bluuebunny/crossref_metadata_2025_split huggingface dataset:
Transient Two-Phase-Flow Model for Predicting Column Formation in Intermittent Gas Lift Systems
Authors: Sandoval S. , Solórzano L. R. , Gasbarri S. 
Published: December 2007

Abstract
The intermittent gas lift (IGL) method has experimented a continuous growth due to well depletion and so is expected from its technology.IGL is a periodic transient process with two major stages: firstly, a liquid column or slug is accumulated at the bottom of the well.Secondly, the slug is displaced by pressurized gas lift to the surface. Current models estimate the height of the fluid column based on single-phase behavior due to the lack of multiphase transient models. These models underestimate dramatically the column when the operating gas lift valve is located far away from the perforations. To improve this model a study focused on a two-phase flow behavior during the accumulation stage is required. In order to achieve this objective a special multiphase flow facility was assembled and more than 200 steady and transient tests were run.Continuous and transient tests were performed with flow conditions and fluid properties selected from typical fields.The collected data allowed identifying the variables that govern the phenomena and establishing a methodology to determine the mixture density, pressure gradient and column's height. Since no previous correlation matched, a new correlation for transient hold up was generated using qualitative and dimensionless analysis. As part of the approach proposed here, time was included implicitly into the equations in order to reduce their complexity. The analysis showed that Reynolds's number, homogeneous liquid holdup and dimensionless viscosity govern the phenomenon. The model was validated with field data . The correlation applies to slug and churn flow patterns because those are the expected patterns for typical field conditions. The accuracy obtained with field data suggests applying this approach for designing and optimizing IGL installations.
Local Experiences Obtained During Appraisal of Heavy and Viscous Oil in Deep Water
Authors: Barreto W. S. 
Published: December 2007

Summary
There are many challenges related to the appraisal of heavy and viscous oil reserves. When this includes a deep-water offshore environment the challenges, including safety issues, increase in complexity. In this paper we share some experiences obtained during the preparation and execution of heavy oil appraisal activities. It is presented a methodology which uses the preliminary results of petrophysical and fluid characterization obtained during the logging phase, as well as prior information from correlated field/wells, in order to design the appropriate configuration and location of the ESP (Electrical Submersible Pump) in the DST (Drill Stem Test) string and the sampler location, which should allow single-phase sampling. During the operation, real-time data interpretation is performed, validating the data obtained and sensitizing parameters such as pump frequency, bubble point pressure, GOR and viscosities, allowing the diagnosis of the operation and consequently appropriate flow conditions in order to provide a optimum picture, supporting decisions regarding sampling time and other specific appraisal objectives. The examples presented illustrate the proposed methodology for integrated appraisal applied to heavy oil, and show its benefits.
Appraisal of Heavy and Viscous Oil in Deep Water
Authors: Barreto W. , Ribeiro C. , Menezes P. , Armacanqui G. , Souza R. 
Published: December 2007

Abstract
Discussions regarding appraisal of heavy and viscous oil in deep water are the subject of this paper. It is destined to new engineers and professionals unfamiliar with DST-ESP-SWT operations in deep water.
It is introduced here a methodology that has been applied locally supporting well testing design and optimization. The process consists in an integrated and fast rock&fluid characterization supporting the DST-ESP-SWT design. During the operation, the optimization of the operation is performed by real time monitoring and lift diagnostic, combined with surface measurements. Our experience related to the application of the referred methodology is illustrated by examples where the benefits of such process are featured. Finally, it is introduced the concept of an integrated appraisal service, which proposes to be a powerful mechanism in order to facilitate the evaluation of complex systems such as heavy and viscous oil in deep water wells.
System for Remote Detection of Pipeline Leakage
Authors: Sadovnychiy S. , Bulgakov I. , Valadez J. 
Published: December 2007

Abstract
This article deals with the development of a remote detection system for early detection of leakages in the oil and gas pipelines. The system is designed to receive data's from various electronic equipments operating in differentfrequency ranges and corroborate the data's with suitable formula's to get the ultimate better yield. Four types of information sensors form the major part of equipment: an infrared camera, a video camera, a laser spectrometer and global positional system. A joint data handling allows to determine the presence and location of leakages.
3D CFD Simulation of ESP Rotary Gas-Separator Performance Under Two-Phase-Flow Condition
Authors: Suarez L. , Kenyery F. , Azuaje M. , Peña M. 
Published: December 2007

Abstract
The performance prediction of a Rotary Gas Separator (RGS) is very important for ESP systems applications. The pump performance is severely affected when it handles high Gas Void Fraction (GVF) at its intake. The function of the RGS is to separate both liquid and gaseous phases, and to expel the gas through a crossover section to the annular area between casing and tubing. Typical designs use separation efficiency values based on an empirical standpoint of view. Also, the literature references regarding an important parameter like the inducer head is very scarce. The performance analysis of a RGS (540 series separator), under two-phase flow conditions, has been conducted using 3D-CFD simulation tools (CFX 5.6). Water-air mixtures were used as working fluid and the mixture GVF was varied from 10% up to 30%. The results shows that the RGS separates efficiently the phases, but the inducer head is insufficient to overcome the friction losses in the crossover and the liquid column static pressure in the annular space. As a consequence, a new inducer design is necessary to create a higher head value to push the gaseous phase out of the RGS and not to be dragged by the liquid phase. The simulation could be an alternative tool for selecting the depth of the downhole equipment as a function of the liquid level. This could help the designer to properly obtain the minimum submergence of the equipment that satisfy the phases separation and gas expulsion of the RGS, getting a lower GVF at the PIP.
Identification of Water-Bearing Layers with Resistivity Image Logs
Authors: Naides C. , Paris M. 
Published: December 2007

Abstract
Traditionally, wellbore images logs have been used to perform structural and stratigraphic analyses. This study presents an approach of the resistivity image oriented to the identification of aquifers, further enlarging the application scope of this tool. From the analysis of borehole resistivity image logs, special image characteristics were observed, which were not related to their traditional application. Consequently, an analysis was carried out integrating well logs and interpreted core data for two different areas and formations located in Argentina in the Neuquén Basin: once at Lower Troncoso Member of the Huitrin Fm (Aptian), and the other at the Sierras Blancas Fm (Kimeridigian). This particular response from resistivity images was calibrated to reservoir zones with high water saturation, corresponding to aquifers.
Certain features were observed in the studied cases which constitute a condition for positively identifying aquifers by means of borehole electrical images. These are as follows: Clastic reservoirs (sand/clay).Reservoirs with good petrophysical conditions.Drilling mud salinity values similar to formation water salinity values.
The high resolution rendered by this image logging tool makes it possible to identify high-water-saturation zones and accurately locate oil-water contacts. No special processing is required, and decisions can be made based on the direct observation of the recorded image.
Use of Quantitative Risk Analysis for Uncertainty Quantification on Drilling Operations-Review and Lessons Learned
Authors: Cunha J. C. , Demirdal B. , Gui P. 
Published: December 2007

Abstract
This paper presents comments and some background on the use of risk analysis methods in the oil and gas industry. Particularly attention is given to applications developed specifically for drilling operations. A literature review emphasizing articles written specifically for risk analysis applications on oil & gas well drilling operation is presented.
Recommendations for procedures related to risk analysis methods implementation as well as an example of application and its results are presented.
A Monte Carlo simulation was run to predict a cumulative distribution function for a well drilling AFE (Authorization For Expenditure.) The simulation procedure as well as the resultant function is presented.
Temperature Behavior in Multilateral Wells: Application to Intelligent Well
Authors: Romero A. , Zhu D. , Hill A. D. 
Published: December 2007

Abstract
Intelligent well completions are being increasingly used in complex wells (horizontal, multilateral, or multibranching). Such completions are equipped with permanent sensors to measure temperature and pressure profiles, which then must be interpreted to determine the inflow profiles of the various phases produced. Distributed temperature measurements using fiber optics in particular are becoming increasingly applied The value of an intelligent completion hinges on our capability to extract such inflow profiles, or, as a minimum, to locate the entry locations of undesirable water or gas entries. In this paper, we develop a model of temperature behavior in multilateral wells. The model predicts the temperature profiles in the build sections connecting the laterals to each other or to a main wellbore, accounting for the changing well angle relative to the temperature profile in the earth. In addition, energy balance equations applied at each junction predict the effects of mixing on the temperature above each junction.
We applied the multilateral wellbore temperature model to a wide range of cases to determine the conditions for which intelligent completions are most useful. Parameters varied included fluid thermal properties, absolute values of temperature and pressure, geothermal gradient, flow rates from each lateral, and the trajectories of each build section. From this parametric study, guidelines for the optimal application of intelligent well completions are represented.
Determining Relative Permeability from Unsteady-State Radial Fluid Displacements
Authors: Toth J. , Bodi T. , Szucs P. , Civan F. 
Published: December 2007

AbstractThe practical interpretation formulae which can be used for determination of the relative permeability data from the production and/or injection performance data are derived based on the formulation of the near-well-bore immiscible fluid displacement process. The formulations for convenient calculation of the relative permeability data similar to the JBN method are provided and validated using the laboratory data obtained by the radial immiscible fluid displacement tests in horizontal porous disks. The applications demonstrate the capabilities of the present interpretation method.
A New Chemical Treatment to Remove Multiple Damage in a Water Supply Well
Authors: Nasr-El-Din H. A. , Al-Mohammad A. M. , Al-Hajri M. A. , Chesson J. B. 
Published: December 2007

Abstract
A vertical well has a history of problems which has contributed to its disappointing performance. A 15 wt% HCl acid treatment was performed in an attempt to remove drilling mud filter cake and improve wellbore to formation connectivity, however the solubility of the formation's cementation material (calcite) was overlooked and sand production resulted after the treatment. A screen liner running operation was then performed, with a need for sand control, and massive mud losses and polymer pills were lost to the formation during the process.
The workover fluids were displaced deep into the formation while loading the hole to maintain well control. The presence of biopolymers in the completion fluids enhanced the activities of sulfate reducing bacteria (SRB). These bacteria further compounded the problem, and the damaged environment was ideal to initiate the production of plugging FeS and biomass in the near wellbore region. Ultimately, the formation was not able to deliver the necessary flow rate to supply the ESP pump when the well was returned to production.
The damage mechanism is a combination of polymer residue, biomass and FeS plugging the screen liner. A three-stage treatment was designed to remove the damaging material. The first stage was based on tetrakishydroxy methyl phosphonium sulfate (THPS) and was designed to remove iron sulfide and hydrogen sulfide, and control the growth of bacteria. The second stage was based on formic acid and was intended to remove FeS and some of the polymer residue in the near wellbore area. The third stage was based on a two-part oxidative treatment and was designed to remove polymer damage deep in the formation. Analysis of well flowback samples before and after the treatments was used to confirm the damaging mechanisms and to evaluate the treatment.
This paper reviews the procedure used to identify the problem, and the unique treatment which successfully restored well productivity.
Hydraulic Frac Stimulations in a Libyan Oil Field - A Case History
Authors: Droegemueller U. , Leonhardt B. 
Published: December 2007

Abstract
Wintershall started in 1994 with the preparation of frac treatments. Between 1995 and 2004 eight wells were fractured. Only one frac was conducted in Libya in the mid 1970s and the challenge was to introduce this technology. Firstly, a service company had to be encouraged to provide the equipment, the service and logistics for chemicals and proppant. Secondly, the National Oil Corporation had to be convinced that application of this kind of technology would be feasible and beneficial for the development of a low-permeable reservoir.
All wells in the subject field produce from a heterogeneous Lower Cretaceous Sandstone at a depth of about 12,000 ft. The drive mechanism is solution gas drive since the underlying aquifer was found to be inactive. Low porosities of 10 to 14 % and poor permeability ranging from 0.1 to 20 mD allow only a low to moderate production, which hampers the economics of a field development.
Today, 80% of the production wells in this field have been successfully stimulated by hydraulic frac treatments. State-of-the-art real-time analysis was performed to evaluate and optimize the frac operation on the fly. Hydraulic frac simulation findings were compared to post-frac well test results obtained from pressure buildup analysis in order to crosscheck the outcome.
About half of the cumulative oil produced to date can be assigned to the frac stimulations. However, they did not only help to improve the productivity of each well, but allowed us to produce longer above the bubble point and even permitted an optimization of production with bottomhole flowing pressures below the bubble point. Hydraulic prop fracs have successfully shown to be an appropriate means of reservoir management in this oilfield.
Scale Inhibitor Application in Injection Wells to Protect Against Damage to Production Wells: When Does It Work?
Authors: Mackay E. J. 
Published: December 2007

Abstract
Prevention of inorganic scale damage in the formation around production wells is usually achieved by batch squeezing the productions wells at risk. However, in Western Siberia protection of production wells is sometimes achieved by application of scale inhibitors in the supporting water injection wells. This technique relies on the effective displacement of the inhibitor across the reservoir from injector to producer. This is not generally considered a viable scale management option due to the extent of chemical retardation that is a necessary result of inhibitor retention on the rock matrix. However, for short inter-well distances, such as may occur in onshore developments, and where fracture conductivity is high enough that inhibitor contact with the matrix rock is minimal, then this technique can provide adequate protection against scale induced formation damage in production wells.
This paper explores the range of reservoir scenarios under which this technique may be applicable, considering inter-well distances, the extent of fracture vs matrix flow, and the potential range of inhibitor retention on various rock substrates that may be encountered in fractured reservoirs. The approach is to use numerical modelling techniques to investigate the range of conditions under which this scale management approach may be applicable. This data may then be used identify when scale control may be adequately achieved using this technique, thereby reducing the need to shut in production wells for treatments, and when this approach would not provide adequate protection in actual field systems. Comparison is made of the potential for performing batch treatments in the injections wells, compared to continuous injection of scale inhibitor in these wells.
Reservoir Study V9 of El Furrial Field, Venezuela
Authors: Acosta L. , Marin E. , Labastidas E. , Bello J. , Jiménez J. , Cordoba P. , Pascual J. C , Auxiette G. , Gou Y. , Thorsen B. 
Published: December 2007

Abstract
El Furrial field is one of the most important hydrocarbon giants of Venezuela. It's located at the north of the Monagas State and it handles approximated 45 % of the production of this area. It was discovered in 1986 and its characteristic makes it unique. The strategy of development has been supported by the combined injection of miscible gas and water, this has allowed to maintain the production plateau of 400 MBPD. A previous feasibility studyshowed a recovery factor ranging from 50 % to 60 % by implementing AGA, that study lead to the necessity of a new numeric model capable of simulate non conventional recovery possesses, creating a model known as the V9 Model.
This new approach is one of the most transcendental advances of the El Furrial field characterization. It's created over a structural model, which is based in 3D seismic of 370 Km2., which allowed a better definition of structural complexity. A petrophysics supported by 13692' of core, classified by 5 types of rocks, representing the heterogeneity of the reservoir. A high resolution stratigraphics model which is based on a cronostatigraphic criterion, which defined 47 statigraphic units. A sediment model based on 24 Paleoambient maps, considering direction of the sediment in the geostatistic model. A fluid model which changed a TarMat surface that varied from a horizontal to a folded one. A Geocellular model which is described by a 350 million cells grid, which generated a simulation grid of 500K active cells out of 900K.
A thermodynamic model which honors the fluid model, with a miscible optionvalidated by a slim tube and iswelling tests and a state equation for the compositional simulation. A rock-fluid model with a set of curves per rock type, which considers the hysteresis process that allowed simulate the AGA and the Dewatering process.
As a result the OOIP increased in 1.3 MMMBls. A fluid model with thicker and area extension of the TarMat in the sands. Drilled new delineation wells in areas previously considered in the non-economic limit incorporating new reserves and the development of new opportunities. A portfolio of 70 locations for the development of reserves of the field. Modeling of an AGA pilot project in order to evaluate the implementation of it. Evaluation different injection processes conventional and non conventional, in order to define the development plan of the field. The integrated subserface-surface simulation achieving the integration between recollectionand the reservoir model V9,which is one of the biggest world wide.
Reservoir-Based Benefits Analysis Demonstrates Value of Intelligent Completions in Latin America
Authors: Cabrera B. , Sakowski S. A. , Anderson A. 
Published: December 2007

Abstract
Intelligent well technology, referring to the implementation of fundamental process control down-hole, has advanced rapidly over the last decade in the upstream oil and gas industry. Focus for application of this technology in Latin America recently has shifted from high profile offshore projects to the more economically sensitive land-based arena. Stimulus for this shifting market in Latin America has been the ability to clearly demonstrate value of intelligent completions in terms of improved well and reservoir performance. Significant reduction in well intervention costs no longer is the primary economic driver for the application of intelligent well technology.
In this paper, we present a reservoir-based benefits analysis process that has successfully been used to quantify the value of Intelligent Well Systems for several operators in Latin America. The process involves close cooperation between the service and operating companies to: identify and rank potential Intelligent Well System candidate wells,understand reservoir and operational issues,design the most appropriate Intelligent Well System solution andquantify the value of the Intelligent Well System application compared to conventional completion alternatives.
A case example will be presented that highlights these major steps of the process and illustrates typical results that allowed the respective operator to make value-based, informed decisions on the application of intelligent completion technology. Post-installation well performance results also are presented for several case examples to illustrate the actual value of Intelligent Well Systems to another operator in Latin America.
Production Enhancement for a Northern Mexico Field Well Resulting from Flowback Evaluations Using Chemical Frac Tracers: A Case History
Authors: Hurtado A. L. , Asadi M. , Woodroof R. A. , Casas D. D. , Morales R. 
Published: December 2007

Proposal
The chemical frac tracing technology is used to evaluate flowback and flowback efficiency. This unique technique utilizes a family of environmentally friendly and fracturing fluid compatible chemical compounds to trace segment-by-segment injection of fracturing fluids. These chemical compounds have unique chemical and physical characteristics that make them detectable at low concentrations of 50 ppt (parts per trillion). These tracers are mixed at a known concentration into individual frac fluid segments as the frac fluid is pumped downhole and into the formation. Upon flowback, samples are collected and analyzed for tracer detection. With the use of the mass balance technique the flowback and flowback efficiency for each fluid segment are calculated. These precise flowback and flowback efficiency calculations yield a more accurate assessment of fracture cleanup efficiency which in turn helps to unravel cleanup problems. This paper presents a case history whereby four different chemical frac tracers were injected into four fluid segments of a frac job. The flowback and flowback efficiency calculations revealed low recoveries of the injected fluid segments through 86 hours of flowback. Based on the flowback results, a recommendation was made to shut in the well for 24 hours. Upon re-opening the well to production, flowback samples were again collected to evaluate flowback enhancement as the result of reservoir pressure buildup and or gel-breaking during the shut-in period. The total flowback efficiency increased by 50% while daily oil production increased by 62%.