bluuebunny/crossref_metadata_2025_split huggingface dataset:
Factors Affecting Cleanup of Water Blocks: A Laboratory Investigation
Authors: Mahadevan Jagannathan , Sharma Mukul M. 
Published: April 2006

Summary
Water-blocked low-permeability gas formations with drawdown pressures comparable to capillary entry pressures can take a very long time to clean up. This work aims to study the effect of permeability, wettability, temperature, and drawdown on the cleanup of cores containing brine.
Gas displacement experiments were conducted on cores fully saturated with brine. Addition of methanol, increasing temperature, and increasing core permeability by changing rock type resulted in faster cleanup after approximately 50 to 100 pore volumes (PV, the volume of vacant pores in the dry sample) of gas flow. The change of wettability of the rock from water-wet to oil-wet also resulted in faster recoveries in gas relative permeability.
The cleanup of water blocks in gas wells occurs in two regimes: displacement of the fluids from the formation, followed by vaporization by the flowing gas, which becomes undersaturated as the pressure decreases. Our observations show that the cleanup of water blocks can be improved by: (a) Influencing the displacement regime (i.e., by changing the wettability) and (b) increasing the rate of vaporization by introducing volatile solvents such as methanol.
The study quantifies the effects of factors such as rock type (permeability), wettability, surface tension/volatility, and temperature on gas relative permeability. The results of this study will help in selecting strategies for cleanup of water blocks created by various operations such as drilling, acidizing, and fracturing, as well as making recommendations for the use of surfactants or solvents for well treatments to remove water blocks.
Drift-Flux Modeling of Two-Phase Flow in Wellbores
Authors: Shi H. , Holmes J. A. , Durlofsky L. J. , Aziz K. , Diaz L. R. , Alkaya B. , Oddie G. 
Published: April 2006

SummaryDrift-flux modeling techniques are commonly used to represent two- and three-phase flow in pipes and wellbores. Unlike mechanistic models, drift-flux models are continuous, differentiable, and relatively fast to compute, so they are well suited for use in wellbore flow models within reservoir simulators. Drift-flux models require a number of empirical parameters. Most of the parameters used in current simulators were determined from experiments in small-diameter (2 in. or less) pipes. These parameters may not be directly applicable to flow in wellbores or surface facilities, however, because the flow mechanisms in small pipes can differ qualitatively from those in large pipes. In order to evaluate and extend current drift-flux models, an extensive experimental program was initiated. The experiments entailed measurement of water/gas, oil/ water, and oil/water/gas flows in a 15-cm-diameter, 11-m-long plexiglass pipe at eight deviations ranging from vertical to slightly downward. In this paper, these experimental data are used to determine drift-flux parameters for steady-state two-phase flows of water/gas and oil/water in large-diameter pipes at inclinations ranging from vertical to near-horizontal. The parameters are determined using an optimization technique that minimizes the difference between experimental and model predictions for phase in-situ volume fraction. It is shown that the optimized parameters provide considerably better agreement with the experimental data than do the existing default parameters.
Analytic Wellbore-Temperature Model for Transient Gas-Well Testing
Authors: Hasan A. R. , Kabir C. S. , Lin D. 
Published: April 2006

Summary
Questions arise whether bottomhole pressures (BHPs), derived from their wellhead counterpart (WHP), lend themselves to transient analysis. That is because considerable heat exchange may affect the wellbore-density profile, thereby making the WHP translation a nontrivial exercise. In other words, gas density is dependent on both spatial locations in the wellbore and time during transient testing. Fully coupled wellbore/reservoir simulators are available to tackle this situation. However, they are not readily adaptable for their numeric formulations.
This paper presents analytic expressions, derived from first principles, for computing time-dependent fluid temperature at any point in the wellbore during both drawdown and buildup testing. The simplicity of the analytic expressions for Tf (z, t) is profound in that one can compute flowing or shut-in BHPs on a spreadsheet.
Two tests were considered to verify the new analytic formulae. In one case, measurements were available at both sandface and surface, and partial wellhead information was available in the other case. We explored a parametric study to assess whether a given wellbore/reservoir system will lend itself to wellhead measurements for valid transient analysis. Reservoir flow capacity (kh) turned out to be the most influential variable.
Dimensions and Degree of Containment of Waterflood-Induced Fractures From Pressure-Transient Analysis
Authors: Hoek P. J. van den 
Published: April 2006

SummaryIt is well established within the industry that injection of (produced) water almost always takes place under fracturing conditions. Particularly when large volumes of very contaminated water are injected—either for voidage replacement or disposal—large fractures may be induced over time.This paper aims to provide a methodology for injection-falloff (IFO) test analysis of fractured (produced) water-injection wells. Some essential elements of IFO for fractured water injectors include the closing fracture, (early) transient elliptical reservoir-fluid flow, finite fracture conductivity, and fracture face skin.An exact semianalytical solution is presented to the fully transient elliptical fluid-flow equation around a closing fracture with finite conductivity, fracture face skin, and multiple mobility zones in the reservoir surrounding the fracture. This solution also captures the case that during closure, the fracture is generally shrinking from adjacent geological layers under higher in-situ stress. Based on this solution, type curves of the dimensionless bottom-hole pressure as a function of dimensionless time are provided, covering both the period during fracture closure/shrinkage and the period after fracture closure. The shape of these type curves is studied as a function of the different relevant parameters, in particular the fracture compliance, the height of in-situ stress contrasts, fracture face skin, fracture closure time, and injection period. It is shown how the fracture length and height and the degree of fracture containment (in combination with the heights of the stress contrasts) can be derived from these types of curves. It is also demonstrated that the analyses based on the storage flow and linear formation flow regimes need to be integrated into one analysis method to obtain consistent results.Finally, the concepts developed in this paper are applied to a number of field examples, in which the dimensions and degree of containment of the induced fractures are derived from the analysis of the IFO data.
The Role of Electrofacies, Lithofacies, and Hydraulic Flow Units in Permeability Prediction From Well Logs: A Comparative Analysis Using Classification Trees
Authors: Perez Hector H. , Datta-Gupta Akhil , Mishra S. 
Published: April 2006

Summary
Predicting permeability from well logs typically involves classification of the well-log response into relatively homogeneous subgroups based on electrofacies, Lithofacies, or hydraulic flow units (HFUs). The electrofacies-based classification involves identifying clusters in the well-log response that reflect "similar" minerals and lithofacies within the logged interval. This statistical procedure is straightforward and inexpensive. However, identification of lithofacies and HFUs relies on core-data analysis and can be expensive and time-consuming. To date, no systematic study has been performed to investigate the relative merits of the three methods in terms of their ability to predict permeability in uncored wells.
The purpose of this paper is three-fold. First, we examine the interrelationship between the three approaches using a powerful and yet intuitive statistical tool called "classification-tree analysis." The tree-based method is an exploratory technique that allows for a straightforward determination of the relative importance of the well logs in identifying electrofacies, lithofacies, and HFUs. Second, we use the tree-based method to propose an approach to account for missing well logs during permeability predictions. This is a common problem encountered during field applications. Our approach follows directly from the hierarchical decision tree that visually and quantitatively illustrates the relationship between the data groupings and the individual well-log response. Finally, we demonstrate the power and utility of our approach via field applications involving permeability predictions in a highly complex carbonate reservoir, the Salt Creek Field Unit (SCFU) in west Texas. The intuitive and visual nature of the tree-classifier approach also makes it a powerful tool for communication between geologists and engineers.
Field Verification: Invert-Mud Performance from Water-Based Mud in Gulf of Mexico Shelf
Authors: Aldea Catalin , Bruton James R. , Dobbs William R. , Klein Aaron L. 
Published: April 2006

Summary
A uniquely designed water-based mud (WBM) was used in two shelf areas of the Gulf of Mexico to drill highly reactive gumbo sections. The drilling performance and inhibition in these shale intervals resembled that of synthetic-based muds (SBMs) previously used in offset wells. Owing to new environmental regulations, obtaining the drilling-performance characteristics of a synthetic-based fluid and the stability of a water-based fluid is a high priority for Gulf of Mexico operators.
A special characteristic of the WBM fluid is its ability to deliver SBM-like shale inhibition without use of any salts, through an ideal combination of a polyamine shale inhibitor, a polymeric encapsulator, and an antiaccretion additive.
This paper presents field data comparing the drilling performance and the inhibition in gumbo-shale sections of the new WBM and the previously used SBM. The combination of this inhibitive WBM and the rotary-steerable tool produced an 85% higher rate of penetration (ROP) than in similar wells in the area drilled with SBM and mud motors. No accretion or bit balling was noted on bottomhole assemblies (BHAs) during bit runs, and the cuttings drilled were well encapsulated and protected from hydration. Economic savings were realized by reducing the drilling time and by not requiring the essential waste-management equipment and engineering associated with SBM-cuttings discharge. Further-more, the new high-performance WBM was easily prepared at the wellsite with seawater, which also translated into cost savings by reducing the volumes handled by the workboats.
These field applications demonstrate that this uniquely designed WBM can effectively replace invert-emulsion fluids in many highly reactive shale sections without sacrificing drilling performance or increasing environmental risk.
A New Thermal Insulating Fluid and Its Application in Deepwater Riser Insulation in the Gulf of Mexico
Authors: Wang Xiaolan , Javora Paul , Qu Qi , Pearcy Ricky 
Published: April 2006

SummaryUndesired heat loss from the production tubing, or uncontrolled heat transfer to outer annuli, contributes to the formation of gas hydrates and causes the deposits of paraffin and asphaltene materials that reduce the production rate. The successful application of thermal-insulating fluids in the last several years has demonstrated that such fluids can control heat loss effectively. In some cases, heat loss from the produced fluids caused by conduction and convection can be reduced by more than 90% when compared with traditional packer fluids.Recently, a new thermal-insulating-fluid system with superior thermal properties has been developed. Compared with the existing insulation fluids, the new insulating-fluid system provides high viscosity at a low-shear-rate range to reduce the fluid-convection rate. It also provides lower viscosity at high-shear-rate range to facilitate fluid placement. The new fluid, with improved insulation properties, has proved to be an attractive alternative to the current insulation method for deepwater risers. This paper highlights the development of this new thermal-insulating fluid and its application in deepwater-riser insulation in the Gulf of Mexico (GOM). Laboratory data and field cases are also presented to demonstrate the effectiveness of this fluid system.
Fast-Fourier-Transform-Based Deconvolution for Interpretation of Pressure-Transient-Test Data Dominated by Wellbore Storage
Authors: Cheng Yueming , Lee W. John , McVay Duane A. 
Published: April 2006

SummaryWe present a deconvolution technique based on a fast-Fourier-transform (FFT) algorithm. With the new technique, we can deconvolve "noisy" pressure and rate data from drawdown and buildup tests dominated by wellbore storage. The wellbore-storage coefficient can be variable in the general case. In cases with no rate measurements, we use a "blind" deconvolution method to restore the pressure response free of wellbore-storage effects. Our technique detects the afterflow/unloading rate function with Fourier analysis of the observed pressure data.The technique can unveil the early-time behavior of a reservoir system masked by wellbore-storage effects, and it thus provides a powerful tool to improve pressure-transient-test interpretation. It has the advantages of suppressing the noise in the measured data, handling the problem of variable wellbore storage, and deconvolving the pressure data without rate measurement.We demonstrate the applicability of the method with a variety of synthetic and actual field cases for both oil and gas wells. Some of the actual cases include measured sandface rates (which we use only for reference purposes), and others do not.Although this paper is focused on deconvolution of pressure-transient-test data during a specific drawdown/buildup period corresponding to an abrupt change of surface flow rate, the deconvolution method itself is very general and can be extended readily to interpret multirate test data.
Closing the Gap: Fracture Half Length from Design, Buildup, and Production Analysis
Authors: Barree R. D. , Cox S. A. , Gilbert J. V. , Dobson M. 
Published: April 2006

SummaryIt is commonly observed that hydraulically fractured wells perform as though the "effective" fracture half-length is much lower than the designed half-length. This observation has been explained by various models, including poor fracture-height containment, poor proppant transport, proppant falling out of zone (convection), ineffective proppant-pack cleanup, capillary-phase trapping, multiphase flow, gravitational-phase segregation, and non-Darcy flow, with combinations of any of these mechanisms. With recent improvements in diagnostic measurements of fracture geometry, some of these explanations have lost credibility, but the problem of low effective fracture length persists.This paper presents detailed evaluations of hydraulically fractured well behavior with continuous production analysis, pressure-transient (buildup) analysis, and fracture-treatment evaluation by use of actual field data from a tight-gas reservoir in the Rocky Mountain Region. The various analyses explain the observed producing behavior of the well and lead to a consistent determination of the actual effective fracture half-length compared with the physically created or propped length. Problems relating to semantics and inconsistent fracture and reservoir description, especially the physical processes encompassed by various analytical techniques, will be addressed.Methods will be outlined for predicting the useful effective length from available proppant-conductivity data. The process outlined helps to close the gap between designed-fracture and producing lengths and points out the causes for the remaining system bottlenecks that limit post-fracture well productivity. Finally, the understanding of these mechanisms provides a means to arrive at an economical optimum fracture-treatment design for a reservoir once key parameters are known.
A New Model To Obtain Representative Field Relative Permeability for Reservoirs Produced Under Solution-Gas Drive
Authors: Bauget F. , Egermann P. , Lenormand R. 
Published: April 2006

SummaryRelative permeability curves (kr) control production and are of primary importance for any type of recovery process. In the case of production by displacement (waterflood or gasflood), the kr curves obtained in the laboratory can be used in numerical simulators to predict hydrocarbon recovery (after upscaling to account for heterogeneity). In the case of reservoirs produced under solution-gas drive (depressurized field, foamy oils), the experiments conducted in the laboratory depend on the depletion rate and cannot be used directly for reservoir simulations.We have developed a novel approach for calculating representative field relative permeabilities. This new method is based on a physical model that takes into account the various mechanisms of the process: bubble nucleation (pre-existing bubbles model), phase transfer (volumetric transfer function), and gas displacement (bubble flow). In our model, we have identified a few "invariant" parameters that are not sensitive to depletion rate and are specific to the rock/fluid system (mainly the pre-existing bubble-size distribution and a proportionality coefficient relating gas and oil velocity for the dispersed-phase regime). These invariant parameters are determined by history matching one experiment at a given depletion rate.The calibrated model is then used to generate synthetic data at any depletion rate, especially at very low depletion rates representative of the reservoir conditions. Relative permeabilities are derived from these "numerical" experiments in the same way as they are from real experiments. The calculated kr is finally used in commercial reservoir simulators.We have tested our model by using several series of published experiments with light and heavy oils. After adjusting the invariant parameters on one or two experiments, we are able to predict other experiments performed at different depletion rates with very good accuracy. Finally, we present an example of determination of relative permeabilities at reservoir depletion rates.
A Comparison of Travel-Time and Amplitude Matching for Field-Scale Production-Data Integration: Sensitivity, Nonlinearity, and Practical Implications
Authors: Cheng Hao , Datta-Gupta Akhil , He Zhong 
Published: April 2006

SummaryThe traditional approach to reconciling geologic models to production data involves an "amplitude matching," that is, matching the production history directly. These include water-cut, tracer concentration, and pressure history at the wells. It is well known that such amplitude matching results in a highly nonlinear inverse problem and difficulties in convergence, often leading to an inadequate history match. The nonlinearity can also aggravate the problem of nonuniqueness and instability of the solution. Recently, production data integration by "travel-time matching" has shown great promise for practical field applications. In this approach, the observed data and model predictions are lined up at some reference time such as the breakthrough or "first arrival" time. Further extensions have included amplitude information by a "generalized travel-time" inversion. Although the benefits of travel-time inversion are well documented in the context of seismic inversion, no systematic study has been done to examine its merits for field-scale history matching.In this paper, we quantitatively investigate the nonlinearities in the inverse problems related to travel time, generalized travel time, and amplitude matching during production data integration and their impact on the solution and its convergence. In our previous works, we speculated on the quasilinear nature of the travel-time inversion without quantifying it. Our results here show, for the first time, that the commonly used amplitude inversion can be orders of magnitude more nonlinear compared to the travel-time inversion. We also examine the resulting implications in field-scale history matching. The travel-time inversion is shown to be more robust and exhibits superior convergence characteristics. The travel-time sensitivities are more uniform between the wells compared to the amplitude sensitivities that tend to be localized near the wells. This prevents overcorrection near the wells.We have demonstrated our results using a field application involving a multiwell, multitracer interwell tracer injection study in the McCleskey sandstone of the Ranger field, Texas. Starting with a prior geologic model, the traditional amplitude matching could not reproduce the field tracer response, which was characterized by multiple peaks. Both travel time and generalized travel time exhibited better convergence properties and could match the tracer response at the wells with realistic changes to the geologic model.
Quantitative Use of 4D Seismic Data for Reservoir Description
Authors: Dong Yannong , Oliver Dean S. 
Published: April 2006

SummaryThe major contribution of this paper is the description of an efficient, gradient-based method for incorporating time-lapse seismic impedance data in anautomatic history matching procedure. We use a finite-difference, black-oilreservoir simulator, with rock physics included, to predict seismic impedanceas a function of saturation and pressure. The adjoint method is used to computethe derivatives of seismic impedance change in each gridblock with respect toporosity, permeability, pressure and phase saturation. With a quasi-Newtonminimization method to efficiently minimize the difference between observedimpedance changes and the impedance changes predicted using the reservoirsimulator, our procedure can be applied to field-scale problems. Thefeasibility of this method of utilizing time-lapse seismic data is illustratedwith an application to a semi-synthetic model created from a relatively largemiddle-eastern oil field.
Development and Field Application of a New Measurement Technique for Organic Acid Additives in Stimulation Fluids
Authors: Taylor K. C. , Al-Katheeri M. I. , Nasr-El-Din H. A. 
Published: April 2006

SummaryFormic and acetic acids, with and without HCl, have been used extensively over the last 40 years as stimulation fluids and as acid additives. A measurement method for these organic acids was not previously available for highly contaminated acid stimulation samples that contain high acid concentrations, dissolved oil, suspended solids, and several different acid additives. Citric and acetic acids are also used in acid treatments as iron control agents at temperatures less than 200 and 150°F, respectively. An analytical method using capillary electrophoresis was developed to simultaneously measure the concentrations of formic and acetic acids in stimulation fluids. The developed method was used to evaluate flowback samples from pickle treatments and stimulation treatments of several high-temperature wells.The following conclusions are made:A method for the simultaneous measurement of formic and acetic acids was developed, evaluated, and implemented for acid stimulation samples. Citric acid concentration can be determined in certain cases, which are identified in the paper. Results of formic and acetic acid concentrations in sandstone and carbonate corefloods were evaluated. Flowback samples from pickle treatments and acid fracture treatments were evaluated. Results from treatments of super chrome-13 and low-carbon steel tubing with 15 wt% HCl/ 9 wt% formic acid show that a small decrease in formic acid relative to chloride concentration occurred over time with carbon steel. No significant decrease of formic acid relative to chloride concentration was observed in the flowback of a well with a super chrome-13 completion.