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Abstract Hydraulic fracture conductivity (wfkf) is a critical parameter in completion design of horizontal shale wells. Field evidence and laboratory investigations suggest that these fractures could have finite conductivity values that are influenced by the fracture closure stresses developing during production. Consequently, the fracture conductivity decreases as a function of production time. Currently no field test exists that can capture the dynamic behavior of the conductivity. Bilinear flow analysis (ยผ-slope flow regime) is a common rate-transient-analysis (RTA) technique that uses the first few days of production data to obtain a conductivity value averaged over time for all the fractures of the well. But it does not consider the stress-sensitivity of the production. In this paper, using forward simulation of flow and production from a hydraulically fractured shale gas well with a stress-sensitive (dynamic) permeability field, we show that the error associated with the averaging of the dynamic behavior of the fracture conductivity could be large. We re-visit bilinear flow theory and modify the RTA method for the presence of stress-sensitive hydraulic fracture conductivity. Now the ยผ-slope analysis gives an average of the dynamic fracture conductivity, which could be lower than the initial conductivity. The work shows the need to extend the analysis to formation linear-flow and boundary dominated flow regimes. Introduction Bilinear flow occurs in shale gas wells, as a manifestation of linear flow in both matrix and fracture simultaneously. The duration of this flow regime spans the first few days of production, typically after the fracture linear flow regime, when flowback of the injected fracturing fluid occurs, preceding the widely-observed half-slope formation linear flow regime. Its signature on a log-log diagnostic plot is ยผ slope on pressure and radial derivative plots and zero-slope on the linear derivative plot (Clarkson and Beierle 2010) The interpretation of fracture linear and bilinear flows can aid us in obtaining a fracture conductivity averaged for all the fractures of the well.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (5 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (2 more...)
Simulation of the Seismic Records (DAS) in a Borehole Throughout CO2 Storage Procedures: Impact of Fracture Roughness on Fines Migration and Fracture Aperture Growth in Calcareous Shale Rocks During Acidized Core Floods
Khan, Hasan J. (King Fahd University of Petroleum & Minerals, Saudi Arabia) | Al-Abdulrabalnabi, Ridha (King Fahd University of Petroleum & Minerals, Saudi Arabia) | Al-Jawad, Murtada S. (King Fahd University of Petroleum & Minerals, Saudi Arabia)
Abstract Shales are impermeable rocks that need to be hydraulically fractured using an acidic hydraulic fracturing fluid (HFF) to enable commercial production. The fracturing process injects HFF at a high pressure to break the rock and create a series of high-flow fractures with rough surfaces; new fractures are generated along the direction of minimum horizontal stress and old cement-filled fractures are reopened. In the process, the oxic HFF physically and chemically alters the fracture surface and creates a "reaction-altered zone". Recent work has shown the depth of reaction penetration to be minute and that most of the changes occur on the fracture surface. To better characterize the impact of fracture roughness on fracture aperture growth, we take a coupled experimental-modeling approach. Two carbonate-rich Wolfcamp shale samples with calcite-filled fractures are cored. One sample is cut through the center to create a smooth fracture and the second is fractured along the calcite-filled fracture to generate a rough fracture. The topography and mineral distribution of the fracture surface is analyzed before a reactive core-flood with an equilibrated acidic brine is conducted. The effluent is collected and analyzed in a optical emission spectrometer. Pre- and post-flood ฮผCT scans are conducted to log the change in the fracture aperture over time. Preliminary results show that calcite dissolution is the main chemical reaction occurring on the fracture surface. Due to this, the fracture roughness has reduced and the largest change in the fracture aperture is observed nearer to the inlet. The majority of the fracture surface still contains Ca but new "growths" of Si are visible, which have been potentially generated by the chipping of the Ca mineral. The smaller calcite-filled fractures, which are deeper inside the rock away from the fracture surface, show loss of Ca due to the acid reaction indicating deeper penetration of the acidic brine. This work shows the potential impact of fracture roughness on the mechanism of fracture evolution during acidized core floods. A higher fracture roughness shows more fines migration and an overall larger change in fracture aperture during the injection.
- North America > United States > Texas (0.25)
- North America > United States > New Mexico (0.25)
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
ABSTRACT Natural fractures and faults result from the tectonic and structural history of rock formations. While laterally extensive fracture networks can increase the depletion area, they can create challenges due to fluid channeling-pressure communication. Electrical imaging is used at the wellbore to identify fractures/faults. However, interpreting open features is difficult in oil-based mud (OBM) as they can appear resistive. Ultrasonic images lose sensitivity in the presence of spirals, drill marks, or non-homogeneous mud. The borehole acoustic imaging uses 3-dimensional slowness time coherence and ray tracing to determine far-field reflectors, providing acoustic reflectors dip/azimuth and their distance away from wellbore. Combining these two it can provide a reflectors map of fractures and faults but cannot confirm their openness. To address this, we present a method that uses Hayman image to assist analyzing open fractures/faults. Correlating the wellbore fracture/fault planes with 3D slowness time coherence and ray tracing (sonic far field) based event, we interpreted the extension of fractures and faults from the wellbore into the formation on surface seismic aligned section and identified potential pressure communication channels. In OBM, MHz frequency imager data can produce resistivity, dielectric permittivity, and standoff images through advanced inversion processing. By combining dielectric and resistivity information, a new Hayman image can be generated through post-processing. Jointly analyzing resistivity and Hayman images helps resolve open/partially open features even when borehole rugosity is high, and other imaging techniques lose sensitivity. Mapping these identified fractures/faults and interpreted potentially unstable fractures away from the wellbore wall helped in identifying the orientations and alignments of the wellbore and far-field events on surface seismic aligned sonic migrated image. A joint interpretation of resistivity and Hayman images (pilot well) identified two additional open/partially open fractures in the upper-middle section, along with several closed fractures and two closed faults. In the middle of the well there is a depth interval where closed fracture density increases compared to above and below. This interval is identified as an unstable zone from the borehole image. Comparing with the far field sonic processed results, this unstable interval has the highest density of sonic reflectors. The azimuth of the open fractures interpreted from the image upper section is in alignment with a side-track well open fractures interpreted in the unstable zone. In this case study, we identified open and unstable closed fractures intervals that extend into the formation and can form a pressure communication channel when the well is put into injection. These observations were consistent with field pressure communication and substantiated with production logging measurements. This spatially resolved fracture network is essential for subsurface understanding and future well placement in this field, providing critical input for the dynamic reservoir model.
- Europe > Norway > North Sea (0.28)
- Asia > Middle East > UAE (0.28)
- North America > United States > Texas (0.28)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Europe > Norway > North Sea > Central North Sea > Central Graben > Block 2/8 > Valhall Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > Block 2/8 > Valhall Field > Hod Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > Block 2/11 > Valhall Field > Tor Formation (0.99)
- (6 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- (4 more...)
ABSTRACT In-situ quantification of fracture properties is challenging as it relies on collected data from core samples, which are hard to acquire, or on indirect geophysical measurements, which often hold oversimplified assumptions for fracture properties. The objectives of this paper are to (a) quantify the sensitivity of dielectric measurements to fracture surface roughness, and aperture size in solid cubic cells through numerical modeling, (b) quantify the sensitivity of dielectric measurements to fracture surface roughness, and aperture size within sandstone samples, and (c) quantify the influence of fluid phase saturation on the dielectric measurements in fractured formations. First, we developed synthetic digital models of fractured rocks with a wide range of fracture surface roughness using fractal theory. Then, we developed different cases where the fracture aperture sizes were allowed to vary. After that, we implanted the fracture models into both solid cubical cells and a real three-dimensional micro-computed tomography (3D micro-CT) image of a Berea sandstone sample. We used the synthetic fractured rock models as inputs to a numerical dielectric permittivity simulator under different brine phase saturations of 100%, 79%, 24%, and 0%. The NaCl brine salinity and temperature conditions of simulations were 50 PPT and 75ยฐC, respectively. The numerical simulator solved Maxwell's equations that describe the propagation of electromagnetic waves using a finite volume algorithm in the frequency domain. The outcomes of numerical simulations included real and imaginary parts of complex dielectric permittivity as a function of frequency in the range of 1 Hz to 20 MHz. Results showed high dependence of the relative dielectric constant on the fracture surface roughness at low frequencies up to 0.01 MHz. Increasing fracture surface roughness from a completely smooth slit-like fracture to a rough fracture with a fractal dimension of 3 led to an increase in the relative dielectric constant by more than one degree of magnitude while the sample conductivity decreased by 40%. Changing sample saturation from 100% water saturation to 100% hydrocarbon saturation decreased the relative dielectric constant by more than two orders of magnitude at a frequency of 1 Hz. This sensitivity of the dielectric permittivity to fracture properties and brine saturation can help in the simultaneous assessment of fracture properties and fluid saturation through the interpretation of multi-frequency dielectric measurements. The ability to assess fracture properties in real-time from electromagnetic measurements will pave the way to building robust fluid-flow and reservoir simulation models.
- North America > United States > Texas (0.31)
- North America > United States > West Virginia (0.28)
- North America > United States > Pennsylvania (0.28)
- (3 more...)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.59)
- Geology > Geological Subdiscipline > Geomechanics (0.50)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract This paper presents the results of numerical simulations of hydraulic fracturing in the immediate vicinity of the wellbore. This research aims to identify the primary mechanisms underlying the complexities in both the fracture morphology and propagation of longitudinal fractures. The study shows that the perforation attributes and characteristics, the cement quality, and the reservoir heterogeneity have a significant impact on the resulting morphology and the trajectory of the propagating hydraulic fracture. The study is based on properties and conditions associated with a field study conducted in the Austin Chalk formation, and concludes that the pattern and the dimensions of the perforations are essential factors controlling the fracture initiation pressure and morphology. The results of the simulation studies provide insights into the principles and mechanisms controlling fracture branching and the initiation of longitudinal fractures in the near-wellbore region and can lead to improved operational designs for more effective fracturing treatments.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (3 more...)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
- (3 more...)
The Effect of Fracture Surface Roughness on Propped Fracture Conductivity Using 3D-Printed Fracture Surfaces
Sistrunk, Carrie (Texas A&M University) | Brashear, Andrew Travis (Texas A&M University) | Hill, Dan (Texas A&M University) | Zhu, Ding (Texas A&M University) | Tajima, Tohoko (Texas A&M University)
Abstract When rocks are fractured in tension, the fracture surfaces created are rough, with a wide range of surface morphologies possible. In previous studies of propped fracture conductivity using fractured samples, the fracture surface topography was found to have a strong influence on fracture conductivity and stimulation efficiency. Fracture surface patterns (relatively uniform, randomly rough, step changes, ridges and valleys) strongly affect propped fracture conductivity. Different types of surfaces can result in propped fracture conductivities differing by an order of magnitude or more for identical proppant loading conditions. To generate quantitative correlations including surface topographic effects, consistent samples with well-defined surfaces should be used in the experiments. However, when using actual rock samples to create realistic fracture surfaces by fracturing them in tension, the surfaces created are never the same, even using small samples all taken from the same block. This lack of repeatability in fracture surfaces greatly complicates identification of the effects of the rough surfaces on propped fracture conductivity. To overcome this, we created repeatable rough fracture surfaces using 3D-printing technology. First, we geostatistically generated a numerical depiction of a rough fracture surface. Then the surface was printed with resin using a 3D-printer. The hardened resin model of the rock sample was used to make a mold, which was in turn used to create a rock sample made of cement. High strength cement was used so that the samples had similar mechanical properties to unconventional reservoir rocks. With this methodology, we created multiple samples with identical surface roughness and features, allowing us to isolate and test other parameters, such as proppant size and concentration. Fracture conductivity tests were conducted using a modified API conductivity cell and artificial rock samples that are nominally 7 inches long and 2 inches wide. A well-established protocol to generate propped fracture conductivity as a function of closure stress was employed to test three different proppant concentrations on identical rough surfaces. For all three experiments, 100 mesh sand was used. The study demonstrates how proppant concentration affects propped fracture conductivity behavior in a systematic way.
- Research Report > Experimental Study (0.67)
- Research Report > New Finding (0.47)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.47)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (9 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
Improved Evaluation Methodology of Fractured Horizontal Well Performance: New Method to Measure the Effect of Gel Damage and Cyclic Stress on Fracture Conductivity
Zhang, Junjing (ConocoPhillips Company) | Nozaki, Manabu (ConocoPhillips Company) | Zwarich, Nola R (ConocoPhillips Company) | Carman, Paul S (ConocoPhillips Company) | Davis, Eric R (ConocoPhillips Company) | Pedam, Sandeep (ConocoPhillips Company) | Buck, Brian R (ConocoPhillips Company) | Childs, Leigh A (ConocoPhillips Company) | Perfetta, Patrick J (ConocoPhillips Company)
Abstract In thinly bedded sandstone reservoirs, hydraulic fractures are required in horizontal wells to connect isolated pay intervals and to improve the volumetric sweep efficiency during waterflooding. This study presents a new, more robust way to evaluate gel damage and cyclic stress in the laboratory. Results from the laboratory evaluation are validated with field production data. Standard ISO/API tests are adequate at comparing proppant types but do not accurately predict resultant conductivity in a well as they do not account for several in-situ damage mechanisms. With a limited number of cores available it is important to clearly define the scope of the laboratory testing and decide which damage mechanisms to investigate. Testing all variables in the laboratory is not practical. For this study, the primary objectives were to 1) compare ceramic proppant to the natural sand, 2) investigate the impact of thinly-bedded sandstone on the fracture conductivity, and 3) determine the minimum required proppant concentration (the cutoff concentration for interpreting the effective fracture half-length in numerical hydraulic fracture model results). The laboratory testing was designed to simulate as realistic the in-situ condition by 1) using actual formation core, 2) performing cyclic stress cycles to mimic multiple shut-in and production periods, and 3) placing the gel and allowing it to cross-link and break in the fracture. During the conductivity experiments, the following steps were taken: 1) oil injection with cyclic stress applied, 2) dynamic cross-linked gel injection and shut-in for gel breaking, and 3) oil injection with cyclic stress applied. Variables investigated include fluid-rock interaction, gel residual, cyclic stress, proppant type, concentration, and size distribution and time dependency of conductivity. Discount factors are derived from the test results which provide a more realistic and repeatable conductivity prediction. This study discovered that for hydraulic fracturing of weak rocks in the shallow formation, the baseline fracture conductivity from API tests should be reduced by 22% first to account for the proppant-rock interaction. After applying the aggressive cyclic stresses, the cumulative conductivity loss increases to 38%. After the cross-linked gel cleanup, a total of 72% fracture conductivity is lost for a proppant pack at 2 lbm/ft and 91% conductivity loss for proppant pack at 1 lbm/ft. It is also found in this study that each large-scale stress cycle reduces an approximate 1% fracture conductivity of the loosely packed proppant until a tighter and stable proppant pack is formed. The cyclic stress effect becomes insignificant when the proppant pack porosity decreases to โผ0.2. Well production history was matched by varying fracture properties in the transient inflow performance analysis. For two wells under the same fracture design, the matched fracture conductivities resulted in less than 25% error compared with the retained conductivities from the laboratory tests. This validated the laboratory findings and method. In summary, this study investigates a critical completion design variable and well performance modeling input, i.e., fracture conductivity, in low-to-moderate permeability, thinly bedded sandstone reservoirs. It breaks down the fracture conductivity degradation into various components and enables further fracturing design optimization, such as proppant selection, fracturing fluid qualification, pump schedule design, well shut-in frequency, frac sleeve spacing, etc. It provides an unbiased estimate of retained fracture conductivity after considering the major impairment mechanisms. It also prevents fictitious and overly optimistic fracture conductivities which originate from the fracturing practices in unconventional reservoirs and the continuous drive for cost savings. This results in calculations of completion skin factors that more accurately represent the fracture conductivity for longitudinal fractures in openhole sleeve completions, reinforcing the importance of fracture design optimization on well productivity.
- Research Report (0.67)
- Overview > Innovation (0.64)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
A Systematic Approach to Fault Sealing Capacity Evaluation in Underground Gas Storage: A Case Study from China
Wang, Rujun (PetroChina Tarim Oilfield Company, CNPC) | Zhou, Wei (RIPED,PetroChina,CNPC) | Zhou, Daiyu (PetroChina Tarim Oilfield Company, CNPC) | Wu, Zangyuan (PetroChina Tarim Oilfield Company, CNPC) | Lian, Liming (RIPED,PetroChina,CNPC) | Yan, Gengping (PetroChina Tarim Oilfield Company, CNPC) | Shao, Guangqiang (PetroChina Tarim Oilfield Company, CNPC) | Zhang, Chao (PetroChina Tarim Oilfield Company, CNPC) | Li, Jun (PetroChina Tarim Oilfield Company, CNPC) | Bian, Wanjiang (PetroChina Tarim Oilfield Company, CNPC) | Jin, Quan (PetroChina Tarim Oilfield Company, CNPC) | Zhao, Zitong (PetroChina Tarim Oilfield Company, CNPC) | Zhang, Yong (Gree Energy Services, Inc) | Deng, Yantao (Singapore Petroleum Company) | Huang, Xingning (Chengdu CK Energy Technology Co., Ltd.)
Abstract Fault stability refers to the risk level of reactivation of the pre-existing fault in the stress field. Fault reactivation within the oilfield is mainly caused by the increase of fluid pressure in the fault zone. The quantitative evaluation index of the fault stability is the critical fluid pressure (that is, additional fluid pressure) required for fault reactivation under the current pore fluid pressure. When the formation pore pressure reaches the critical value, the corresponding fault part will be in the critical stress state. The sliding of the fault in the critical stress state will easily cause oil and gas leakage and casing damage at the edge of the fault. Therefore, it is of great significance to study fault stability for oilfield production. Ground stress is a key parameter for fault stability evaluation. There are many methods to calculate the geomechanics including hydraulic method, acoustic emission method, and the use of the logging data, among which the hydraulic fracturing method can be used to obtain the most accurate horizontal minimum principal stress. This paper calculates the continuous geomechanics by using the logging data. There are many methods available for evaluating fault stability, among which fault sealing analysis technology (FAST) method is most widely used. FAST can be used to not only quantitatively evaluate fault stability, but also evaluate the impact of fault cohesion on fault stability. There are many factors affecting fault stability. The relationship between the differential stress and tensile strength of the fault rock will affect the trend of the fault reactivation.The direction of the stress field also affects the fault stability greatly. The argillaceous material weakens the strength of fault rock. When a large amount of argillaceous material enters the fault zone, the fault tends to reactivate. The change of reservoir fluid pressure will also lead to the change of horizontal stress to affect the stability of the fault. In addition, the accuracy of seismic interpretation will also affect the evaluation results of fault stability. Based on the geological model framework and one-dimensional geomechanical model calibration, this paper establishes a three-dimensional geomechanical model by using the finite element simulation method to carry out four-dimensional geomechanical research to evaluate the fault stability in the development of the Donghe 1 Reservoir in Tarim basin. The research results show that the fracture sealing gradually strengthens during the development of Donghe 1 Reservoir, and the quantized critical fracture opening pressure is 67.38MPa.
- Asia > China > Xinjiang Uyghur Autonomous Region (0.34)
- North America > United States > Texas (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.87)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
Abstract Acid fracturing creates conductive fractures in carbonate reservoirs through acid-rock dissolution. However, over-etching or stimulating weak carbonate formation could result in a fast decline of fracture conductivity. In addition, most models in the literature showed that rock strength has an exponential impact on fracture conductivity. This work conducted experiments to mitigate this problem through rock strengthening with diammonium phosphate (DAP). Different fracture surfaces were tested using the ACM-3000 acid fracture conductivity system to compare the conductivity of intact samples with the treated ones. The fracture conductivity of 4 pairs of weak Austin chalk samples (7in ร 1.34in ร 3in) with flat surfaces was evaluated by flowing nitrogen gas (200-350 cc/min) at increasing stresses up to 1,500 psi. Half of the samples were kept intact to represent the control group to which treated samples were compared. The treatment consists of saturating vacuumed chalk samples with 1M DAP for 72 hrs at pressure and temperature of 1,000 psi and 75ยฐC, respectively. In addition, the surface hardness of the samples was measured pre-and post-treatment, and conductivity measurements were performed to evaluate the treatment effect on the samples. The chalk samples used in this study are naturally weak with low average surface hardness (i.e., 3 GPa compared to 15 GPa for Indiana limestone). However, the DAP solution could significantly enhance the surface hardness of soft chalk up to almost 3.5 times its original value. The chalk hardness increase reduced the normal deformation and increased the yield stress of the treated samples. The untreated sample exhibited lower endurance to loading and developed cracks at lower stresses. Also, the results showed that the normalized conductivity of the treated flat samples is at least double the untreated ones. The chemical treatment makes the chalk stiffer with less deformation when stressed, which leads to enhanced conductivity at higher stress. In this paper, an additional stage is suggested in acid fracturing to harden the surface of carbonate rocks chemically after acid injection. Successful application of such treatment in the field can extend fracture life and substantially reduce the need for re-fracking jobs.
- Europe (0.94)
- Asia > Middle East (0.69)
- North America > United States > Texas (0.35)
- (3 more...)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.56)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (0.91)
Abstract Embedded discrete fracture models (EDFM's) are commonly used to study fluid flow in unconventional reservoirs. The EDFM, however, requires extensive pre-processing of non-neighboring connections. More importantly, it becomes further demanding when grid refinement is required to accurately model mass transfer between the fractures and the tight matrix rock, primarily to resolve transients in the matrix. This renders the EDFM an expensive option to model large-scale fractured reservoirs where the number of fracture segments can be substantial. In this paper, an upscaling procedure is proposed to construct a dual-porosity model (DPM) from a discrete fracture characterization. The implicit representation of the fractures provides for an improved simulation efficiency. While the DPM's are often perceived as simple sugar-cube representations of complex fracture networks, the upscaling technique presented here, demonstrates the capability of DPM's in providing accurate and efficient solutions for a broad range of complex fractured systems. The potential of the DPM is unlocked via application of a flexible matrix/fracture transfer function, that is similar in form to the generalized Vermeulen transfer function (gVer) introduced by Zhang et al. (2022). Unlike the traditional class of transfer functions, first introduced by Warren and Root (1963), the gVer transfer function incorporates a time-dependent correction factor to resolve the transient within the matrix without the need for sub-gridding. The use of an advanced DPM becomes key to our proposed upscaling workflow which also includes the evaluation of effective rock properties and a unique set of matrix/fracture interaction parameters. We first examine several test cases of ultra-tight fractured systems and establish the need for advanced modeling techniques to accurately capture the matrix transient, as observed from single-porosity reference models (SPM's). In the context of EDFM, this can be accomplished by refining the mesh for the matrix grid at an increased computational cost, while the use of gVer transfer function to describe the mass transfer in the DPM is demonstrated to accomplish the same at a marginal computational cost. We then apply the approach to solve more complex problems including models with fracture networks, exhibiting arbitrary fracture orientations and geometries, in a heterogeneous nano-darcy rock. Calculations for such examples are performed using EDFM, and an equivalent upscaled DPM. We furthermore demonstrate the versatility of our approach by refining the DPM in regions of higher spatial variation to capture the details of the fractured rock as dictated by the original EDFM representation. The proposed upscaling procedure overcomes the commonly assumed limitation of the classical DP approach and allows for modeling of unconventional reservoirs without losing the realism of a discrete fracture characterization. It is demonstrated that the proposed technique reproduces the correct response with significantly fewer grid-blocks and hence enables reduction of computational cost of advanced optimization studies in unconventional reservoirs.
- North America > United States > California (0.46)
- North America > United States > Texas (0.28)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (1.00)
- (3 more...)
- Information Technology > Modeling & Simulation (0.49)
- Information Technology > Software (0.47)
- Information Technology > Scientific Computing (0.34)