bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimization of Barite Dissolvers by Organic Acids and pH Regulation
Authors: Lakatos I. , Lakatos-Szabó J. , Kosztin B. 
Published: December 2007

Abstract
The data in literature clearly proved that the polyamino carboxylic acids (PACAs) are promising barite dissolvers. So far, however, only the ethylene-diamin-tetraacetic acid (EDTA) and the diethylene-triamin-pentaacetic acid (DTPA) were studied and tested in detail. Therefore, an extensive research programme was launched to compare the potential of other barite dissolvers. The laboratory study were also extended to nitrilo-triacetic acid (NTA), diamino-cyclohexane-tetraacetic acid (DCTA), dioxaoctamethylene-tetraacetic acid (DOCTA), hydroxyethylene-diamin-triacetic acid (HEDTA) and triethylene-triamin-hexaacetic acid (TTHA).
Dissolving capacity of each compounds was determined as a function of concentration for barite and reservoir rocks. The absolute and relative dissolution selectivity and the matrix effect of formation rocks were precisely analyzed. Independent variable of the measurements was the pH and type of organic acids used as complex-forming promoters. In the batch type studies oxalic acid (OXA), malonic acid (MOA), maleic acid (MEA), succinic acid (SUA) and tartaric acid (TARA) were tested. It was concluded that the performance of well treatment methods (mitigation of formation damage, removal of barium sulfate scales, etc.) based on application of polyamino carboxylic acids can significantly be increased by adding sodium (potassium) hydroxide to the complex-forming agents and setting its concentration to optimal level. Application of organic acids jointly with polyamino carboxylic acids, however, could not be justified if the dissolver system had already been optimized by alkali addition. Thus, from practical point of view it has to be emphasized that optimization of barite dissolving methods by pH regulation is much more efficient and cost-effective than adding multi-functional organic
Acid Removal of Scale and Fines at High Temperatures
Authors: Huang T. , McElfresh P. M. , Gabrysch A. D. 
Published: December 2007

Abstract
With the onset of water production, fines are usually mobilized to the wellbore, resulting in screen plugging. Fines-plugged screens and/or gravel pack can then accelerate scale precipitation, especially in high-temperature formations. Due to the type of metallurgy, long acid contact times and high acid sensitivity of the formations, removal of the scale with HCl acids has been largely unsuccessful. In high-temperature wells, the choice of acid must be done such that the formation and the completion are not damaged, but the scale and the fines are removed. A series of tests conducted on screens and clay-rich cores show that a new organic acid system, which is highly biodegradable, can successfully remove the calcium carbonate scale and fines to stimulate production. Core flood testing demonstrates that this organic acid system can effectively remove calcium carbonate scales and fines at temperatures up to 204°C(400°F). In addition to its reactivity, the acid system, when combined with corrosion inhibitor, exhibits very low corrosion at high temperatures. Corrosion tests show that at 177°C (350°F), the corrosion rate caused by this organic acid is 0.00049 g/cm2 (0.001 lb/ft2) on 22-Cr for 16 hours. Acid soaking to completely remove scale prior to removal of fines is now possible at temperatures in excess of 121°C (250°F). Successive removal of plugging fines from screens can then proceed without further damage to the integrity of the screen.
Stimulating Depleted HP/HT Sand Screen Completions using Coiled Tubing
Authors: Munro C. , Allam R. , Erbil M. M. , Law D. 
Published: December 2007

Abstract
The Marnock Field contains four near horizontal gas condensate producers containing open hole dual wire wrap sand screens. Virgin pressure was 9123 psia but has dropped significantly on three wells to as low as 2200 psia. Reservoir temperature is 310°F. Pressure build up and material balance data showed limited inflow from the Marnock wells, and this was thought to be due to possible wellbore and sand screen mud blockage as only 50% of the drilling mud was recovered on initial well clean ups. Platform based stimulations were conducted in three wells to remove wellbore mud damage and potential sand screen mud blockage. Stimulation techniques consisted of a coiled tubing chemical placement from above the sand screens, a surface bullhead treatment and a coiled tubing sand screen jet wash. Barite attacking chemicals were deployed as the main treatment, including diversion for the bullheading operation.
Preparation, planning and execution of these stimulations have been complex given the potential to access un-depleted virgin reservoir pressure intervals. Well flow back and clean up post chemical deployment was critical and extensive chemical compatibility trials were carried out to ensure no damage to the formation or the process plant was incurred. A temporary clean up package including a high pressure cyclonic de-sander was used to separate flowback products and protect the process plant from solids contamination.
No significant well intervention operations had been conducted previously on the Marnock field on a non–rig basis apart from slickline operations. The challenges faced with installing and operating a full coiled tubing package including support tower and clean up package were substantial. Robust contingency measures were required to address the issues of stuck pipe, pipe cutting, well kill and high-pressure zones. Contingency innovations included the design and manufacture of an explosive cutter suitable for the heavy wall tapered coiled tubing. A special kill pill was also formulated for use with Cesium Potassium Formate in the event of a high-pressure well kill. Platform modifications were also required to enable the tie in of large diameter high and low pressure relief lines to the existing facilities.
As a result of the stimulations the Marnock Field has increased production potentials by 105 mmscf/d of gas and 6500 stb/d of associated condensate, equating to an increase of 25,000 boe/d.
New Empirical Friction Loss Correlation for Foam Fluids in Coiled Tubing
Authors: Khade Sudhakar D. , Shah Subhash N. 
Published: December 2007

Abstract
Friction losses for foam fluids in coiled tubing are not the same as that of in straight tubing. The flow properties of the foam are also very different than that of conventional two-phase fluids7. Factors like foam quality, liquid phase viscosity, flow rate, gel concentration, temperature, and curvature of pipe strongly affect the frictional behavior of foam fluids. The present work discusses and analyges friction pressure losses and rheology, and friction loss correlation development for guar based foam fluids through coiled tubing.
The present study investigates frictional pressure losses in coiled tubing for polymer based foam fluids. The experiments are conducted using guar gel and guar foam employing a pipe flow viscometer at 1000 psig. Foams are prepared and tested for qualities 0 to 80 % at various shear rates using temperatures from 100 to 200 °F. Three polymeric foam solutions are examined for their frictional pressure losses related to their flow behavior in coiled tubing.
The experimental data of differential pressure drop and flow rate converted to Fanning friction factor and Reynolds numbers respectively are used to obtain new empirical correlations to predict Fanning friction factors. These empirical friction loss correlations are function of foam liquid phase properties and curved geometry, and are applicable for the range of shear rates investigated. Significant increase in friction pressure loss is observed in coiled tubing compared to that in straight tubing. Empirical friction loss correlations can be used to predict an accurate Fanning friction factor for foam fluids in coiled tubing.
Improved CT Operational Efficiency by Use of Detailed Planning
Authors: Laun Lyle , Young Steve , Sund Jon-Arild , Vibjorn Dagestad 
Published: December 2007

Abstract
Offshore well operations in the North Sea involve many contractors and require a lot of co-ordination with the platform organization. Well shut-in time is a critical factor because the wells are producing high volumes (up to 56 000 bbl/day initially). Due to this, a project group was formed to improve the efficiency of coiled tubing operations on the Heidrun field. The field center is a Tension Leg Platform (TLP) at 330 m water depth. Because of rig movement, a complicated rig-up structure with heave compensation is used. On most operations, both coil tubing and wireline is used throughout the different operational phases. This comes in addition to pumping and return handling equipment. A lot of equipment is rigged up in a relatively confined area.
The project group started off with identifying all operational steps and finding the critical path. Areas with high potential for savings were identified and the cost for proposed improvements were calculated. Systematic implementation of improvements to the rig-up equipment and procedures gave a reduction in the rig-up time from 82 hours down to 11.5 hours over a 6-month period. As an extra bonus, the operations were carried out at a higher safety level than before. The savings for the client were calculated to USD 450 000 per well, whilst the cost of new equipment, modifications and implementation was USD 110 000.
Development of a Stiff-String Forces Model for Coiled Tubing
Authors: McSpadden A. , Newman K. 
Published: December 2007

Abstract
A mathematical model of tubing forces is proposed which accounts for the bending moment due to stiffness of the coiled tubing (CT) string. The models commonly used in the design of CT operations have typically ignored tubing stiffness. Exclusion of tubular stiffness effects in such "soft string" models has not typically detracted greatly from the accuracy of predicted drag and torque loads. However, CT is being used increasingly in applications such as pipeline workover which may be characterized by unusually small bending radius. In these cases the exclusion of bending stiffness may be result in increased error. The calculation of CT bending moment for CT should also account for plastic bending and residual stresses incurred at the guide arch and reel. Example calculations are presented to evaluate the usefulness of the proposed "stiff-string" model for CT job design.
Pressure Transient Analysis In Bottom Water Drive Reservoir With Partial Completion
Authors: Tippie D.B. , Abbot W.A. 
Published: December 2007

Abstract
A study of a partially completed massive carbonate reservoir with a strong bottom water indicates that existing buildup theory does not adequately describe the flow system under producing conditions. Examination of field well producing conditions. Examination of field well test data using conventional transient radial analysis techniques and results from a single well radial simulation model show that flow geometry changes with time during the buildup period. Studies show that while spherical flow period. Studies show that while spherical flow initially exists during flow and shut-in periods, the system undergoes changes from spherical to hemispherical to linear vertical flow geometry. Permeabilities determined from radial buildup Permeabilities determined from radial buildup analysis do not agree with those determined from drawdown analysis because the flow geometry changes with shut-in time. The results of this study suggest that transmissibility, formation damage and permeability should be determined from drawdown tests which describe the flow system under producing operations. Flow nets are presented to illustrate flow geometry at various presented to illustrate flow geometry at various flow and shut-in times.

Introduction
A study of a partially completed massive carbonate reservoir with a strong bottom water drive indicates that existing buildup theory does not adequately describe the flow system under producing conditions. When partial completions producing conditions. When partial completions exist in a reservoir of this type, it will be shown that the flow geometry during the buildup period changes with time and that existing period changes with time and that existing buildup theory does not adequately describe the flow system under producing conditions. Failure to consider this phenomenon results in erroneous permeabilities and formation damage factors permeabilities and formation damage factors calculated from buildup curves by conventional techniques. This study indicates that drawdown testing should be used for calculating permeability and formation damage. Recognition permeability and formation damage. Recognition that the drawdown tests give more reliable values of permeability and formation damage than buildup tests may save a company considerable time and making performance predictions.
Physical and Numerical Simulations of Steamflooding in a Medium Crude Oil Reservoir, Lake Maracaibo, Venezuela
Authors: Ovalles Cesar , Angel Rico , Perez-Perez Alfredo , Hernandez Miguel , Guzman Nora , Anselmi Lorenzo , Manrique Eduardo 
Published: December 2007

Abstract
Physical and numerical simulations of steamflooding were carried out to determine the technical feasibility of applying this technology to a medium crude oil reservoir (25° API) located in the Lake Maracaibo, Western Venezuela, specifically, 3rd phase LL-03 reservoir. A one-dimension cell with steam injection (80% quality and 400 psi) was used to study the steamflooding behavior at laboratory scale. Oil rates cumulative oil productions and temperature profiles were reported and the results showed an increase of 14-20 percent of oil recovery with respect to original oil in place after waterflooding. Additionally, the use of steam drive as primary recovery method showed an additional of 5% in cumulative oil production. Compositional-thermal numerical simulations were carried out and validated using the laboratory scale results. Based on analysis of the crude oil true boiling point curve, the oil fraction was represented by a three pseudo-components model. The results (oil rates and cumulative oil productions) showed a reasonable match between the calculated and experimental simulations.
Using this model, a numerical simulation study was carried out in a seven-spot inverted pattern (300 m) in order to provide performance forecast and other useful information for the design, implementation and operation of a field scale steamflooding test. After seven-year of steamflooding, the simulation showed only 15 percent of incremental oil recovery in comparison with waterflooding. However, using a five-spot inverted pattern (100 m), 2.5-fold increase in cumulative oil production can be predicted with respect to waterflooding during the same period. Based on these results, it can be concluded that steamflooding technology in a Lake Maracaibo medium crude oil reservoir (25° API) represents a feasible alternative with high potential applications.
Experimental Study of Heavy Oil Production from Diatomite by Water Imbibition at Elevated Temperatures
Authors: Tang G. , Kovscek A. R. 
Published: December 2007

AbstractOil production from many fractured reservoirs is frustrated by not only low matrix permeability but also large oil viscosity and a matrix wettability state that is not sufficiently water wet to favor water imbibition. Some diatomaceous reservoirs, especially those containing heavier crude oil, appear to exhibit these attributes. Thermal recovery using hydraulically fractured wells is one process to improve oil recovery and unlock these heavier resources. Steam injection is typically carried out under saturated conditions and initial heating of a reservoir is accompanied by significant condensation and flow of the resulting hot water away from the injector. Thus, hot-water imbibition is an important component of thermal recovery in fractured, low permeability porous media.This work presents the results from a series of spontaneous, counter-current water imbibition tests using outcrop diatomite cores (2 to 4 md) and reservoir diatomite cores (0.8 to 2 md). The experiments are isothermal and temperatures from 20 to 180°C are explored. Decane (nC10), two white mineral oils with differing viscosities, and heavy diatomite crude oil were all used as oil phases. At room temperature, oil-phase viscosities ranged from 0.9 to 6400 mPa-s. An X-ray computed tomography (CT) scanner, in combination with a high-temperature and high-pressure core holder, was used to visualize fluid movement and production of these oils. It is observed that temperature has a significant effect on water imbibition rate and residual oil saturation to spontaneous imbibition. In reservoir core filled with crude oil, the spontaneous oil recovery increased from 3% at 40°C (reservoir temperature) to more than 40% of oil in place at 180°C. The effect of temperature is to reduce oil-phase viscosity and increase water wetness of the rock. Finally, it is found that the experimental data scale according to dimensionless groups available in the literature. Inclusion of the mobility ratio as a function of temperature during scaling is necessary to collapse data.
How Artificial Intelligence Methods Can Forecast Oil Production
Authors: Weiss William W. , Balch Robert S. , Stubbs Bruce A. 
Published: December 2007

Abstract
The application of artificial intelligence tools such as fuzzy logic and neural networks is evolving as an oilfield technology. Log analysis work done in 1989 by Halliburton focused on applying backpropagation neural networks to identify total porosity and to identify lithofacies. In 1996 PRRC researchers used fuzzy logic to prioritize the significance of petrographic attributes to minipermeameter permeability measurements. Recently (2001), Zadeh Institute workers revisited the use of these tools in a manner consistent with soft computing terminology. In this paper, fuzzy ranking is used to prioritize inputs to neural networks that are trained, tested, and used to forecast oil production.
Patterns related to oil production are sometimes obvious in datasets from easy-to-interpret logs, but sometimes they are not, such as those in datasets from logs run through thin-bedded turbidite zones. The correlation between the individual log charts and core measurements varies from "good" to "bad" (fuzzy).
A neural network can be used to generate regressions when given the "good" log charts. The regression equations are developed with several log charts and core measurements and the resulting pseudo-logs are then correlated with known production. The resulting correlations can be used to estimate future oil production from potential producing wells.
Two field examples are used to demonstrate the fuzzy ranking technique and production forecasting correlations. The method to generate fuzzy curves is presented and sources of public domain neural networks are included in the references. The pitfalls involved in training and testing a neural network to predict oil production are also presented.
Conformance Improvement with Low Concentration Polymer Gels in a Heterogeneous, Multilayer Reservoir
Authors: Wouterlood C. J. , Falcigno E. D. , Gazzera C. E. , Norman C. A. 
Published: December 2007

Abstract
The Entre Lomas Block is located in the northeastern Neuquen Basin of Argentina. The Block, with an area of 742.5 Km2, is divided by the borders of Neuquen and Rio Negro provinces (Figure 1). The area includes two large anticlinal structures, Charco Bayo (CB) and Piedras Blancas (PB), that are productive from the Tordillo Formation.
The field, located approximately 90 kilometers north of Neuquén City, Argentina, was discovered in 1960. In 1975, secondary recovery operations began in the Charco Bayo structure.1 As of November 2001, the oil production rate of Tordillo Formation was 936 m3/d (5,887 bbl/d), with a cumulative produced crude oil volume of nearly 20 MMm3.
Due to reservoir heterogeneity and low permeability, cumulative oil production as of December 2001 was approximately 13.5 % of OOIP. Water channeling has been severe in most areas of the field, in spite of previous efforts to improve reservoir conformance with cement, aluminum silicate squeezes, and selective injection installations2.
In 1995, Petrolera Perez Companc S. A. (PPCSA) performed several high concentration, low volume injection well gel treatments. In 1999, further study indicated that lower concentration injection well gel treatments would be more appropriate in the Tordillo formation. This new gel treatment strategy was implemented in 1999/2000 in a group of injection wells. Certain marginally economic producing wells were also treated with higher polymer concentration gels. This paper describes the results of the 1999/2000 gel campaign.
As of November 30, 2001, PPCSA has quantified 585,800 barrels of incremental oil associated with the gel treatments, at a cumulative cost of approximately $2.22 per barrel. Incremental costs are expected to decline further as the oil response to the gel treatments reaches maturity.
Improved Oil Sweep through Discrete Fracture Network Modeling of Gel Injections in the South Oregon Basin Field, Wyoming
Authors: Dershowitz W. , Shuttle D. , Parney R. 
Published: December 2007

Abstract
Gel injection is used with water injection in fractured and heterogeneous reservoirs to decrease water production and improve the oil sweep efficiency. Gel treatments are able to achieve this because the gel is preferentially deposited to the most conductive fractures, blocking the water flow through those structures, and forcing to water to displace oil from the rock matrix instead.
This paper describes discrete fracture network (DFN) analyses and simulations of gel injection at the South Oregon Basin, Wyoming Phosphoria formation. These simulations were carried out to evaluate the efficacy of gel injection in improving water injection strategies.
The Mathematical Model of Non-Equilibrium Effects in Water-Oil Displacement
Authors: Barenblatt G. I. , Patzek T. W. , Silin D. B. 
Published: December 2007

Abstract
Forced oil-water displacement and spontaneous countercurrent imbibition are crucial mechanisms of secondary oil recovery. The classical mathematical models of these phenomena are based on the fundamental assumption that in both these unsteady flows a local phase equilibrium is reached in the vicinity of every point. Thus, the water and oil flows are locally redistributed over their flow paths similarly to steady flows. This assumption allowed the investigators to further assume that the relative phase permeabilities and the capillary pressure are universal functions of the local water saturation, which can be obtained from steady-state flow experiments. The last assumption leads to a mathematical model consisting of a closed system of equations for fluid flow properties (velocity, pressure) and water saturation. This model is currently used as a basis for predictions of water-oil displacement with numerical simulations.
However, at the water front in the water-oil displacement, as well as in capillary imbibition, the characteristic times of both processes are comparable with the times of redistribution of flow paths between oil and water. Therefore, the non-equilibrium effects should be taken into account. We present here a refined and extended mathematical model for the non-equilibrium two-phase (e.g., water-oil) flows. The basic problem formulation as well as the more specific equations are given, and the results of comparison with experiments are presented and discussed.