Effective Fracture Permeability Research Articles

Effect of Cross-Well Natural Fractures and Fracture Network on Production History Match and Well Location Optimization in an Ultra-Deep Gas Reservoir

Understanding subsurface natural fracture systems is crucial to characterize well production dynamics and long-term productivity potential. In addition, the placement of future wells can benefit from in-depth fracture network connectivity investigations, vastly improving new wells’ profitability and life cycles if they are placed in dense, well-connected natural fracture zones. In this study, a novel natural fracture calibration workflow is proposed. This workflow starts with the extraction of sector geology and a natural fracture model from the pre-built full-field model. Then, a cross wellbore discrete fracture network (CW-DFN) is created using a novel CW-DFN generation tool, based on image log data. An innovative fracture network identification tool is developed to detect the interconnected regional fracture network (IcFN) with CW-DFN. The non-intrusive embedded discrete fracture model (EDFM) is utilized to numerically incorporate the complex IcFN and CW-DFN in a reservoir simulation, and it is history-matched by tuning their conductivities. This workflow is applied to a single vertical well within a natural fracture carbonate reservoir in Northwest China. The study results show that the number of CW-DFNs is 11, and the number of IcFNs is 72. The non-intersected natural fractures only account for 5.5% of the production, and thus can be removed to improve simulation efficiency. The history-matching absolute average relative deviation (AARD) is 15.16%. The calibrated effective fracture permeability is 280 millidarcy, with an aperture of 0.001 m, equating to a conductivity of 0.28 millidarcy-meter. The 30-year gas production forecast is estimated to be 1.66 billion cubic meters based on a history-matched model. Finally, if the well is drilled to the east of the sector, 30-year production declines to 1.33 billion cubic meters (a reduction of 20%). However, if the well is drilled to the west of the sector, 30-year production increases to 2 billion cubic meters (an improvement of 20.5%).

A model of fluid expulsion from compacting tight sedimentary rocks based on the Toggle-Switch algorithm

Expulsion of fluids from tight rocks is an important process in sedimentary basins for phenomena such as distribution of overpressure and primary migration of hydrocarbons. This paper shows that the “Toggle Switch” (TS) algorithm of Miller and Nur is well-suited to model expulsion of brine by hydraulic fracturing from tight rocks undergoing compaction. Local random overpressure is generated in the TS algorithm using a void ratio function with random compaction length. The TS algorithm equilibrates critical fluid pressure by local exchange of excess fluid. We show that the algorithm gives net migration of fluid upwards, because the least compressive stress is decreasing towards the surface. The random void ratio makes the total expulsion rate from the layer intermittent. In the limit of zero cell size the expulsion rate approaches a mean value. When the rock has a random strength, it is shown that critically pressured clusters remain after the TS algorithm has been applied. The implementation of the algorithm is mass conservative, which ensures that the expelled mass is exactly the mass of pore fluid lost by compaction. Expressions are derived for the rate of fluid expulsion and for an effective fracture permeability.

Application of response surface methodology for the optimization of viscosity of foam fracturing fluids for the unconventional reservoir

Maintaining the optimum viscosity of foam required to create the effective fracture permeability and placing the proppant inside the fracture are difficult because of its poor thermal stability. The objective of this study is to optimize the viscosity of foam by using the Response Surface Methodology (RSM) technique. The Box-Behnken design matrix was selected based on the feasibility, efficiency and simplicity of response surface methodology, which contains 17 number of experiments. Statistical analysis of the model was performed by Analysis of variance (ANOVA), which helps to confirm the robustness of the tested model. The diagnosis of the model was reported with internally studentized residual plots, which proves that the data is authentic with less error value, and the model is significant. The desirability function approach is utilized to analyze the optimized viscosity, followed with a confirmation test, which assists in validating the predicted optimal viscosity results. The input parameters, such as solid particles concentration and foam quality, were set in a range and temperature was set to be at maximizing condition, so that corresponding response, i.e., viscosity was optimized. The optimized viscosity of the foam fracturing fluids systems is in between 36.74 and 74.61 cP at 500 s−1 shear rate. The abovementioned methods and its analysis for the estimation of the optimal viscosity at a high shear rate are very significant and consequently acceptable for the design and development of foam fracturing fluid at the field conditions of unconventional reservoirs. This method is expected to apply for effective designing of foam for fracking of unconventional reservoirs without undergoing rigorous field trials for selecting the correct foam composition.

The Key Factors That Determine the Economically Viable, Horizontal Hydrofractured Gas Wells in Mudrocks

We assemble a multiscale physical model of gas production in a mudrock (shale). We then tested our model on 45 horizontal gas wells in the Barnett with 12–15 years on production. When properly used, our model may enable shale companies to gain operational insights into how to complete a particular well in a particular shale. Macrofractures, microfractures, and nanopores form a multiscale system that controls gas flow in mudrocks. Near a horizontal well, hydraulic fracturing creates fractures at many scales and increases permeability of the source rock. We model the physical properties of the fracture network embedded in the Stimulated Reservoir Volume (SRV) with a fractal of dimension D < 2 . This fracture network interacts with the poorly connected nanopores in the organic matrix that are the source of almost all produced gas. In the practically impermeable mudrock, the known volumes of fracturing water and proppant must create an equal volume of fractures at all scales. Therefore, the surface area and the number of macrofractures created after hydrofracturing are constrained by the volume of injected water and proppant. The coupling between the fracture network and the organic matrix controls gas production from a horizontal well. The fracture permeability, k f , and the microscale source term, s, affect this coupling, thus controlling the reservoir pressure decline and mass transfer from the nanopore network to the fractures. Particular values of k f and s are determined by numerically fitting well production data with an optimization algorithm. The relationship between k f and s is somewhat hyperbolic and defines the type of fracture system created after hydrofracturing. The extremes of this relationship create two end-members of the fracture systems. A small value of the ratio k f / s causes faster production decline because of the high microscale source term, s. The effective fracture permeability is lower, but gas flow through the matrix to fractures is efficient, thus nullifying the negative effect of the smaller k f . For the high values of k f / s , production decline is slower. In summary, the fracture network permeability at the macroscale and the microscale source term control production rate of shale wells. The best quality wells have good, but not too good, macroscale connectivity.

Evaluation of Cyclic Gas Injection in Enhanced Recovery from Unconventional Light Oil Reservoirs: Effect of Gas Type and Fracture Spacing

ultra-low permeability; hydraulic fracturing; cyclical gas injection; fracking stages

Effect of Dilute Acid on Hydraulic Fracturing of Carbonate-Rich Shales: Experimental Study

Summary Matrix and fracture permeability of carbonate-rich tight cores from Horn River Basin, Muskwa, Otter Park, and Evie Shale formations, were measured before and after exposing the core samples to spontaneous imbibition using dilute acid [1- or 3-wt% hydrochloric acid (HCl) diluted in 10-wt% potassium chloride (KCl) brine]. Permeability and porosity were measured at net stress between 1,000 and 5,000 psia. Brine and dilute-acid imbibition effect on proppant embedment, rock softening/weakening, and fracture roughness were assessed. The following are some of the experiment observations: (a) Formation damage caused by water blockage of water-wet shales can be improved by adding dilute HCl or by using hydrocarbon-based fracturing fluids; (b) matrix permeability of clay-rich or calcite-poor shale samples is usually impaired/damaged by dilute-acid imbibition; (c) matrix permeability and porosity of calcite-rich shales usually improved with dilute-acid imbibition; (d) effective fracture permeability of unpropped calcite-rich shales is reduced by dilute-acid imbibition; the latter is because of “rock softening” and “etching/smoothing” of fracture roughness on the “fracture faces.” Nevertheless, dilute-acid imbibition is less damaging than brine (slickwater) imbibition; and (e) proppant embedment was observed during both brine (slickwater) and dilute-acid imbibition. Hence, experimental results of this study imply that dilute-acid injection/imbibition/fracturing in carbonate-rich shale reservoirs can lead to hydrocarbon-production improvement caused mainly by the matrix/permeability improvement.

Numerical Study on Behavior of Groundwater Flow in Single Rough Fractures Under Mechanical Effect.

This paper numerically investigates the characteristics of groundwater flow in spatially correlated variable aperture fractures under the mechanical effect. Spatially correlated aperture distributions are generated using the geostatistical method (i.e., turning bands algorithm in this study). To represent a nonlinear relationship between the effective normal stress and the fracture aperture, a simple mechanical formula is combined with a local flow model. Numerical results indicate that the groundwater flow is significantly affected by the geometry of aperture distribution, varying with the applied effective normal stress as well as the spatial correlation length of aperture distribution. Moreover, using the flow results simulated in this study, two empirical formulae are proposed: (1) the first one (modified Louis formula) is to represent the relationship between the effective normal stress and the effective permeability of fracture and (2) the second one is to represent the relationship between relative roughness and effective permeability.

Static and Dynamic Assessment of DFN Permeability Upscaling (SPE 154369)

Nearly half of the remaining petroleum reserves are contained in naturally fractured reservoirs (NFR). An accurate estimate of the effective fracture permeability tensor is a key to the successful prediction of oil recovery from NFR. Standard workflows nowadays employ discrete fracture network (DFN) modelling and analytical or flow-based methods to upscale fracture permeabilities. However, DFN modelling imposes some important challenges, which can cause great uncertainty in the effective permeability tensor and subsequent recovery prediction: Analytical upscaling methods, which are commonly used due to computational efficiency, are inaccurate for poorly connected fracture networks. Flow-based upscaling methods depend on boundary conditions and are computationally expensive. Defining the optimum grid size for either method is also very difficult. In addition, DFN upscaling is often driven by practical issues such as time constrains and computational limitations, leaving little room to investigate the effects of upscaling methods and grid size. In this paper we compare the performance of three different DFN simulators used in standard industry workflows for computing effective permeability tensors with flow-based and analytical methods. We use a dataset from a fractured formation of an on-shore reservoir in our assessment. Not surprisingly, there is up to three orders of magnitude variation in the effective permeability based on the chosen upscaling method and perceived optimum grid cell size. Quality control with streamline calculations provides no robust assessment of the best upscaling method. We hence introduce a new simulation technique, Discrete Fracture and Matrix (DFM) modelling, which accounts accurately for flow in the fractures and rock matrix as a robust. It is an efficient alternative for computing effective permeability tensors or assessing the accuracy of classical DFN upscaling approaches, which all help reducing uncertainty in recovery prediction.

Permeability correction factor for fractures with permeable walls

Enhanced Geothermal Systems (EGS) are based on the premise that heat can be extracted from hot dry rocks located at significant depths by circulating fluid through fracture networks in the system. Heated fluid is recovered through production wells and the energy is extracted in a heat exchange chamber. There is much published research on flow through fractures, and many models have been developed to describe an effective permeability of a fracture or a fracture network. In these cases however, the walls of the fracture were modelled as being impermeable. In this paper, we have extended our previous work on fractures with permeable walls, and we introduce a correction factor to the equation that governs fracture permeability. The solution shows that the effective fracture permeability for fractures with permeable walls depends not only on the height of the channel, but also on the wall permeability and the wall Reynolds number of the fluid. We show that our solution reduces to the established solution when the fracture walls become impermeable. We also extend the discussion to cover the effective permeability of a system of fractures with permeable walls.

Stabilized Well Productivity in Double-Porosity Reservoirs

Summary In this work, we present a simple1 analytical formula for the stabilized productivity index (PI) of an arbitrary well in an arbitrary closed, naturally fractured reservoir that can be modeled as a double-porosity reservoir. The formula relates the PI to the PI of a well in a single-porosity reservoir with permeability equal to the effective fracture permeability of the double-porosity reservoir. We have elaborated this formula for a vertical and a horizontal well in a rectangular reservoir made up of orthogonal matrix blocks. It appears that the double-porosity characteristics, along with reservoir flow capacity and reservoir volume, combine into a single factor, which plays the same role as the familiar skin factor. For small values of this double-porosity skin, well productivity is dominated by fracture permeability; for large values, the controlling parameter is matrix permeability. Inflow-performance relationship (IPR) curves of wells in double-porosity gas reservoirs can be created readily with the help of the new PI formula. An example is included showing the production profiles of a vertical and a horizontal well in a double-porosity gas reservoir with cubes and square pillars as matrix blocks. The results of this work are particularly relevant for the reservoir engineering of naturally fractured gas reservoirs.

Development of an Integrated Reservoir Model for a Naturally Fractured Volcanic Reservoir in China

Summary This paper presents the development of an integrated, multidiscipline reservoir model for dynamic flow simulation and performance prediction of a geologically complex, naturally fractured volcanic reservoir in the Shang 741 Block of the Shengli field in China. A static geological model integrates lithological information, petrophysics, fracture analysis, and stochastic fracture network modeling with Formation MicroImage (FMI) log data and advanced 3D seismic interpretations. Effective fracture permeability, fracture-matrix interaction, reservoir compartmentalization, and flow transmissibility of conductive faults are obtained by matching various dynamic data. As a result of synergy and multiple iterations among various disciplines, a history-matched dynamic reservoirsimulation model capable of future performance prediction for optimum asset management is constructed.

A New Method To Calculate Effective Permeability of Gridblocks Used in the Simulation of Naturally Fractured Reservoirs

Summary Current simulation technology for naturally fractured reservoirs is based on either the continuum or the discrete-fracture approach. The more commonly used continuum model can simulate complex recovery mechanisms. However, it uses a very simplified representation of the fracture system for calculating effective fracture permeability. The discrete-fracture flow method can handle complex fracture geometry. However, its use has been typically limited to basic flow calculations through a connected fracture system embedded in zero-matrix-permeability rock. We have developed a new technique for estimating the effective permeability of gridblocks used in conventional simulators. The idea behind this technique is to integrate the realism of fracture systems, as captured by discrete-fracture models, with the complexity of the flow calculations offered by continuum models. The end product of developing this technique is an efficient numerical code based on the boundary-element method. This code permits the fracture system to be complex and poorly connected, and it also includes the contribution from flow through the matrix rock. For fluid flow in the matrix rock, the fractures are treated as planar-source distributions. Periodic boundary conditions, for the flow properties, are used for the calculation of the effective permeability of individual gridblocks. We first use a simple fracture system to demonstrate the validity of our method and to evaluate the sensitivity of the results to matrix and fracture properties. We then use fracture statistics data from the Mesaverde sandstone, effective permeability values from our code, and a continuum simulator to calculate tracer-flow patterns for a more realistic system.

Saturated permeability measurements on pumice and welded-tuffaceous materials

Fluid flows in consolidated porous media of volcanic origin are being investigated to support such diverse efforts as the modeling of thermal/outgassing phenomena at Mount St. Helens and the hydrological modeling of tuffaceous rocks in support of the Department of Energy’s (DOE) Nevada Nuclear Waste Storage Investigations Project An experimental apparatus was designed and built to allow water-saturated permeabilities as low as 10−18 m2 to be measured on cores of diameter 5 cm and length 10 cm under steady-state flow conditions. This same apparatus can also be utilized in a transient (pressure-decay) mode in order to measure permeabilities several orders of magnitude lower than the steady-state limit. Tests were conducted on samples of pumice, fractured welded tuff, and welded tuff, representing a permeability range of seven orders of magnitude Pumice was found to have a permeability of ∼3×10−12 m2, sufficiently high to allow the complete Darcy-to-Ergun regime to be investigated Welded (unfractured) tuff was tested in the transient mode, yielding a permeability of ∼5×10−19 m2. Two, long-time-scale, steady-flow experiments were conducted on a core of welded tuff containing a single, through-going fracture. For the first experiment, the core was an integral cylinder containing a naturally occurring fracture. For the second experiment, the core was separated into two pieces along the existing fracture plane, then rejoined. Effects of essentially constant, as well as rapidly varied, circumferential stress were studied in both tests. Results showed core permeability to decay to 2×10−18 m2 in both cases, independent of the initial fracture state (closed versus open). With a naturally occurring fracture, core permeability decreased by a factor of 2 over a 200-h test period. With an initially open fracture, core permeability decreased by a factor of 4 under the influence of a comparable 200-h load-time history, after 700 h of testing, core permeability was reduced by an order of magnitude from its initial level. Final effective hydraulic fracture aperture was calculated to be 10−6 m, corresponding to a calculated effective fracture permeability of 10−13 m2 Fracture flow was thus estimated to account for 80% of the total flow rate through this core under final test conditions.

Fracture Permeability and High Initial Water Cut in a Carbonate Gas Reservoir: ABSTRACT

Waveland field in Hancock County, Mississippi, produces gas and condensate from the Lower Cretaceous Mooringsport Formation at approximately 13,400 ft. Total gas reserves have been estimated at 256 bcf. The reservoir is a fractured lime packstone, containing milliolid and orbitolinid foraminifers, mollusk fragments, and echinoderms. Core plug permeability is low, commonly below 1 md, yet productive wells flow at rates of as much as 8,000 MCFGD. Thus, fracture permeability is an important reservoir property. Short-term flow tests can be misleading, as productive wells may initially produce an uneconomically high water cut for several days. The trap is a south-southwest-plunging anticline with no apparent structural closure to the north. A map of averaged, thickness-weighted porosity values for productive stratigraphic intervals indicates that porosity does not decrease across the northern limit of production. In order to compare the productivity potential of zones with varying porosity and water saturation, Buckles Numbers (product of porosity and water saturation) were mapped for zones within the productive stratigraphic interval. Averaged, thickness-weighted Buckles Numbers indicate that productivity potential does not decline across the northern limit of the field. Thus, it is concluded that the northern (updip) extent of effective fracture permeability controls the northern limit of production at Waveland field. High initial water cut indicates that water is in the fractures and gas and water are in the matrix. The presence of water in fractures adjacent to rock with much narrower effective pore-throat radii is a normally unstable situation, as capillary pressure would be expected to result in the matrix imbibing water and releasing gas to the fractures. It is proposed that fracturing occurred after hydrocarbon migration and that there is little or no fluid exchange between fractures and matrix prior to wellbore drawdown. Waveland is an example of a field where limits of productivity are controlled by permeability rather than by porosity, hydrocarbon saturation, or trap geometry. Buckles Numbers maps are a useful tool for describing productivity potential of similar fields. End_of_Article - Last_Page 282------------

Hydraulic Fracturing - Fracture Flow Capacity vs Well Productivity

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 91–95. Abstract In the past few years much consideration has been given to the evaluation of the effect of hydraulic fracturing on the productivity of wells. Generally, these studies included the evaluation of fracturing materials, fracture extension and formation damage due to the use of various fracturing fluids. Only little consideration has been given to the characteristics, and in particular the flow capacity, of the fracture itself and its effect on well productivity. This paper presents the results of laboratory investigations pointed toward the evaluation of the efficiency of various fractures with special emphasis on the flow capacity of these fractures. Data presented in this paper are the results of both an electrical model study and physical testing. Under consideration are (1) effect of overflush, (2) premature production of well after treatment,(3) "tailing-in" with coarse sand near the end of the treatment,(4) effect of propping agent size and concentration, (5) reduction in effective fracture permeability caused by formation caused by formation fines, silt and clays, and (6) effect of various fluids on formation strength and competency. The results of this investigation indicate that the flow capacity of a fracture is affected by any or all of the various parameters mentioned above. The authors believe that a better understanding and utilization of these factors should result in more efficient formation fracturing. Introduction Hydraulic fracturing has become almost a standard practice of many companies for stimulating production from old and new wells. Although most companies utilize this service, techniques of application vary widely between companies and areas. Probably too often when a well in an area responds favorably to a particular technique all future wells in the same area are treated in a similar manner. Possibly a modification of the technique would result in a further production increase. Variables, of which many are extremely difficult to evaluate from field results, hamper the selection of procedure changes.