methods stems from the challenge of making robust forecasts for naturally fractured carbonate reservoirs. First order uncertainties including the distribution and properties of natural fractures, matrix heterogeneity and wettability can all negatively impact on recovery. A robust multi-realisation approach to production forecasting is often rendered impractical due to the time cost for simulating many models.
We have extended existing flow diagnostics techniques to dual porosity systems by accounting for the matrix-fracture exchange. New metrics combine the transfer rate with the advective time of flight in the fractures identifying risk factors for early water breakthrough and providing quantitative measures of dynamic heterogeneity.
We have compared ranking a large ensemble of synthetic fractured reservoir models using dual porosity flow diagnostics and using full-physics simulation. The synthetic ensemble explores a number of different geological concepts around the fracture distributions, wettability and matrix heterogeneity which can. Not only does the flow diagnostic ranking agree well with the cumulative oil ranking the run time for the flow diagnostics is <0.25% of the total simulation time. This significant reduction in the time to compare models allows more time to spend running full physics simulation on the important and geologically diverse cases that offer the most insight.
Due to numerical difficulties in conducting high fidelity simulation of recovery mechanisms in complex natural fracture systems, there are no published studies that address the impact of preserving details of the fracture networks. We used highly refined grids to conduct fine scale simulations of various recovery mechanisms in different complex fracture settings and compared the results to those obtained on simplified dual porosity dual permeability (DPDK) representations created by applying a consistent upscaling procedure.
Our study considers densely connected, sparsely connected, and isolated fracture networks that are extracted from a field-scale fractured carbonate reservoir model. Discrete fracture-matrix (DFM) models were constructed using an unstructured grid with refinement of the matrix rock near fractures. High-resolution simulations of spontaneous imbibition, gravity drainage, and viscous displacement recovery mechanisms were conducted on these DFM models. We also built equivalent DPDK models by using single phase flow-based upscaling and actual fracture geometry and distribution. The recovery mechanisms were simulated on these DPDK models and compared to high-resolution DFM models.
The fine scale simulations revealed that lateral viscous displacement recovery depends on the details of the fracture networks and can be significantly higher than those predicted from equivalent DPDK models. The DPDK models all predict the same recovery. For spontaneous imbibition, both fine scale and equivalent DPDK models show dependence on fracture geometry, but the DPDK models predict much higher rates. Fine scale and equivalent DPDK models agree reasonably for gravity drainage. These findings are explained by analyzing the matrix-fracture flows, and implications on efforts to improve shape factors in DPDK models and upscaling efforts in DFM models are discussed.
In an unconventional reservoir, the biggest challenge is to know how the natural fractures drain the reservoir as they have the greatest impact on production. But unfortunately very little information is available about them. Microseismics aid in building a picture of the fracture network, but give no information about fractures where actual fluid flow occurs. Production logging results give information around wellbore area only. Conventional rate transient analysis has major drawbacks, as long shut-in times are not possible and with dimensionless variables multiple results are possible. The method outlined in this paper overcomes these limitations using simplified assumptions.
The simulation modeling method uses dual porosity method as an idealization of the fracture network, which is the conventional wisdom, but with constant volume hydraulic fractures. This restricts the possible fracture lengths and the associated geometries of these hydraulic fractures, when modeled in 1D, 2D or 3D orientation. These HF-NF connectivity scenarios, using idealized fracture network of slabs (planar 1D HF-NF), matchstick (non-planar 2D HF-NF) and cubes (non-planar 3D HF-NF) is used to establish those fundamental connectivity scenarios where the fracture spacing can either be 1:1:1 (equidistant) or in the ratio 1:2:3. In order to assign permeability to the fractures, under these six different fundamental scenarios which have the same production performance, we follow the single block approach based on rate transient analysis. It also helps in establishing fracture permeability for other fracture connectivity variants such as 2D HF - 3D NF or 3D HF - 2D NF and with the two previously specified fracture spacings.
The results of this study, which essentially deals with the reservoir linear flow, are presented in the form of characteristic plots based on the ratio of average dimensionless pressure in the block with the square root of dimensionless time versus the dimensionless time for different fracture pressure declines. In each of fracture connectivity scenarios the solution rises to a discreet 1, 2, 3 value if idealized blocks are used or fall short of these values for non-idealized block combination depending on block geometry of NF. These conclusions are also shown by field models, analyzing actual history matched data.
Basic knowledge of the orientation of NF network gives better history match and prediction results. Also, with the help of a reservoir simulator one can assign physical meaning to different fracture spacings, which could be in the increasing or decreasing form. Rate transient analysis, using dimensionless parameters, fails to illustrate this fact. This helps a long way in establishing optimum fracture spacing with the same volume of proppant being pumped in the reservoir and known NF orientation.
Wheeler, Mary F. (The University of Texas at Austin, USA) | Srinivasan, Sanjay (Pennsylvania State University, USA) | Lee, Sanghyun (Florida State University, USA) | Singh, Manik (Pennsylvania State University, USA)
Optimal design of hydraulic fractures is controlled by the distribution of natural fractures in the reservoir. Due to sparse information, there is uncertainty associated with the prediction of the natural fracture system. Our objective here is to: i) Quantify uncertainty associated with prediction of natural fractures using micro-seismic data and a Bayesian model selection approach, and ii) Use fracture probability maps to implement a finite element phase-field approach for modeling interactions of propagating fractures with natural fractures.
The proposed approach employs state-of-the-art numerical modeling of natural and hydraulic fractures using a diffusive adaptive finite element phase-field approach. The diffusive phase field is defined using the probability map describing the uncertainty in the spatial distribution of natural fractures. That probability map is computed using a model selection procedure that utilizes a suite of prior models for the natural fracture network and a fast proxy to quickly evaluate the forward seismic response corresponding to slip events along fractures. Employing indicator functions, diffusive fracture networks are generated utilizing an accurate computational adaptive mesh scheme based on a posteriori error estimators.
The coupled algorithm was validated with existing benchmark problems which include prototype computations with fracture propagation and reservoir flows in a highly heterogeneous reservoir with natural fractures. Implementation of a algorithm for computing fracture probability map based on synthetic micro-seismic data mimicking a Fort Worth basin data set reveals consistency between the interpreted fracture sets and those observed in the reference. Convergence of iterative solvers and numerical efficiencies of the methods were tested against different examples including field-scale problems. Results reveal that the interpretation of uncertainty pertaining to the presence of fractures and utilizing that uncertainty within the phase field approach to simulate the interactions between induced and natural fracture yields complex structures that include fracture branching, fracture hooking etc.
The novelty of this work lies in the efficient integration of the phase-field fracture propagation models to diffusive natural fracture networks with stochastic representation of uncertainty associated with the prediction of natural fractures in a reservoir. The presented method enables practicing engineers to design hydraulic fracturing treatment accounting for the uncertainty associated with the location and spatial variations in natural fractures. Together with efficient parallel implementation, our approach allows for cost-efficient approach to optimizing production processes in the field.
A novel approach is introduced for simulation of multiphase flow, geomechanics, and fracture propagation on very general semi-structured grids. Complex networks consisting of both natural and hydraulically stimulated fractures are able to be represented using a diffusive zone model in large scale reservoirs. A mass conservative method called the enhanced velocity mixed finite element method is used to model multiphase flow with a fully-compositional equation-of-state model. Its recent reformulation on semi-structured, spatially non-conforming grids allows very general local refinement and dynamic mesh adaptivity.
Iteratively coupled geomechanics is simulated, which can predict fracture opening on fixed networks based upon induced stresses and poromechanical effects. In the most complex case, it is coupled with the phase field method to model nucleation and branching of non-planar fractures in highly heterogeneous media. Several examples are demonstrated to model fracture networks. The general semi-structured discretization can simulate flow and geomechanics on networks of fractures in large reservoirs with local resolution where desired. Dynamic adaptive mesh refinement can be used for both tracking transient flow features such as sharp the propagation of new fractures via hydraulic stimulation. This framework allows the seamless ability to switch from production to propagation scenarios, by varying the degrees of physics.
This work demonstrates a capability to perform high-fidelity simulations on complex fracture networks in large reservoirs at a reasonable computational cost. The gridding algorithms are straightforward extensions to traditional finite difference reservoir simulators. It can also be coupled with state-of-the-art complex phase field fracture propagation. This extends the capabilities of many legacy reservoir simulators to handle more physics.
The objective of this study is to compare the laboratory behavior of natural (Mode II) and induced (Mode I and II) fractures during stress-dependent permeability tests (SDk) to verify under which conditions the hydraulic behavior of induced fractures may be assumed to be representative of that of in-situ natural fractures. Fracture modes are identified by the way the force that enables the crack to propagate is applied and may be of three different types. Mode I fractures (propagated by a tensile stress normal to the plane of the crack) and Mode II fractures (propagated by a shear stress acting parallel to the plane of the crack and perpendicular to the crack front) are of import in the present study. To test under which conditions this assumption may hold, cylindrical specimens of different rock types including plugs with an intact matrix and plugs with a natural fracture propagating through their body were selected. When possible, the plugs were grouped in pairs so as to form homogeneous sets characterized by a coherence in specific matrix properties (porosity, density, permeability), with each pair including a plug containing a natural fracture. Induced Mode I and Mode II fractures were then propagated axially through the intact specimens and each plug set was tested for SDk. All of the tests were run under similar triaxial test conditions.
The fracture description plays an important role in shale gas well production performance prediction, late production refracturing design and infill well trajectory design. Based on the development and geological parameters of Fuling shale gas field, the enhanced discrete fracture network (EDFN) numerical simulator is used to study the influence of fracture length, total fracture length, stage spacing and relative position of fractures on the contribution ratio of fracture stage. According to the relationship among JY46-3HF gas production profile, gas production contribution ratio and fracture characteristic parameters, a fracture network model is established. The simulation results of gas production contribution ratio of each fracture stage are highly consistent with the measured data. The research results show that: the contribution ratio of gas production in each fracture stage is positively related to the total cumulative fracture length, and the fracture spacing and relative position of fractures affect the contribution ratio of fracture stage to shale gas well by the size of matrix area controlled by fracture.
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.