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Ngameni, K.L., Miskimins, J.L., Abass, H.H., Cherrian, B.,
Experimental Study of Proppant Transport in Horizontal Wellbore Using Fresh Water, SPE 184841-MS, SPE Hydraulic Fracturing Technology Conference and Exhibition, Woodlands, TX, 24-26 January 2017
Abstract: Proppant transport in hydraulic fractures has been studied by numerous authors in the oil and gas industry, however, very little research has been conducted to evaluate proppant transport in horizontal wellbores and through perforation clusters prior to fracture entrance. With the extensive use of water and slickwater systems in the stimulation of unconventional reservoirs, an understanding of how proppant behaves as it is being transported by these fluids in horizontal wellbores and between perforation clusters would be beneficial.
This paper presents the results of an experimental investigation of proppant distribution among perforation clusters in a horizontal wellbore. The work considers the settling nature of proppants in the wellbore and the amount of proppant exiting a given set of perforations. The experiments show that proppant distribution between perforation clusters is not even, and the main causes of the uneven distribution are variable flow velocity and the associated proppant type and size. The results also indicate that in most commonly used sand proppant systems (100 mesh, 40/70 mesh, and 20/40 mesh), significant amounts of sand are left in the wellbore even above calculated critical velocity values.
Li, X., Abass, H.H., Teklu, T.W., Cui, Q.,
A Shale Matrix Imbibition Model ‐ Interplay Between Capillary Pressure and Osmatic Pressure, SPE-181407-MS, Spe Annual Technical Conference and Exhibition, Dubai, UAE, 26-28 September, 2016.
Abstract: High and efficient deliverability of stimulated reservoir volume through a hydraulic fracturing treatment relies on three segments: fluid flow from matrix to the interface between fracture and matrix media, fluid-rock interaction at the fracture-matrix interface, and conductivity of fracture network. Thus, fluids and salt exchange between matrix and fracture network are critical and worth detailed investigation. Moreover, matrix imbibition as an important EOR mechanism has been extensively studied but the focus was mostly given to capillary effect. However, for shale, due to the pore structure and clay content, some physico- or electro-chemical forces at molecular level cannot be overlooked anymore, such as osmosis.
A multi-mechanistic numerical shale matrix imbibition model is developed. The model takes into account dynamic water movement caused by capillary pressure and osmotic pressure as a function of water saturation and salt concentration, respectively. The rock matrix is considered as the mixture of two different components, one with small nano/micro-pores and semi-permeable membrane property and the other having larger meso-pores. The model properly simulates water and salt transportation occurring across the matrix-fracture network contact surface driven by capillarity, osmosis, and salt diffusion. To honor the physics, the salt/ions concentration equation differs from previous work by removing the osmosis component and a new membrane efficiency coefficient is defined and properly incorporated in the model.
Spontaneous imbibition test results were used for matching and validation purposes. The simulation results well explained laboratory high-salinity water imbibition curve, which can be divided into three processes. Initially, a capillary driven imbibition sucks high salt-concentration water into matrix near the matrix-fracture contact surface. However, due to the significant salinity contrast between imbibed fluids and in-situ matrix salinity, a drainage process can be induced. Eventually, as salinity difference decreases and osmosis is weakening, final imbibition stage starts. This model provides a basis for laboratory measurements interpretation and brings some insights to reveal the underlying mechanisms for field post-frac flow-back behavior.
Wang, L., Yao, B., Cha, M., Alqahtani, N.B., Patterson, T.W., Kneafsey, T.J., Miskimins, J.L., Yin, X. and Wu, Y.,
Waterless Fracturing Technologies for Unconventional Reservoirs ‐ Opportunities for Liquid Nitrogen, Journal of Natural Gas Science and Engineering, v. 35, p. 160-174, August 2016.
Abstract: During the past two decades, hydraulic fracturing has significantly improved oil and gas production from shale and tight sandstone reservoirs in the United States and elsewhere. Considering formation damage, water consumption, and environmental impacts associated with water-based fracturing fluids, efforts have been devoted to developing waterless fracturing technologies because of their potential to alleviate these issues. Herein, key theories and features of waterless fracturing technologies, including Oil-based and CO2 energized oil fracturing, explosive and propellant fracturing, gelled LPG and alcohol fracturing, gas fracturing, CO2 fracturing, and cryogenic fracturing, are reviewed. We then experimentally elaborate on the efficacy of liquid nitrogen in enhancing fracture initiation and propagation in concrete samples, and shale and sandstone reservoir rocks. In our laboratory study, cryogenic fractures generated were qualitatively and quantitatively characterized by pressure decay tests, acoustic measurements, gas fracturing, and CT scans. The capacity and applicability of cryogenic fracturing using liquid nitrogen are demonstrated and examined. By properly formulating the technical procedures for field implementation, cryogenic fracturing using liquid nitrogen could be an advantageous option for fracturing unconventional reservoirs.
Li, X., Teklu, T., Abass, H., Zhou, Z, Cui,
The Impact of Water Salinity/Surfactant on Spontaneous Imbibition Through Capillarity and Osmosis for Unconventional IOR, URTeC #2461726, Unconventional Resources Technology Conference, San Antonio, TX, August 2016
Abstract: Spontaneous imbibition has been considered as one of the important mechanisms for unconventional reservoir Improved Oil Recovery (IOR). Capillary pressure and osmotic pressure are the driving forces during the imbibition process and are associated with different rock components. Ions and surfactant in water can modify the surface properties of minerals and organic component, thus wettability moves towards more water-wet to enhance oil recovery. Depending on the membrane efficiency and in-situ water salinity, osmosis can contribute to the imbibition as well. In this paper, a multi-component matrix imbibition model is coupled with wettability alteration by low water salinity/surfactant.
The simulation results are consistent with the experimental observations reported in the paper and literature. Some insights on the ion/surfactant and rock interactions are drawn and water imbibition volume is controlled by rock components (clay, organic matter and other minerals) and different concentrations of salt ions and surfactant. Depending on the ion strength of ion species and surfactant, the concentration of water-wet site on the rock surface increases, thus the contact angle is changed to more water-wet. In addition, interfacial tension can be lowered by surfactant. The combination effects determine capillary pressure imbibition. The concentration of charged ions and surfactant molecules affect the osmosis imbibition. These processes for different rock components associated with pore size distributions are incorporated into the imbibition model. The results showed that there is an optimum water salinity for maximum imbibition. Explained by adoption/desorption theory, anionic surfactant has stronger wettability alteration ability than nonionic surfactant. High TOC rock is prone to bigger contact angle change. To validate the model, spontaneous imbibition tests were performed on cleaned and dried Three Forks core samples for fluids with varying water salinities or surfactant. The imbibition curves were matched very well using the developed model and proved that the interplay of capillarity and osmosis control the imbibition rate and amount following the adsorption dominated imbibition.
Cui, Q, Abass, H.H.,
Experimental Study of Permeability Decline in Tight Formations during Long-Term Depletion, SPE-108257-MS, SPE Low Perm Symposium, Denver, CO, 5-6 May 2016
Abstract: Hydrocarbon production decline behaviors in low permeability reservoirs and conventional reservoirs are significantly different; in such a way that high initial rate is usually observed for a short period in tight formation wells, then the well productivity drops dramatically. The rapid production decline in shale wells has a strong relationship with the loss of rock matrix permeability and reservoir conductivity, resulting from the dissipation of pore pressure during reservoir depletion. This paper presents experimental studies of stress-dependent compaction in tight reservoirs and its impact on long-term recovery.
The magnitude of rock permeability change depends on the in-situ effective stress, which is a combined effect of reservoir pore pressure and confining stress. In this research, permeability of a series of shale and sandstone core plugs are measured in the laboratory using pressure transmission test technique. The samples are tested under multiple confining stress and pore pressure combinations. Several confining stress are pre-set to represent different reservoir stress conditions. Different pore pressures are then applied to mimic reservoir depletion process under specific confining stress conditions. The permeability is calculated for all scenarios and pressure dependent permeability behaviors are analyzed for each type of sample.
The interpretations of effective stress dependent permeability show that different types of rocks have different permeability decline signatures responding to the depletion effect. In addition, tight rocks with different dominate porous media (i.e., matrix and fractures) are found to have different permeability behaviors. Characteristics of permeability decline at different pore pressure intervals area analyzed and the critical reservoir pressure and depletion index (i.e., ratio of pore pressure to overburden stress) are identified for different types of rocks where significant permeability change occurs. Based on the stress dependent permeability measurements, the Biot Coefficient is also determined for different tight samples.
Recognizing permeability decline signatures of tight reservoirs provides significant insights into long-term dynamic reservoir conductivity monitoring and contributes to the field management practices. It is indicated from the study that the permeability decline in tight reservoir wells can be significant with continuous depletion while maintaining reservoir pressure above the critical level has the potential to mitigate the sharp production decline in tight formations and therefore enhance ultimate hydrocarbon recovery.
Zhou, Z., Abass, H., Li, X., Teklu, T.,
Experimental Investigation of the Effect of Imbibition on Shale Permeability During Hydraulic Fracturing, Journal of Natural Gas Science and Engineering, January 2016
Abstract: Hydraulic fracturing technology is widely applied in shale reservoirs to significantly increase production. However, when many operators report a large percentage of the fracturing fluid is not recovered, it is unclear how the remaining fracturing fluid affects the shale formation. It is believed that the unrecovered fracturing fluid could be imbibed by shale matrix, micro-fractures, and surfaces of fractures that are already separated. This paper is to investigate the influence of imbibition on the matrix permeability, micro-fracture permeability, and fracture permeability. It is the first time to correlate permeability change with shale imbibition, and provide quantitative results of increase and decrease in permeability due to imbibition process in shale during hydraulic fracturing.
This paper uses the pressure build-up method to measure permeability of the shale sample, and applies the under-weighing approach to do the imbibition experiment. The Niobrara, Horn River, and Woodford shale formations are the source of the samples in the experiment.
The experimental results show that the imbibed fracturing fluid will damage and seriously reduce the matrix permeability of the shale sample. When the sample imbibes more fluid, the matrix permeability is reduced greater. Imbibition also decreases the fracture permeability of open fractures, but decrease is less than the reduction of matrix permeability. Moreover, there is a lubrication effect that can reopen micro-fractures on shale samples and stimulate and increase the micro-fracture permeability during imbibition.
Permeability is a criterion that determines the long-term production from a formation. By studying the permeability change caused by imbibition during hydraulic fracturing stimulation, this paper presents a new observation that imbibition in shale can not only damage, but also potentially stimulate the shale formation by increasing permeability due to open closed or sealed natural fractures.
Alotaibi, M.S. and Miskimins, J.L.,
Slickwater Proppant Transport in Complex Fractures: New Experimental Findings & Scalable Correlation, SPE 174828 presented at SPE Annual Technical Conference and Exhibition, Houston, TX, September 28-30, 2015.
Abstract: Slickwater hydraulic fracturing is an important technology that has enabled the oil and gas industry to economically develop enormous unconventional resources. Despite its great success, this technology faces challenges, especially with proppant transport in complex fractures. Very limited work exists in literature about slickwater proppant flow in subsidiary fractures or predictive correlations to estimate settled proppant dune heights.
This paper provides a scalable correlation to predict dune height across a wide range of flow rates and proppant concentrations. A unique feature about this correlation is its inclusion of the friction effect, as roughness was introduced to the fracture slot walls. 30/70 mesh brown sand was used to conduct the slot flow experiments and build the correlation. This paper also spotlights the proppant transport mechanism during proppant dune development. Understanding this mechanism reveals key information about the horizontal and vertical settled proppant size distribution. In addition, experimental results are presented to answer the debatable question whether slickwater can transport proppant into tertiary fractures or not. In fact, the data shows that proppant in slickwater is not only capable of “turning the corner” but also developing high dune levels exceeding 96% of the tertiary fracture slot heights.
Corapcioglu, H., Miskimins, J.L. and Prasad, M.,
Fracturing Fluid Effects on Young’s Modulus and Embedment in the Niobrara Formation, SPE 170835 presented at SPE Annual Technical Conference and Exhibition, Amsterdam, The Netherlands, October 27-29, 2014.
Abstract: Shale plays and the evolving technologies of horizontal drilling and hydraulic fracturing are driving the petroleum industry in many regions. Due to their low permeability, hydraulic fracturing is necessary for economic production in these shale systems. The success of these reservoirs is dependent on optimized hydraulic fracturing designs, and requires an understanding of the mechanical properties of these reservoirs.
One of these properties, Young’s modulus, can weaken the formation if it is reduced. This weakening of the formation can, in turn, lead to; increased proppant embedment into the fracture face and a subsequent loss of conductivity. In low permeability shale reservoirs, the conductivity achieved through fracturing is just as critical as in other formations, thus making proppant embedment an issue that needs to be fully understood. This paper focused on how different fracturing fluids impacted the Young’s modulus of the Niobrara shale, a major producing formation in the states of Colorado and Wyoming, and how this change affects proppant embedment and conductivity with certain proppants.
Nanoindentation technology was used to determine Young’s modulus changes in Niobrara core samples after they were saturated for 30 days in certain fracturing fluids, and after they were heated under selected proppants, simulating a fracture to test the proppant embedment profiles using scanning acoustic microscope (SAM) and profilometer measurements.
The experimental results showed that Young’s modulus decreased with fluid exposure regardless of the fracturing fluid type and also increased (rebounded) after a certain saturation time. The magnitude of decrease in Young’s modulus values was dependent on fluid type and saturation time. In one extreme case, (when KCI+friction reducer fluid was used as treatment fluid for 30 days) Young’s modulus decreased by approximately 80%. The Young’s modulus reduction is believed to be mainly caused by a weakening of the calcite minerals. Higher reductions experienced by KCI based fluids could be due to a detrimental chemical reaction between KCI and calcite minerals. Results also showed proppant embedment and crushing are inevitable under the tested circumstances and are dependent on distributed stress on the contact pints as well as proppant type and fluid exposure.
Li, X., Miskimins, J.L. and Hoffman, B.T. ,
A Combined Bottom-hole Pressure Calculation Procedure Using Multiphase Correlations and Artificial Neural Network Models, SPE 170683 presented at SPE Annual Technical Conference and Exhibition, Amsterdam, The Netherlands, October 27-29, 2014.
Abstract: The desire to have accurate bottom-hole pressure (BHP) data can come during different phases of a well’s life, including well design, mini-frac test, well testing, and production analysis. But frequently, it is not practical, feasible, or economic to deploy a pressure gauge to measure the BHP directly. In most cases, however, the unknown flowing BHP is calculated from the known parameters and surface measurements using multiphase correlations or mechanistic modeling. Recently, artificial neural network (ANN) techniques have been adopted to predict BHP and proved to have better prediction performance than other conventional prediction methods. With the design applied in this study, the use of ANN techniques can be more fully utilized to solve complex multiphase flow problems, such as pressure gradient prediction and complex well trajectories.
Back-propagation(BP) neural network models have been modified to fit into the piece-wise calculation procedures of multiphase correlations to achieve higher prediction accuracy and broaden the prediction range. The model training requires well-segment-scale data sets, which contain pressure gradients as the model output and the model inputs, including inclination angle, liquid and gas superficial velocities, gas-liquid surface tension, liquid density, specific gravity of free gas, liquid and gas viscosities, average pressure and temperature. Different BP neural network model structures have been tested to find a suitable neuron number in the hidden-layer of the model. Two pressure gradient prediction models were trained for slug flow and annular mist flow. Ultimately, a combined BHP calculation procedure was designed combining the multiphase correlations and trained ANN models. The statistical test using the collected data showed that the combined procedure gave the best prediction performance against the eleven multiphase correlations studied in this work and had the lowest average absolute percent error of 3.1% and standard deviation of 0.034. Independent field data was used to test the extendibility of the combined procedure perdition range. Comparing to the multiphase correlations, the combined procedure gave fairly accurate predictions with an average absolute percent error 23.0% and a standard deviation of 0.176. To facilitate field application, a multiphase flow BHP calculator with a user interface was developed.
Li, X., Miskimins, J.L., Sutton, R.P. and Hoffman, B.T.,
Multiphase Flow Pattern Recognition in Horizontal and Upward Gas-Liquid Flow Using Support Vector Machine Models, SPE 170671 presented at SPE Annual Technical Conference and Exhibition, Amsterdam, The Netherlands, October 27-29, 2014.
Abstract: Multiphase flow occurs in wellbores during the production of oil and gas. Depending on the physical forces and interactions acting on different phases, there can be various phase distributions in the pipes, known as flow patterns or flow regimes, such as bubble flow, slug flow, annular mist flow, and stratified flow. Because multiphase flow pressure gradients change significantly with different flow patterns, the flow pattern prediction is usually the first step before any pressure drop estimation is performed. Moreover, in gas production wells, flow regime prediction can help engineers to determine the continuous phase to deal with liquid loading problems.
Many efforts, including correlation fitting, fluid dynamic calculation, and back-propagation neural network models, have been used to match experimental observations, which are usually presented as flow regime maps. However, there are often mismatches or errors between the prediction results and the experimental data. To avoid such matching errors, this study applies Support Vector Machine (SVM) models to directly represent the measured experimental data. If the assumption is made that there is no error in the experimental data, the SVM models always give correct output results. An SVM model is a mathematical model that is popularly used for pattern classification and non-linear regression.
For producing oil and gas wells, horizontal and upward multiphase flow is studied in this paper. Experimental data was collected from literature and other sources in order to train the SVM models. Different flow regimes are divided by the boundaries created by the trained models. The model prediction results are plotted in 3-D plots, which provide a clear visualization of how the well inclination angle affects the flow regime transition. The SVM models also perform interpolation approximation to predict the flow regimes at various inclination angles where no experiments have been conducted. Well trained SVM models can be conveniently used and easily combined with pressure loss correlations to calculate pressure drops in well bores. Finally, an approach using the trained SVM models to deal with liquid loading problems in gas production wells is presented.
Zhou, Z., Hoffman, T., Bearinger, D., Li, X., Abass, H.H.,
Experimental and Numerical Study on Spontaneous Imbibition of Fracturing Fluids in the Horn River Shale Gas Formation, SPE-171600-MS, SPE/CSUR Unconventional Resources Conference, Calgary, Alberta, Canada, 30 September–2 October 2014
Abstract: After hydraulic fracturing only 10% to 50% of the fracturing fluids is typically recovered. This paper investigates how the remaining fracturing fluids are imbibed by shale as a function of time, and it investigates the influence of various parameters on the imbibition process including: lithology, reservoir characteristics, and fluid properties. In addition, based on experimental results, a numerical model has been developed to estimate the volume and rate of spontaneous imbibition over the entire fracture face.
The rock samples are from the Horn River formation onshore Canada. The fracturing fluids used in the experiments included 2% KCl, 0.07% friction reducer and 2% KCl substitute. In the experimental control group, distilled water was used. Through spontaneous imbibition experiments, the relationship between imbibed fluid volume and time indicated that clay content was the most important factor that affected the total imbibed amount. Shale matrix with high clay content could imbibe more fracturing fluids than its measured porous space because of the clay’s strong ability to expand and hold water. According to contact angle test results, the strongly water-wet shale samples had a faster imbibed rate. Total organic carbon (TOC) and porosity had no influence on imbibed volume and rate.
These experimental findings can contribute to an improved fracturing fluid design for different shale formation conditions to reduce fluid loss. The experiment showed that 2% KCl and 2% KCl substitute fracturing fluids were imbibed from 10% to 40% less than 0.07% friction reducer in the shale formation with high clay content; whereas in the shale formation with low clay content, the opposite occurred. In the low clay content shale, 0.07% friction reducer test fluid was imbibed from 10% to 30% less than 2% KCl fluid, but had a similar imbibed amount with 2% KCl substitute fluid.
The numerical model result was matched with the experimental result to estimate a relative permeability in the model which could represent the rock properties. This model could be used to estimate the total imbibed volume along fracture faces through spontaneous imbibition.
Charoenwongsa, S., Kazemi, H., Fakcharoenphol, P. and Miskimins, J.L.
Simulation of Gel Filter Cake Formation, Gel Cleanup, and Post-Frac Well Performance in Hydraulically Fracture Gas Wells, SPE 150104, SPE Production & Operations Journal, v. 28, No. 3, August 2013.
Abstract: Polymer and gel damage is a major issue in the cleanup of hydraulically fractured gas wells. This paper addresses the issue by using a gas/water flow model that simulates fracture propagation with gel filter cake-formation as mechanical trapping of polymer molecules on the fracture face and filtrate transport into the adjacent matrix. The model accounts for polymer as a chemical component. This approach is different than treating polymer as a highly viscous gel phase, which is the common method in most literature. In this model, the gel filter-cake thickness is calculated on the basis of experimental data. For leakoff, the model allows only the sheared polymer molecules, which are the major cause of formation permeability reduction, to cross the fracture face into the formation and adsorb on matrix. Other features of the model include water blockage, non-Newtonian flow, non-Darcy flow, and proppant and reservoir compaction.
Mohammad, N.A. and Miskimins, J.L.
A Comparison of Hydraulic-Fracture Modeling with Downhole and Surface Microseismic Data in a Stacked Fluvial Pay System, SPE 134490, SPE Production & Operations Journal, v. 27, No. 3, August 2012.
Abstract: This paper presents a study that combines and compares the results of hydraulic fracture mapping and modeling using both downhole and surface microseismic arrays. There were three objectives for the study including 1) developing detailed posttreatment models of hydraulic fracturing treatments in the subject well, Well D1, which was monitored with downhole microseismic tools; 2) developing detailed post-treatment models of the hydraulic fracturing treatments in the subject well, Well S1, which was monitored with surface microseismic tools; and 3) determining the match characteristics of the downhole and surface microseismic data to hydraulic fracture models developed for both Wells D1 and S1.
Input data for this project were obtained from two wells in the Greater Natural Buttes field, Uinta basin, Utah. Ten fracture models were built using five stages each from the two subject wells, Wells D1 and S1, and detailed pressure matches were made. Comparisons of the match characteristics from the multiple inputs were then developed. They hydraulic fracture stimulation models were graphically integrated with the microseismic events using visualization software. This software allowed the final model-simulated fracture geometries to be plotted along with the microseismic events in three-dimensional space thus allowing the viewer to see a full integration of data in a stacked fluvieal pay system.
Results from the integration process show good agreement in geometries and depth for most stages in the downhole-monitored well, whereas comparisons of surface microseismic mapping measurements with the simulated fracture geometries yielded variable results. When combined with additional inputs, such as geologic models, the integration methodology used in this project provides an excellent tool for hydraulic fracture modeling and reservoir management in stacked pay systems.
Lai, B., Miskimins, J.L. and Wu, Y.S.
Non-Darcy Porous-Media Flow According to the Barree and Conway Model: Laboratory and Numerical-Modeling Studies, SPE 122611-PA, SPE Journal, v. 17, No. 1, March 2012.
Abstract: This paper presents the results of our new experimental studies conducted for high flow rates through proppant packs, which show that the Barree and Conway (2004) flow model is capable of overcoming limitations of the Forchheimer non-Darcy equation at very high flow rates. To quantify the non-Darcy flow behavior using the Barree and Conway model, a numerical model is developed to simulate non-Darcy flow. In addition, an analytical solution is presented for steady-state linear non-Darcy flow and is used to verify the numerical-simulation results. The numerical model incorporates the Barree and Conway model into a general-purpose reservoir simulator for modeling multidimensional, single-phase non-Darcy flow in porous and fractured media and supplements the laboratory findings. The numerical model is then used to perform sensitivity analysis of the Barree and Conway flow model’s parameters and to investigate transient behavior of non-Darcy Flow at an injection well.
Neuhaus, C.W. and Miskimins, J.L.
Analysis of Surface and Downhole Microseismic Monitoring Coupled with Hydraulic Fracture Modeling in the Woodford Shale, SPE 154804, SPE Europec/EAGE Annual Conference, Copenhagen, Denmark, June 4-7, 2012.
Abstract: The work presented in this paper analyzes surface and downhole microseismic data for a horizontal well in the Woodford Shale in Oklahoma and compares those results with calibrated hydraulic fracture modeling. Hydraulic fracture models were created for each of five stages with a three-dimensional modeling software, incorporating available petrophysical data in order to match the recorded treatment pressure and the fracture geometry obtained from the microseismic data. Further analysis investigated the congruency of the downhole and the surface microseismic data, what differences they produced in a match if used exclusively, the influence of the number of events on the fracture geometry obtained from the microseismic data, the error of event location, the degree of complexity of the created fracture network, and the relationship between the magnitude of events and the time and location of their occurrence.
The fracture models produced good matches for both pressure and fracture geometry but showed problems matching the fracture height due to cross-stage fracturing into parts of the reservoir that were already stimulated in a previous stage. Surface and downhole microseismic data overlapped in certain regions and picked up on different occurrences in others, giving a more complete picture of microseismic activity and fracture growth if used together. However, they deviated in terms of vertical event location with surface data showing more upward growth and downhole data showing more downward growth. In general, the downhole microseismic data showed that the stimulation treatment was successful in creating a fairly complex hydraulic fracture network for all stages, with microseismic recordings making flow paths visible governed by both paleo and present day stresses. Plots showing the speed of event generation, the cumulative seismic moment, and the event magnitude versus the event-to-receiver-distance identified interaction with pre-existing fault structures during Stages III and V.
Mohammad, N.A. and Miskimins, J.L.
A Comparison of Hydraulic-Fracture Modeling With Downhole and Surface Microseismic Data in a Stacked Fluvial Pay System, SPE Production & Operations, v. 27, No. 3. 2012
Abstract: This paper presents a study that combines and compares the results of hydraulic-fracture mapping and modeling using both downhole and surface microseismic arrays. There were three objectives for the study: developing detailed post-treatment models of hydraulic-fracturing treatments in the subject well, Well D1, which was monitored with downhole microseismic tools; developing detailed post-treatment models of the hydraulic-fracturing treatments in the subject well, Well S1, which was monitored with surface microseismic tools; and determining the match characteristics of the downhole and surface microseismic data to hydraulic-fracture models developed for both Wells D1 and S1.
Input data for this project were obtained from two wells in the Greater Natural Buttes field, Uinta basin, Utah. Ten fracture models were built using five stages each from the two subject wells, Wells D1 and S1, and detailed pressure matches were made. Comparisons of the match characteristics from the multiple inputs were then developed. The hydraulic-fracture-stimulation models were graphically integrated with the microseismic events using visualization software. This software allowed the final model-simulated fracture geometries to be plotted along with the microseismic events in 3D space, thus allowing the viewer to see a full integration of data in a stacked fluvial pay system.
Results from the integration process show good agreement in geometries and depth for most stages in the downhole-monitored well, whereas comparisons of surface microseismic-mapping measurements with the simulated fracture geometries yielded variable results. When combined with additional inputs such as geologic models, the integration methodology used in this project provides an excellent tool for hydraulic-fracture modeling and reservoir management in stacked pay systems.
Charoenwongsa, S., Kazemi, H., Fakcharoenphol, P., and Miskimins, J.L.
Simulation of Gel Filter Cake Formation, Gel Cleanup, and Post-Frac Well Performance in Hydraulically Fractured Gas Wells, SPE 150104, SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, February 15-1, 2012.
Abstract: Polymer and gel damage is a major issue in the cleanup of hydraulically fractured gas wells. This paper addresses this issue by using a gas-water flow model which simulates fracture propagation, gel filter cake formation as mechanical trapping of polymer molecules on the fracture face and filtrate transport into the adjacent matrix. The model accounts for polymer as a chemical component. This approach is different than treating polymer as a highly viscous gel phase, which is the common method in most literature. In our model, the gel filter cake thickness is calculated based experimental data. For leakoff, the model allows only the sheared polymer molecules, which are the major cause of formation permeability reduction, to cross the fracture face into the formation and adsorb on the matrix. Other features of the model include water blockage, non-Newtonian flow, non-Darcy flow, and proppant and reservoir compaction.
Morrill, J.C. and Miskimins, J.L.
Optimizing Hydraulic Fracture Spacing in Unconventional Shales, SPE 152595, SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, February 5-8, 2012.
Stress shadowing, where the stress field around an induced hydraulic fracture reorients from its far field directions by up to 90 degrees, is a major factor in designing and executing multiple hydraulic fractured, horizontal well completions. This is especially true as the number of hydraulic fracture increases for a given lateral length. Often the number of fracture stages is determined by well analogues without considering how stress shadows alter fracture properties. In this paper, the main objective is to determine what properties are most important in determining the minimum distance needed between hydraulic fractures to avoid stress interference. A finite element model of a horizontal wellbore with a transverse hydraulic fracture is constructed in order to perform numerical simulations of the stress around the fracture. The model is used to perform sensitivities on various mechanical properties to investigate how and why the stress field changed.
The simulation results show that the ratio of minimum to maximum horizontal stress is the most important parameter to know in order to determine the optimal fracture spacing. Changes in this ratio show a exponential change in fracture spacing, affecting spacing requirements by up to 81%. Poisson's ratio, Biot's parameter, and net fracture pressure were also important.
It can be concluded that fracture spacing cannot be determined by looking only at one or two properties. The fracture spacing must be determined by looking at all the important variables and identifying those that are most variable for the reservoir in question. The sensitivity of the "stress shadow" to various properties is an indication that obtaining good data is key to proper completion design.
Putthaworapoom, N., Miskimins, J.L. and Kazemi, H.
Numerical Investigation of Hydraulic Fracturing Process and Sensitivity to Reservoir Properties and Operation Variables, SPE 151060, SPE/EAGE European Unconventional Resources Conference and Exhibition, Vienna, Austria, March 20-22, 2012.
Abstract: This paper presents the results of a sensitivity study of numerous reservoir properties and operational control variables on hydraulic fracture effectiveness and production from a hydraulically fractured gas well using a reservoir simulation. The simulation is based on Wills et al's (2009) mathematical model for hydraulic fracture propagation and cleanup processes. A few modifications are introduced to Wills et al's work to improve the physics of the process and its computational efficiency.
The numerical simulation model considers a three-dimensional reservoir which can either be homogenous or heterogeneous. The created hydraulic fracture is assumed to have a constant height. The fracture extension with time and the corresponding leak-off are determined using two-phase flow equations both in the fracture and the surrounding matrix (i.e. dual-porosity system). The developed simulation model is validated by history matching with an actual field performance of a hydraulically fracture gas well which produces from the Codell formation in the Denver-Julesberg basin, Colorado. The history matched results are used as base case values for the sensitivity study. The sensitivity results show the creation of different leak-off profiles, the effectiveness of their corresponding cleanup processes and, most importantly, the productivity of different hydraulic fracturing treatments.
Results show that shut-in time between creation of the fracture and production has a large effect on created damage. They also show that capillary pressure differences between the reservoir matrix and the hydraulic fracture have an impact on production. Not only does this study provide significant insight to the phenomenon happen on the fracture face and inside the hydraulic fracturing stimulated reservoir, the reservoir simulator developed for this study can also be easily used as a tool for hydraulic fracturing design or even for post-stimulation evaluation.
Akrad, O., Miskimins, J.L. and Prasad, M. "The Effects of Fracturing Fluids on Shale Rock Mechanical Properties and Proppant Embedment", SPE 146658, SPE Annual Technical Conference and Exhibition, Denver, CO, October 31 ‐ November 2, 2011.
Abstract: The development of shale reservoirs has grown significantly in the past few decades, spurred by evolving technologies in horizontal drilling and hydraulic fracturing. The productivity of shale reservoirs is highly dependent on the design of the hydraulic fracturing treatment. In order to successfully design the treatment, a good understanding of the shale mechanical properties is necessary. Some mechanical properties, such as Young's modulus, can change after the rock has been exposed to the hydraulic fracturing fluids, causing weakening of the rock frame. The weakening of the rock has the potential to increase proppant embedment into the fracture face, resulting in reduced conductivity. This reduction in conductivity can, in turn, determine whether or not production of the reservoir will be economically feasible, as shale rocks are characterized by their ultra-low permeability, and conductivity between the reservoir and wellbore is critical. Thus, shale reservoirs are associated with economic risk; careful engineering practices; and a better understanding of how the mechanical properties of these rocks can change are crucial to reduce this risk. This paper discusses various laboratory tests conducted on shale samples from the Bakken, Barnett, Eagle Ford, and Haynesville formations in order to understand the changes in shale mechanical properties, as they are exposed to fracturing fluids, and how these changes can affect the proppant embedment process. Nanoindentation technology was used to determine changes of Young's modulus with the application of fracturing fluid over time and under high temperature (300 °F) as well as room temperature. Mineralogy, porosity, and total organic content were determined for the various samples to correlate them to any changes of mechanical properties. The last part of the experiments consisted of applying proppants to the shale samples under uniaxial stress and observing embedment using scanning acoustic microscope. The results of this study show that maximum reduction of Young's modulus occurs under high temperature and in samples containing high carbonate contents. This reduction in Young's modulus occurs in "soft" minerals as well as the "hard"rock-forming minerals. This reduction of modulus can cause the effective fracture conductivity to decrease significantly.
Tonnsen, R.R. and Miskimins, J.L.: "Simulation of Deep-Coalbed-Methane Permeability and Production Assuming Variable Pore-Volume Compressibility", SPE 138160, Journal of Canadian Petroleum Technology, v. 50, No. 5, May 2011.
Abstract: One of the horizons of interest for future unconventional-resource development is deep- (> 5,000 ft) coalbed-methane (CBM) production. Unfortunately, coal permeability is highly sensitive to changes in stress, leading to the belief of limited permeability in deep coals. However, this conclusion is generally based on the assumption of constant pore-volume (PV) compressibility of a coal's porosity/cleat system during changing stress conditions. Modelling the evolution of permeability within potential deep coal reservoirs is highly dependent on this assumption of constant or variable PV compressibility. This paper shows how this assumption affects modelled permeability changes and that permeability in deep coals may maintain much higher values during production than previously suggested. Using prior work and data, ideas are reorganized into an alternative view of deep-CBM permeability. The modelled compressibility and permeability results are then applied to the simulation of deep-CBM reservoirs to discover the practical difference of the compressibility assumption on a coal's simulated production. Simulations show significant difference in production based on the two assumptions. Application of the simulation results may provide a justification for exploration into deeper CBM reservoirs.
Wu, Y.S., Lai, B., Miskimins, J.L., Fakcharoenphol, P. and Di, Y.: "Analysis of Multiphase Non-Darcy Flow in Porous Media", Transport in Porous Media, 88:205-223, 2011.
Abstract: Recent laboratory studies and analyses have shown that the Barree and Conway model is able to describe the entire range of relationships between flow rate and potential gradient from low- to high-flow rates through porous media. A Buckley and Leverett type analytical solution is derived for non-Darcy displacement of immiscible fluids in porous media, in which non-Darcy flow is described using the Barree and Conway model. The comparison between Forchheimer and Barree and Conway non-Darcy models is discussed. We also present a general mathematical and numerical model for incorporating the Barree and Conway model in a general reservoir simulator to simulate multiphase non-Darcy flow in porous media. As an application example, we use the analytical solution to verity the numerical solution for and obtain some insight into one-dimensional non-Darcy displacement of two immiscible fluids with the Barree and Conway model. The results show how non-Darcy displacement is controlled not only by relative permeability, but also by non-Darcy coefficients, characteristic length, and injection rates. Overall, this study provides an analysis approach for modeling multiphase non-Darcy flow in reservoirs according to the Barree and Conway model.
Kazakov, N.Y. and Miskimins, J.L. “Application of Multivariate Statistical Analysis to Slickwater Fracturing Parameters in Unconventional Reservoir Systems”, SPE 140478, SPE Hydraulic Fracturing Technology Conference, The Woodlands, TX, January 24-26, 2011.
Abstract: Hydraulic fracturing is essential for economic production in tight gas and shale gas reservoirs due to their low permeability nature. Slickwater fracturing has been successfully performed in shales and tight gas reservoirs using low viscosity fluid, usually water, with friction reducers. Slickwater fracturing has the advantage of reducing formation damage and generally being less expensive than conventional gel. Predicting which slickwater parameters are important to successful production and which are less important has been an important but unanswered question. This research uses multivariate statistical methods to discover whether production from the Jonah Field, Wyoming, and the Barnett Shale, Texas, can be predicted using slickwater parameters and whether these parameters can provide insight into the design and analysis parameters of the slickwater treatments.
Factor, cluster, and multiple regression analysis show that production data from the sampled Barnett Shale and Jonah Field databases group separately from the slickwater parameters. Multiple regression, used to predict the EUR and the cumulative produced water from the slickwater parameters in the Barnett Shale, yielded best adjusted-R”’s of 34.7% and 25.3%, respectively. Multiple regression was also used to predict the EUR from the slickwater parameters in Jonah Field resulting in the best R” of 22.9%. Multiple regression analysis established a relationship with an adjusted R” of 93.0% between the fluid pumped and the fluid recovered from the Barnett Shale treatments. Multiple regression analysis also established that the amount of proppant used for Jonah Field hydraulic fracturing operations was calculated from the total fluid pumped and the net pay.
This research provides a methodology to use multivariate statistics to analyze stimulation treatments. Additionally, it opens opportunities for the analysis of different fields with more data using multivariate statistics and can aid in improving designs in an operator's current field or in understanding previous designs in a newly acquired field. Finally, it also demonstrates how “no information” can be valuable in cutting costs on commodities purchased to stimulate a well when no benefit is seen from those additional purchases.
Roundtree, R. and Miskimins, J.L. “Experimental Validation of Microseismic Emissions from a Controlled Hydraulic Fracture in a Synthetic Layered Medium”, SPE 140653, SPE Hydraulic Fracturing Technology Conference, The Woodlands, TX, January 24-26, 2011.
Abstract: Experiments using acoustic sensors to monitor stress changes and hydraulic fracture propagation in moderate size, layered rock samples are described in this paper. The results show that microseismic event locations closely follow the actual growth of the hydraulic fracture, especially near the well bore. More events are detected and localized near the acoustic transducers indicating that signal attenuation is significant. In the work performed, event location based on automated picking techniques is not yet accurate enough to make diagnostic conclusions about fracture propagation near and through the different layered materials. Advanced processing techniques being developed in industry may well have the additional resolution necessary to focus some of these more subtle events at the laboratory scale. The conducted experiments indicated that controlling hydraulic fracture growth in laboratory-sized samples is difficult in small and moderate sized samples, and dynamically changing flap jack pressures, and injection rates and pressures is mandatory to slow the fracture growth for proper analysis once it has initiated. A key outcome of the work is the recognition that rocks emit substantial amounts of acoustic energy when stressed at incremental pressure levels of only a few psi, which corroborates a model of rocks as being meta-stable materials and explains frequently observed field phenomena. Further advancements in the use of acoustic monitoring at the laboratory scale are warranted and significant breakthroughs are possible for non-invasive investigations of solid and layered materials under stress.
Wang, Y. and Miskimins, J.L. “Experimental Investigations of Hydraulic Fracture Growth Complexity in Slickwater Fracturing Treatments”, SPE 137515, SPE Tight Gas Completions Conference, San Antonio, TX, November 2-3, 2010.
Abstract: Friction-reduced water, i.e. “slickwater”, fracturing was first introduced in the late 1950’s. It fell out of favor with the advent of gelled fluids systems; however, slickwater fracturing has seen a large resurgence with the increasing development of unconventional reservoirs. Slickwater fracturing has once again become popular for stimulating these tight gas sand and shale gas systems. The main advantages of slickwater fracturing treatments are the economics and the adequate conductivity they can place in low permeability reservoirs. Additionally, it is possible for slickwater treatments to create long, complex fractures which enhance the well’s “stimulated reservoir volume” (Mayerhofer et al. 2008). Most treatments use large quantities of water pumped at very high rates. However, the relationship between complexity and rate is not well understood. This paper presents an experimental study on slickwater fracturing performed by using a unique testing system, which was developed to study slickwater fracturing treatments at a laboratory scale. The intent was to study the effects of rate on the complexity of growth in the reservoir. Laboratory results were scaled to field conditions by applying scaling law analysis. The scaled results suggest that for field water fracturing treatment design in shale reservoirs, large injection volumes result in large SRA (“stimulated reservoir area”, a comparison term to “stimulated reservoir volume”) which should result in increased production. The optimal injection rate can vary for different reservoir conditions. At low injection rates, reservoir complexity does not seem to affect fracture network growth. At the same time, different rock types will also affect the fracture network growth in water fracturing processes. Quantitatively, the laboratory results agree well with the conclusions drawn from actual field applications.
Charoenwongsa, S., Kazemi, H., Miskimins, J.L. and Fakcharoenphol, P. “A Fully-Coupled Geomechanics and Flow Model for Hydraulic Fracturing and Reservoir Engineering Applications”, SPE 137497, Canadian Unconventional Resources & International Petroleum Conference, Calgary, Alberta, Canada, October 19-21, 2010.
Abstract: In this paper we present a practical fully-coupled geomechanics and flow model for application to hydraulic fracturing, especially in tight gas reservoirs, and other reservoir engineering applications. The mathematical formulation is consistent with conventional finite-difference reservoir simulation code to include any number of phases, components and even thermal problems. In addition, the propagation of strain displacement front as a wave, and the relevant changes in stress with time, can be tracked through the wave component of the geomechanics equations. We show the development of an efficient finite-difference computer code for rock deformation including thermal and wave propagation effects. The numerical approach chosen uses two different control volumes—one for fluid and heat flow and another one for rock deformation. The ultimate goal is to provide a tool to assess the effect of pore pressure, cooling or heating the reservoir, and propagation of a strain wave resulting from hydraulic fracturing on the reservoir rock frame. This information is crucial for determining the effect of shear stress on opening or closing of natural fractures during creation of hydraulic fractures, and changes in shear- and compressional- wave velocities for seismic imaging purposes. A specific application of the product of this research is to simulate fracture propagation, gel cleanup and water block issues in hydraulic fracturing. The modeling results indicate significant change in shear stresses near hydraulic fractures as a result of hydraulic fracture face displacement perpendicular to the fracture face and not as much from pore pressure change because the filtrate does not travel very far into the reservoir. Similarly, temperature change effects are also very significant in changing stress distribution.
Tonnsen, R.R. and Miskimins, J.L. “Simulation of Deep Coalbed Methane Permeability and Production Assuming Variable Pore Volume Compressibility”, SPE 138160, Canadian Unconventional Resources & International Petroleum Conference, Calgary, Alberta, Canada, October 19-21, 2010.
Abstract: One of the horizons of interest for future unconventional resource development is deep (greater than ~5,000 ft) coalbed methane (CBM) production. Unfortunately, coal permeability is highly sensitive to changes in stress leading to the belief of limited permeability in deep coals. However, this conclusion is generally based on the assumption of constant pore volume compressibility of a coal’s porosity/cleat system during changing stress conditions. Modeling the evolution of permeability within potential deep coal reservoirs is highly dependent on this assumption of constant or variable pore volume compressibility. This paper shows how this assumption affects modeled permeability changes and that permeability in deep coals may maintain much higher values during production than previously suggested. Utilizing prior work and data, ideas are reorganized into an alternative view of deep CBM permeability. The modeled compressibility and permeability results are then applied to the simulation of deep CBM reservoirs to discover the practical difference of the compressibility assumption on a coal’s simulated production. Simulations show significant difference in production based on the two assumptions. Application of the simulation results may provide a justification for exploration into deeper CBM reservoirs.
Singh, I. and Miskimins, J.L. “A Numerical Study of the Effects of Packer-Induced Stresses and Stress Shadowing on Fracture Initiation and Stimulation of Horizontal Wells”, SPE 136856, Canadian Unconventional Resources & International Petroleum Conference, Calgary, Alberta, Canada, October 19-21, 2010.
Abstract: “Stress shadowing”, where the creation of hydraulic fractures affect the stresses in certain parts of the reservoir, has the dual effect of assisting and hampering the generation of hydraulic fracture stimulation in horizontal wells. In this paper, the stress contrast and pressure profiles around the near wellbore regions of a horizontal wellbore with the presence of packers and hydraulic fractures are investigated. This was accomplished by using a finite element software package where the numerical results of the behavior of the stress envelopes and stress shadowing phenomena could be evaluated and different sensitivities analyzed. From the results obtained, it is concluded that packers with higher pressure generation allow for easier fracture initiation as compared to packers with lower pressure generation. Additionally, modeling indicates that the weakest point for fracture initiation in a wellbore with a packer is at the ends of the packer. When two packers, with differing pressure generations, are placed in the wellbore, fracture initiation will occur near the packer with the higher pressure generation. Finally, it can be concluded that in areas of high stress concentration, the ability to generate hydraulic fractures is reduced as compared to areas of low stress concentrations.
Lai, B. and Miskimins, J.L. “A New Technique for Accurately Measuring Two-Phase Relative Permeability Under Non-Darcy Flow Conditions”, SPE 134501, SPE Annual Technical Conference and Exhibition, Florence, Italy, September 19-22, 2010.
Abstract: A new steady-state technique for determining gas-water relative permeability curves for proppant packs under high confining stress conditions is presented. In this technique, a time domain reflectometry (TDR) device that can measure the saturation inside the proppant pack instantly and efficiently is introduced. De-aired water and nitrogen gas are simultaneously injected into the proppant pack under a desired confining stress, and the pressure drop and saturation are measured when steady-state conditions are reached. Two different proppant mesh sizes, 12/18 and 20/40, have been tested under four confining stresses ranging from 1000-4000 psi with repeatable and accurate results. In the majority of published techniques, two-phase relative permeability curves are determined by using Darcy’s law. This might be accurate enough for low permeability formations under low flow rate conditions, but in high permeability fracture proppant packs, the non-Darcy flow effects, or inertial effects, cannot be neglected. Thus relative permeability curves neglecting inertial effects may lead to inaccurate predictions. In this paper, three flow models: the classic generalized Darcy ‘s Law, the generalized Forchheimer flow model, and the two-phase Barree and Conway model (Barree and Conway, 2007) are employed to calculated and compare the relative permeability results. The experimental results show that the non-Darcy flow effects on gas relative permeability are higher than those calculated using Darcy’s Law. In addition, the various confining stress effects on water and gas relative permeability curves are also presented. A significant decrease in gas relative permeability and minor effects on water relative permeability occur as the confining stress increases. These results help to further understand the effects of multiphase flow in porous media.
Mohammad, N.A. and Miskimins, J.L. “A Comparison of Hydraulic Fracture Modeling With Downhole and Surface Microseismic Data in a Stacked Fluvial Pay System”, SPE 134490, SPE Annual Technical Conference and Exhibition, Florence, Italy, September 19-22, 2010.
Abstract: This paper presents a study that combines and compares the results of hydraulic fracture mapping and modeling using both downhole and surface microseismic arrays. There were three objectives for the study including 1) developing detailed posttreatment models of hydraulic fracturing treatments in the subject well, Well D1, which was monitored with downhole microseismic tools; 2) developing detailed post-treatment models of the hydraulic fracturing treatments in the subject well, Well S1, which was monitored with surface microseismic tools; and 3) determining the match characteristics of the downhole and surface microseismic data to hydraulic fracture models developed for both Wells D1 and S1. Input data for this project were obtained from two wells in the Greater Natural Buttes field, Uinta basin, Utah. Ten fracture models were built using five stages each from the two subject wells, Wells D1 and S1, and detailed pressure matches were made. Comparisons of the match characteristics from the multiple inputs were then developed. The hydraulic fracture stimulation models were graphically integrated with the microseismic events using visualization software. This software allowed the final model-simulated fracture geometries to be plotted along with the microseismic events in three-dimensional space thus allowing the viewer to see a full integration of data in a stacked fluvial pay system. Results from the integration process show good agreement in geometries and depth for most stages in the downholemonitored well, whereas comparisons of surface microseismic mapping measurements with the simulated fracture geometries yielded variable results. When combined with additional inputs, such as geologic models, the integration methodology used in this project provides an excellent tool for hydraulic fracture modeling and reservoir management in stacked pay systems.
Alqahtani, N.B. and Miskimins, J.L. “3D Finite Element Modeling of Laboratory Hydraulic Fracture Experiments”, SPE 130556, SPE EUROPEC/EAGE Annual Conference and Exhibition, Barcelona, Spain, June 14-17, 2010.
Abstract: Laboratory experiments are an excellent way to visualize and improve our understanding of the hydraulic fracturing process. However, in order to truly apply the results of laboratory work to the field, an understanding of what artificial conditions are being created during the laboratory process must also be developed. This paper describes 3D finite element modeling and associated results using actual laboratory block tests as a basis. These models consisted of seven basic block systems, including a single layer system, with and without a wellbore, as a control case; a three-layer model with and without a wellbore; and a seven layer system, with a wellbore, without a wellbore, and with a cased wellbore. These seven systems were based on actual triaxial hydraulic fracturing experiments that were performed on mid-sized blocks (11 X 11 X 15 in) consisting of the same single, three, and seven-layers. The fracture growth patterns in the actual laboratory tests were extremely complex, not at all like the planar fractures dictated by hydraulic fracturing theory. The intent of the modeling was to 1) determine the spatial stress contrasts being created by the material property contrasts of the layered systems in the triaxial system and 2) determine if the complex fracture growth could be accounted for by these modeled contrasts. Results were also used to determine the potential for shearing across the layered systems. A commercial, modeling software, capable of numerically determining the 3D stress distributions in the various porous media, was used. Numerical results were validated with analytical calculations. The results of the modeling provide insight into the time-dependent application of stresses in a laboratory setting. It helped to explain the complex fracture growth in the actual experiments and gave some insight into the conditions that would cause vertical or horizontal fracture growth in a layered system of different material properties. The modeling also documented the creation of shear stresses which accounted for some fracture path deviation. The results of this paper aid in understanding the mechanisms of complex hydraulic fracture growth in reservoirs settings. Additionally, insight into the shear and tensile fracture mechanisms that generate acoustic events was gained.
Wills, H.A., Miskimins, J.L. and Kazemi, H. “Coupled 3D Numerical Investigation of Hydraulic Fracture Cleanup for Both Slickwater and Gelled Fluids”, SPE 124327, SPE Annual Technical Conference and Exhibition, New Orleans, LA, October 4-7.
Abstract: This paper presents the results a systematic study on fracture cleanup using a two-phase 3-D numerical simulation model specifically developed for this purpose. Previous simulation models consider that the hydraulic fracture is already created and the state of pressure and water saturation around the created fracture (invasion profile) could be replicated by a controlled waterflood. For our work we adopted a different perspective where the invasion profile around the fracture is directly linked to the leakoff of fracture fluid during creation. In other words, a fracture growth model have been linked directly to a finite difference simulator. All simulations are performed in three stages. First, a fracture creation period is applied, second is a shut-in period and finally, a flowback period. In all these three stages the link to/from the reservoir is through source terms, which varies according to the simulation stage. During fracture creation and shut-in, the created fracture is considered one layer and acts as a boundary condition for the reservoir; then for flow back the fracture is discretized on the z direction to enhance the resolution in the fracture medium. Relative permeability curves for the fracture medium and reservoir medium, are based on real laboratory data. Cases were run for both slickwater and gel-based fracturing fluids. A base case analysis based on a low permeability sandstone reservoir is shown, followed by sensitivities that include: applied pressure drawdown during production; shut-in time between fracture creation and production; interfacial tension between the gas and aqueous phases; placement of perforations across the entire producing interval versus the upper portion of the reservoir; and different gel concentrations. Results show the pressure drawdown, shut-in times, and perforation placement all have significant effect on fracture face damage and clean-up potential.
Wu, Y.S., Lai, B., and Miskimins, J.L. “Simulation of Multiphase Non Darcy Flow in Porous and Fracture Media”, SPE 122612, SPE Annual Technical Conference and Exhibition, New Orleans, LA, October 4-7.
Abstract: A Buckley and Leverett type analytical solution is derived for non-Darcy displacement of immiscible fluids in porous media, in which non-Darcy flow is described using the general model proposed by Barree and Conway. Recent laboratory studies and analyses have shown that the Barree and Conway model is able to describe the entire range of relationships between rate and potential gradient from low- to high-flow rates through porous media, including those in transitional zones. We also present a general mathematical and numerical model for incorporating the Barree and Conway model to simulate multiphase non-Darcy flow in porous and fractured media, while flow in fractured rock is handled using a general multi-continuum approach. The numerical solution of the proposed multiphase, non-Darcy flow model is based on a discretization scheme using an unstructured grid with regular or irregular meshes for multi-dimensional simulation. The final discretized nonlinear equations are handled fully implicitly with the Newton iteration. As an application example, we use the analytical solution to verify the numerical solution for and to obtain some insight into one-dimensional non-Darcy displacement of two immiscible fluids according to the Barree and Conway model. Overall, this work provides an improved platform for modeling multiphase non-Darcy flow in oil and gas reservoirs, including complex fractured systems such as shale gas reservoirs.
Green, C.A., Barree, R.D., and Miskimins, J.L.: "Hydraulic-Fracture-Model Sensitivity Analysis of a Massively Stacked, Lenticular, Tight Gas Reservoir", SPE 106270-PA, SPE Production & Operations Journal, Volume 24, Number 1, February 2009.
Abstract: This paper assesses critically the importance of various inputs that are used for a common method to develop a simulator model of hydraulic fractures (HFs) in geologically complex, fluvial, tight gas reservoirs. A planar 3D fracture simulator is used with a fully coupled fluid-/solids-transport simulator. The geomechanical rock properties from logs (Young’s modulus, Poisson’s ratio, and Biot’s constant) and diagnostic minifracture injection tests of individual sandstone reservoirs were investigated to assess their importance in developing a valid stress model.This paper describes the investigations by use of a model matched previously with both net surface pressure and microseismic/tiltmeter data. From these results, it is possible to obtain a better understanding of how fractures grow and interact with complex fluvial reservoirs, allowing operators to optimize field-well performance and completion methods better in these geologic settings. Additionally, the minimum critical data recommendations necessary to develop such a model have been identified and will aid operators in developing their data-acquisition programs. Although developed in the Rocky Mountain region, the presented technique can be extended to other similar geologically complex reservoirs worldwide.
Lai, B., Miskimins, J.L. and Wu, Y.S. “Non-Darcy Porous Media Flow According to the Barree and Conway Model: Laboratory and Numerical Modeling Studies”, SPE 122611, SPE Rocky Mountain Petroleum Technology Conference, Denver, CO, April 14-16.
Abstract: This paper presents supplementary laboratory data to show that a non-Darcy flow model, proposed by Barree and Conway in 2004, is capable of overcoming the limitation with the Forchheimer non-Darcy equation in high flow rates while describing the entire range of relationships between rate and potential gradient from low- to high-flow rates through proppant packs using a single equation or model. To supplement these laboratory findings, a numerical model is developed that incorporates the Barree and Conway model into a general-purpose reservoir simulator for modeling single-phase non-Darcy flow in porous and fractured media. In the numerical approach, flow through fractured rock is handled using a general multi-continuum approach, applicable to both continuum and discrete fracture conceptual models. The numerical formulation is based on a discretization using an unstructured grid of regular or irregular meshes, followed by time discretization carried out with a backward, first-order, finite-difference method. The final discrete nonlinear equations are handled fully implicitly, using Newton iteration. Additionally, an analytical solution under steady-state linear flow condition is derived and used to verify numerical simulation results for the steady-state linear flow case. The numerical model is applied to evaluate the transient flow behavior at an injection well for non-Darcy flow according to the Barree and Conway model. Results show that the parameter of characteristic length, τ, is more sensitive than other parameters; while the impact of the minimum permeability plateau is shown only at extremely large flow rates or pressure gradients. The proposed numerical modeling approach is suitable for modeling various types of multi-dimensional non-Darcy flow through porous and fractured heterogeneous reservoirs.
Benedict, D.S. and Miskimins, J.L. “Analysis of Reserve Recovery Potential from Hydraulic Fracture Reorientation in Tight Gas Lenticular Reservoirs”, SPE 119355, SPE Hydraulic Fracturing Technology Conference, The Woodlands, TX, Jan. 19-21.
Abstract: The basic concept of hydraulic fracture reorientation involves inducing a second artificial fracture into the producing zone, with this secondary fracture propagating in a different direction from the original. For reorientation to occur, the near wellbore stress has to have altered in orientation from the time the original fracture was created. To investigate the effects of this action on reserve recoveries in tight gas lenticular reservoirs, a series of simulations were run in a reservoir modeling program where orientation was assumed to occur at various given angles. The reservoir and fracture properties that were manipulated in order to run the model under different scenarios included the following: fracture orientation, fracture half-length, fracture conductivity, reservoir area, permeability anisotropy, and geologic aspect ratios. For each scenario, production of the field was then simulated over a period of time to study sensitivities of the parameters.
The research presented in this paper led to the following main conclusions: 1) refracture reorientation can be effectively studied using a reservoir simulator through manipulation of the fracture and reservoir parameters over time; 2) incremental gains in production and pressure responses were observed with the variance of these various reservoir and fracture properties that were consistent with the possibility of hydraulic fracture reorientation; and 3) results indicate that even assuming refracture reorientation is possible, it would not be economical under typical conditions in most tight gas lenticular reservoirs due to their limited volumes.
Athavale, A. and Miskimins, J.L.: “Laboratory Hydraulic Fracturing Tests on Small Homogeneous and Laminated Blocks”, paper ARMA 08-67 presented at the American Rock Mechanics Associated 2008 Symposium, San Francisco, CA, June 29 – July 2, 2008.
Abstract: This paper describes the design and experimental observations for laboratory-scaled hydraulic fracturing treatments of two 11” x 11” x 15” (height) artificially prepared blocks, a laminated composite block and a homogeneous cement block. Hydraulic fracturing tests performed on these small blocks showed that planar bi-winged penny-shaped fracture growth occurred in the homogeneous cement block, while complex fracture growth (wandering fracture paths, fracture branching, etc.) with possible shear slippage along an un-bonded interface occurred in the laminated block. Complex fracture growth is thought to be occurring in the laminated block primarily because of the material property contrasts between different layers and the stress contrasts set up inside the block. Such phenomena are known to transpire in the field for laminated reservoirs and have been reported in the literature. A significant outcome of this work was the successful combination of two different scaling analysis techniques. The combination of these scaling analyses along with the use of a high viscosity fracturing fluid allowed field-like quasi-static fracture growth to be achieved in a laboratory setting. This type of controlled fracture growth in the laboratory is unique and allowed detailed observations to be made.
Green, C.A., Barree, R.D., and Miskimins, J.L.: "Hydraulic Fracture Model Sensitivity Analysis of a Massively Stacked, Lenticular, Tight Gas Reservoir", paper SPE 106270 presented at SPE Production and Operations Symposium, Oklahoma City, OK, Mar. 31-Apr. 3, 2007. Also presented at the SPE Rocky Mountain Oil & Gas Technology Symposium, Denver, CO, Apr. 16-18, 2007.
Abstract: This paper critically assesses the importance of various inputs that are used for a common methodology to develop a simulator model of hydraulic fractures in geologically complex, fluvial, tight gas reservoirs. A planar 3-D fracture simulator is used with a fully coupled fluid/solid transport simulator. The geomechanical rock properties from logs (Young's modulus, Poisson's ratio and Biot's constant) and diagnostic mini-frac injection tests of individual sandstone reservoirs were investigated to assess their importance in developing a valid stress model.
The work describes the investigations using a model previously matched using both net surface pressure and microseismic/tiltmeter data. From these results it is possible to get a better understanding of how fracs grow and interact with complex fluvial reservoirs, allowing operators to better optimize field well performance and completion methods in these geologic settings. Additionally, the minimum critical data recommendations necessary to develop such a model have been identified and will aid operators in developing their data acquisition programs. Although developed in the Rocky Mountain region, the presented technique can be extrapolated to other similar geologically complex reservoirs world-wide.
Woodworth, T.R. and Miskimins, J.L.: "Extrapolation of Laboratory Proppant Placement Behavior to the Field in Slickwater Fracturing Applications", paper SPE 106089 presented at SPE Hydraulic Fracturing Technology Conference, College Station, TX, Jan. 29-31, 2007.
Abstract: Low-viscosity slickwater treatments are a popular hydraulic fracturing technique in low permeability reservoirs. Slickwater treatments can provide adequate conductivity in tight gas sand operations at comparatively low costs, and wells treated with low-viscosity slickwater often produce better results than those treated with cross-linked fluids in low permeability situations. Theoretically, proppant transport is poor in low-viscosity slickwater type fluids. Improving the understanding of proppant transport capabilities of slickwater would be beneficial to many operators if the cost or performance were not endangered. Improved proppant transport would result in longer propped fracture half-lengths and more favorable conductivity.
Laboratory experiments performed by STIM-LAB, Inc.'s Proppant Consortium show proppant falls from suspension and builds a proppant mound before any form of proppant transport takes place. Clean fluid stages pumped between sand-laden stages were shown to erode proppant from the proppant mound. These results formed the basis for the development of power and bi-power laws to describe the transport. These laws and the results of the laboratory experiments were used to perform sensitivity analysis to determine the relative effects of fluid viscosity, fluid density, pump rate, proppant diameter, proppant density, proppant concentration, and fracture width on slickwater treatments in the field.
Using the power and bi-power laws, the resulting sensitivity analysis, and the laboratory observations, experimental slickwater schedules were designed and field tested. A total of five experimental slickwater fracturing treatments were performed. Production data from each experimental slickwater treatment and well were compared to offset data to determine any possible effects from improved proppant transport. Production results from the field trials, including both initial production (IP) rates and early cumulative production totals, indicate significant improvement when compared to offset wells.
Green, C.A., Barree, R.D., and Miskimins, J.L.: "Development of a Methodology for Hydraulic Fracturing Models in Tight, Massively Stacked, Lenticular Reservoirs", paper SPE 106269 presented at SPE Hydraulic Fracturing Technology Conference, College Station, TX, Jan. 29-31, 2007.
Abstract: This paper describes and critically assesses a common methodology currently used to model hydraulic fractures in geologically complex, fluvial, tight gas reservoirs. A planar 3-D fracture simulator is used with a fully coupled fluid/solid transport simulator. The model incorporates a unique data set from the Piceance basin, Colorado, which produces hydrocarbons from the Cretaceous-age Mesaverde formation. Initially, vertical variations in geo-mechanical rock properties (Young's modulus, Poisson's ratio and Biot's constant) were calculated from well logs. The results were then compared with previous work undertaken on the Mesaverde formation and carried out at the DOE/GRI MWX site. From this analysis, specific correlations were developed for rock properties derived from well logs on a foot-by-foot basis to be used in the hydraulic fracture model. Diagnostic mini-frac injection tests of individual sandstone reservoirs were used to confirm model inputs and develop a valid stress model.
Previous attempts to model hydraulic fracture growth in the Mesaverde have been hampered by a lack of detailed input data sets and the inability to accurately determine horizontal rock property variations. This paper outlines a method which uses micro-seismic/tiltmeter data to constrain and verify the model inputs. The resulting frac model is shown to have not only matched the fracture containment but also pressure matched the actual net surface pressure data in this extremely geologically complex area. From these results it is possible to get a better understanding of how fracs grow and interact with complex fluvial reservoirs, allowing operators to better optimize field well performance and completion methods in these geologic settings. Additionally, the minimum critical data required to develop such a model has been identified and will aid operators in developing their data acquisition programs. Although developed in the Rocky Mountain region, the presented technique can be extrapolated to other similar geologically complex reservoirs world-wide.
Casas, L.A., Miskimins, J.L., Black, A.D., and Green, S.J.: "Laboratory Hydraulic Fracturing Test on a Rock With Artificial Discontinuities", paper SPE 103617 presented at SPE Annual Technical Conference and Exhibition, San Antonio, TX, Sept. 24-27, 2006.
Abstract: The design and subsequent results of a hydraulic fracturing test performed on a large block of high modulus and low permeability rock (Colton sandstone) are presented. The focus of this experimental study was to assess the effects of discontinuities on hydraulic fracture growth. A high viscosity fluid was used in order to provide fracture growth similar to actual field conditions. Fracture growth and its internal fluid pressure were monitored by fixed probes placed normal to the expected plane of propagation. Fracture tip arrivals were captured by the fixed pressure probes and showed a distinct fluid lag region (i.e., a lower fluid pressure region close to the fracture tip). The controlled laboratory experiments showed planar fracture propagation trends as expected from three-dimensional modeling.
Bai, M., Green, S., Casas, L.A., and Miskimins, J.L.: "3-D Simulation of Large Scale Hydraulic Fracturing Tests", paper ARMA/USRMS 06-959 presented at the American Rock Mechanics Association GoldenRocks Conference, Golden, CO, June 17-21, 2006.
Abstract: With proper scaling, the large scale laboratory hydraulic fracturing tests can be an effective way to provide parametric justification for the fracturing design. The tests can also be used to validate hydraulic fracturing models, considering the significant cost reduction via the laboratory tests in lieu of the field tests. Similarly, numerical simulation may act as a "virtual test" to imitate the laboratory test for achieving improved flexibilities at further reduced cost. In this paper, the result of numerical simulation of the hydraulic fracturing using 3-D model is presented and compared with the measurements from the large scale laboratory hydraulic fracturing tests. The excellent match between the numerical simulation and the experimental tests validates both processes. Further pressure analysis offers an in-depth study on transient fracture propagation and contrasting pressure responses based on the relative positions from the perforation, as well as offers certain validation for the zone of fluid lag near the fracture tip area.
Casas, L.A., Miskimins, J.L., Black, A., and Green, S.: "Hydraulic Fracturing Laboratory Test on a Rock with Artificial Discontinuities", paper ARMA/USRMS 06-917 presented at the American Rock Mechanics Association GoldenRocks Conference, Golden, CO, June 17-21, 2006.
Abstract: The design and subsequent results of a hydraulic fracturing test performed on a large block of high modulus and low permeability rock (Colton sandstone) are presented. The focus of this experimental study was to assess the effects of discontinuities on hydraulic fracture growth. A high viscosity (586 Pa.s) fluid was used in order to provide fracture growth similar to actual field conditions. Fracture growth and its internal fluid pressure were monitored by fixed probes placed normal to the expected plane of propagation. Fracture tip arrivals were captured by the fixed pressure probes and showed a distinct fluid lag region (i.e. a lower fluid pressure region close to the fracture tip). The controlled laboratory experiments showed planar fracture propagation trends as expected from three-dimensional modeling.
Miskimins, J.L., Lopez, H. E., and Barree, R.D.: "Non-Darcy Flow in Hydraulic Fractures: Does It Really Matter?", paper SPE 96389 presented at SPE Annual Technical Conference and Exhibition, Dallas, TX, Oct. 9-12, 2005. (summary publication in March 2006 SPE Journal of Petroleum Technology).
Abstract - In recent years, non-Darcy flow has seen a significant increase in interest in the petroleum industry, especially in flow in fractures-both artificial and natural. In hydraulic fracture stimulation, non-Darcy flow can have a major impact on the reduction of a propped half-length to a considerably shorter "effective" half-length, thus lowering the well's productive capability and overall reserve recovery. These non-Darcy flow effects in propped fractures have been typically associated with high flow rates in both oil and gas wells.
This paper shows that non-Darcy flow effects have an impact on the performance of a hydraulically fractured well even at low flow rates. Although not as drastic as the effects on high flow rate wells, reductions in flow capacity of 5-30% can be realized in low rate wells. Such reductions are due solely to non-Darcy effects. When combined with other concerns, such as multiphase flow, the production reduction effects are even greater.
Development of a simple spreadsheet is provided to aid engineers in assessing the impact non-Darcy flow may have in a given situation. The spreadsheet is not intended to replace more in-depth investigation of non-Darcy flow effects but instead provides a conduit to assess the sensitivity of certain parameters in a hydraulic fracture stimulation situation.
For comparison purposes, results of the loss in long-term dynamic conductivity on well performance and cumulative gas recovery over time in low permeability reservoirs are also presented. These calculations were performed using dynamic conductivity loss calculations coupled with a transient gas reservoir simulator. These results showed that for the cases examined, non-Darcy effects could reduce cumulative gas production by up to 18.1% over a ten-year period.