bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mechanistic Study of Alternative Gas Injection Processes for Enhanced Oil Recovery in the Los Jabillos (Cretaceous) Reservoir, Furrial Field, Norte Monagas, Venezuela
Authors: Todd M. R. , Claridge E. L. , Almeida J. , Alvarez R. , Echeverria I. 
Published: December 2007

Abstract
A numerical simulation study of enhanced oil recovery alternatives has been conducted for a reservoir characterized by a thick oil column having varying crude oil composition and associated transport properties with depth. The high asphaltene content of the crude, together with indication of plugging if precipitation is allowed to occur in the reservoir, has forced the maintenance of pressure by injection. This study examines the efficacy of alternative injection processes. Described is the procedure used to represent a miscible-immiscible transition, as anticipated to occur between injectors and producers, in a pseudo-miscible simulator, starting with the results of slim-tube experiments. Reservoir stratification in the representative cross-section model used for the simulations is based on Lorenz functions. The modeling work indicates significant sensitivity to both process and well configuration, with continuous gas injection predicted to recover 0.03 to 0.09 OOIP more oil than water injection, and 1:1 WAG predicted to recover 0.06 to 0.10 OOIP more oil than continuous gas injection, depending on the well configuration.
Application of Low Invasion Coring and Outcrop Studies to Reservoir Development Planning for the Villano Field
Authors: Rathmell J. J. , Atkins Laura K. , Kralik James G. 
Published: December 2007

Abstract
Drilling and coring of a discovery well in the Hollin sand, Villano Field in 1992 was followed by low invasion coring in a confirmation well. A large discrepancy existed between water saturation derived from the capillary pressure and well logs in the discovery well. Low invasion coring and outcrop studies were implemented to calculate oil-in-place and hydrocarbon reserves.
The field is located in environmentally sensitive rain forest. Low invasion coring with water based mud was the only feasible method for obtaining connate water saturation from core. The bromide tracer of mud filtrate indicated low invasion (&lt;10 % pv filtrate) was found in 86% of the horizontal core plugs. Core plugging and preservation were conducted in a facility established at the drilling base camp, 30 minutes by helicopter from the rig.
These plugs were then shipped to the USA for analysis. Core water saturation was in good agreement with capillary pressure tests. The low invasion core data indicated salinity varied from 2600 ppm chloride at water-oil contact to 36,000 ppm chloride at the top of the Hollin reservoir. This salinity gradient and native-state, Archie saturation exponent yielded log-derived water saturation equal to the low invasion core values.
Reservoir description would be critical to a development plan for the field, which would produce by aquifer influx. The size and distribution of sand bodies and shales was addressed by a detailed description of the core to determine the sedimentary sequence and quality of the productive intervals, and measurements from a Hollin sand outcrop located in the Andes Mountains to the northwest of the field.
Geostatistical methods were used for shale mapping. An objective geological model based on cores and outcrop was used to assign sand permeability, porosity and water saturation. Numerical simulation with this description and the steady state relative permeability data provided an oil rate forecast and the Plan of Development for the field.
Knowledge Communities Help to Identify Best Operating Practices
Authors: Saputelli Luigi , Ungredda Alessandro 
Published: December 2007

Abstract
This paper addresses state-of-the-art in knowledge management as applied to an E&P organization, lessons learned in the last decade and current challenges for adopting this philosophy. It shows the advantages in using novel knowledge management techniques, as applied in many successful and competitive companies. It promotes learning organization's philosophy, and the creation of virtual knowledge communities to identify best operating practices. Some techniques and tools are described in order to promote team effectiveness strategies and communications to leverage knowledge sharing and valur creation.
Multiple Internal Rates of Return - When to Anticipate Multiple IRRs and How to Take Advantage of Them to Perform a Better Evaluation
Authors: Rosbaco Juan A. 
Published: December 2007

Abstract
There are different rules to delimit or exactly determine the number of Internal Rates of Return a project may have or has. These rules show that, when the sequence of signs of the cumulative cash flow vs time function is the normal one - negative figures at the start and then only positive ones - there is only one Internal Rate of Return. There are few projects in which there are multiple intersections of cumulative cash flow with the time axis: a number of acceleration projects, complex financing investments, and a few other serial projects. However, not all of them have multiple Internal Rates of Return. The discussion presented in this paper addresses the question of how to empirically infer the existence of multiple rates, and how to use them for the benefit of the evaluation. Moreover, it demonstrates that all multiple rates have the same physical meaning, which does not vary with respect to the traditional single rate case.
A New Micro-Emulsion Polymer Gelling Agent with an External Surfactant Gellant Activator Improves Acid Fracturing
Authors: Woo G. T. , Lopez H. , Metcalf A. S. , Boles J. 
Published: December 2007

Abstract
Typically, the gelling agents used in crosslinked hydrochloric acid are available as polymer dispersions with a pre-blended inverting agent or gellant activator. An inverting agent increases the polymer dispersion' s viscosity initially and will further increase the polymer dispersion' s viscosity over the shelf life of the product. As a result, the polymer dispersion' s pour point and stability are adversely affected, thereby reducing the polymer dispersion' s shelf life. Additionally, the use of a nonylphenol ethoxylate, the inverting agent commonly pre-blended in polymer dispersions has been banned in the North Sea due to environmental concerns.
A new gelling system for crosslinked acid fracturing treatment has been developed. The system includes a microemulsion polymer gelling agent and a highly specific surfactant that is used as an external activator. The microemulsion polymer possesses very unique and more desirable properties such as a lower pour point and viscosity profile, a greatly enhanced dispersability, and a microscopic emulsion polymer particle.
With a lower pour point and innate viscosity profile, the gelling agent is readily pumped directly from the shipping vessels to the blending unit even in cold weather. With such a greatly enhanced dispersability, the gelling agent is readily dispersed in the hydrochloric acid without the risk of forming unhydrated masses or " fish eyes". Additionally, the microscopic emulsion particle greatly prolongs the shelf life of the gelling agent by virtually eliminating polymer settling. With the use of the special external gellant activator, the emulsion polymer could achieve 70% or more hydration within one minute. The characteristics of the gelling agent and the use of the external activator enable the gelling system capable of "continuous mix" or " on the fly" operations.
In addition, this external activator is biodegradable making it more conducive to the environment.
This paper describes the chemistry of the new gelling system, its enhanced gelling capabilities, discusses the results of lab testing leading to its development, and finally, the results of extensive field-testing.
Use of Capillary Pressure Data and Log Calculated Water Saturation for the Characterization of Dual Porosity, Dual Permeability Systems
Authors: Ozgen C. , Araujo H. , Firincioglu T. 
Published: December 2007

Abstract
This paper describes a simple method to divide the effective porosity values that can be calculated from log analysis into two flow media (fracture and matrix) pore volumes for use in numerical simulation models. The division of the porosity is based on the assumption that the total porosity of the system is made up from two contributing rock types or lithofacies that have distinct pore size and/or pore size distribution such that they can be represented by different capillary pressure functions. This assumption is applicable to the non-fractured as well as to the fractured systems.
When the method is used for the fractured systems, the fracture is typically represented by a zero capillary pressure value (gravity segregation). The matrix has its own laboratory measured capillary pressure curve. Based on a predetermined water-hydrocarbon contact and using the difference between the density gradients of the fluids, the capillary pressures of the two media are converted to theoretical water saturation profiles as a function of TVD. Next, at each depth point, the two extreme theoretical water saturation values are compared to the log calculated water saturation measurements. Based on a simple weighting algorithm, the contributions of the fracture and matrix media to the total porosity are calculated. The results can be upscaled to the numerical simulation grid block size or be used in geostatistical approaches.
Using the developed technique, we have built simulation models for two different reservoirs. One of the models represents a fractured system, while the other represents a non-fractured system with two distinct rock types. For the non-fractured reservoir, the dual porosity formulation enabled us to accurately upscale the capillary pressure functions by default. The approach and the results of the numerical models are presented in the body of this paper.
Velocity Dispersion as a Tool for Reservoir Imaging
Authors: Sidorovskaia Natalia A. , Lockard Emmitt S. 
Published: December 2007

Abstract
A comparison of the seismic velocities estimated from actual seismic data and well logs shows apparent discrepancies for the certain frequency ranges. The difference is related to the presence of the propagation velocity dispersion typically ignored in seismic signal processing as the second order effect In addition, neglecting the effects of velocity dispersion in seismic imaging algorithms reduces the resolution in mapping the reservoir properties. Several theoretical models relating seismic data and their dispersive properties to important reservoir characteristics, such as porosity, permeability, fluid saturation, etc., are discussed. Velocity dispersion and signal attenuation in rocks with fluids are mostly affected by two mechanisms of the fluid-solid interactions, the Biot mechanism and the so-called "squirt flow" mechanism. The Biot mechanism is the more conventional one and it occurs at the macroscale level, whereas the "squirt flow" mechanism describes fluid flow at the pore scale level. It is considered how one can relate velocity dispersion and attenuation to measurable rock and fluid properties by coupling two mechanisms. New aspects of modeling attenuation and dispersion effects in partially saturated fluid based on statistical approach to scattering from aggregates of gaseous bubbles is also introduced.
The results indicate the first step in modeling complex reservoir properties from broadband interwell and surface seismic data. It can be particularly applied to the extraction of permeability anisotropy from attenuation and dispersion data to image the fluid flow in a reservoir. The separation of the elastic scattering component of the velocity dispersion could be useful for the prediction of depositional environments. The task to predict the dispersive properties of the reservoir away from the well control using interwell and surface seismic information can be also accomplished.
Integrated Reservoir Characterization Incorporating Horizontal Well Data. Bare Field (Seismic 3D Area) Orinoco Oil Belt. Venezuela.
Authors: Granado A. , Rojas B. , Fuenmayor M. , Calderon P. , Ramos C. , Nalsen M. 
Published: December 2007

Abstract
This paper summarizes the results of an integrated reservoir characterization study, and the volumetric analysis of a section of the stratigraphic column of the Bare field, Hamaca Norte, Orinoco Oil Belt, in eastern Venezuela (fig.1). Also development plans for the studied area, containing an OOIP of approximately 9.5 MMMSTB of heavy/extraheavy (8–18 API) crude, are provided.
The reservoir characterization study was made by an integrated interdisciplinary team of Geoscience professionals, facilitating the identification of opportunities for growth in hydrocarbon reserves in the Bare area. The process was initiated with the determination of the reservoir internal architectures, through the description, correlation and mapping of the geological data. The application of high-resolution sequence stratigraphy was essential for the determination of the reservoir architectures. Next, after all the production and reservoir data were incorporated and integrated, a reservoir model was generated for dynamic simulation and for the development of potentially recoverable reserves. 32 possible locations for horizontal wells were identified and ranked according to productivity and profitability.
The geological model was corroborated through the drilling of 8 new horizontal wells, during 1997–98, minimizing the geological uncertainties of the area. The number of pilot holes was reduced, and navigational difficulties, during the drilling of the horizontal section, were surmounted. This has resulted in a 25 % increment in the quality and in the effective horizontal length sections of the wells. Initial well production rates are between 800 and 1400 BOPD, an average of 200 additional BOPD as compared to wells drilled prior to this study. Additionally, the study defined the optimum distribution and location of production facilities and infrastructure.
Application of Surface Modification Agent in Wells with High Flow Rates
Authors: Weaver Jim D. , Baker John D. , Woolverton Sean , Parker Mark A. 
Published: December 2007

Abstract
This paper describes the laboratory development and field evaluation of a new enhanced proppant surface-modification agent (ESMA) that increases fracture conductivity, dramatically reducing proppant backproduction during the initial high flow-rate well cleanup after fracture-stimulation treatments. The conventional surface-modification agent (SMA), which has been used extensively, enhances fracture conductivity by reducing proppant flowback in wells with moderate flowback conditions. ESMA extends the use of proppant surface-modification technology to wells with potentially harsh flowback conditions.
SMA applications allow proppant packs to withstand three-to five-fold the critical flow velocity required to erode a proppant pack. When a crosslinker additive is incorporated, forming ESMA, this range extends 10- to 20-fold. Laboratory tests indicate that ESMA will demonstrate the same improvements expected from SMA in vertical distribution of proppant because of hindered settling. Typically, these materials provide a 15 to 30% increase in proppant-pack porosity. With both SMA and ESMA, fines resulting from proppant crushing and formation fracturing adhered to the treated pack and did not migrate or block pore throats. Fracture-fluid cleanup significantly improved when proppant was treated with either additive.
Several successful field tests were performed with ESMA, including fracture stimulation with limited entry in the Mesa Verde, where proppant packs were subjected to initial flow rates as high as 45 bbl/hr. In all of these tests, no proppant flowback was observed, and well productivity was enhanced. The paper includes designs and results for some of these field tests.
A New High-Temperature Oil-Based Drilling Fluid
Authors: Mas M. , Tapin T. , Márquez R. , Gabay R. , Negrín Z. , Díaz C. , Bejarano L. 
Published: December 2007

Abstract
This paper presents the laboratory development and a field trial of a novel 100% oil base drilling fluid system. In response to the need for a competitive high temperature inhibitive system, lab testing found an oil soluble polymer that imparts high temperature high pressure fluid loss control in a mud system with stable rheology and low formation damage. The polymeric additive is the basis for the 100% oil system, which also has an application in standard invert emulsion systems. The 100% oil system is designed to use mineral or diesel oil as the base. The attributes of the system include inherent inhibition and lubricity from the base oil, a mud weight range of 7.0–18.0 ppg, minimal formation damage, resistance to contamination and maintenance of the HPHT filtration control and rheology during high temperature high pressure applications. Laboratory testing has shown the fluid is temperature stable to 400 °F with diesel or low toxicity mineral oil as the base.
This system has been field tested on two wells in Eastern Venezuela. One test was a 6,353', 8 ½" directional interval and the other a 1,053', 5 7/8" horizontal section drilled in near balance conditions with the fluid being nitrogenated to achieve the desired ECD. Both wells were drilled successfully and one well is discussed in this report.
This fluid has a wide range of applications evidenced by the documented properties from the lab and the field tests. This paper covers the system formulations, properties, formation damage tests, and the results from the field test.
Design and Application of a Drill-In Fluid System for the Production Interval in Barinas Area
Authors: Martínez Alfonso , Luzardo Juan P. 
Published: December 2007

Abstract
Drilling of the production interval of oil wells in Barinas area has been carried out using oil-based fluids. In most cases the same fluid used in the intermediate hole has been used to drill the pay zone, after processing it with SCE to adjust to the required density for the final interval. This has led to production indexes below expected forecasts. In order to increase productivity in the area, PDVSA-SOUTH requested to put together a plan in which a water-based Drill-In fluid system had to be designed for two exploratory wells in Torunos and Borburata fields. The objective was to drill the production interval through Gobernador and Escandalosa Formations, reducing damage and controlling any wellbore instability problem that might arise from the water-sensitive shale section above the production interval, known as La Morita Formation. In order to meet this requirement, a detailed study about the petrophysic characterization of the reservoir rock and a compatibility study between wellbore fluid and reservoir fluid were performed. Drill cuttings were used for the former, and crude oil and Drill-In fluids were used for the latter. Scanning Electron Microscopy was used for the cuttings analysis, in order to establish the structure, pore geometry and mineralogy of the reservoir and non-reservoir rock. Shale swelling and dispersion tests as well as permeability plugging and filtration tests were also performed. Based on the results, a FLO PRO™ system was designed, choosing the type and concentration of shale inhibition additives to be included. The particle size distribution of the CaCO3 used as bridging agent and weighting material was also selected. Finally, a hydraulic analysis was done to adjust the rheologic properties of the fluid and recommend some operational practices, so as to have a controlled ECD. The fluid design was successful and the expectations were met.
Primary Cementing Optimisation: Well Conditioning Procedure and Foamed Spacer Use
Authors: Degni Carlos D. , Marcinkevicius Carlos R. 
Published: December 2007

Abstract
Since late 1993, in El Tordillo Field, Chubut, Argentina, Tecpetrol S.A. has experienced severe cleaning and loss of circulation problems while drilling and cementing production casing in very depleted zones located from 4265 ft to 6562 ft, El Trébol and Upper Comodoro Rivadavia formations.
The average depth for the wells studied is 9843 ft, the desired cement top for isolating primary and secondary production zones is 4265 ft.
Several drilling fluids and cementing procedures were optimised through the fifty-well drilling program. In spite of this optimisation procedure, random results were experienced while cementing the production casing, either single or two-stage cementing jobs.
In the last thirteen wells a different approach to circulating and cementing the production casing was adopted.
The 7-inch production casing was circulated while running at pre-selected depths. Preflushes for the cementing job were lightened with nitrogen, thus providing a low density, high viscosity foamed spacer in the front of the primary cement job. The foamed spacer was used to improve displacement efficiency in open hole. The results were positive, the low-density spacer and preflushes reduced loss of circulation while cementing the production casing and improving hole cleaning.
So far the thirteen wells were cemented in one stage using foamed spacer and lightened preflushes ahead of normal density cement slurries. Results have been very good with cement columns rising up to 4265 ft. The casing and formation bond for these jobs have been excellent, achieving consistent results and a total saving over 42% of the total cementing costs.
Finite Element Modeling of Heavy Oil Production Using PCP
Authors: Blanco L. B. , Ribeiro P. R. 
Published: December 2007

Abstract
The Progressive Cavity Pumping (PCP) system has become one of the most attractive artificial lift methods used for heavy oil production in land fields. One of the problems associated with PCP is the prediction of the pressure losses in the annular flow between the production tubing and the rod string, which transmits power downhole to the PCP. The irregular annular section due to the rod upsets and the non-Newtonian behavior of some heavy oil initially precludes any analytical approach of the problem, requiring the use of numerical solution. Different heavy oils from onshore and offshore Brazilian fields were rheologically characterized using a strain-controlled rheometer in order to study temperature and elasticity effects on its rheological behavior. For the temperature and strain rate ranges used in the lab, the Power Law model has been chosen to represent the fluid behavior for the numerical simulation of the annular flow field. In order to understand the physical problem, a 2D finite element modeling of the laminar, steady-state, helical flow of a generalized Newtonian fluid was performed, by using Newton's method with an incremental loading scheme. A mixed formulation was applied for the approximation of Navier-Stokes equations and the flow domain was discretized by quadratic quads with linear pressure interpolation. The general conclusions regarding the physical problem are concerned with the rheological behavior of the fluid and with the parameters which mostly influence the pressure losses in the annular flow, during progressive cavity pumping of the heavy oil.