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Abstract A new laboratory has been constructed with test equipment designed to expose foam fracturing fluids to test conditions simulating treatment conditions of shear, time, temperature and pressure during the tests. The goal for designing this laboratory was to simulate treating and downhole conditions as closely as possible and to determine fracturing foam properties under these conditions. This paper describes the design parameters and equipment in this unique laboratory. parameters and equipment in this unique laboratory Introduction Foamed fracturing fluids were introduced in 1974 by Blauer and Durborow and Blauer and Kohlhaas. Many cave reported the rheological properties of foams. Foams discussed in these papers were generated in laboratory equipment under a variety of conditions. The authors recognized the importance of the gas total volume ratio (GVR) and made an effort to include pressure in procedures. Their primary goal was to test the properties of foams. It was assumed that "foam was foam," thus the method of generating foam was secondary to the measurement of foam properties. This rationale was probably satisfactory for properties. This rationale was probably satisfactory for early foam systems which consisted of foaming agent and water. In more recent work, rheology and fluid leakoff tests have been conducted under more realistic test conditions, i.e., adding temperature and time, and acknowledging that shear conditions play a role in the results obtained. With the introduction of polymeric stabilizers to foamed fracturing fluids, the importance of simulating mixing and preparation procedures was recognized. Incorporating crosslinked polymers as stabilizers has made it imperative to simulate shear history, as well as all of the other conditions, i.e., time, temperature, pressure and GVR. Another important condition is bubble-size distribution. Preliminary studies of the effect the velocity of the gas-liquid stream has on foam properties showed that turbulence plays a major role in bubble-size distribution. The study will be continued by determining the bubble-size distribution which occurs in actual foam fracturing treatments. Foams which have similar bubble size will be created and tested in the laboratory. Discussion The foam fracturing laboratory described here is, in effect, a simulated well above ground where measurements and observations of foam under downhole conditions can be made. It is constructed of high-pressure stainless steel tubing in which shear rates and residence times encountered during a foam fracturing treatment can be duplicated. It is designed for studying the rheological properties of foams to 10,000 psi (68.9 MPa), temperatures to 400F (204C) and shear rates well in excess of treating conditions. The preparation of fluids, introduction of additives and mixing of gas and liquid streams closely follow the shear conditions present in field operations. In order to simulate shear history, a 1,200-ft (394-m) Wellbore Simulator loop provides the ability to subject foamed fracturing fluids to shear rates and times which occur in pumping foam from the surface to the producing zone. A high-temperature heat exchanger is used to raise foam temperatures to 400F (204C). Rheological properties are measured in a Tube Rheometer consisting of four tubes. High-pressure view cells, observed with a microscope and video camera, provide viewing of the foam and bubble-size determination at both the foam generator before it passes through the test devices and at the cooler after it has been through the equipment. The effect of time on the rheology of foam at low shear rates, elevated temperatures and pressure, such as occurs in a fracture, is measured in the Fracture Simulator. Dynamic fluid loss and formation damage are also determined in this equipment. A volume of foam is reciprocated at a controlled shear rate through a fixed length of tubing and a fluid-loss chamber.
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
Abstract A fully 3D modeling tool to evaluate and predict acid fracture performance across the wide range of carbonate field properties has been developed. The model simulates acid transport and fracture face dissolution. The acid transport model includes the non-Newtonian characteristics of most acid fracturing fluids, the solution of the 3D velocity and pressure fields, and diffusion of acid toward the fracture surface. The acid reaction algorithm permits live acid to leakoff and react within the rock matrix, forming wormholes that update the leakoff boundary condition for each time step. The acid fracture model utilizes commercial 3D fracture propagation software to define the physical domain of the acid fracture simulation. The performance of an acid fracturing treatment is quantified with conductivity, which is strongly dependent on the etched width created by the acid. The model numerically solves equations describing 3D acid transport and reaction within a fracture to yield the etched width created by acid along the fracture. This conductivity is calculated with the simulator derived acid-etched width, using correlations recently developed that reflect the small scale heterogeneity of carbonate rock as it creates etching along the fracture surface. A case is presented typical of industry practice that demonstrates the model capabilities.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.34)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Novel simulator for optimizing the design of near-wellbore zone treatment (Russian)
Shcherbakov, G. Yu. (Gazpromneft โ Technological Partnerships LLC) | Maltcev, A. A. (Gazpromneft STC LLC) | Kazakov, A. V. (MIPT Center for Engineering and Technology) | Vasekin, B. V. (MIPT Center for Engineering and Technology) | Filippov, D. D. (MIPT Center for Engineering and Technology) | Blonskiy, A. B. (MIPT Center for Engineering and Technology)
In this paper the path of novel software development is described. The aim of that research is the simulation of near-wellbore zone treatment. The core of the simulator is the numerical solution of the system of linear equations. Equations describe hydrodynamic processes and chemical homogenous and heterogeneous interaction in porous media. The simulator implements the ability to simulate the geometry of the near-wellbore zone for different well constructions (horizontal well, fractures wells and multi-stage fractures). Algorithms and methods have been developed for modeling the properties of the rock and its mineralogical composition, as well as for modeling formation damage distribution. In addition to solving the system of equations for porous media around the wellbore, a module was implemented for calculating the movement of fluids along the well casing from the wellhead to the bottomhole. This module takes into account the internal structure and geometry of the formation penetration and heat movement. The simulator implements the ability to simulate acid compositions with various types of diverters based on modeling the flow of non-Newtonian fluids in the well and reservoir. Special important addition is heat transfer modeling. The developed simulator is focused on optimizing the treatment design in field conditions. Therefore, optimization modules were additionally developed based on multivariate calculations and optimization algorithms, taking into account the economic model and the forecast of the extra oil production module. An adaptation module has been developed to search for empirical coefficients characteristic of an object based on previously carried out treatments and laboratory studies. The article presents comparative calculations of the implemented software package with simplified models. It allows to substantiate and assess the significance of the implemented additional features. Examples of calculations for various types of wells and conditions are given. In addition, it was taken into account previously conducted laboratory experiments and real treatment experience. Computational experiments were considered and carried out on the following problems: the effect of the temperature of the injected fluid on the treatment efficiency, the distribution of the acid injection front for wells with horizontal construction, the diverters influence, the effect of acid injection volumes in wells with hydraulic fractures, the effect of acid composition injection volumes on the treatment efficiency in carbonate and sandstone reservoirs. The existing problems and prospects for the development of modeling the well treatment are analyzed and identified with account taken of the experience of developing the simulator.
Abstract To exploit the substantial tight-gas resources worldwide, hydraulic fracturing is, for many cases, economically a viable option. However, despite the state of the art techniques such as multiple fracturing of horizontal wellbores, the gas recovery from these reservoirs is frequently unsatisfactory. Poor reservoir rock quality, strong stress dependency in permeability, hydraulic and mechanical damage caused by the fracturing process and inertial non-Darcy flow effects were considered to be key parameters for poor performance in previous studies. A further one, related to the cleanup of the cross-linked fracturing fluid with its non-Newtonian characteristics, was rarely taken into account before and is the subject of the current paper. For this purpose, an enhanced three-phase cleanup numerical model is developed. A generalised non-Newtonian fluid flow model for porous media is derived and implemented in a reservoir simulator, capturing the yield stress of common polymer gel. The model is applied to typical cleanup scenarios. Using the model, it can be shown that the residing, non-recoverable gel (typically 50%) decreases the fracture conductivity and, hence, the production potential of a fractured gas well. This coincides with experiences in the field where these parameters are frequently lower than anticipated. Results of the study further indicate that within the fracture, gel saturations gradually increase towards the fracture tips. Contrary to the assumption made in analytical studies, there is no sharp interface between the residual gel and the reservoir fluids after the cleanup. The new non-Newtonian fluid flow implementation allows for more detailed investigations of fracture cleanup processes and, hence, an improved understanding of formation damage processes in fractured wells. Furthermore, the model enables the design of more successful fracture treatments in tight-gas reservoirs. Introduction Evaluation of postfracture performance has been the subject of extensive investigations over the past decades. For hydraulically fractured gas wells, a number of potential damage mechanisms were identified, such as hydraulic damage caused by invading fluids during the treatment and damage due to the stresses exerted on the fracture face. In addition, damage to proppant pack, reducing the conductivity and the associated non-Darcy flow effects which cause additional inertial pressure drops, were also attributed as causes of possible productivity impairment. However, these effects are not solely responsible for potential productivity impairment in tight-gas reservoirs. Many tight-gas wells do not respond to hydraulic fracturing as expected. Following the fracturing treatment, a typical tight-gas well achieves its maximum gas rate within a few days after stimulation and then experiences a rapid production decline. Some tight-gas wells, in contrast, do not show such obvious production peaks but instead sustain a flat production profile or exhibit a slowly increasing production rate for several weeks or months.[1] A major potential reason for this behaviour given in previous studies was the fracturing fluid. Commonly, cross-linked polymers facilitate hydraulic fracturing treatments, the intent being that the polymer will be recovered once production is initiated. In the field, only a fraction of the injected polymer can be produced during the cleanup process, typically up to 50%. Slugs of unbroken residuals were reported during the post-fracture production and indicate the existence of gel residues inside the fracture after the cleanup process. The incomplete degradation of the polymers in the fracturing fluid results in productivity impairments due to formation and proppant pack permeability reduction. Fracturing fluid issues are suspected to contribute to the discrepancy of effective and propped fracture half-lengths with fracture conductivities commonly much lower than anticipated.
Abstract A three-dimensional simulator for the IOR hydraulic fracturing technique has been developed by the authors based on the theoretical coupling of fluid flow and fracture mechanics models. Heterogeneous formations of hydraulically-induced fractures such as non-planar curvilinear shaped fractures in a complex stress field and unsymmetrical fractures generated from deviated or horizontal boreholes are modelled using fully coupled modelling of fracture opening and injected fluid flow in the simulator. The hydraulic fracturing processes including the post-shut-in process are calculated so as to satisfy the equilibrium of injected fluid volume, fracture volume and leak-off volume. The models of physical phenomena, the fundamental algorithms and numerical techniques are introduced, and their applicability to the conditions of real field problems as well as the theoretical and numerical correctness and choice of the models are verified. The pressure history data during the injection and post shut-in periods obtained from fracturing in a North Sea field are used for the evaluation, with the formation model determined by wireline logging and empirical knowledge. The simulation results suggested the adopted fracture propagation criteria need to be reviewed. Nevertheless, history matching of the results of the bottom hole pressure between the numerical and real data confirms that the models developed by the authors can be used to estimate the geometry and extension during hydraulic fracturing. Introduction Application of hydraulic fracturing as an improved oil recovery technique is becoming common in the petroleum engineering field. The improvement of the productivity of wells by the IOR hydraulic fracturing technique is governed by the geometry of the created fractures, so it is important to predict the geometry in advance. Use of drill cuttings re-injection as a disposal scheme also requires more accurate and reliable design of the hydraulically-induced fracture. The economic feasibility of the technique depends on whether a sufficient volume of waste can be injected into the created fracture. However, fractures which contain environmentally hazardous oil-based mud drill cuttings, should be confined in a formation of low permeability, and must never break through the surface, seabed or aquifers. On the other hand, the hydraulic fracturing process is a combination of many complicated physical phenomena, namely, fracture opening/closure in elastic, elasto-plastic or poro-elastic rock formations, non-linear behavior of injected slurry, and its leak-off into the fracture surface. Fracture propagation in the brittle or ductile rock masses is an important phenomenon to be taken into account. Proppant transport and its action to prevent fracture closure, and conveyance of hydrocarbons through the channel created in the fractures are also important because they govern the successfulness of the fracturing operation. Therefore, tools for the optimal design of fractures are being studied and developed by many researchers with several approaches from both macroscopic and microscopic viewpoints, and on theoretical and empirical bases.
- Europe (1.00)
- North America > United States > Texas (0.46)