bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experiments and Computer Analysis Show How Perforators Damage Natural Fractures
Authors: Halleck Phillip M. , Dogulu Y. Serdar 
Published: December 2007

Abstract
Numerical modeling has been used to analyze the results of a series of perforation flow experiments in fractured rock. Perforating across the fracture reduced conductivity by 75% in oil-saturated samples and 83% in gas-saturated samples. In both cases, single individual tests showed large increases in fracture conductivity, showing that the mechanisms involved are subject to random factors. More important, flow into the perforation is only ~40% (44% in oil-saturated samples and 38% in gas saturated samples) of that calculated from post-shot fracture conductivity. This suggests some combination of perforation tunnel plugging and sealing of the fracture near the perforation.
Cylindrical samples of a 1-mD tight sandstone, containing a saw-cut fracture, were perforated with a conventional oil-well perforator under simulated down-hole pressure conditions. The flow impedance through the fracture was measured before and after perforating, and flow rate out through the perforation was also measured after perforating. Analysis of the results was performed using two numerical models to simulate matrix and fracture flow. These models were used to calculate the change in effective fracture conductivity caused by perforating and to predict flow out through the perforation.
Post-test examination of the samples by visual and X-ray CT analysis show that shock stress resulting from penetration of the shaped charge jet causes deformation of the rock near the perforation tunnel, sealing the fracture where it intersects the perforation. This mechanism is a newly recognized form of formation damage specific to fractured formations. Underbalance conditions up to 5.0 MPa (750 psi) were not sufficient to clean the perforation or the perforation-fracture junction. Jet metal can also invade the fracture if the intersection is near the tip of the perforation where the jet velocity is low. This effectively shortens the usable penetration depth. These effects will be present despite efforts to ensure adequate penetration and to prevent fluid loss.
Fracture Optimization eXpert (FOX) - How Computational Intelligence Helps the Bottom-Line in Gas Storage; A Case Study
Authors: Mohaghegh Shahab , Hefner M. Hugh , Ameri Sam 
Published: December 2007

Abstract
Just like any other industry, the bottom-line in gas storage is economics. Any tool, new or old, conventional or unconventional, is evaluated by its contribution to the bottom-line. Fracture Optimization eXpert (FOX) is a new software tool that has been developed using the cutting edge of information technology, namely Computational Intelligence. Two different paradigms of Computational Intelligence was used in development of FOX. They are Artificial Neural Networks and Genetic Programming.
What distinguishes FOX from conventional frac simulators (Frac-pro, …) is its unique capability to A) not only predict post-frac deliverability but also B) suggest the best possible combination of frac parameters for optimum results. Furthermore, FOX is able to do this using only historical (production / injection) data and well completion data. In other words, FOX can do without reservoir data such as porosity, permeability, and stress profile data that are an essential part of any conventional approach.
In this paper FOX is applied to a gas storage field in north eastern Ohio (Clinton Sand). The accuracy of its post-frac deliverability prediction is demonstrated. Using only available historical data optimum frac jobs are designed and the improvement of post-frac deliverability is calculated. A cost - benefit analysis is performed to show the advantages of using this method when compared to conventional approach.
FOX can help the bottom-line by eliminating the need for expensive data collection processes such as well tests, coring,…., while its predictions of post-frac deliverability has a high accuracy. Furthermore, even if such data is available for a field, conventional frac simulators only provide frac job outcome for any particular design, planned by engineers. They are not able to optimize the frac treatment procedure to get the best possible result for any individual well, a capability that makes FOX unique.
Estimation of Turbulence Coefficient Based on Field Observations
Authors: Kelkar M.G. 
Published: December 2007

Abstract
Isochronal testing is commonly used to evaluate the performance of gas wells. This paper proposes a new technique to estimate the value of turbulence coefficient based on isochronal tests. The proposed method is easy to apply and evaluate. Further, the method also provides a value of bg under stabilized conditions which can be used to predict the performance of gas wells under stabilized conditions.
The proposed method is validated using field data under a variety of operating conditions. The values of turbulence coefficient based on the field data can differ significantly compared to the literature correlations. This further shows the importance of obtaining appropriate reservoir parameters based on the field rather than the lab data.

Introduction
The use of isochronal or modified isochronal testing is well established in the gas industry. These tests are common for gas wells which take a long time to reach a stabilized rate. A common example would be a low permeability, fractured reservoir. Instead of testing these wells till a stabilized rate is reached, the wells are tested for a fixed period of time and the bottom hole pressure is measured. For isochronal testing, the well is then shut in till it reaches a stabilized pressure and the procedure is repeated for different rate. For modified isochronal testing, the well is shut in for a fixed period of time, and the shut in pressure is measured at the end of that period. The procedure is then repeated at other rates.
By repeating this procedure for different time intervals, we can gather information about rate versus pressure drop in the formation for these time intervals. Ultimately, using this information, our goal is to establish an appropriate rate versus pressure drop relationship under stabilized conditions.
Two procedures are commonly used to establish the equation for rate versus pressure drop. An empirical method states that,
(1)
where qg is the gas rate, C and n are constants and p and pwf are average pressure and bottom hole pressure respectively. We can write a simpler equation in terms of pseudo-real pressures as,
(2)
where m(p) and m(pwf) are pseudo-real average pressure and pseudo-real bottom hole pressure respectively.
Under transient conditions, the value of C is not constant. Instead, we can write Eq. 2 as,
(3)
where c(t) represents a term which is a function of isochronal interval t. In literature, methods are proposed to estimate the value of C corresponding to stabilized rate based on the transient state information −C(t). See e.g., Hinchman et al. In that paper, Hinchman et al. propose that be plotted as a function of log t, and the line be extrapolated till t is equal to the time it takes to reach stabilized state period. P. 223^
Continuous-Flow Gas-Lift Installation Design Based on Decreasing Production Rate with Required Increased Depth of Lift
Authors: Winkler H. W. , Maier H. 
Published: December 2007

Abstract
A continuous-flow gas-lift installation design for injection-pressure-operated gas-lift valves is outlined on the basis of tubing capacity and daily injection-gas rate. The maximum daily production rate by gas lift decreases with a required increase in the depth of lift. The reservoir inflow performance of the producing formation is not considered in the installation design procedure. This valve spacing method is suited for gas-lift installations in wells with unknown productivity and/or changing reservoir pressure.
Controlling Liquid Load-Up with "Continuous Gas Circulation"
Authors: Boswell J. T. , Hacksma James D. 
Published: December 2007

abstract
"Continuous Gas Circulation" (CGC) is a new method of controlling liquid load-up in gas wells. CGC uses a compressor to continuously circulate the wellbore gas (down the tubing-casing annulus and up the tubing), increasing the velocity of the gas flowing up the tubing. The higher velocity carries liquid to the surface and prevents an accumulation in the wellbore. Accumulating liquid increases the hydrostatic gradient, increases backpressure on the formation and reduces production.
Continuous-Improvement Stimulation Program Generates Excellent Results in the Morrow Sandstone of the North Texas Panhandle
Authors: Harrington T.R. , Lehman L.V. , Bowman M. 
Published: December 2007

Abstract
This paper illustrates a process that allowed the operator to optimize production by placing large concentrations of proppant in the Morrow Sandstone in the North Texas Panhandle. This process first consisted of analyzing data and results from previous Morrow fracture stimulations within the study area, but it soon proressed to optimizing pad volume percentage, proppant grade, perforation scheme, frac fluid selection, and other critical factors over a four-well stimulation project. Initial efforts placed 8 lbm/gal of proppant; by the end of the project, 19.8 lbm/gal were being placed. Stimulation practices developed through this continual improvement process provided more cost-effective results.
This paper illustrates the challenge to place extreme concentrations of proppant in face of a high leakoff environment. This process required the use of an advanced, real-time, three-dimensional (3D) frac model to monitor prefrac calibrations and, in some cases, redesign the treatment to accommodate the leakoff field. Fracture stimulation quality control played a key role in these efforts.

Introduction
The Morrowan Series in the western Anadarko Basin is commonly divided into the Upper Morrow and Lower Morrow formations. Production from both formations is from relatively clean, porous sandstones that comprise some of the most prolific producing gas reservoirs in the Texas and Oklahoma panhandles. Average initial production rates are 3 MMscf/D, with ranges from 0.1 MMscf/D to 21 MMscf/D. To date, the average gas recovery per well is 1.5 Bcf, with ranges between 0.1 Bcf to 8 Bcf. All Morrow wells within the study area are less than 15 years old, and 56% have produced for less than 5 years. These high initial rates are possible with average permeabilities between 5 to 5 md.
The inherent dry-hole risk of both formations can be attributed to the discontinuous nature of Morrow sand deposition. Lower Morrow sands are generally marine barrier/offshore sands deposited parallel to paleo shoreline trends. Within the study area of NE Sherman and NW Hansford Counties (Fig. 1), production typically occurs only at the updip termini of these sands. Upper Morrow sands are fluvial.1 These sands are deposited as discrete point bars within a broader valley system, resulting in a semilinear trend of segregated reservoirs. Only 34% of the Morrow exploration and development tests in the study area encountered productive Morrow.
Morrow fracture stimulation technology has grown dramatically over the past 15 years. In the early 1980's, fracturing jobs were conducted with gelled 3% acid and sand concentrations that rarely exceeded 1.5 lbm/gal. Energized fracturing jobs with N2 and CO2 foams, then became the norm, even in nondepleted wells, because of the nondamaging nature of these fluids. Job schedules were more aggressive, but sand concentrations rarely exceeded 4 lbm/gal.
Use of Acoustic Surveys for Field Calibration of Surface Readout BHP Gages in ESP Installations
Authors: McCoy J. N. , Podio A. L. , Rowlan Lynn , Garrett Mark 
Published: December 2007

Abstract
The use of surface readout BHP gages in ESP systems has become more prevalent with the development of cost effective installations. In spite of the improvement in their reliability, the BHP pressure sensors are subject to zero drift during their operational life. It thus becomes necessary to periodically check the indicated pressure and adjust its value to eliminate the zero shift. Since it is not economically justifiable to pull the tubing and the sensor, a method has been developed and field tested that permits to make the calibration check from surface measurements.
In an operating well, the method requires the periodic measurement of annular surface pressure using a pressure transducer with an accuracy of 0.1% and acoustic fluid level depth digitally acquired with a resolution of one millisecond while the casing valve is closed and produced gas is accumulating in the annulus. As fluid enters the wellbore the liquid is produced through the pump while the gas accumulates in the casing annulus. A software program determines the density of the gas in the annulus and computes the pressure at the gas/liquid interface accounting for the effect of the gas column hydrostatic. The process is continued until the gas/liquid interface is displaced near the pump intake, at which point the computed bottom hole wellbore pressure should be very close to the pressure indicated by the surface readout. Any discrepancy between the two measurements is used to estimate the zero shift and to correct the surface readout.
Effective HCl Diffusion Coefficients From Correlations of HCl-Limestone Reactions
Authors: Mumallah Naim A. 
Published: December 2007

Abstract
Hydrochloric acid solutions were reacted with limestone core plugs using an annular flow reactor at acid-fracturing conditions. The obtained reaction rates were correlated with theory using a correlation that was recently verified to be suitable for correlating HCI reaction rate with mass transfer parameters. Applying the correlation to the present data produced effective diffusion coefficients for HCI from the different acid solutions at acid-fracturing conditions. The results showed that the diffusion coefficient of an acid solution made in distilled water was larger than the diffusion coefficient of an acid solution made in synthetic North Sea water. The diffusion coefficient of a retarded acid was found to be an order of magnitude smaller than the diffusion coefficient of neat acid.
Kinetics of the Primary Reaction of HF on Alumino-Silicates
Authors: Gdanski Rick 
Published: December 2007

Abstract
The standard description of HF-acidizing chemistry clearly demonstrates a primary and secondary reaction of HF with alumino-silicates.1 Field experience has taught our industry that possible precipitation during the secondary reaction can ad-versely affect treatment success,2 especially in formations with high K-feldspar content or temperatures above 300°F. Recent work has also reported the existence of a third, or tertiary reaction of HF with alumino-silicates.3
This paper reports the determination of the rate law and kinetics for the primary reaction of HF on sand, clay, and feldspar over a broad temperature range. The rate law for the primary reaction of HF with sand had no HC1 dependence and was second-order in HF concentration. The rate law for the primary reaction of HF with clay and feldspar was assumed to also have no HC1 dependence and was adequately described by a first-order in HF concentration. In addition, a mass transfer equation for reactive fluids flowing through porous sandstone media is proposed. These findings were made possible by recently applied experimental techniques including 19F NMR Spectroscopy,3 fractional pore-volume flow experiments4 and an accurate knowledge of the HF stoichiometry.5 Laboratory findings have been verified through detailed analyses of flowback samples from field treatments.6
Field Evaluation and Optimization of Matrix Acidizing Treatments
Authors: da Motta E. Ponce , dos Santos J.A.C.M. , Zhu D. , Hill A. D. 
Published: December 2007

Abstract
In a matrix acidizing treatment, it is extremely important that the appropriate acid formulation be used, that no damage be left in the reservoir, and that no excess acid be injected. Nowadays, this can be easily accomplished with the aid of computerized real-time monitoring techniques, which provide on-site evaluation of the stimulation results.
We applied a real-time monitoring technique to a series of acidizing treatments to evaluate stimulation performance and to optimize subsequent treatments in the same area. From the measured surface pressure and injection rate, a computer program calculated the bottomhole pressure and estimated the skin factor as the treatments progressed. In this way, the responses of the wells to stimulation were evaluated. Real-time monitoring of the evolving skin factor showed when further acid injection resulted in no further stimulation, leading to reduced acid volumes in subsequent treatments.
By applying this real-time monitoring method, we have improved acidizing practices in two fields, located in the northern part of Brazil. In a series of injection well treatments, acid volumes were reduced by 25% from standard practice, with no loss in acidizing efficiency. We were also able to change one of the acid compositions from regular mud acid to a more compatible 6% HC1/1.5% HF.
In more sensitive production well treatments, the real-time monitoring of skin factor may be even more useful by ensuring total damage removal or in identifying deleterious effects of overtreatment More importantly, this technique will also indicate when design changes such as increased acid volume, different acid formulation, or different injection rate schedule are needed to reach the treatment objectives.
Optimization of Stimulation Treatments for Improved Oil Recovery in Complex Lithological Reservoirs
Authors: Yao C. Y. , Squyres J. W. , Baycroft P. D. 
Published: December 2007

Abstract
Well stimulation normally consists of matrix acidizing, acid fracturing and proppant fracturing. The optimum stimulation treatment depends on both reservoir characteristics and the formation damage mechanism. The oil recovery can be improved with successful stimulation treatments.
This paper presents a case study of a pilot stimulation project in the Onbysk oil field in Tatarstan, Russia. The objective of this project was to optimize stimulation treatments in geologically complex reservoirs for the improved oil recovery. The Onbysk field consists of seven stacked reservoirs with a complex lithology of shaly sandstone and limestone with microfractures. Different stimulation techniques have selective applications to different reservoirs for improved oil recovery. The improved oil recovery has been evaluated using production history data and decline technique.
An Experimental Investigation of the Diversion Characteristics of Foam in Berea Sandstone Cores of Contrasting Permeabilities
Authors: Siddiqui S. , Talabani S. , Yang J. , Saleh S. , Islam M. R. 
Published: December 2007

Abstract
Foam has been used successfully in the field as a diverting agent for matrix acidizing when layers of contrasting permeabilities are present. However, the mechanisms governing the diversion performance of foam are still not properly understood and only a limited number of foam diversion papers can be found in the literature. This paper discusses the results from several dual-core experiments using 11- and 22-inch long and 1.5-inch diameter fired Berea sandstone cores (permeability range: 10 to 1000 md) in which parameters such as foam quality, total injection rate, foam slug size, etc. are varied systematically for different permeability contrasts. Each experiment consists of a gas-free surfactant injection phase, followed by a foam injection phase, which is then followed by a brine injection phase simulating the post-foam acid injection stage. The pressure data along each core at four locations and the weight of the liquid effluents for each core are recorded continuously. An attempt is made to quantify the diversion performance by the introduction of various diversion factors. The effect of each of the variables such as foam quality, injection rate, slug size etc. on the diversion factors are then compared for different permeability contrasts. Results show strong dependence of the diversion performance on permeability contrast, foam quality and total flow rate. This study provides important guidelines for designing acid jobs for different permeability contrasts and ranges when foam is used as a diverting agent.
Water Cone Histeresis and Reversal for Well Completions Using the Moving Spherical Sink Method
Authors: Shirman E. I. , Wojtanowicz A. K. 
Published: December 2007

Abstract
Presented in this paper is a theoretical and experimental study of water cone development and reversal. The theoretical study employed a new analytical method, called moving spherical sink model (MSSM), for accurate modeling of flow in the vicinity of a limited-entry well in a heterogeneous (kv,kh) reservoir. In contrast to other analytical models, MSSM does not lose validity in the near-well zone. It calculates pressure precisely at and outward from the borehole surface. This high resolution of MSSM in well's vicinity enables studying flow mechanisms that have been beyond competence of conventional models such as pressure distribution outside well's completion and development and reversal of water coning.
The results of this water coning study show that for oil production rates below critical (breakthrough) rate there are two equilibrium shapes of the water cone: lower (stable), and upper (unstable). Also shown is a hysteresis of the water cone height development and reversal caused by the increase – decrease scheme of production rate. The paper explains why reversing the cone is difficult because it requires reduction of production rate much below its critical value. It also describes how to determine the water cone reversal rate.
The experimental part of this study provides verification of the theoretical findings using a physical model. The results, summarized in this paper, showes all four stages of the water cone histeresis: from equilibrium cone buildup with increased production rates, to stability loss followed with water breakthrough at critical production rate, to continuing water breakthrough in spite of decreasing production rates, to water cone reversal at very low value of the reversal production rate.
This study provides basic understanding of stability mechanisms that control three-dimensional water coning. It also provides an analytical method for finding the cone reversal production rates.