bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Impact of Pertinent Parameters on the Design of Hydraulic Fracturing in Gas Condensate Reservoirs
Authors: Carvajal G. A. , Danesh A. , Jamiolahmady M. , Sohrabi M. 
Published: December 2007

AbstractFracturing is the most common well stimulation technique in gas condensate reservoirs. Flow of black oil and dry gas in induced fracture systems has been widely studied by numerical simulation, core-flood and well tests. However, the flow behavior in fractures surrounding a gas condensate well, which could be significantly different to that of conventional systems, has not been fully understood. Most of the available literature has quantified the negative effect of condensate banking and inertial (non-Darcy) flow on well productivity, giving a pessimistic view of the gas rate in these systems. The above studies have neglected improvement in the gas and condensate relative permeability by increasing rate due to positive coupling of the two phases.In this work, measured values of permeability, single-phase inertial factor and relative permeability of a propped fracture were used to evaluate the effect of pertinent parameters on fracture performance more realistically. A reservoir simulator was used to develop realistic models of flow in fractured systems. A comprehensive sensitivity analysis on the impact of fracture characteristics on well productivity for different fluids and rock properties was conducted. The results demonstrated that not only inertia was important but also positive coupling strongly affected the flow performance. In particular for a tight formation, whereby fracturing is most effective, positive coupling in the matrix can overcome negative inertia in the fracture region. The results also reveal the important contribution of the fracture width, as wide fractures reduce the inertial effect significantly. Furthermore, we will show that increasing the fracture length does not necessarily lead to higher gas well productivity as there are optimum values for any given set of parameters.
Field Experiment of ECBM-CO2 in the Upper Silesian Basin of Poland (RECOPOL)
Authors: Pagnier H. J. M. , van Bergen F. , Kreft E. , van der Meer L. G. H. , Simmelink H. J. 
Published: December 2007

Abstract
The RECOPOL project is an EC-funded research and demonstration project to investigate the technical and economic feasibility of storing CO2 permanently in subsurface coal seams. This is considered to be an option for CO2 sequestration, which will be required to meet the Kyoto protocol. The main aim is to demonstrate that CO2 injection in coal under European conditions is feasible and that CO2 storage is a safe and permanent solution before it can be applied on a larger scale in a socially acceptable way. An international consortium of research institutes, universities and industrial partners is carrying out the project activities. This is the first field demonstration experiment of its kind in Europe. The development of the pilot site in the Upper Silesian Basin in Poland began in summer 2003. One of the existing coalbed methane wells was cleaned up, repaired and put back into production. A new injection well was drilled at 150 m from the production well, the distance being based on the available amount of CO2 and project time. After completion of the well with casing, cementing and perforations, the perforated zones were tested. Activities in autumn 2003 included the finalizing of the injection facilities. Production was started in the first half of June 2004 to establish a base line gas production without CO2 injection. First injection tests took place in the first week of July 2004. During the injection period the process was monitored to assess any potential, although unlikely, leakage of CO2 to the surface.
Integrated Modeling of the El Furrial Field Asset Applying Risk and Uncertainty Analysis for the Decision Making
Authors: Acosta L. M. , Jiménez J. , Guedez A. , Ledezma E. A. , Bello J. A. , Millán A. J. , Guzman M. , Marin E. , Gómez F. J. , Herrera I. , Córdoba P. 
Published: December 2007

Abstract
The El Furrial field is one 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 maintaining the production plateau of 400 MBPD of 28 ° API oil. A transcendental advance in the characterization of the field was done with a new dynamic model called V9, what promoted the evaluation of new development scenario.
This paper presents one of the first integrated development plan built by PDVSA; focus on the Integrated Modeling of the Asset, considering risk and uncertainty analysis in the decision taking. The project was developed under a philosophy of collaborative work and changing the way of thinking from deterministic to probabilistic. The Project was executed by a multidisciplinary team integrated by personnel of the core areas of the asset, creating a milestone in the traditional way of working. This integration allowed evaluation through statistic and expert interview, the uncertainties associated to the variables involved in the evaluated scenarios. Huge reduction of capital expenses related with the grow of facilities were obtain due to the estimation of production profiles based on risk and uncertainty analysis. As a result of this analysis a decision matrix was built, with the recovery factor, investment, qualitative risk factor, and economic indexes, which were evaluated to decide the optimum development plan.
The Kansas Arbuckle Formation: Performance Evaluation and Lessons Learned from More Than 200 Polymer-Gel Water-Shutoff Treatments
Authors: Portwood J. T. 
Published: December 2007

Abstract
Polymer gels used for shutting off unwanted water in producing oil wells are certainly no stranger to the Arbuckle dolomite formation in Kansas, but in years past, they have delivered short-lived results and have been only marginally successful. In November 1997, that all changed after a unique design strategy utilizing proven polymer gel technology caused dramatic increases in oil production that resulted from shutting off a significant volume of water from a well located in the Bemis-Shutts field. Since that time, more than 200 wells have been treated for about 35 different operators with a greater than 95% success rate. Thousands of barrels of incremental oil at each treated well are being realized, and hundreds of thousands to millions of barrels less water are being produced from each treated well, than otherwise would have been produced without the treatment. These treatments are extending, by several years, the economic life of many Arbuckle wells, and are bringing shut-in wells back to life.
This paper will report lessons learned from applying polymer gel water shut off technology to the Arbuckle formation, and present statistical data derived from a detailed database that has been maintained throughout the project. In addition to using the database as a tool to quantify results and further improve job performance, it is also being used to improve the predictability of response to treatment. Post-treatment oil and water production performance and treatment longevity will be compared to several variables like polymer gel treatment volume and injection pressure. The paper will also discuss how polymer injectivity and post-treatment well performance changes from place to place within the Arbuckle formation. Finally, treatment economics including job cost, payout time, revenue gain from increased oil and decreased water production, and return on investment will be presented.
Capillary Interaction of Different Oleic and Aqueous Phases Between Matrix and Fracture Under Ultrasonic Waves
Authors: Hamida T. , Babadagli T. 
Published: December 2007

AbstractVarious mechanisms may be responsible for enhancing the flow of oil through porous media in the presence of an acoustic field. Major capillary related mechanisms are peristaltic transport due to mechanical deformation of the pore walls, reduction of capillary forces due to the destruction of surface films generated across pore boundaries, coalescence of oil drops due to the Bjerknes forces, oscillation and excitation of capillary trapped oil drops, and sono-capillary effects. This study aims at analyzing the influence of high-intensity ultrasonic radiation on spontaneous imbibition of surfactant and polymer solutions into porous media.A series of laboratory experiments were performed using cylindrical Berea sandstone samples with all sides (co-current imbibition) and only one side (counter-current imbibition) open to flow contacting with the aqueous phase. Emphasis was given to the fluids of special interest to well stimulation and EOR applications. Anionic and nonionic surfactant solutions above and below the CMC were chosen to evaluate the effects of ultrasonic waves on the imbibition of low interfacial tension fluids and microemulsions. Xanthan gum solutions were also used as an aqueous phase to examine the effects of ultrasonic waves on the imbibition of viscoelastic fluids. The oil-saturated cores (crude and processed oil) were placed in an ultrasonic reaction chamber, and brought into contact with the aqueous phase. The recovery rate due to capillary imbibition was monitored against time.We compared the capillary imbibition recoveries with and without ultrasonic waves. A substantial increase in final recovery (up to 25% OOIP) and minor increase in recovery rate was observed when ultrasonic waves were applied to the surfactant solution. High intensity ultrasound was observed to enhance surfactant solubility and reduce adsorption onto the rock matrix. A small increase in the ultimate recovery was observed at low polymer concentration. At higher polymer concentrations, however, the difference rose significantly (up to 12% OOIP).
Estimation of Water Content in Sour Gases
Authors: Mohammadi A. H. , Samieyan V. , Tohidi B. 
Published: December 2007

Abstract
Estimating the water content of natural gases is necessary in many chemical and petroleum engineering processes, e.g., calculating the amount of water condensed in a pipeline for designing hydrate inhibition strategy. An empirical method based on correction of ideal model for estimating the water content of sweet natural gases in equilibrium with the liquid water or ice has been developed. This predictive method estimates the water content of sweet natural gases using the water/ice vapor pressure, the system pressure and temperature. In order to extend the capabilities of the new approach to sour gases, a correction factor is proposed for taking into account the effect of acid gases on the water content. The new approach has been developed using the predictions of a comprehensive thermodynamic model as pseudo experimental data. The data on water content of methane with different concentrations of carbon dioxide and hydrogen sulfide were generated and fed to a multi-dimension regression program. The predictions of the developed empirical correlations are in good agreement with independent experimental data, demonstrating their reliability in estimating the water content of natural gases. Finally, a discussion is made on determining the location of water condensation along a pipeline using a simplified energy balance equation and the method developed in this work.
Application of Tracer Technology for Optimising RKF Miscible Gas Injection Recovery - Field Case
Authors: Cubillos H. , Torgersen H. , González O. , Lamela M. 
Published: December 2007

Abstract
The paper shows a field application of gas tracer technology for improving the reservoir description and optimising RKF miscible gas injection project.
In a miscible gas injection process, the dynamic characterisation of flow paths is critical. Gas tracer technology is emerging as a powerful tool to quantify reservoir properties that control gas displacement processes. The Capillary Absorption Tube (CAT) combined with Gas Chromatography with Mass Spectrometer detection (GC/MS) method has significantly improved the ease and safety of tracer sample collection and transport, providing cost-efficient information.
RKF field, operated by the Sonatrach/CEPSA Association in the Berkine Basin of Algeria, is producing mainly from TAGI formation by peripheral down dip miscible gas scheme. Perfluorocarbon gas tracers were injected as part of the initial 1997 reservoir management plan and monitoring allowed to building good tracer production profiles.
CEPSA has developed an "integrated tracer-reservoir performance analysis" program consisting of qualitative and numerical analysis techniques. Operational plan modifications are developed from this program to optimise field performance. Slim tube and sector model, were built with VIP™ to evaluate tracer flow simulation under miscible gas injection conditions. Following these studies, tracer breakthrough times were history matched in the full field simulation model.
Some operational changes made to gas injection patterns, as a result of the tracer monitoring program, have increased oil production and improved recovery.
A New Two Phase Pseudo Pressure Approach for the Interpretation of Gas Condensate Well Test in the Naturally Fracture Reservoir
Authors: Mazloom J. , Kelly R. T. , Mahani H. 
Published: December 2007

Abstract
This study introduces a novel approach in the use of two-phase pseudo-pressures for the interpretation of gas condensate well test data in naturally fractured reservoirs. In a gas condensate reservoir, where the pressure falls below the dew point in the vicinity of a well, calculation of pseudo-pressures requires knowledge of the relationship between condensate saturation and pressure in all regions of the reservoir. An equation that relates condensate saturation to pressure is developed in this study for the region away from the well where condensation occurs but the condensate is immobile until its critical saturation is reached. A different equation, based on steady state flow, is presented for the region near the wellbore where the condensate is mobile. A single-phase, pseudo-pressure equation is used for the region of the reservoir further away from the well, where the pressure is still above the dew point pressure. This approach is verified using well test data generated with a compositional simulator, and real PVT data from a gas condensate field. Analysis of the computer-generated data yields dual porosity reservoir parameters and condensate saturation profile that are similar to the ones used in, or produced by simulation. It is also shown that the majority of the condensate dropout occurs in the fractures and not in the matrix in a dual porosity system and that the saturation profile in fracture media governs the build-up derivative curve. The amount of condensate in matrix has no effect on the derivative curve.
Monitoring PVT Properties Derivatives Ensures Physically Sound Tuned EoS Behaviour over the Entire Operating Conditions Range
Authors: Gaganis V. , Varotsis N. , Nighswander J. , Birkett G. 
Published: December 2007

AbstractIn this work, a method is proposed for guiding the Equation of State (EoS) tuning procedure against a set of laboratory measurements such as that a physically sound behaviour of the model can be produced throughout the operating compositions and conditions range.The derivatives of each individual EoS PVT prediction with respect to each of the input parameters are directly evaluated and subsequently utilised for verifying the behavior of the model throughout its applicability range. Thermodynamically sound profiles of the model derivatives which should be respected during tuning are also provided.By applying the Taylor expansion method, we demonstrate how typical EoS tunings can lead to significant prediction errors while moving along the multidimensional surface as conditions and composition vary during production.
Preventing Annular Flow after Cementing, One Pulse at a Time: Offshore Gulf of Mexico Cement Pulsation Field Results
Authors: Aslakson J. , Doherty D. , Smalley Ed 
Published: December 2007

Abstract
The initial offshore application of cement pulsation to prevent annular flow/pressure after cementing has been successfully performed in the Gulf of Mexico (GoM). This paper describes the methodology and cementing results achieved following application of the cement pulsation technology in multiple shallow offshore GoM casing strings. The compressible volume of the cement column is recorded during the pulsation operation, and this data can provide for surface monitoring of the downhole cement setting process. An overview of the equipment and cement pulsation pre-job design considerations are also included in this paper.
Recent Developments in Homeland Security Laws That Impact Exploration and Production
Authors: Randle J. S. 
Published: December 2007

Abstract
In the aftermath of September 11, 2001, a significant amount of legislation was passed by the U.S. Congress aimed at improving homeland security in the United States. At the same time, the petroleum industry, working with the government, began increasing its efforts to reduce the industry's vulnerability to terrorism. Today, petroleum companies face the burden of implementing new security measures and complying with new security laws which often are complex, overlapping in scope, and enforced by multiple agencies. This paper provides an overview of industry-sponsored security initiatives and relevant homeland security laws and offers practical solutions for companies trying to minimize liability risks related to terrorism.
Analytical Technique for Allocating Production to Subzones to Evaluate Prospect Candidates in the Terminal Zone of Fault Blocks III and IV, Wilmington Field, CA
Authors: Bust V. K. , Phillips C. C. , Hara P. S. 
Published: December 2007

Abstract
The analytical technique integrated the 3D geologic model, reservoir and production and injection information into a single Project database for a study area that comprised 109 acres in Fault Blocks III and IV in the Wilmington Oil Field, California. The result was the creation of a new reservoir evaluation tool that enables the user to quickly evaluate reservoir performance and potential development well locations. It provided a "snapshot" picture of well production or injection on a subzone basis for any selected time interval without using a simulator. The Project database is flexible because it utilizes whatever well, reservoir characterization, production and geologic information that are available to provide a more robust analysis than typical cumulative production and injection bubble maps.
An empirical mathematical algorithm was created to allocate the commingled total well fluid production to subzones. The algorithm allocated subzone production based on: 1) fraction of completed interval open in each subzone; 2) net sand weighted-value; and 3) flow capability (KH) weighted-value. The subzone flow capability (subzone KH) was calculated by multiplying the subzone average core air-permeability by the net sand thickness for each subzone. The allocation algorithm was developed for single fluid flow and not for fractional fluid flow. Fluid flow trends were identified by analysis of the produced oil and water volumes, WORs and water injection volumes tracked over selected time intervals and well completions. Volumetric analysis was used to estimate remaining oil in-place for each subzone and drainage areas. Pseudo oil saturation maps were generated to visually site and evaluate infill waterflood development well prospects.
The validity of the allocation algorithm was confirmed by the reasonable agreement found between the measured and predicted percent injection splits. This reservoir evaluation-screening project demonstrated the potential for a field-wide application to identify and prioritize drilling prospects.
Technical Enhancements Increase the Life and Add Value to New and Existing Wells by Use of Solid Expandable Tubular Solutions
Authors: Wallace J. 
Published: December 2007

Abstract
As completions become more complex and operating environments more severe, deeper, hotter and in higher pressure, exploration and field development solutions are needed that provide results and improve well savings. Five years of improving the application record of solid expandable tubulars with solution enhancements have resulted in greater value and mitigated risks for end users. This enabling technology has been used to address a myriad of drilling situations and downhole conditions as part of the well design, as a planned contingency option and as a last resort. Currently, the technology consists of several expandable systems that include cased-hole liners, openhole liners, openhole cladding systems and flexible cladding systems. These systems have been used to solve problems associated with borehole instabilities, pore-pressure/frac-gradient issues, wellbore tapering and perforated sections to name a few.
The ability to run, clad and expand into the base casing efficiently and reliably is paramount considering the increase in well pressures, production depths and drilling costs. An application legacy of over 300 installations has led to system enhancements and process modifications that have helped increase reliability and efficiency. These changes to solid expandable systems help operators reach and produce reserves that previously were unattainable due to drilling conditions and economic constraints, provide flexibility for exploration well uncertainties, reduce nonproductive time, provide larger corrosion resistant production conduit and reduce well costs by slimming well design.
This presentation will discuss improvements made to solid expandable tubular systems and how this technology can increase the life of, and add value to, both new and existing oil and gas wells.
CO2 Foam Behavior: Influence of Temperature, Pressure, and Concentration of Surfactant
Authors: Liu Y. , Grigg R. B. , Svec R. K. 
Published: December 2007

Abstract
A high-pressure, high-temperature (HPHT) bubble chamber apparatus is used to determine carbon dioxide (CO2) foam stability, interfacial tension (IFT) between HPHT CO2 and surfactant solutions and critical micelle concentration (CMC). Chaser CD1045™ (CD) was used in this study. In this study, changes of temperature from 25 to 75°C, pressure from 800 to 2000 psig, and surfactant concentration from 0.005 wt% to 1 wt% were tested for foam stability, IFT and CMC. The relationship of foam stability and IFT is also discussed in this paper.
IFT decreased with surfactant concentration below the CMC and was essentially constant above the CMC, increasing with the increase of temperature and the decrease of pressure. Stability of CO2-foam is surfactant concentration-dependent. The coalescence of bubbles was observed only at CD concentration of 0.005 wt%, well below the CMC at 25°C and 1500 psig. The foam was stable under all tested temperatures at surfactant concentrations of 0.1 wt% and above, and decreased with increase of temperature at surfactant concentrations of 0.05 wt% and below at 1500 psig. The foam was stable under all tested pressure at surfactant concentrations of 0.025 wt% and above, and decreased with increase of pressure at CD concentrations of 0.005 wt% at 25°C, and similar behaviors were observed at high CD concentrations at 75°C.