The high near-wellbore pressure drop which has frequently been reported in fracture treatments is indicative of ineffective communication between the wellbore and the fracture. Although numerous observations of such effects have been published, few attempts have been made to understand them. This paper describes three possible mechanisms of near- wellbore effects: perforation phasing misalignment-induced rock pinching, perforation pressure drop, and fracture reorientation (deviation tortuosity) - and their implementation in a numerical fracture simulator. Typical signatures of all three effects in fracture treatment records are shown, and a method proposed by which to distinguish them. Perforation phasing misalignment has been identified as a cause of near-wellbore restriction. Because the fracture does not always initiate at the perforation, the fluid must communicate with the fracture through a narrow channel (micro-annulus) around the casing. The paper describes this pinching effect and shows that it is related to the contact stress between the cement and the formation. Perforation pressure drop and deviation tortuosity, which have previously been proposed by other authors, have also been modeled. They have been incorporated in the simulator, together with the phasing misalignment effect, to allow investigation of the differences in response between the different mechanisms. Results of simulating the effects of erosion of near-well effects on treating pressure are also shown. Introduction Over the past five years high near-wellbore pressure drop has often been observed in fracture treatments, and attempts have been made to understand the effect of near-wellbore conditions on the placement of a hydraulic fracturing job and to develop new methods to prevent unplanned screenouts. Near-wellbore pressure drops have been attributed to phenomena such as wellbore communication (perforations), tortuosity (fracture turning and twisting), and multiple fractures. These geometries were identified as being detrimental to the success of a fracturing treatment, because of the increase in net pressure and the increased likelihood of unplanned screenouts. Fracture geometry around a wellbore Several researchers have investigated critical mechanisms related to fracture initiation from vertical and deviated wells. P. 569

Summary While the effect of 2D proppant transport during hydraulic fracturing has been studied extensively and debated frequently, relatively little attention has been given to acid-fracturing treatments. In addition to fluid-density differences and gravity-driven segregation, spatial variation of the acid temperature and of the rock chemical properties results in more complicated physical phenomena for acid fracturing. Acid diffusion in the fracture has been estimated empirically with no considerations made to model correctly the acid flow across the fracture width. The etched-width profile resulting from 3D flow could differ significantly from that predicted by the 1D, piston-like displacement normally included in acid-fracture simulators. An important consequence of this variation in the etched pattern is a substantially different prediction of the fracture conductivity, and hence the post-stimulation hydrocarbon production. Acid flow in the fracture can affect the outcome of reservoir stimulation and must be considered when designing acid-fracturing treatments. The equations governing fluid flow are developed initially for a 2D pressure profile. These equations are coupled with the formulations for acid wall reaction, heat transfer, and diffusion within the framework of a P3D hydraulic fracturing simulator. The theoretical formulation for acid transport across the fracture width is presented then and coupled with the equations for 2D acid flow. The equation of acid diffusion is solved across the fracture width, hence solving the equations of fluid flow for three dimensions in the fracture. The resulting fracture geometry and conductivity are used subsequently with a reservoir simulator to illustrate the consequences of the 3D acid formulation on hydrocarbon production. Simulated and field examples are presented to illustrate the effects of 3D acid flow on the etched-width distribution and post-stimulation production. Introduction Hydraulic fracturing with acid is an alternative to propped fractures in acid-soluble formations such as dolomite and limestone. In such cases, fracture conductivity is obtained by etching the fracture faces instead of using proppant to prevent the fracture from closing. The acid treatment, however, is more complicated to design because of the difficulty in controlling both the fracture length and conductivity. The former is governed by the chemical reaction between the rock and the fracturing fluid, and the latter by etching patterns formed by the reacting acid in the formation. To design and evaluate such acid treatments, numerical simulators have been developed based on several physical mechanisms. The first mechanism is the acid reaction at the wall that creates the etched width and decreases the acid concentration at the wall. An acid concentration profile is created across the fracture width, with the acid diffusing from the center of the fracture to the fracture wall because of the concentration differences and leakoff velocity (second mechanism). Finally, because of fluid flow, the acid is transported along the fracture. The two limiting cases in modeling these mechanisms are the "diffusion-limited" case and the "reaction-limited" case. The diffusion-limited case occurs when the reaction is very fast, so that the rate of diffusion is limited by the rate at which acid can be transported to the surface and the acid concentration at the wall is apparently zero. The other case is obtained when the acid can be brought to the face as rapidly as it is consumed by reaction. This is called reaction-limited and implies that the wall concentration is approximately equal to the average acid concentration. Several simulators for treatment design and evaluation have been developed1–3 during the past decade based on acid-reaction models and 1D fluid flow. The basic assumptions of these models are the following:Fluid flow in the fracture is assumed to be plug flow. The fluid in the fracture has vertical fronts; i.e., the effects of the fracture width profile and leakoff variation along the fracture height are neglected.Acid diffusion from the center of the fracture to the fracture wall is calculated based on empirical formulations that assume a constant fracture width, infinite reaction rate, and no entrance effects. A new acid model is proposed to eliminate such limitations by solving the fluid-flow equation in three dimensions. This simulator has been developed based on a P3D hydraulic fracturing simulator that has been tested widely and validated.4,5 Two fundamentally different but intrinsically coupled principles are involved in developing a 3D acid fracturing simulator. The first is a 2D fluid transport along the fracture length and height. This formulation requires calculating the pressure gradients and velocities along the fracture length and height. The second concept involves a rigorous calculation for acid diffusion across the fracture width. This is achieved by superimposing a 3D finite difference mesh within the fracture width and tracking the acid concentrations at every cell across the fracture. Finally, the standard principles of acid reaction and fracture-height growth are coupled within this framework to develop the implicit 3D acid simulation. Various physical principles implemented in the development of the simulator that are central to acid fracturing are presented. Secondary considerations in hydraulic fracturing are briefly discussed in the Appendix. The equations describing the acid-reaction model are presented first, followed by the algorithm for 2D acid transport. The 3D formulation that solves for the acid concentration across the width is presented next. Results obtained by applying this simulator to different examples and field cases are given; simple benchmark problems are presented to validate these results against known solutions. Finally, field examples are shown to illustrate its application for real life situations.

Summary The high near-wellbore pressure drop, which has frequently been reported in fracture treatments, is indicative of ineffective communication between the wellbore and the fracture. Although numerous observations of such effects have been published, few attempts have been made to understand them. This article describes three possible mechanisms of near-wellbore effects [perforation phasing misalignment-induced rock pinching, perforation pressure drop, and fracture reorientation (deviation tortuosity)] and their implementation in a numerical fracture simulator. Typical signatures of all three effects in fracture treatment records are shown, and a method is proposed by which to distinguish them. Perforation phasing misalignment has been identified as a cause of near-wellbore restriction. Because the fracture does not always initiate at the perforation, the fluid must communicate with the fracture through a narrow channel (microannulus) around the casing. Here we describe this pinching effect and show that it is related to the contact stress between the cement and the formation. Perforation pressure drop and deviation tortuosity, which have previously been proposed by other authors, have also been modeled. They have been incorporated into the simulator, together with the phasing misalignment effect, to allow investigation of the differences in response between the different mechanisms. Results of simulating the effects of erosion of near-well effects on treating pressure are also shown. Comprehensive field cases studies exhibiting near-wellbore mechanics are presented. The relevant near-wellbore mechanism is first identified and the downhole pressure is then simulated, demonstrating the validity of the model. Introduction Over the past few years, high near-wellbore pressure drop has often been observed in fracture treatments, and attempts have been made to understand the effect of near-wellbore conditions on the placement of proppant1,2 and to develop new methods to prevent unplanned screenouts.3–5 Near-wellbore pressure drops have been attributed to phenomena such as wellbore communication (perforations), tortuosity (fracture turning and twisting), and multiple fractures. These geometries were identified as being detrimental to the success of a fracturing treatment because of the increase in net pressure and the increased likelihood of unplanned screenouts. Over the past few years, significant effort has been devoted to developing field methodologies to overcome the effects of near-wellbore pressure losses. The use of small, high-concentration proppant slugs has been recommended to induce screenouts of secondary fracture strands in cases where multiple near-well fractures are suspected. Injection of low concentration proppant slugs has also been suggested to remove near-wellbore effects due to phasing misalignment and insufficient perforations. The use of a viscous fluid has also been proposed to prevent premature screenouts by increasing the near-wellbore fracture width in the tortuous path for a single fracture,2 or by biasing the near-wellbore hydraulic conductivity for a multiple fracture system,6 thereby preventing premature screenouts. In this article we focus on the identification and evaluation of fracture treatments showing near-wellbore effects. A model is proposed here to take into account such effects. The theoretical model has the inherent advantage of measuring near-wellbore pressure losses in terms of the underlying physical variables contributing to these effects. Additionally, the model considers the evolution of these physical parameters, and hence changes in near-wellbore pressure losses, as the treatment progresses, thereby permitting a robust re-design of the main fracture treatment. Current Near-Wellbore Evaluation Tests It is generally accepted that pressure losses associated with near-wellbore effects are proportional to the injection rate raised to a suitable power, a, (?PNWB˜qa) where a depends on the dominant near-wellbore mechanism. This observation has led to recommending rate changes as a part of the calibration treatment,7 or even during proppant injection.4 Instantaneous bottomhole pressure drops corresponding to these rate changes are then used to determine the existence of near-wellbore effects. A particularly useful field methodology used to identify near-wellbore effects is the step-down test. This test calls for monitoring bottomhole pressure drops corresponding to a progressively decreasing injection rate. A plot of ?PNWB vs. ?q is then used as a diagnostic tool to characterize whether insufficient perforations or fracture re-orientation is the cause of near-wellbore pressure losses: concave-up behavior is indicative of perforation pressure drops (?PNWB, P˜q2) while concave-down behavior is characteristic of fracture re-orientation (?PNWB, P˜q0.5) A theoretical analysis for identification of multiple fractures using a step-down test was presented by Chapman et al.7 The step-down test pressure characteristics of multiple fracture dominated near-wellbore pressure losses were shown to be similar to those exhibited by fracture re-orientation. To date, no equivalent tests are known to diagnose near-wellbore effects due to phasing misalignment. Near-Wellbore Geometry Several researchers have investigated critical mechanisms related to fracture initiation from vertical and deviated wells. Behrmann and Elbel8 found that the perforation must be oriented within a small angle of the plane normal to the minimum far-field stress for a fracture to initiate at the perforation and extend. These limited experiments suggested that this angle is about 10°. Other experiments have shown that, when the perforations are misoriented and the well deviated, the fractures can be nonplanar or S shaped.9 It has also been observed that the increase in breakdown pressure can be related to near-wellbore pressure drop in horizontal wells. However, in field operations it has been very difficult to predict the near-wellbore pressure drop because of the uncertainty of the reorientation path geometry. More recently, the creation of multiple fractures during a treatment has been identified as a mechanism which could explain the near-wellbore pressure drop.4 This effect was not considered in the work described in this article.

After placement of cement on conductor and surface casing, the temperature anomalies caused by the hydration of cement can be substantial. From volumetric considerations, it is known that the maximum temperature anomalies depend on the size of the casing-annulus gap and the cement/water ratio as well as on reaction kinetics. For deepwater wells, because of the low temperature and large annular gap, special attention should be paid to the hydration process of the cement to properly design and evaluate the cement treatment. Currently, there is no universally accepted way of defining temperature schedules for testing cement setting. Operators and field locations rely mostly on local experience, and API-proposed temperature schedules are not applicable conditions where setting time is important such as deep-water conditions. In an effort to better understand the dynamics involved with cement temperature during hydration, a numerical model was developed to predict the temperature evolution in the wellbore, cement and formation during the setting of cement. The model takes into account heat exchange with the formation and casing fluid (heating or cooling effect) as well as the heat generated during the hydration of the cement. The key parameters (formation thermal conductivity, cement thermal properties and annulus size) were assessed with the model. Based on the model, a study was completed to characterize temperature and cement strength development. And this in turn is essential to properly design conductor and surface casings in deepwater conditions, which represent the most critical sections for ensuring a competent cement hydraulic seal and support the casing. The results of the study allow to define compressive strength schedules that effectively mirror down-hole conditions and thus give reliable estimates of the necessary wait-on-cement time that could lead to substantial savings for deepwater drilling operations. Introduction When cement is mixed with water, an exothermic reaction occurs and a significant amount of heat is produced. This heat in typical wellbore geometry can produce an important temperature increase for the cement placed in the annulus. Based on that principle, field temperature logs following cementing operations have often been used for locating the top of the cement column behind the casing. Field measurements have shown that in some cases the temperature increases can be substantial1. Temperature increase of up to 50°F has been observed in some cases. Cement hydration and its related heat generation is highly dependent on temperature. The rate of heat generation during cement hydration increases with temperature and at low temperature hydration reaction can become extremely slow. Indeed the temperature in the annulus is one of the most important factors influencing the development of the cement compressive strength. Previous studies of cement hydration have primarily measured only the total amount of heat release over long periods of time2. However, cement hydration reactions are complicated and the rate of heat release is not constant.

Summary The most comprehensive hydraulic-fracturing data including the first objective measurements of fracture height, length, and width are acquired from the Gas Research Inst. (GRI)/Dept. of Energy (DOE) Multiwell Site (M-Site) tests. In spite of the availability of extensive and reliable fracturing data, significant deviation between predicted and microseismic-determined fracture geometry was reported. The purpose of this study is to provide a consistent analysis of B-sand experiments by applying a systematic methodology for fracture-treatment evaluation. For this analysis, fracture parameters are estimated initially from laboratory data, well logs, and calibration tests. These parameters are refined by matching simulated pressures to field-measured fracturing pressures recorded during the first linear gel injection. These fracture parameters then are used to compare predicted- and measured-fracture pressures on all subsequent injections. Although general agreement for the fracturing pressures was obtained, a discrepancy was noticed between zone stresses estimated by evaluation and their variation as indicated on published stress logs. Stress data were reinterpreted and an acceptable pressure match was established. Fracture parameters resulting from this study are in agreement with independently inferred estimates. In addition, an apparent difference between closure pressure and microfrac stress is resolved. Finally, good agreement between predicted fracture geometry and microseismic readings is observed for each injection test considered in this study. This study shows that fracture pressures and geometry can be predicted consistently with good accuracy using elementary analysis techniques, without a reliance on ad hoc physical explanations. Background Over the past decade, a series of hydraulic-fracturing experiments, jointly conducted by the GRI and DOE at the M-Site, has provided the most comprehensive data available for hydraulic-fracture treatments. The initial objective of these experiments was to establish the character of gas production from lenticular, low-permeability formations common in the western United States.1 Through the course of the experiments, the focus has evolved toward developing methodologies to increase the accuracy for measurement of field-scale hydraulic fractures.2 The primary effort in this direction has been the successful use of subsurface triaxial accelerometers to locate microseismic events along the extent of a propagating hydraulic fracture. This objective measure of fracture dimensions and other supporting fracturing data provide critical constraint for evaluating fracture models and thus provide an excellent example for comprehensive fracture evaluation. In spite of the availability of such exhaustive and reliable fracturing data, widely used fracture simulators failed to explain comprehensively the observed fracture response for this important data set. This discrepancy for B-sand experiments was reported3 when using both cell-based3 and lumped fracture simulators.4 Although net pressures were matched for calibration treatments,3 disagreement was noticed between the simulated fracture geometry and the geometry outlined by microseismic measurements. Disparity in fracture geometry was particularly pronounced on propped treatment for which not even a satisfactory net pressure match was achieved.3 An undesirable feature of this lenticular formation is the complex geological environment that is prone to inefficient hydraulic fracturing. Nolte discussed a comprehensive list of factors responsible for abnormal fracture behavior.5 A majority of these characteristics are applicable to the in-situ conditions at the M-Site, leading to its classification as the "worst-case scenario."5 Indeed, evaluation of prior tests at this site using both fracture simulations6 and far-field core samples7 refer to these complexities to explain differences between expected and observed behavior. The effect of such complexities can be assessed using a factor, Fc, defined5 asEquation 1 where ?pw=net pressure at the wellbore and seV=effective vertical stress. A low value of Fc is desirable for successful fracture placement. Applying Eq. 1 to the B-sand tests predicted an Fc value of 0.48. A reservoir pressure of 1,950 psi inferred on prior GRI experiments8 was used and an overburden stress based on a gradient of 1.07 psi/ft at 4,530 ft was assumed. The value of ?pw is based on bottomhole fracturing pressure of 4,800 psi recorded at the end of injection during propped treatment and closure pressure of 3,500 psi (estimated later in this paper). Although still higher than the suggested threshold value5 of Fc˜0.35 for the beginning of complex behavior in homogeneous reservoirs, this estimate is significantly lower than an Fc value of 1.02 encountered during fracture tests in the lower Paludal interval at this site.5 A lower Fc value suggests the likelihood of less complicated behavior that is amenable to routine fracture evaluation. This paper presents an evaluation study of the B-sand fracture experiments. Although these tests sought to address numerous other issues, such as proppant encapsulation and fracture conductivity, this analysis focuses on comparing simulator-predicted fracturing pressures and geometry with field measurements. Table 1 lists six injection tests performed during B-sand experiments. However, fluid was flowed back at the end of the first three KCl injections. Because shut-in pressures are essential for assessing fracture behavior, only pumping pressures are considered during these injections. Comprehensive evaluation, however, was performed for linear gel tests and propped treatment listed in Table 1. The fracture simulator used to evaluate these experiments is described in Appendix A. The first linear gel injection in the B-sand is analyzed initially using a systematic evaluation methodology to determine fracture parameters. Fracturing pressures predicted using these parameter estimates then are compared with field measurements on subsequent injections. Simulated geometries are compared with microseismic measurements in each case. The paper finally reconciles discrepancies between independent assessments of these experiments and results arrived at in this study. Primary results are provided in the main body of the paper and additional details are given in the appendices.