In the porous matrix type (the more common), most of the hydrocarbons are stored in the matrix porosity, and the fractures serve as the principal flow conduits. Such reservoirs typically are identified as "dual-porosity" systems. Some cherts exhibit dual porosity and have significant storage capacity in the matrix, but that contributes little to reserves. Such reservoirs frequently are associated with basement rocks. Examples include: When they occur in carbonates, fractures tend to facilitate extensive leaching and diagenesis, which may lead to the development of vugular, sometimes karstic, porosity. Fractured reservoirs pose formidable difficulties for estimating reserves.
Figure 1 shows the type of production response that is possible when applying a polymer gel treatment to a waterflood injection well to improve sweep efficiency. The figure shows the combined production-response of the four direct offsetting production wells to the gel-treated injection well. The gel treatment was applied for waterflood sweep-improvement purposes to the naturally fractured Embar carbonate formation surrounding Well O-7 of the highly mature SOB field in the Big Horn basin of Wyoming. The wide variations in water/oil ratio (WOR) and oil production rate are quite common in many of the well patterns of this highly fractured reservoir. Sydansk provides more details regarding the 20,000 bbl gel treatment.
Fractures are the most abundant visible structural features in the Earth's upper crust. They are apparent at most rock ridges, and it is likely that most reservoirs contain some natural fractures. Naturally fractured reservoirs are elusive systems to characterize and difficult to engineer and predict. It is important to establish some basic criteria for recognizing when fractures are an important element in reservoir performance and to recognize the nature and performance characteristics of a naturally fractured reservoir. Unlike induced fractures, natural fractures are caused by stress in the formation usually from tectonic forces such as folds and faults.
This article focuses on interpretation of well test data from wells completed in naturally fractured reservoirs. Because of the presence of two distinct types of porous media, the assumption of homogeneous behavior is no longer valid in naturally fractured reservoirs. This article discusses two naturally fractured reservoir models, the physics governing fluid flow in these reservoirs and semilog and type curve analysis techniques for well tests in these reservoirs. Naturally fractured reservoirs are characterized by the presence of two distinct types of porous media: matrix and fracture. Because of the different fluid storage and conductivity characteristics of the matrix and fractures, these reservoirs often are called dual-porosity reservoirs.
Zhang, Hui (PetroChina) | Wang, Lizhi (Schlumberger) | Wang, Zhimin (PetroChina) | Pan, Yuanwei (Schlumberger) | Wang, Haiying (PetroChina) | Qiu, Kaibin (Schlumberger) | Liu, Xinyu (PetroChina) | Yang, Pin (Schlumberger)
Located at the foothills of Tianshan mountains, western China, the Dibei tight gas reservoir has become one of the key exploration areas in last decade because of its large gas reserve potential. The previous exploration effort yielded mixed results with large variations of the production rates from these exploration wells and many rates are too low to be deemed as discovery wells. Petrophysical properties were excluded as controlling factors because these properties for most exploration wells are very similar. Under the large tectonic stress, heterogeneous natural fracture systems are induced and unevenly distributed in the reservoir, which might be the controlling factor for production. However, due to the limitation of the seismic data quality, quantitative fracture modeling with seismic is not possible for this field. A new method predicting the 3D occurrence of the natural fractures in the reservoir is needed.
In this study, geomechanics-based methods were used to predict the natural fracture systems in the reservoir. The methods started from classification of natural fracture systems based on borehole image and core data into either fold-related and/or fault-related fractures. Geomechanics-based structure restoration was conducted to compute the deformation and the perturbed stress field from the restoration of complex geological structures through time. A correlation was established between the fold-related perturbated stress field and the occurrence of fold-related fractures from wells to predict the 3D occurrence of this type of natural fractures. Meanwhile, the computation of the perturbed stress field around 3D discontinuities (i.e. faults) for one or more tectonic events was conducted by the Boundary Element Method (BEM) until a good match was achieved between the fault-related perturbed stresses and observed fault-related fractures from the wellbore. By using the output from the two methods, the discrete fracture network (DFN) model was constructed to explicitly represent the occurrence and geometry of the natural fracture system in the reservoir in a geological model. A geomechanical model was constructed based on an integrated workflow from 1D to 3D. The fracture stability was then calculated based on the 3D geomechnical model.
Detailed analysis was conducted among the DFN model, the geological model of the reservoir and productivity of the exploration wells, and very good correlation was revealed between the productivity of the exploration wells and the occurrence and geometry of the natural fractures and the structural position of the reservoir.
This study shows that geomechanics-based methods efficiently capture the occurrence of natural fracture systems and reveal the production-controlling factors of the tight gas reservoir. It demonstrates that geomechanics is a powerful tool to support successful exploration of the tight gas reservoir in tectonically stressed environments.
The objective of this study is to visualize the drained rock volume (DRV) and pressure depletion in hydraulically and naturally fractured reservoirs, using a high-resolution simulator to plot streamlines and time-of-flight contours that outline the DRV, based on computationally efficient complex potentials. A recently developed expression based on fast, grid-less Complex Analysis Methods (CAM) is applied to model the flow through discrete natural fractures with variable hydraulic conductivity. The impact of natural fractures on the local development of DRV contours and streamline patterns is analyzed. A sensitivity analysis of various permeability contrasts between natural fractures and the matrix is included. The results show that the DRV near hydraulic fractures is significantly affected by the presence of nearby natural fractures. The DRV location shifts according to the orientations, permeability and the density of the natural fractures. Reservoirs with numerous natural fractures result in highly distorted DRV shapes as compared to reservoirs without any discernable natural fractures. Additionally, the DRV shift due to natural fractures may contribute to enhanced well-interference by flow channeling via the natural fractures, as well as the creation of undrained rock volumes between the natural fractures. Complementary pressure depletion plots for each case show how the local pressure field changes, in a heterogeneous reservoir, due to the presence of natural fractures. The results from this study offer insights on how natural fractures affect the DRV and pressure contour plots. This study uses a fast grid-less and meshless high-resolution flow simulation tool based on CAM to simulate the flow in heterogeneous naturally fractured porous media. The CAM tool provides a practical/efficient simulation platform, complementary to grid-based reservoir simulators.
Numerical modeling of unconventional reservoirs, using commercial simulator, requires the construction of SRV that incorporates explicit geometries of primary and secondary fractures. Most of the time, during two phase flow, these models exhibit constant GOR. The method outlined in this paper eliminates the limitations of constant GOR being the only outcome and shows all other possible GOR responses that have a direct bearing on long term deliverability.
To overcome the drawback of numerical simulation, we make use of a dual porosity semi-analytical model. Using the concept of dimensional productivity index and its derivative, two-phase solutions are generated with the help of sandface pseudopressure. This model helps define all GOR variations of a ‘complete’ dual porosity system, wherein the fracture domain is assumed to contain part natural fracture and part induced hydraulic fracture. Apart from the impact of fluid variation, the other contributing factor in GOR variation is fracture density, which is addressed with the help of idealized fracture orientations such as the slab (planar 1D primary fracture only), the cylinder (non-planar 2D fracture with planar secondary fracture) and the sphere (non-planar 3D fracture with non-planar secondary fracture). These matrix shapes encompass all possible range of fracture densities (both natural and induced) that impact long-term performance.
The results of this method are shown for different fluids and for different idealized fracture orientations. It demonstrates that if the volume of fractures, in a given volume of SRV, is kept constant then the fluid type and fracture orientation are directly responsible for rate of pressure depletion that gives rise to these variations in GOR. It brings out the effect of different fracture orientations on the same fluid type and the effect of the same orientation on different fluid types. Additionally, with the help of published literature data, it is also demonstrated how GOR variation complements the conventional rate transient analysis for such unconventional reservoirs.
With the use of this method we can evaluate horizontal fractured well performance for different types of fluids and different fracture orientations in liquids-rich shale reservoirs. This GOR variation is important sensitivity parameter conveying the information about natural fractures present in the reservoir, information which is hard to get by from any other source, thus bringing out the significance of this method.
Tian, Changbing (Research Institute of Petroleum Exploration and Development, PetroChina) | Lei, Zhengdong (Research Institute of Petroleum Exploration and Development, PetroChina) | Jiang, Qingping (Exploration and Development Research Institute of Xinjiang Oilfield Company) | Chang, Tianquan (Exploration and Development Research Institute of Xinjiang Oilfield Company) | Chen, Dongliang (Exploration and Development Research Institute of Xinjiang Oilfield Company) | Lu, Zhiyuan (Exploration and Development Research Institute of Xinjiang Oilfield Company) | Li, Sheng (Exploration and Development Research Institute of Xinjiang Oilfield Company)
Large platforms, long horizontal sections, small well spacings and dense cutting have become economical and effective development means for tight oil reservoirs. Well spacing and fracture design are critical parameters impacting production and Internal rate of return (IRR) of tight oil reservoirs. In order to maximize the total stimulated reservoir area and fracture-controlled reserves, the well spacing and fracture spacing should be small enough. However, in order to minimize the chance of fracture hits caused by offset wells and the overlapping drainage area of a nearby well to avoid Asset spillover, the spacing well should large enough.
Based on minifrac data and microseismic fracture mapping results, a natural/hydraulic fracture network was generated and input into an unstructured-grid-based discrete fracture reservoir simulation model. Its accuracy was calibrated with the well production history. For each group of fracture design and well spacing, well interference was determined by estimating ultimate recovery (EUR) difference between a single well and a middle well among multiple wells. Based on actual information of tight oil developments, the pressure interference were examined by field trail data and well spacing simulations. The real scenarios were selected to study effects of well spacing on EUR and ultimate IRR. Effects of reservoir permeability and fracture half-length on optimal well spacing were also analyzed.
It was found that the decrease in Long-term EURs for different well spacings is a good indicator for well spacing optimization. Based on the reservoir simulation and economic analysis, the maximum IRR of the tight oil reservoir with permeability of 0.23mD can achieved when the well spacing is 260m. Meanwhile, the detailed results were also illustrated to show the effects of fracture half-length, reservoir permeability as well as oil price variation on IRR.
The paper demonstrates an effective method and a workflow to optimize well spacing and fracture treatments design through integrating advanced multi-stage fracture modeling with discrete fracture reservoir simulation in the area of unconventional resource developments. Such optimization studies contribute to minimize operation cost and improve the economy of resource development.
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.