Developing a Tool for 3D Reservoir Simulation of Hydraulically Fractured Wells

2007 ◽  
Vol 10 (01) ◽  
pp. 50-59 ◽  
Author(s):  
Josef R. Shaoul ◽  
Aron Behr ◽  
George Mtchedlishvili
Keyword(s):  
Simulation Model ◽  
Reservoir Simulation ◽  
Hydraulic Fracture ◽  
Fracture Plane ◽  
Tight Gas ◽  
Fracture Conductivity ◽  
Fracture Width ◽  
Fracture Simulation ◽  
Reservoir Simulator ◽  
Actual Fracture

Summary This paper describes the development and capabilities of a novel and unique tool that interfaces a hydraulic fracture model and a reservoir simulator. This new tool is another step in improving both the efficiency and consistency of connecting hydraulic fracture engineering and reservoir engineering. The typical way to model hydraulically fractured wells in 3D reservoir simulators is to approximate the fracture behavior with a modified skin or productivity index (PI). Neither method captures all the important physics of flow into and through the fracture. This becomes even more critical in cases of multiphase flow and multilayered reservoirs. Modeling the cleanup phase following hydraulic fracture treatments can be very important in tight gas reservoirs, and this also requires a more detailed simulation of the fracture. Realistic modeling of horizontal wells with multiple hydraulic fractures is another capability that is needed in the industry. This capability requires more than an approximate description of the fracture(s) in the reservoir-simulation model. To achieve all the capabilities mentioned above, a new tool was developed within a commercial lumped 3D fracture-simulation model. This new tool enables significantly more accurate prediction of post-fracture performance with a commercial reservoir simulator. The automatically generated reservoir simulator input files represent the geometry and hydraulic properties of the reservoir, the fracture, the damaged zone around the fracture, and the initial pressure and filtrate fluid distribution in the reservoir. Consistency with the fracture-simulation inputs and outputs is assured because the software automatically transfers the information. High-permeability gridblocks that capture the 2D variation of the fracture conductivity within the reservoir simulator input files represent the fracture. If the fracture width used in the reservoir model is larger than the actual fracture width, the permeability and porosity of the fracture blocks are reduced to maintain the transmissibility and porous volume of the actual fracture. Both proppant and acid fracturing are handled with this approach. To capture the changes in fracture conductivity over time as the bottomhole flowing pressure (BHFP) changes, the pressure-dependent behavior of the fracture is passed to the reservoir simulator. Local grid refinement (LGR) is used in the region of the wellbore and the fracture tip, as well as in the blocks adjacent to the fracture plane. Using small gridblocks adjacent to the fracture plane is needed for an adequate representation of the filtrate-invaded zone using the leakoff depth distribution provided by the fracture simulator. The reservoir simulator input can be created for multiphase fluid systems with multiple layers and different permeabilities. In addition, different capillary pressure and relative permeability saturation functions for each layer are allowed. Introduction Historically, there have been three basic approaches commonly used for predicting the production from hydraulically fractured wells. First, analytic solutions were most commonly used, based on an infinite-conductivity or, later, a finite-conductivity fracture with a given half-length. This approach also was extended to cover horizontal multiple fractured wells (Basquet et al. 1999). With the development of reservoir simulators, two other approaches were developed. For complicated multiwell, multilayer, multiphase simulations (i.e., full-field models), the fracture stimulation was usually approximated as a negative skin. This is the same as increasing the effective wellbore radius in the simulation model. An alternate approach, developed initially for tight gas applications, was to develop a special-purpose numeric reservoir simulator that could explicitly model the flow in the fracture and take into account the special properties of the proppant, such as the stress-dependent permeability or the possibility of non-Darcy flow. Such models typically were limited to a single-layer, single-phase (oil or gas) situation.

Advances in Tightly Coupled Reservoir/ Wellbore/Surface-Network Simulation

2001 ◽  
Vol 4 (02) ◽  
pp. 114-120 ◽  
Author(s):  
V.J. Zapata ◽  
W.M. Brummett ◽  
M.E. Osborne ◽  
D.J. Van Nispen
Keyword(s):  
Simulation Model ◽  
Reservoir Simulation ◽  
Network Simulation ◽  
Simulation System ◽  
Model Description ◽  
Fully Implicit ◽  
Black Oil ◽  
Tightly Coupled ◽  
Surface Network ◽  
Reservoir Simulator

Summary One of the most perplexing and difficult challenges in the industry is deciding how to develop a new oil or gas field. It is necessary to estimate recoverable reserves, design the most efficient exploitation strategy, decide where and when to drill wells and install surface facilities, and predict the rate of production. This requires a clear understanding of energy distribution and fluid movements throughout the entire system, under any given operational scenario or market-demand situation. Even after a reservoir-development plan is selected, there are many possible facility designs, each with different investment and operating costs. An important, but not always considered, fact is that each facility scheme could result in different future production rates owing to various types, sizes, and configurations of fluid-flow facilities. Selecting the best design for the asset requires the most accurate production forecasts possible over the forecast life cycle. No other single technology has the ability to provide this insight, as well as tightly coupled reservoir and facility simulation, because it combines all pertinent geological and engineering data into a single, comprehensive, dynamic model of the entire oilfield flow system. An integrated oilfield simulation system accounts for all dynamic flow effects and provides a test environment for quickly and accurately comparing alternative designs. This paper provides a brief background of this technology and gives a review of a major development project where it is currently being applied. Finally, we describe some recent significant advances in the technology that make it more stable, accurate, and rigorous. Introduction Finite-difference reservoir simulation is widely used to predict production performance of oil and gas fields. This is usually done in a "stand-alone" mode, where individual well performance is commonly calculated from pregenerated multiphase wellbore flow tables that cover various ranges of wellhead and bottomhole pressures, gas/oil ratios (GOR's) and water/oil ratios (WOR's). The reservoir simulator determines the predicted production rate from these tables, normally assuming a fixed wellhead pressure and using a flowing bottomhole pressure calculated by the reservoir simulator. With this scheme it is not possible to consider the changing flow-resistance effects of the piping system as various fluids merge or split in the surface network. Neglecting this interaction of the surface network can, in many cases, introduce substantial errors into predicted performance. Basing multimillion- (in some cases, billion-) dollar exploitation designs on performance predictions that are suboptimal can be very detrimental to the asset's long-range profitability. To help eliminate this problem, considerable attention is being given to coupling reservoir simulators and multiphase facility network simulators to improve the accuracy of forecasting. Landscape Surface-network simulation technology was first introduced in 1976.1 Although successfully applied in selected cases, the concept was not widely adopted because of the excessive additional computing demands on computers of that era. In those earlier applications, the time consumed by the facility calculations could actually exceed the reservoir calculations.2,3 As computer performance has increased by orders of magnitude, this has become less of an issue. Reservoir model sizes have increased dramatically with much finer grids that take advantage of the increased computer power, but there was no need for a corresponding increase in the size of the facility models. Today, with tightly coupled reservoir/wellbore/surface models, the facility calculations are a fairly small part of the overall computing time and there is considerable effort in the industry to build these types of systems.4,5 Chevron's current tightly coupled oilfield simulation system is CHEARS®***/PIPESOFT-2™****. CHEARS® is a fully implicit 3D reservoir simulator with black-oil, compositional, thermal, miscible, and polymer formulations. It has fully implicit dual porosity, dual permeability options, and unlimited multiple-level local grid refinement. PIPESOFT-2™ is a comprehensive multiphase wellbore/surface-network simulator. It has black-oil, compositional, CO2, steam, and non-Newtonian fluid capabilities. It can solve any type of complex nested looping, both surface and subsurface. The coupling is done at the wellbore completion interval, which is the natural domain boundary between the flow systems. We refer to our implementation as "tightly coupled" because information is dynamically exchanged directly between the simulators without any intermediate intervention. A simple representation of the interaction between the simulators is shown in Fig. 1. Gorgon Field Example The following is an example of how this technology is currently being used. The Gorgon field is a Triassic gas accumulation estimated to contain over 20 Tscf of gas, located 130 km offshore northwest Australia in 300 m of water (Fig. 2). It is currently undergoing development studies for an LNG project. Field and Model Description. The field is 45 km long and 9 km wide, and it comprises more than 2000 m of Triassic fluvial Mungaroo formation in angular discordance with a Jurassic-age unconformity. It has been subdivided into 11 vertical intervals (or zones) on the basis of regional sequence boundaries and depositional systems. These 11 zones were first modeled individually with an object-based modeling technique before being stacked into a 715-layer full-field geologic model. This model was subsequently scaled up to a 46-layer reservoir simulation model, reducing the size of the model from 4.5 million cells to 290,000 cells. While the scaleup process preserved the original 11 zone boundaries, the majority of the layers were located in regions identified as key flow units. In addition to vertical subdivision, seismic and appraisal well data suggest structural compartmentalization, resulting in six major fault blocks. After deactivating appropriate cells, the final simulation model contained 50,000 active cells and was initialized with 35 independent pressure regions. Each of these regions corresponds to a single zone in a single fault block.

A New Method of Optimization Design of Hydraulic Fracture Parameters in Low Porosity and Fractured Gas Reservoir

2013 ◽  
Vol 380-384 ◽  
pp. 1656-1659
Author(s):  
Xiu Ling Han ◽  
Fu Jian Zhou ◽  
Chun Ming Xiong ◽  
Xiong Fei Liu ◽  
Xian You Yang
Keyword(s):  
Simulation Model ◽  
Hydraulic Fracture ◽  
Optimization Design ◽  
Outer Part ◽  
Gas Production ◽  
Natural Fracture ◽  
Fracture Permeability ◽  
Gas Reservoir ◽  
Fracture Conductivity ◽  
High Production Rate

A new composite reservoir simulation model of lower computation cost was used to optimize hydraulic fracture length and fracture conductivity during performing a hydraulic fracturing. The simulation model is divided into inner part and outer part. The inner part is dual-porosity and dual-permeability system, and the other is single porosity system. The research shows that the natural fracture permeability and density are the most influential parameters; a relative long fracture with high hydraulic fracture conductivity is required for a high production rate due to non-Darcy flow effects. A shorter primary fracture is better in a gas reservoir of high natural density. The composite model represents the flow characteristic more accurately and provides the optimal design of fracturing treatments to obtain an economic gas production.

Three-Dimensional Hydraulic Fracture Simulation Using Fixed Grid Finite Element Algorithms

1994 ◽  
Vol 116 (1) ◽  
pp. 2-9 ◽  
Author(s):  
T. S. Lee ◽  
S. H. Advani ◽  
C. K. Pak
Keyword(s):  
Finite Element ◽  
Hydraulic Fracture ◽  
Fluid Pressure ◽  
Three Dimensional ◽  
Fracture Width ◽  
Coupled Equations ◽  
Fixed Grid ◽  
Fracture Simulation ◽  
Fracture Fluid ◽  
Novel Algorithms

A three-dimensional hydraulic fracture simulator (HYFFIX) is reformulated using finite element methodology and a newly adapted fixed grid. The numerical procedures for the coupled equations governing the fracture width, fluid pressure, and evolution of equilibrium planar crack in layered media are summarized. Fixed grid mesh control algorithms for the efficient tracking of the moving crack/fracture fluid front are detailed. The introduction of these novel algorithms in the simulator makes it numerically efficient and stable, in comparison to previously reported models which utilize migrating mesh techniques. Due to the enhanced numerical efficiency and compactness of the refined code, the model can also be readily implemented on a workstation or microcomputer.

Effect of Multiple Fracture Initiation on the Accuracy of Hydraulic Fracturing Simulation

2020 ◽  
Author(s):  
Ziad Bennour ◽  
Walid Mohamed Mahmud ◽  
Mansur Ermila
Keyword(s):  
Hydraulic Fracturing ◽  
Simulation Model ◽  
Fracture Model ◽  
Single Fracture ◽  
Multiple Fractures ◽  
Actual Treatment ◽  
Fracture Simulation ◽  
Fracturing Process ◽  
Simulation Results ◽  
Actual Fracture

Abstract Hydraulic fracturing is a stimulation technique in which the formation is fractured using high pressure exerted by a fluid. The induced fracture increases the permeability of the formation by providing conductive channels to the formation which results in improved fluids productivity. Hydraulic fracturing is a common practice in oil and gas, particularly in the development of unconventional low porosity and low permeability reservoirs. However, as the hydraulic fracturing technique is costly, considerable preparations efforts must be made before executing the fracturing operation including simulating the intended fracture model. A simulation model of a hydraulic fracturing assists in forecasting and controlling the intended fractures that are to be induced. Although the simulation model can be helpful, it may not exactly mimic or predict the actual initiated fractures due to the complex nature of the actual fracturing process. Thus, the simulated model and the actual fracture might differ in many ways which results in an uncertainty in the simulated fracture model. Therefore, in order to reduce uncertainty, initial data input and assumptions made before and during the fracturing simulation need to be precise in order to obtain accurate simulation results. The growth of a single fracture is often assumed during the simulation of hydraulic fracturing which maybe incorrect as multiple fractures may initiate at the start or middle of the actual fracturing treatment and can have significant effect on the simulated fracturing results. This paper proposes a method to minimize the difference between fracturing simulation and actual fracture treatment results by utilizing sensitivity tests to the main fracturing parameters. Thus, the initial actual fracturing results were used to detect the occurrence of multiple fractures where the latter was considered to enhance the upcoming simulation accuracy of the proposed treatments. The analysis of high net pressure data during the actual treatment indicates the possible presence of multiple fractures where history matching between actual treatment and simulation results data can give an estimate on when and how many multiple fractures were initiated during the fracturing treatment. As a result, the data analysis showed that multiple fractures initiation had a significant effect on the fracture simulation results and the assumption of a single fracture during hydraulic fracturing should be discarded unless it is confirmed to be the case. Geological settings of the reservoir and the presence of natural fractures were also found to cause multiple fractures initiation during the treatments, and therefore, the reservoir data and description need to be determined properly before attempting the simulation of a fracturing treatment.

A Semianalytical Model for Production Simulation From Nonplanar Hydraulic-Fracture Geometry in Tight Oil Reservoirs

SPE Journal ◽  
2016 ◽  
Vol 21 (03) ◽  
pp. 1028-1040 ◽  
Author(s):  
Wei Yu ◽  
Kan Wu ◽  
Kamy Sepehrnoori
Keyword(s):  
Hydraulic Fracture ◽  
Transient Flow ◽  
Flow Behavior ◽  
Tight Oil ◽  
Well Performance ◽  
Fracture Permeability ◽  
Fracture Geometry ◽  
Fracture Conductivity ◽  
Fracture Width ◽  
Stress Dependent

Summary Two key technologies such as horizontal drilling and hydraulic fracturing have led to the economic production of unconventional resources such as shale gas and tight oil. In reality, a nonplanar hydraulic-fracture geometry with varying fracture width and fracture permeability is created during the hydraulic-fracturing process. However, it is challenging to simulate well performance from the nonplanar fracture geometry. For the sake of simplicity, the nonplanar fracture geometry is often represented by ideal planar fracture geometry with constant fracture width, which one can easily handle analytically, semianalytically, and numerically. However, such ideal fracture geometry is inadequate to capture the physics of the transient flow behavior of the nonplanar fracture geometry. Although significant efforts were made in recent years to numerically model well performance from the complex fracture geometry, these approaches are still challenging to model the nonplanar fracture geometry with varying width because of a large considerable fracture-gridding issues and an expensive computation cost. In addition, the effect of nonplanar fracture geometry on well productivity and transient flow behavior was not reported in the literature. Hence, a model to handle the nonplanar fracture geometry by considering varying fracture width and fracture permeability is still lacking in the petroleum industry. Zhou et al. (2014) proposed a semianalytical model to handle the complex fracture geometry with constant fracture width. However, the semianalytical model did not consider the effects of stress-dependent fracture conductivity and the nonplanar fracture geometry as well as planar fracture geometry with varying fracture width along the fracture. In this work, we extended the semianalytical model to simulate production from the nonplanar fracture geometry as well as planar fracture geometry with varying width. In addition, the effect of stress-dependent fracture conductivity was implemented in the model. We verified the semianalytical model against a numerical reservoir simulator for single planar fracture with constant width. We performed two case studies. The first case contains a comparison of two planar fractures, one with constant fracture width and another with varying fracture width. In the second study, we compared two fractures with different fracture geometries such as planar fracture geometry and nonplanar fracture geometry, which were generated from the fracture-propagation model. In addition, transient flow regimes were investigated on the basis of a log-log graph of the dimensionless pressure drop and pressure-drop derivative vs. the dimensionless time. This work can provide critical insights into understanding the well performance from tight oil reservoirs with the nonplanar hydraulic-fracture geometry.

scholarly journals Laboratory Testing of Fracture Conductivity Damage by Foam-Based Fracturing Fluids in Low Permeability Tight Gas Formations

Energies ◽  
2021 ◽  
Vol 14 (6) ◽  
pp. 1783
Author(s):  
Klaudia Wilk-Zajdel ◽  
Piotr Kasza ◽  
Mateusz Masłowski
Keyword(s):  
Hydraulic Fracturing ◽  
Guar Gum ◽  
Polymer Concentration ◽  
Laboratory Research ◽  
Damage Effect ◽  
Tight Gas ◽  
Fracturing Fluid ◽  
Fracture Conductivity ◽  
Fracturing Fluids ◽  
Sandstone Rock

In the case of fracturing of the reservoirs using fracturing fluids, the size of damage to the proppant conductivity caused by treatment fluids is significant, which greatly influence the effective execution of hydraulic fracturing operations. The fracturing fluid should be characterized by the minimum damage to the conductivity of a fracture filled with proppant. A laboratory research procedure has been developed to study the damage effect caused by foamed and non-foamed fracturing fluids in the fractures filled with proppant material. The paper discusses the results for high quality foamed guar-based linear gels, which is an innovative aspect of the work compared to the non-foamed frac described in most of the studies and simulations. The tests were performed for the fracturing fluid based on a linear polymer (HPG—hydroxypropyl guar, in liquid and powder form). The rheology of nitrogen foamed-based fracturing fluids (FF) with a quality of 70% was investigated. The quartz sand and ceramic light proppant LCP proppant was placed between two Ohio sandstone rock slabs and subjected to a given compressive stress of 4000–6000 psi, at a temperature of 60 °C for 5 h. A significant reduction in damage to the quartz proppant was observed for the foamed fluid compared to that damaged by the 7.5 L/m3 natural polymer-based non-foamed linear fluid. The damage was 72.3% for the non-foamed fluid and 31.5% for the 70% foamed fluid, which are superior to the guar gum non-foamed fracturing fluid system. For tests based on a polymer concentration of 4.88 g/L, the damage to the fracture conductivity by the non-foamed fluid was 64.8%, and 26.3% for the foamed fluid. These results lead to the conclusion that foamed fluids could damage the fracture filled with proppant much less during hydraulic fracturing treatment. At the same time, when using foamed fluids, the viscosity coefficient increases a few times compared to the use of non-foamed fluids, which is necessary for proppant carrying capacities and properly conducted stimulation treatment. The research results can be beneficial for optimizing the type and performance of fracturing fluid for hydraulic fracturing in tight gas formations.

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