bluuebunny/crossref_metadata_2025_split huggingface dataset:
Recommended Practices for Slim-Hole Steam Injectors
Authors: Castrup Suzanne Griston 
Published: December 2007

Summary
Single-string and multistring slim-hole completions have become popular in recent years as an inexpensive means of injecting steam into shallow, low-pressure sands. While slim-hole injectors appear to be simpler and cheaper to drill and complete, wellbore heat losses can be excessive at low injection rates. In addition, if a good bond is not achieved during primary cementing, thermal stresses, incurred once steam is injected, increase the likelihood of tubing failure and steam channeling behind pipe. Therefore, an appropriate tubing size and weight must be used to prevent well failures.
For example, initial slim-hole steam injectors completed with 2⅜-in. and 2⅞-in. tubing are no longer advisable because of insufficient mechanical integrity. Similarly, poor cement bond in triple-string slim-hole injectors has resulted in a high percentage of well failures. Consequently, the costs associated with tubing deformation, poor steam containment, and high wellbore heat losses cannot be ignored when considering slim-hole injectors for a steamflood project.
This paper discusses current drilling and completion practices and addresses the benefits and risks associated with slim-hole steam injectors. The short-term economics of initial low drilling and completion costs are compared to the long-term economics of efficient steam placement to target sands using single-string and multistring slim-hole injectors. Recommended practices and guidelines are presented for proper, cost-effective application of slim-hole injectors to improve steamflood performance.
A New Two-Dimensional Model for Acid-Fracturing Design
Authors: Settari A. , Sullivan R. B. , Hansen Chris 
Published: December 2007

SummaryThe paper describes a 2D model of acid fracturing that is more rigorous than current acid-fracturing simulators. The equations are discretized and solved along fracture length and across the width (in x and y directions), as opposed to a lumped formulation in the conventional model in which the y-solution is replaced by a mass transfer coefficient Kg. In the 2D model, correlations for Kg are not needed, and the model uses directly measurable data only. In addition, the model can represent transient effects (Kg is variable along time and fracture length), combined with dispersion and thermal effects. Two models, one for lab experiments and one for field design, were developed. The lab model was validated, with excellent agreement, against the results of Roberts and Guin1 and compared with the 1D approach on data typical for phosphoria dolomite. The results show large differences in regions of high and low leakoff. Acid spending predicted by the 2D model is also higher, even when the Kg values are comparable. Correspondingly, the field-design model predicts larger spending and fracture conductivity. An example of the field design and post-fracture history match from the Cottonwood Creek Unit, Washakie County, Wyoming, is presented. It shows that the new model is in better agreement with field data. Extensions to 3D modeling are also discussed.
Shale Preservation and Testing Techniques for Borehole-Stability Studies
Authors: Chenevert M. E. , Amanullah M. 
Published: December 2007

Summary
Shale rocks are known to be the primary troublesome formation that has plagued drillers for many years. Attempts have been made to investigate the characteristics of shales, but results are limited because of the scarcity of test samples. Rapid deterioration of cuttings and cores has made data collection limited at best and a complete failure in many cases. It now appears that the shales become unsaturated as they dry out because of poor storage conditions, which result in false test results owing to the incorporation of capillary pressure artifacts.
This paper discusses results obtained with a specially preserved, highly reactive shale core obtained at a depth of 4,500 ft in the North Sea. A previously developed method was used for the evaluation of shale cores to determine their level of saturation. This study shows that shales must be preserved at their native water content if accurate physical measurements are to be made.
Swelling data show that shales that are altered during handling (hydrated or dehydrated) do not respond properly even when restored to their native hydration conditions. They tend to experience excessive swelling compared to cores kept at their native water content.
Results also showed that the North Sea core used in this study was maintained in a fully saturated condition during coring, retrieval, and storage. The technique used is discussed here.
Applications of Polymer Gel for Establishing Zonal Isolations and Water Shutoff in Carbonate Formations
Authors: Pérez D. , Fragachán F. E. , Barrera A. Ramírez , Féraud J. P. 
Published: December 2007

SummaryIn this paper, we present the results of successful applications of polymer gels to control water production in Mexico. We discuss three case studies that used a systematic methodology to correctly diagnose near-wellbore water channeling behind the casing. The methodology uses diagnostic plots based on the historical behavior of the water/oil ratio (WOR) as a function of time. These include correlation with information from original cement bond logs (CBL's), oxygen-activated logs during production to effectively determine the origin of the water, and saturation logs to determine the water levels independent of the salinity of the water produced.In addition, we present successful applications of polymer gels to re-establish zonal isolations in the three case studies previously mentioned. We discuss gel placement and present the procedure followed in each case, evaluate a water injectivity test followed by a temperature log taken before gel placement to determine the height propagation of the water, and anticipate potential zone damage of adjacent producing intervals during gel placement. In one case, a new interval completed perforating through the gel with excellent results. Another case involved a zone abandonment with gel, in which positive pressure was tested with 35 and 70 kg/cm2 wellhead pressure at 2500 m. In all cases, the advantages of gel treatments over common cement squeezes are discussed.Finally, we present the treatment results, including the analysis of pressures recorded during gel placement and the oil and water production before and after treatment.
A Note on the Skin Effect
Authors: Hawkins Murray F. 
Published: December 2007

Horner and van Everdingen have shown that the pressure drop within the wellbore, as a result of having produced the well at a constant rate q for time t, where t is sufficiently large, is:
(Equation 1)
van Everdingen observed that better agreement between theory and well performance can be obtained if, instead of assuming the permeability is ke everywhere about the well, it is assumed the permeability near the wellbore is substantially reduced as a result of drilling, completion and/or production practices. In order to account for the additional pressure drop he introduced the dimensionless quantity S, the skin effect factor, so that Eq. 1 becomes:
(Equation 2)
Eq. 2 might have also been obtained as follows. Assume a zone of altered permeability ka exists about the well out to a radius ra, and beyond that the unaltered, external permeability ke. The additional pressure drop required to overcome this skin of reduced permeability may be calculated with sufficient accuracy using the incompressible flow equation; for Brownscombe and Collins have shown almost no difference between compressible and incompressible steady-state flow, in the vicinity of the wellbore, and the small volume of fluid in the vicinity of the wellbore makes unsteady-state mechanics unnecessary. Then,
(Equation 3)
The sign of this skin pressure drop will be positive or negative depending upon whether the altered permeability ka is smaller or larger, respectively, than the external permeability ke.
Three-Phase Relative Permeability
Authors: Corey A.T. , Rathjens C.H. , Henderson J.H. , Wyllie M.R.J. 
Published: December 2007

Abstract
The results of three-phase relative permeability tests on nine water-wet consolidated Berea sandstone samples are presented as composite ternary diagrams showing isoperms of oil, water and gas. Capillary pressure control was exercised over the flow of gas and oil in the presence of water. The water saturations ranged from 17 to 71 per cent pore volume.
A method of calculating both the oil and water permeabilities of a three-phase system from the easily measured gas relative permeability is presented.

Experimental Procedure and Results
A renewed interest has been shown in three-phase relative permeability as a result of recent developments involving underground combustion processes, steam injection, and other multiphase displacement processes. The experiments and results described here involved simultaneous flow of oil and gas in consolidated Berea sand with brine present as the wetting phase.
Gas and oil relative permeabilities were measured on nine cores with CaCl2 brine present as the wetting phase in saturations ranging from 17 to 71 per cent.
Orifice Metering of Two-Phase Flow
Authors: Mattar Louis , Nicholson Murray , Aziz Khalid , Gregory G.A. 
Published: December 2007

Several correlations for two-phase flow through orifice meters are reviewed and verified experimentally, using air and oil mixtures in a 2-in. (5.08-cm) orifice meter. A simple, empirically determined relationship is shown to be valid for a limited range of oil/gas ratios when separator tests are possible. For predictive purposes, however, a more complex relationship is recommended.

Introduction
The flow of two-phase mixtures in a single pipeline is becoming more common. To determine the rates of flow in such systems, the phases are separated first, and the flow rate of each phase is measured individually.In many instances, we need to know the flow rates without having to separate the phases. A typical example would be when continuously (automatically) monitoring sour gas fields, where retrograde condensation occurs before measurement by an orifice meter. Sometimes existing installations, which were once producing dry gas, now are producing in two-phase flow, and satisfactory interpretation of these orifice meter readings is desired. Another application of interest is the determination of steam quality during the flow of wet steam when the total mass flow rate (boiler feed rate) is known.This study tries to obtain a relationship between the orifice-meter differential reading and the flow rates of the individual phases, using air and oil as the flowing fluids.

Review of the Literature
Most investigations into two-phase flow-rate measurement with orifices have been concerned with the flow of wet steam. Occasionally, air/water systems were studied. There are few papers relating to natural gas/oil flow.
All correlations presented in the literature are based on the single-phase, orifice-meter equation, which may be written as
(1)
James, working with geothermal steam wells, used Eq. 1, but replaced the density with an effective two-phase mixture density. He obtained this density by raising the mass dryness fraction to the empirically determined power of 1.5.In another approach, Smith and Leang used a "blockage factor" to modify the coefficient of discharge, Kd, and expressed it as a function-of-dryness fraction.Smith and Leang and Smith et al., reviewed and evaluated several published correlations.Murdock, Bizon, and Chisholm and his coworkers took a different approach from those mentioned before. They related the two-phase pressure drop to that obtained by flowing the gas and liquid pressure drop to that obtained by flowing the gas and liquid separately. Murdock and Bizon assumed there was no interfacial shear between the gas and liquid phases (no slip model) and derived the relationship,
(2)
We show in the Appendix that / is proportional to the liquid-to-gas ratio. When there is no proportional to the liquid-to-gas ratio. When there is no liquid flowing, the liquid-to-gas ratio is zero, and must equal one. Eq. 2 then becomes equivalent to that reported by Wichert,
(3)
JPT
P. 955
Modeling the Propagation of Waterflood-Induced Hydraulic Fractures
Authors: Hagoort Jacques , Weatherill Brian D. , Settari Antonin 
Published: December 2007

Abstract
A mathematical reservoir model is presented to simulate the propagation of waterflood-induced hydraulic fractures in a symmetry element of a waterflood pattern. The model consists of a conventional single-phase reservoir simulator coupled with an analytical fracture model.
The model is capable of simulating fracture propagation as a function of (1) injection and production rates or pressures, (2) reservoir and fluid properties, and (3) formation-fracturing pressures.
Examples are given that clearly illustrate the characteristics of hydraulic-fracture growth. The key variables are injection rate and voidage/replacement ratio. Fractures can be contained by restricting the injection rate and by imposing a voidage/ replacement ratio equal to or less than 1.
The modeling technique presented here also may be applied to other fracturing problems, particularly in cases where leakoff is significant and, thus, should be taken into account rigorously.
A Finite-Element Method for Reservoir Simulation
Authors: Young Larry C. 
Published: December 2007

Abstract
Several previous studies have applied finite-element methods to reservoir simulation problems. Accurate solutions have been demonstrated with these methods; however, competitiveness with finite difference has not been established for most nonlinear reservoir simulation problems.
In this study a more efficient finite-element procedures is presented and tested. The method is Galerkin-based, and improved efficiency is obtained by combining Lagrange trial functions with Lobatto quadrature in a particular way. The simulation of tracer performance, ion exchange preflush performance, and adverse mobility ratio miscible displacements is considered. For the problems considered, the method is shown to yield accurate solutions with less computing expense than finite differences or previously proposed finite-element techniques.
For the special case of linear trial functions, the method reduces to a five-point central difference approximation. In contrast to previously reported results, this approximation is found to simulate adverse mobility ratio displacements without grid orientation sensitivity, provided a sufficiently fine grid is used.
A Streamline Approach for Integrating Transient Pressure Data Into High-Resolution Reservoir Models
Authors: Kulkarni Kari Nordaas , Datta-Gupta Akhil , Vasco D.W. 
Published: December 2007

Summary
We generalize the streamline approach to transient pressure applications by introducing a "diffusive" time of flight along streamlines. This allows us to define drainage areas or volumes associated with primary recovery and compressible flow under the most general conditions. We then employ developments in seismic tomography and waveform imaging to formulate an efficient approach for integrating transient pressure data into high-resolution reservoir models. The proposed approach exploits an analogy between a propagating wave and a propagating "pressure front" via high-frequency asymptotic solutions to the transient pressure equation. A key advantage of the asymptotic approach is that parameter sensitivities required for solving inverse problems related to production data integration can be obtained analytically using a single streamline simulation. Thus, the approach can be orders of magnitude faster than current techniques that require multiple flow simulations. We demonstrate the power and utility of the approach by applications to both synthetic and field examples. In the field example, the predominant fracture patterns emerging from the inversion are shown to be consistent with outcrop mapping and crosswell seismic imaging.
Experimental Study of Fracture Conductivity for Water-Fracturing and Conventional Fracturing Applications
Authors: Fredd C. N. , McConnell S. B. , Boney C. L. , England K. W. 
Published: December 2007

Summary
Hydraulic fracturing treatments that use treated water and very low proppant concentrations (commonly referred to as water-fracturing treatments or "waterfracs") have been successful in stimulating low-permeability reservoirs. However, the mechanism by which these treatments provide sufficient conductivity is not well understood. To understand the effects of fracture properties on conductivity, a series of laboratory conductivity experiments was performed with fractured cores from the east Texas Cotton Valley sandstone formation.
The results of this study demonstrate that fracture displacement is required for surface asperities to provide residual fracture width and sufficient conductivity in the absence of proppants. However, the conductivity may vary by at least two orders of magnitude, depending on formation properties such as the degree of fracture displacement, the size and distribution of asperities, and rock mechanical properties. In the presence of proppants, the conductivity can be proppant- or asperity-dominated, depending on the proppant concentration, proppant strength, and formation properties. Under asperity-dominated conditions, the conductivity varies significantly and is difficult to predict. Low concentrations of high-strength proppant overcome the uncertainty associated with formation properties and provide proppant-dominated conductivity. The implication of these results is that the success of a water-fracturing treatment is difficult to predict because it will depend significantly on formation properties. This dependence can be overcome by using high-strength proppants or proppants at conventional field concentrations.
Identifying and Estimating Significant Geologic Parameters With Experimental Design
Authors: White Christopher D. , Willis Brian J. , Narayanan Keshav , Dutton Shirley P. 
Published: December 2007

SummaryVariability in production predictions caused by geologic heterogeneity and uncertainty was examined with a new method. The experimental design maximized the information derived from the flow simulation of various geologic models. Empirical response surface models were fit to simulation results to assess the consequences of varying several geologic factors. Posterior distributions of geologic parameters were estimated from flow responses. Improvements in the accuracy of the reservoir model were quantified by computing changes in factor uncertainties resulting from response measurements. Monte Carlo simulations with prior and posterior factor distributions illustrate uncertainty reduction. This approach can be used for model comparison, sensitivity analysis, and estimation of probability distributions of geologic model parameters.
Unified Model for Steady-State Foam Behavior at High and Low Foam Qualities
Authors: Alvarez J. M. , Rivas H. J. , Rossen W. R. 
Published: December 2007

SummaryFoams are routinely used worldwide to divert acid in well-stimulation treatments, and to divert gas flow in improved oil recovery (IOR) projects on a pilot basis. The complexity of foam behavior and the apparent contradictions among foam studies have bedeviled attempts to understand foams and to design effective field treatments.In 1992, Osterloh and Jante1 identified two distinct foam-flow regimes: a high-quality (dry) regime, in which the steady-state pressure gradient is independent of the gas flow rate, and a low-quality (wet) regime, in which the pressure gradient is independent of the liquid flow rate. New data for strong foams in a variety of porous media, with various surfactant formulations, and over a range of flow rates, show this behavior to be general. In each regime, foam behavior is dominated by a single mechanism: at high qualities by capillary pressure and coalescence, and at low qualities by bubble trapping and mobilization. Based on these insights, a new, unified model unites foam behavior in acid-well stimulation and gasdiversion IOR and reconciles apparently contradictory data. This model correlates the effects of parameters, such as rock permeability and surfactant formulation, on foam behavior in the two flow regimes and on the transition between the two regimes. A variety of laboratory data supports the model's assumptions.The implications of these results for designing foam processes for IOR and acid diversion are discussed. These insights can guide the selection of foam formulation and injection quality for foam applications.
A Newton-Raphson Iterative Scheme for Integrating Multiphase Production Data Into Reservoir Models
Authors: Wu Zhan 
Published: December 2007

Summary
This paper presents a new linearized iterative algorithm for building reservoir models conditioned to multiphase production data and geostatistical data. The significant feature of the proposed algorithm is that the computation of the sensitivity coefficients of production data, with respect to model parameters, can be avoided. This leads to dramatic reduction of computational cost. Instead of generating the sensitivity matrix as required for the least-squares algorithms, the proposed approach relies on solving the inversion equations, which are derived from the necessary conditions for a functional extremum.
It is proved that the proposed method requires considerably less computational effort than the traditional algorithms such as the Gauss-Newton method, the Levenberg-Marquardt method, and the generalized pulse-spectrum technique (GPST). This is because the computation of the sensitivity coefficients makes the traditional algorithms computationally intensive. However, for the proposed linearized iterative scheme, the computational requirement only depends on the timesteps used in the reservoir simulator rather than the number of parameters or the number of observed data.
The linearized iteration scheme converges quickly because the inversion equations can be solved through the Newton-Raphson method. At each iteration, the new approach requires solving the finite difference equations and the linear adjoint equations only once, respectively. Since the solver for the flow equations can be used to solve both the adjoint equations and the inversion equations, the proposed algorithm can be easily applied to commercial reservoir simulators. In this paper, two numerical examples for incorporating water oil rate data into geostatistical models are given to prove the efficiency of the proposed algorithm.
A Semianalytical Model for Calculating Pressure Drop Along Horizontal Wells With Stinger Completions
Authors: Jansen J. -D. 
Published: December 2007

Summary
Pressure drop along horizontal wells causes unequal drawdown along the well, thus reducing the effectiveness of the toe of the well, and increasing the tendency for water and gas coning at the heel. Completions have been proposed to combat this effect using a stinger that extends from the heel into the horizontal section. This reduces the magnitude of the pressure drop over the wellbore, because the well is effectively split into two segments of reduced length. If the stinger also has an intermediate inflow opening, possibly equipped with a remotely controlled inflow control valve, a further reduction in the wellbore pressure drop can be obtained. We present a semianalytical model to compute the flow in stinger completions in a reservoir that may have varying inflow characteristics along the wellbore. The model is capable of handling flow in a looped configuration, which occurs when the stinger has an intermediate inflow point. It combines either numerical integration or analytical integration in terms of Jacobian elliptic functions, with an iterative "shooting" method to solve the two-point boundary value problem for pressure and flow rate along the well. It can be used to rapidly determine the optimal configuration of a stinger completion with intermediate inflow.