Alfred Daniel Hill

Laboratory Measurement of Hydraulic Fracture Conductivities in the Barnett Shale

Horizontal wells that intersect multistage transverse fractures created by low-viscosity fracturing fluid with low proppant loadings are the key to revitalizing production from the Mississippian Barnett shale in the Fort Worth basin in Texas. However, direct laboratory measurements of both naturaland induced-fracture conductivities under realistic experimental-design conditions are needed for reliable well-performance analysis and fracture-design optimization. In this work, a series of experiments was conducted to measure the conductivity of unpropped natural fractures, propped natural fractures, unpropped induced fractures, and propped induced fractures with a modified American Petroleum Institute (API) conductivity cell at room temperature. Fractures were induced along the natural bedding planes, preserving fracture-surface asperities. Natural-fracture infill was taken into consideration during conductivity measurements. Proppants of various sizes were placed manually between rough fracture surfaces at realistic concentrations. The two sides of the rough fractures either were aligned or were displaced with a 0.1-in. offset. After pressure testing on the system integrity, nitrogen was flowed through the proppant pack or unpropped fracture to measure the conductivity. Results from 88 experiments show that the conductivity of hydraulic fractures in shale can be measured accurately in a laboratory with appropriate experimental procedures and good control over experimental errors. It is proved that unpropped, aligned fractures can provide a conductive path after removal of free particles and debris because of the brittleness and lamination of shale. Moreover, poorly cemented natural fractures and unpropped displaced fractures can create conductivities of up to 0.5 md-ft at formation-closure stress, which is one to two orders of magnitude greater than the conductivity provided by cemented natural fractures and unpropped aligned fractures. This study shows that propped-fracture conductivity increases with larger proppant size and higher proppant concentration. Longer-term fracture-conductivity measurements indicate that, within 20 hours, the fracture conductivity could be reduced by as much as 20%.

A New Correlation of Acid Fracture Conductivity Subject to Closure Stress

This paper (SPE 140402) was accepted for presentation at the SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, USA, 24–26 January 2011, and revised for publication. Original manuscript received for review 18 November 2010. Revised paper received for review 26 August 2011. Paper peer approved 31 August 2011. Summary The conductivity of an acid-etched fracture depends strongly on void spaces and channels along the fracture resulting from uneven acid etching of the fracture walls. In this study, we modeled deformation of the rough fracture surfaces acidized in heterogeneous formations based on synthetic permeability distributions and developed a new correlation to calculate the acid-etched fracture conductivity. In our previous work, we modeled the dissolution of the fracture surfaces in formations having small-scale heterogeneities in permeability. The characterization of the correlated permeability fields of rock includes the average permeability, normalized correlation lengths in both horizontal and vertical directions, and normalized standard deviation. These statistical parameters have a significant influence on the fracture-etching profiles obtained from the model. Beginning with this fracture-width distribution, we have modeled the deformation of the fracture surfaces as closure stress is applied to the fracture. The elastic properties of the rock, such as Young’s modulus and Poisson’s ratio, have effects on the size of the spaces remaining open after fracture closure. After the model yields the width profile under closure stress, the overall conductivity of the fracture is then obtained by numerically modeling the flow through this heterogeneous system. In this paper, we introduce our models and investigate the effects of permeability and mineralogy distributions and rock elastic properties on the overall conductivity of an acid-etched fracture. A new acid-fracture conductivity correlation is developed on the basis of many numerical experiments.

A New Correlation of Acid-Fracture Conductivity Subject to Closure Stress

This paper (SPE 140402) was accepted for presentation at the SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, USA, 24–26 January 2011, and revised for publication. Original manuscript received for review 18 November 2010. Revised paper received for review 26 August 2011. Paper peer approved 31 August 2011. Summary The conductivity of an acid-etched fracture depends strongly on void spaces and channels along the fracture resulting from uneven acid etching of the fracture walls. In this study, we modeled deformation of the rough fracture surfaces acidized in heterogeneous formations based on synthetic permeability distributions and developed a new correlation to calculate the acid-etched fracture conductivity. In our previous work, we modeled the dissolution of the fracture surfaces in formations having small-scale heterogeneities in permeability. The characterization of the correlated permeability fields of rock includes the average permeability, normalized correlation lengths in both horizontal and vertical directions, and normalized standard deviation. These statistical parameters have a significant influence on the fracture-etching profiles obtained from the model. Beginning with this fracture-width distribution, we have modeled the deformation of the fracture surfaces as closure stress is applied to the fracture. The elastic properties of the rock, such as Young’s modulus and Poisson’s ratio, have effects on the size of the spaces remaining open after fracture closure. After the model yields the width profile under closure stress, the overall conductivity of the fracture is then obtained by numerically modeling the flow through this heterogeneous system. In this paper, we introduce our models and investigate the effects of permeability and mineralogy distributions and rock elastic properties on the overall conductivity of an acid-etched fracture. A new acid-fracture conductivity correlation is developed on the basis of many numerical experiments.

Interpretation of Temperature and Pressure Profiles Measured in Multilateral Wells Equipped with Intelligent Completions

SPE 94097 Interpretation of Temperature and Pressure Profiles Measured in Multilateral Wells Equipped with Intelligent Completions K. Yoshioka D. Zhu and A.D. Hill Texas A&M U. and L.W. Lake U. of Texas at Austin Copyright 2005 Society of Petroleum Engineers This paper was prepared for presentation at the SPE Europec/EAGE Annual Conference held in Madrid Spain 13-16 June 2005. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper as presented have not been reviewed by the Society of Petroleum Engineers and are

Fine-Scale Simulation of Sandstone Acidizing

We have developed a fine-scale model of the sandstone core acid flooding process by solving acid and mineral balance equations for a fully three-dimensional flow field that changed as acidizing proceeded. The initial porosity and mineralogy field could be generated in a correlated manner in three dimensions; thus, a laminated sandstone could he simulated. The model has been used to simulate sandstone acidizing coreflood conditions, with a I in. diam by 2 in. long core represented by 8000 grid blocks, each having different initial properties. Results from this model show that the presence of small-scale heterogeneities in a sandstone has a dramatic impact on the acidizing process. Flow field heterogeneities cause acid to penetrate much farther into the formation than would occur if the rock were homogeneous, as is assumed by standard models. When the porosity was randomly distributed (sampled from a nominal distribution), the acid penetrated up to twice as fast as in the homogeneous case. When the porosity field is highly correlated in the axial direction, which represents a laminated structure, acid penetrates very rapidly into the matrix along the high-permeability streaks, reaching the end of the simulated core as much as 17 times faster than for a homogeneous case.

Modeling of Spent-Acid Blockage Damage in Stimulated Gas Wells

Aqueous fluids introduced by different stimulation treatments cause water blockage in the near-wellbore region of wells. This water blockage acts the same as formation damage when the well is put back on production. One of the examples is when gas wells in carbonate reservoirs are acid-stimulated; the wormholes that propagate into the formations might be surrounded by a region of high water saturation created by the leakoff of spent acid. The spent-acid blockage damage could be severe, especially in lower permeability regions where capillary forces are relatively high. This paper presents a model that investigates the spent-acid damage in wormhole region of acid-stimulated gas wells. The phenomenon of spent-acid blockage was first investigated in the experimental study to identify the problem. A labscaled model was then developed to characterize the capillary pressure and relative permeability behavior by matching the results from the model to the experimental observation. We then extended the study to field-scale by approximating the wormhole as a long, slender half-ellipsoid centered in an ellipsoidal flow field. The simulations that focused on the displacement regime of spent acid recovery process were developed. These models were solved numerically to predict pressure behavior and spent acid distributions for the flow-back process. With the models, we studied the effects of several key factors, such as capillary pressure, relative permeability, and addition of additives, on the efficiency of spent acid recovery. The results show that common additives routinely added to acid systems may aid, or hinder, spent acid recovery, depending primarily on their effects on rock wettability. With the studies performed on the model developed, we provide recommendations for minimizing spent acid damage to gas well productivity.

Temperature Prediction Model For A Horizontal Well With Multiple Fractures In A Shale Reservoir

Fracture diagnostics is a key technology for well performance prediction of a horizontal well in a shale reservoir. The combination of multiple fracture diagnostic techniques gives reliable results, and temperature data has potential to provide more reliability on the results. In this work, we show an application of a temperature prediction model for a horizontal well with multiple hydraulic fractures in order to investigate the possibility of evaluating reservoir and hydraulic fracture parameters using temperature data. The model consists of wellbore model and reservoir model. The wellbore model was formulated based on mass, momentum and energy balance. The reservoir flow model was solved by a numerical reservoir simulation, and the reservoir thermal model was formulated by transient energy balance equation considering viscous dissipation heating and temperature variation caused by fluid expansion besides heat conduction and convection. The reservoir flow and reservoir thermal model were coupled with the wellbore model to predict temperature distribution in a horizontal well considering boundary conditions at the contact of reservoir and wellbore. In the reservoir system, primary hydraulic fractures which are transverse to the horizontal well were modeled with thin grid cells explicitly, and the hydraulically-induced fracture network around the horizontal well was modeled as higher permeable zone to unstimulated matrix zone. The reservoir grids between two primary fractures were logarithmically spaced in order to capture transient flow behavior. We applied the model to synthetic examples: horizontal well with identical five fractures and with different five fractures. The results show two fundamental mechanisms: heat conduction between formation and wellbore fluid at non-perforated zone, and wellbore fluid mixing effect at each fracture. The synthetic example with identical fractures shows that fracture locations affect wellbore temperature distribution because of fluid mixing effect between reservoir inflow and wellbore fluid. And also, the synthetic example with different fractures shows that the fracture heterogeneity causes different magnitude of temperature change due to inflow variation per fracture. In addition, the model was applied to synthetic examples without network fracture region in order to find the effects by the network. It reveals that under constant rate condition, network fracture masks large temperature change due to small pressure change at the contact between fracture and formation, and that under constant BHP condition, network fracture augments temperature change with the increase of flow rate in wellbore and inflow rate from reservoir. Sensitivity studies were performed on temperature distribution to identify influential parameters out of the reservoir and hydraulic fracture parameters including reservoir porosity, reservoir permeability, fracture half-length, fracture height, fracture permeability, fracture porosity, fracture network parameters, and fracture interference between multiple…

Diagnosis of Fracture Flow Conditions with Acoustic Sensing

.................................................................................................................... ii DEDICATION ................................................................................................................ iii ACKNOWLEDGEMENTS ............................................................................................ iv NOMENCLATURE ......................................................................................................... v TABLE OF CONTENTS ............................................................................................... vii LIST OF FIGURES......................................................................................................... ix LIST OF TABLES ......................................................................................................... xii

Theoretical and Numerical Simulation of Herschel-Bulkley Fluid Flow in Propped Fractures

The flow of non-Newtonian fluids in porous media is important in many applications, such as polymer processing, heavy oil flow, and gel cleanup in propped fractures. Residual polymer gel in propped fractures results in low fracture conductivity and short effective fracture length, sometimes causing severe productivity impairment of a hydraulically fractured well. But non-Newtonian fluid flow behavior in porous media is difficult to be described and modeled. The Kozeny-Carman equation, a traditional permeability-porosity relationship, has been popularly used in porous media flow models. However, this relationship is not suitable for non-Newtonian fluid flow in porous media. The aim of this work is to use a combination of 3D finite volume simulation and analytical calculations to develop a comprehensive model of Herschel-Bulkley non-Newtonian fluid flow through porous media. We present the mathematical model development, and then modify the model based on numerical simulation results. In the simulations, we developed a micro pore-scale model to mimic the real porous structure. The correlation of pressure gradient and superficial velocity was investigated under the influence of primary parameters, such as yield stress, power law index, and consistency index. We also considered the effect of proppant packing arrangement and proppant diameter. The Herschel-Bulkley model was used with an appropriate modification proposed by Papanastasiou to avoid the discontinuity of the apparent viscosity and numerical difficulties. The result of the new model indicates that yield stress has a significant impact on non-Newtonian fluid flow through porous media, and the pressure gradient strongly depends on pore structure. The analytical expression reveals the physical principles for flow velocity in porous media.The variation trends of the threshold pressure gradient versus different influence factors are presented. By Computational Fluid Dynamics (CFD), we obtained a detailed view of the flow streamlines, the velocity field, and the pressure distribution in porous media. Numerical calculation results show that, in the center of the throats of porous media, the increasing yield stress widens the central plug-like flow region, and the increasing power law index sharpens the velocity profile. The new model can be readily applied to provide a clear guide to selection of fracture fluid, and can be easily incorporated into any existing reservoir simulators.