bluuebunny/crossref_metadata_2025 huggingface dataset:
Application of an Advanced Dynamic-Underbalance Perforating System for Improved Oil Production in Development Wells: Case Histories from Eastern Venezuela
Authors: Casas C. , Mattey A. , Molina O. , Larez A. , Mata J. , Fam M. , Fernandez R.
Published: May 2009

The deep reservoir sandstones of the El Furrial and Pirital oilfields, located in northern Monagas state, eastern Venezuela, are famous for their high degree of geological complexity and heterogeneity. Typical well completions in this area consist of natural flow from multiple intervals through perforations in cemented casing. However, conventional perforating guns used in these completions cause additional near-wellbore formation damage that adversely affects well productivity and results in reduced productivity indexes in these wells.

There have been significant efforts in recent years to implement new methods and technologies to produce cleaner perforations and better production rates. One of these technologies is a new dynamic underbalance perforation system which allows precise management of the underbalance differential pressures to produce a relatively clean perforated tunnel while minimizing formation damage. Application of this system results in improved connectivity between the reservoir and wellbore which allows substantial improvement in oil production rates.

Formation petrophysical properties are used to determine whether an interval is a suitable candidate for application of this technology. A separate nodal analysis model is created for every reservoir interval in each well. These models are designed to represent the actual and expected production conditions and account for reservoir heterogeneity. In the El Furrial and Pirital fields, reservoir properties can vary widely: permeabilities from 0.1 to 1,000 mD; porosities from 9 to 18%; oil gravities from 22° to 32° API; static pressures from 6,000 to 8,000 psi; and confined compressive strengths from 7,000 to 20,000 psi.

This paper presents case histories from wells in eastern Venezuela to illustrate the production benefits derived from this advanced perforating system technology. In three wells, supporting evidence demonstrates that near-wellbore damage caused by this new innovative underbalance perforation system is close to zero, resulting in over 100 % increase in the productivity index. In the fourth case history, we discuss the reasons why the actual well production rates did not achieve the rates projected by nodal analysis.
Improved Drilling Performance: Downhole Dynamic Logging Tools Break Paradigm in Ecuador
Authors: Barton S. , Clarke A. , Garcia A. , Perez D. , Mora G. , Carrion C.
Published: May 2009

In today's high cost drilling environment, vibrations are recognized as the primary contributor to drilling inefficiency. As such, accurate prediction, identification, and quantification of vibration along the drill string has become increasingly important in order to reduce drilling costs. Near-bit measurements are also particularly important, as the drill bit is often predicted to be an important cause of vibration.

This paper reviews a project within Ecuador, where high vibration and mechanical damage to drill bits has been observed, clearly affecting performance. This application is drilled with Fixed Cutter (FC) bits on a Rotary Steerable System (RSS) through a challenging sequence of formations including sandstone, shale, limestone, and conglomerates. Initial steps had been taken to optimize the drill bit design in terms of cutting structure, gauge geometry, and cutter technology. However, in order to truly understand the vibration issues, a unique downhole dynamic logging tool was utilized. This tool records drilling dynamics data at a high frequency sample rate, enabling lateral and torsional events to be accurately identified and recorded. Due to its size, and thus flexibility in string placement, the tool was located in two different points in the BHA.

Evaluation and interpretation of the vibration data led to the recommendation of new drilling parameters, very different to traditional practices in this application, in a critical section for the next well in the same pad. This resulted from detection of torsional vibration, not only at the bit, but also at points along the BHA.

Implementation of the recommended drilling parameters resulted in significant mitigation of torsional vibration at the bit and in the BHA. This resulted in reduction of wear to components within the BHA, as well as both time and cost savings in excess of $200K.
Fracturing Very High Permeability Gas Wells in Offshore Brazil: It Works!
Authors: Neumann L. F. , Rocha J. D. H. , Denadai N. J.
Published: May 2009

This paper presents the results of a fracpack campaign in a series of very high permeability gas wells in Espirito Santos Basin, off-shore Brazil. This first fracpack campaign in four wells was conducted from March 2007 to June 2008. Permeability ranges from high 50 mD to very high 200 mD.

The main debate was internal: why does someone need to fracturing very high permeability gas wells? In fact, this question is associated to two issues: overcome formation damage and assure very reliable sand control. The answer is obvious: fracpack.

Several injection tests and minifrac prior to the main treatment were performed in order to address mainly closure stress and fluid leakoff although perforation friction, near-wellbore tortuosity were minor concerns. The main drive was the amount of fluid required to effectively propagate a fracture in such very high permeability gas wells. Again, someone claimed the volumes would be enormous! However, it was observed that this volume was almost the same ordinary volume used in Campos Basin's regular oil fracpacks.

The results were outstanding. The production tests showed some of the greatest absolute open flows in Brazilian gas wells. All the wells are current in production and sustaining the very high productivity levels.
Rock Types and Flow Units in Static and Dynamic Reservoir Modeling: Application to Mature Fields
Authors: Osorio Peralta Oscar
Published: May 2009

The definition of rock types (RT) and flow units (FU) in the static and dynamic models is useful to have a better description of the potential zones with a reservoir quality. The study and integration of information from conventional and special core analysis, well logs, test pressure, geocellular model, gridding and properties upscaling to simulation are required for the reservoir modeling characterization.

The Winland and Flow Zone Indicator (FZI) methods to identify RT, as well as, the Stratigraphic Modified Lorenz (SMLP) method for FU; are the most used techniques to determine the properties at the well level. This document describes a workflow of that techniques at well level to be applied to the 3D static and dynamic reservoir models. The main objective is to identify the different features of the RT and FU in the entire reservoir. As result of this methodology, the FU are well defined and are used to determine the zone mapping in the upscaling process to perform the reservoir simulation model; and put new wells with oil opportunities in a mature field.
Impact Analysis and Interpretation of the Sand Thickness Obtained From Electric Logs and Outcrops in the Geostatistical Modeling of Stratigraphic Complex
Authors: Gómez R. A. , Morales J. , Pérez H. H. , Sandoval J. E , Jaimes M. A.
Published: May 2009

In the modeling of deposits with a stratigraphic complexity, one of the main purposes is to determine in 3D, the direction, continuity and distribution of sand layers. This goal is achievable with a degree of uncertainty depending on the information available such as the 3D seismic to interpret the filled canal deposits, as well as the electrical logs that allow definition in the vertical. Unfortunately in mature fields, we have little information which mostly consists only of 2D seismic and well logs. Under these conditions the definition of potential channels becomes a process with highly uncertainity and requires further work on integration of geological data field and electric logs to achieve a first approximation to the distribution channels of different formations and thus achieve improved geostatistical models.

A methodology is proposed, based on a statistical analysis of the different sand lenses identified in the electric logs. With this statistical analysis the value of average thickness of the predominant channels for each formation is obtained, which are supported and integrated to the collected information from data from outcrops in a phase of field and thereby define its main features. This definition of the cannel, guide allows geostatistical modeling in such stratigraphic fields with acceptable results according to the response of the existing wells.

The methodology was applied to the Mugrosa and Colorado Formations in the Lisama Field, located in the Middle Valley of the Magdalena River in Colombia, to conduct a geostatistical modeling based on objects to which the petrophysics of the facies information was integrated, leading to obtain the modeling of channels not only in direction, but also in size, continuity and its associated petrophysical properties.
Foam Detection in Process Units
Authors: Fransen G. , Carbajal R. , Guevara I.
Published: May 2009

Foaming in refinery applications and production processes has been a longstanding industry concern. Commonly available solutions such as DP gauges, capacitance probes and electromagnetic radiation, to name a few, fail to provide early warning detection1. These technologies only detect the presence of foam after severe foaming has occurred and often not until the foam has upset downstream operations leading to off-spec products, loss of liquid product due to foaming carry-over, damage to compressors, reduced through-put and increased chemical usage.

Because foam buildup can occur in many production, refining and petrochemical processes, the need for a technology that acts as an early warning system, accurately detects the presence of foam, responds to changing foam concentrations, and automatically adjusts the defoamer injection rates in the process separators/contactors before upsets occur is critical.

A newly marketed foam detection system, operating on the principle of energy absorption, meets these criteria. The foam detector is a device that is installed into the process vessel providing early detection as foam begins to form - advising operations to take preventative action before process upsets or equipment damage occurs.

With this early detection system, operators can automatically initiate or increase the anti-foam chemical injection rate causing foam to dissipate. As a result, anti-foam chemical feed rates are optimized, which in turn, reduces overall chemical costs.
Application of Combined Technologies for the Treatment of Phenols in Wastewater Oil Productions
Authors: Restrepo R. , Forero J. E. , Cardenosa M. , Gonzalez J.
Published: May 2009

The removal of phenols from wastewaters at crude oil production fields is one of the most important challenges in the Arauca-Field of ECOPETROL S.A. (Saravena, Arauca). Based on the review of available technologies for wastewaters treatment with variable phenol concentrations above maximum allowable limits, both at National and International levels, a combined alternative using biological (biodegradation) and physical (aeration - photo oxidation) technologies was considered. The implementation of this combination of technologies allowed the crude oil production field to comply with phenol concentrations at the discharge, obtaining higher than 99% removal efficiency and being consistently lower than the maximum allowable limit set by environmental authorities.
Inflow Performance Relationships for Heavy Oil
Authors: Gasbarri S. , Martinez V. , Garcia J. , Pinto R. , Garcia L. , Gil C.
Published: May 2009

Inflow Performance Relationships, IPR, are quantitative estimates of the productive potential of a well-reservoir system. Through this relationship, engineers determine basic elements such as the optimum production scheme and artificial lift design and operation. Several authors studied IPR in vertical and deviated wells considering two and three-phase flow in light oils. Other studies have also estimated productivity index for horizontal and slanted wells but only based on single-phase flow. All of them have not explicitly included how the oil API gravity affects the performance.

Since a large amount of the world oil reserves are heavy oils, the goal of this research is to generate a general Vogel type correlation valid not only for light oil reservoirs but also for heavy oils. The experimental study, performed with numerical reservoir simulation, was run over variables such as: permeability; relative permeability curves; reservoir pressure, degree of depletion, and PVT fluids properties. Due to the huge advantage of horizontal and deviated wells for producing heavy oil, vertical to horizontal permeability ratios was also analyzed within different angles of inclination. Furthermore, different water cuts were generated for vertical wells using reservoir water saturation in order to evaluate the effect of this variable over the IPR.

A general correlation for the V coefficient of Vogel's equation was generated that depends on the angle of inclination of the well, and several reservoir and fluids characteristic. Additionally, reservoir depletion was addressed through the reservoir pressure ratio with respect to the bubble point pressure. The application of the relationship described in this study is simple and only requires common known parameters of the field.
Waste Injection: The Environmentally Safe and Cost-Effective Solution for Ultimate Waste Disposal
Authors: Ovalle A. , Ronderos J. , Simmons S.
Published: May 2009

As the worldwide consciousness concerning environmental protection evolves along with the technology, the need for new methodologies to dispose of oilfield wastes in a safe manner grows under tight governmental regulations and careful management of risks, liabilities and costs. This is particularly true for remote areas such as deep water and environmentally sensitive locations where there is a strong emphasis on protecting the natural resources of the drilling area. Accordingly, many regulatory agencies demand zero-discharge policies and require all generated wastes to be disposed in a responsible manner. Such a process involves the adequate management of by-products generated during drilling operations including cuttings, excess drilling fluid, contaminated rainwater, produced water, scale, produced sand, and even production and cleanup waste. Old practices involve temporary box storage and hauling of the waste products to a final disposal site. Often, these practices create not only liabilities for the operating company but also environmental risks such as accidental spills, gas emissions and eventually, high operating costs.

Waste Injection (WI) into sub-surface formations has proven to be the most effective technology for final disposal of wastes from oil and gas drilling and production that provides a secure operation achieving zero discharge. WI achieves this by storing the injected material several meters below surface in hydraulically created fractures, avoiding surface environmental risks and future liabilities for operating companies.

This paper presents the methodology based on risk analysis, supported by successful worldwide case histories, to prepare an operational and cost-efficient operation that continuously analyzes information and provides fit-for-purpose recommendations to achieve a seamless injection process. The Assurance Waste Injection process permits the detection and identification of potential risks giving mitigation options to prolong the life of the injector.
Water Injection in Espadarte Module I Field
Authors: Reid M. G. , Melo V. L. A. , Lima L. M. S. , Serra A. L. S.
Published: May 2009

Espadarte Field is located in Campos Basin at about 110 km offshore of Rio de Janeiro state, Brazil. The water depth ranges from 750 to 1,500 m and its ring fence has an area of 720 km2.

The Espadarte field exploitation strategy comprises 8 producers and 5 injectors and was developed using subsea vertical, deviated and horizontal wells, all they producing to the FPSO Espadarte. These wells produce from 4 oil reservoirs with maximum thickness of 53 m and saturated with 29° API oil and the production started in August 2000. Water injection started in 2001 and it is the main drive mechanism to replace the reservoir energy, having the field an active aquifer as well. In 2002, after the seawater breakthrough, a production decline was observed and Barium and Strontium Sulphates scale were detected. After that, the seawater injection was stopped in order to provide a Scale Control Plan, based on a remote inhibitor squeeze treatment.

During the seawater injection interruption, an intense production decline and pressure reduction in the reservoirs was observed. In 2005, the injection was resumed and improvements in production and reservoir pressure were observed immediately.

In 2007, a study to increase the seawater injection in the field was conducted to anticipate the production. From this study, several parameters were analyzed, including the reservoir fracture pressure, the capacities of water injection and treatment at the production facility, the wells injectivity index and the quality of injected water. These parameters are monitored by technical teams including reservoir, production operation and lifting & flow people.

This paper presents the methodologies adopted to increase the seawater injection in the Espadarte Field Module I. It is discussed the reservoir management and the results obtained with the reservoirs pressurization, namely production anticipation and stability of the process.
Geomechanical Factors Affecting the Hydraulic Fracturing Performance in a Geomechanically Complex, Tectonically Active Area in Colombia
Authors: Osorio J. G. , Lopez C. F.
Published: May 2009

The Cusiana and Cupiagua fields are located in a tectonically active, geologically complex and highly faulted region in the Colombia foothills. These features lead to unusual complex hydraulic fracturing performances which can not be taken into account by conventional models and practices. To reduce risks and associated costs related to unsuccessful hydraulic fractures, it is imperative to identify the primary factors and mechanisms affecting the hydraulic fracturing performance in this geomechanically complex environment.

In this study, the main factors affecting the hydraulic fracturing performance in geomechanically complex oil and gas fields have been investigated. To achieve this objective, it was necessary to compile, interpret and process of a wide set of data relevant to hydraulic fracturing performance from previous successful and unsuccessful hydraulic fractures from several fields and formations. Geomechanics models were constructed for each well and the actual performance for each hydraulic fracture was simulated to study the effect of the following factors: initial failure type (shear or tensile), wellbore orientation, stress anisotropy, stress continuity with depth, near-well faults, natural fractures, rock strength, geomechanical properties, pore pressure and stress path. This paper refers to the first four factors (initial failure type, wellbore orientation, stress anisotropy and stress continuity with depth). The remaining factors will be subject of a future publication.

Results show that the factors having the strongest effect on fracturing performance are initial failure type and well orientation, which are highly correlated. In past successful hydraulic fracturing operations, tensile failure occurred prior to shear failure. Conversely, unsuccessful hydraulic fracturing operations are associated with shear failure having occurred prior to tensile failure. Thus, it is imperative to select well orientation and fractured interval such that tensile failure is guaranteed to occur prior to shear failure to assure a successful fracture. Additional observations show that stress continuity with depth and stress anisotropy favors fracture performance.

Application of the new findings and best practices obtained from this study has led to improve the hydraulic fractures geomechanics performance in Cusiana and Cupiagua fields.
The New, Generalized Material Balance Equation for Naturally Fractured Reservoirs
Authors: Sandoval P. , Calderon Z. , Ordonez A.
Published: May 2009

The complexity associated to naturally fractured formations constrain reservoir engineers to use simplified versions of the material balance equation for determining the initial hidrocarbon in place and predicting reservoir performance. This work presents a new material balance equation for naturally fractured reservoirs, wich is presented by complementing a mathematical model introduced by Peñuela et al 2001, that considers a porous medium composed of interdependent matrix and fracture system. By including both dissolved gas and volatilized oil was able to overcome the long standing limitations of the material balance in naturally fractured reservoirs resulting a unique material balance equation wich was applicable to full range of reservoir fluids –including volatile oils and gas condensates.

The proposed equation extend the equations presented by Peñuela et al 2001 and Niz et al 2004, in handling compositional effects of fluid composition in naturally fractured reservoirs. The new equation can be shown to degenerate to preexisting methods under appropiate reservoir conditions. Synthetic examples are given to validate the approach and illustrate how to apply this method in compositional and no compositional reservoirs. All previously published works become subsets of the present method.
Logistics and Design Considerations When Cementing Large Casing Strings in Extended, Deviated Wells: A Case History
Authors: Borja Latorre , Carlos Bórquez , Juan Delgado , Ariel Lueje
Published: May 2009

As part of a special project for expanding natural gas reserves, an extended-reach, high-angle, exploratory well was drilled, targeting a zone under Los Barriales lake, in the western boundary of the Loma La Lata field (Neuquén Basin). This basin is the main gas producing area in Argentina. The primary target was Sierras Blancas formation, a gas sandstone.

The well consisted of four cemented sections with the following casings: 20 inch at 510/510 m, 13 3/8 inch at 1980/1612 m, 9 5/8 inch at 3790/2457 m and 7 x 9 5/8 inch at 5848/2824 m (depths are MD/TVD, maximum deviation 81°). The final section was completed open hole. Cementing operations were planned based on the vast experience collected in Loma La Lata field, particularly referring to cementing high-angle (and horizontal) wells drilled with oil base mud (OBM).

The 9 5/8 inch and 7 x 9 5/8 inch casings were particularly complicated due to gas kicks from an abnormally pressurized layer that required the use of heavyweight OBM (14,7 ppg), which resulted in circulation loss during drilling, uncertainty regarding hole size and narrow margin between pore equivalent density and fracture equivalent density. These issues made the operations more risky than expected. A very careful and detailed design of cementing operations was needed with flexible slurry design and logistics in order to allow changes during the operations.

This paper summarizes the challenges of how to properly cement this well. Engineering, design, laboratory testing and field implementation are shown as a guide to reach a proper and long-term zonal isolation in future similar cases.
Coupling a Reservoir Simulator With a Network Model to Evaluate the Implementation of Smart Wells on the Moporo Field in Venezuela
Authors: Alvarez A. , Guerra E. , Gammiero A. , Velasquez C. , Perdomo J. , Hernandez R. , Rodriguez N. , Infante M.
Published: May 2009

Pursuing new alternatives to develop and produce sands B1 and B4 together, belonging to the reservoir VLG-3729 of Moporo Field located in western Venezuela, different exploitation schemes were evaluated, where intelligent completions have been highlighted. A pilot well with inflow control valves (ICVs) was proposed with the goal of maximizing the well oil production, avoiding cross-flow, minimizing operational risks and well interventions(coil-tubing operations), leading to better reservoir management.

To evaluate the intelligent completion technology, an Integrated Asset Model (IAM) was implemented. This model was divided in two sections: the first section involves the reservoir model using a reservoir simulator, which includes the representation of the ICVs through the multi-segment wells option; the second section represents the fluid flow in the well and pipelines from the couple point to the sink including the artificial lift system (Electrical Submersible Pump, ESP) through a network simulator. Both sections were coupled taking an intermediate point between the ESP and ICVs as a coupled node.

The differences using a stand alone model and a coupled model were analyzed. Given that in both models the main constraints are handled in different ways, the calculated liquid production trend is different for each model. The stand alone model is constrained by maximum liquid rate and minimum bottom hole pressure (BHP), while the BHP constraints on the coupled model is calculated dynamically by the production system. In this case, the stand alone reservoir model leads to an optimistic production profile. These results show the advantage in the use of an IAM, taking into account the network constraints to obtain more accurate results.

To evaluate the performance of the smart well, several sensitivities to the coupled model were made, changing the opening valves position at the beginning of the forecast. An increment in the cumulative oil production was observed when the cross flow between sands were not allowed.
Conceptualization and Modeling of Flow and Transport Through Fault Zones
Authors: Wu Yu-Shu , Karasaki Kenzi
Published: May 2009

A physically based fault conceptual model is presented for modeling multiphase flow and transport processes in fractured rock of fault zones. In particular, we discuss a general mathematical framework model for dealing with fracture-matrix interactions, which is applicable to both continuum and discrete fracture conceptualization in fault zones. In this conceptual model, faults or fault zones of formations are conceptualized as a multiple-continuum medium, consisting of (1) highly permeable, large-scale and well-connected fractures, (2) low-permeability rock matrix, (3) various-sized vugs or large pore volumes, and (4) surrounding fractured or matrix formations on both sides. Flow through fault zones may be different from that through fractured reservoir rock, because of higer permeabilities and larger pore spaces in fault zones. In addition fault flow may be further complicated by non-Darcy's and other nonlinear flow behavior because of large pore space. To account for such complicated flow regime, our model formulation includes non-Darcy flow, using the multiphase extension of the Forchheimer equation as well as descriptions for flow in parallel-wall fractures or tubes, based on solutions of flow through a parallel-wall, uniform fracture and Hagen-Poiseuille tube flow.

The proposed fault flow model is discretized using an unstructured grid with regular or irregular meshes, followed by time discretization carried out using a backward, first-order, finite-difference method. The final discrete nonlinear equations are handled fully implicitly, using Newton iteration. The numerical scheme proposed is applicable to simulating multiphase fluid and heat flow as well as solute transport through the fractured fault zones and their interaction with surrounding rocks. The conceptual fault model is implemented into a general-purpose reservoir simulator, applicable to 1-D, 2-D, and 3-D simulation of multiphase flow in fault zones. As a demonstration example, we apply the model to simulate pressure and temperature responses in wells for a flow system controlled by faults.
Industrial Operations and Water Quality: A Case Study of UTU River Pollution by Oil Production Activities
Authors: Ossai C. I. , Duru U. I. , Ossai I. A. , Arubi I. M. T.
Published: May 2009

Among the principal environmental and public health dimension of the global water quality issues are ecosystem dysfunction and loss of biodiversity. This exactly the implication of pollution of surface and ground waters by oil production activities because pollution induces an imbalance in the physico-chemical properties of these water bodies. This paper studied the effect of industrial operations on water quality with reference to the pollution of UTU River by oil production activities. The physico-chemical properties and heavy metals concentration in the waters and sediments of the river were analyzed to determine the deviation of their concentrations from set standards. It was observed that the pH, turbidity, total suspended solids, oil and grease were not within the limits as specified by World Health Organization (1984) for fresh water. The concentration of some of the heavy metals like lead, copper and zinc were found to be above the limit suitable for human consumption. It was also observed that these heavy metals slightly polluted the sediment of the river. The objective of this research is to determine the extent of pollution of this river which is the major source of water to the inhabitants of the area. This will aid in controlling the resultant health impact to the people and also help to predict whether or not the pollutants discharged to the river in course of the industrial activities are within the stipulated control limits.
Anisotropy Identification During a High-Pressure, High-Temperature (HPHT) Drilling Operation in a "Salt-Related" Structure – Real Case in South Mexico
Authors: Salazar Martin , Cabrera Jose R. , Coletta Claudio J. , Holzberg Bruno , Balasejus Detlef , Cortes Cesar A.
Published: May 2009

In the southern region of Mexico, PEMEX along with Schlumberger-IPM is currently drilling deep wells into the Mesozoic Era reaching total depths between 6,000 to 6,500 meters. The challenge of drilling into these reservoirs lies in the depositional environment, including the presence of salt domes, strong dipping layers, heavily faulted Tertiary formations and abnormal high pressures and temperatures. This paper presents a case study where a joint Geomechanics and Drilling approach was put in place to solve an emerging drilling problem in this area.

Despite the geological complexity, the previous drilling experience at the studied field showed good drilling statistics and no major drilling problems were expected for the subsequent wells. Nevertheless, several serious events occurred while drilling the first deviated well at the field, including stuck pipes events, which led to two sidetracks and loss of the expensive downhole tools. After analyzing operational practices and offset field characteristics it was decided to re-evaluate the geomechanical model, geology, and geophysics in order to identify the mechanisms which caused the problem. As part of the analysis after the second sidetrack, an acoustic anisotropy tool was intentionally run, since the cavings reported during the operations indicated evidence of multiple rock failure.

This study shows the methodology used to evaluate and determine the possible mechanisms of borehole instability as well as the recommended drilling practices and optimum mud weight adopted to avoid or minimize packoff events. It was demonstrated that a timely data acquisition together with an integrated drilling and geosciences analysis can indeed support real-time operations, understanding the root causes of the problems and proposing adequate solutions. In this case study, a USD 3 million nonproductive time problem was solved in an intense 3-day analysis. Obviously, appropriate data and a multidisciplinary team are needed to put in place such solutions.
A Generalized Semi-Analytical and Statistical Model To Estimate Oil and Water Production, Pore Volume Injected, and Ultimate Recovery in Mature Waterflooding Projects
Authors: Espinel A. L. , Barrufet M. A.
Published: May 2009

This project has developed a new procedure and a unique statistical and semi-analytical model to predict oil recovery at any water/oil ratio (WOR) and ultimate oil recovery for mature reservoirs under water injection. The new approach uses fractional flow, and multiple linear regressions. We have studied the linear portion of the commonly used plot of log WOR vs. recovery factor (RF) determining the boundaries of that straight-line zone (SLZ) in terms of initial and final RF and/or initial and final WOR numerically using mathematics rules. We also determined slopes and intercepts of this line as functions of commonly used rock and fluid properties values, such as relative permeability curves end-points, connate water saturations (Swc), residual oil saturations (Sor), mobility ratios (M) and Dykstra-Parsons coefficients (VDP). Characterizing this line helps us to determine the performance of a waterflood in terms of RF and pore volumes injected (PVI). We correlated the results from homogeneous and heterogeneous reservoirs by using a correction in terms of the VDP and mobility ratios. We validated the model using reservoir simulation and field cases. Limitations and assumptions are those derived from the application of the simplified fractional flow equation, including that no dip angle, no capillary pressure, and no gravity effects were considered. The model was tested and validated for waterfloods with relatively small initial gas saturation (Sg < 0.2). At higher gas saturations waterflooding process must be applied with extreme care to avoid displacing oil into the gas cap zone and reducing the remaining oil saturation (ROS).
Use of Time-Delayed Filter-Cake Removal System Significantly Improves Productivity Index in 20-Well Comparison
Authors: Carrera Carlos , Ferreira Christian
Published: May 2009

Drilling horizontal wells successfully has become one of the most important challenges facing oil companies. Horizontal wells allow operators to obtain more oil production from a single hole, compared to the cummulative production from several traditional vertical wells. New technologies have been developed to help maximize productivity in horizontal wells.

A highly effective, field-proven new technology is the time-delayed filter cake removal system. The system is applied mainly in horizontal wells and can be used with different completion types including open hole, stand-alone screens, expandable screens, slotted liner, or gravel pack. The system generates organic acid downhole in a controlled manner, which dissolves all acid-soluble materials present in the mud cake throughout the horizontal interval. This breaker can be formulated to match specific well conditions and reaction delay requirements based on temperature and pressure requirements and return permeability analysis.

This paper discusses the laboratory tests, planning and application processes of the system in 20 horizontal wells in Ecuador and compares the resulting productivity index of each well as a function of system design and operational parameters.
An Accurate Numerical Method for Calculating Solubilities of Hydrocarbons in Hydrate Inhibitors
Authors: Bahadori A. , Vuthaluru H. B.
Published: May 2009

Significant amount of work has been performed in order to determine the solubility of light hydrocarbons (methane and ethane) in the most commonly used hydrate inhibitors (such as methanol and ethylene glycol) at various temperatures and pressures. These solubility data have been compiled and correlated. In most cases, however, the current models may not be sufficient if accurate predictions are needed. The aim of this study is to present a numerical method for accurate prediction of solubilities of light hydrocarbons in methanol and ethylene glycol (at different weight percantages in water) as a function of reduced partial pressure and reduced temperature. The predictions from the proposed method have been compared with reported experimental data and found good agreement with average absolute deviation being less than 1.6% It was also found that this method is more accurate than conventional thermodynamical approaches (in particular, the NRTL model with average deviations of 20 percent) in predicting the solubilities of light alkanes in hydrate inhibitors.
Diffusion of Hydrocarbon Gases in Heavy Oil and Bitumen
Authors: Guerrero-Aconcha U. , Kantzas A.
Published: May 2009

The use of gas hydrocarbon solvents in the recovery of heavy oil has been increased because of the advantages they have over the thermal methods under some reservoir conditions. The injection of a miscible solvent in the reservoir implies a mass transfer process which is governed by a diffusion coefficient. Consequently the measurement of the diffusion coefficient is extremely important. This, however, presents a significant amount of challenges in the laboratory and in the data analysis.

In spite of the importance of the diffusion processes not much effort has been put in the understanding and calculation of the gas-liquid diffusion coefficient. In a recent work Guerrero-Aconcha and Kantzas (2008) used the "Slopes and Intercepts" analytical technique to successfully obtain the diffusion coefficient of liquid hydrocarbons in heavy oil. However the technique involves the previous knowledge of the composition density relationship. Here a non-iterative finite volume method was used to obtain the diffusion coefficient dependent on concentration without previous knowledge of relations for the diffusion coefficient and density with concentration. Computed Assisted Tomography (CAT) was used to obtain the density profiles and back calculate the concentration-dependent diffusion coefficients.

The results agree very well with the theory of diffusion in binary mixtures. An empirical model was used to perform predictions on the studied systems. The results are the vital importance for VAPEX and cyclic solvent injection recovery processes.
Numerical Modeling of Fully-Transient Flow in the Near-Wellbore Region During Liquid Loading in Gas Wells
Authors: Zhang He , Falcone Gioia , Valko Peter , Teodoriu Catalin
Published: May 2009

In oil and gas field operations, the dynamic interactions between reservoir and wellbore cannot be ignored, especially during transient flow in the near-wellbore region. A particular instance of transient flow in the near-wellbore region is the intermittent response of a reservoir that is typical of liquid loading in gas wells.

Despite the high level of attention that the industry has devoted to the alleviation of liquid loading, the fundamental understanding of the associated phenomena is still surprisingly weak. This applies not only to the flows in the wells, but also to the ways in which these flows interact with those in the reservoir. The classical way of dealing with these interactions, inflow performance relationships (IPRs), relate the inflow from the reservoir to the pressure at the bottom of the well, which is related to the multiphase flow behavior in the tubing. These relationships are usually based on steady-state or pseudo steady-state assumptions.

However, such IPRs may be inadequate when a transition from an acceptable liquid loading regime to an unacceptable occurs over a relatively small range of production rates and, hence, over a relatively short time. The most satisfactory solution would be to couple a transient model for the reservoir to a transient model for the well.

This paper presents the results of a numerical modeling effort focused on the identification of the transient pressure profile in the near-wellbore region during fully transient flow conditions. The preliminary results, obtained for a single-phase (gas) situation and for a three-phase (oil-water-gas) situation, show a "U-shaped" pressure profile along the reservoir radius. The existence of a similar pressure profile could be the explanation for the reinjection of the heavier phase into the reservoir during liquid unloading in gas wells.
Design of a High-Pressure Research Flow Loop for the Experimental Investigation of Liquid Loading in Gas Wells
Authors: Fernandez J. , Falcone G. , Teodoriu C.
Published: May 2009

Existing models to predict and analyze liquid loading in gas wells are based on steady-state flow. Even when transient multiphase wellbore models are employed, steady-state or pseudo steady-state inflow performance relationships are used to characterize the reservoir. A more reliable approach consists of modeling the dynamics in the near-wellbore region with its transient boundary conditions for the wellbore. The development of new models to mimic the dynamic interaction between reservoir and wellbore requires a purpose-built flow loop. We have developed a design to construct such a facility.

This new facility will be the first to integrate pipe representing the wellbore with a porous medium that will fully mimic the formation surrounding the wellbore. This design will account not only for flow into the wellbore, but any reverse flow from the pipe into the medium.

We used integrated wellbore/reservoir system analysis to screen the parameters required to recreate liquid loading under laboratory conditions. Our results suggested using a compressed air system with a discharge pressure between 470 to 650 psi with gas rates of 400 to 650 scf/m along with water injected at a rate of 100 gpm. Once the range in operating conditions was defined, the equipment and mechanical components for the facility were selected and designed.

Our results showed that three reciprocating compressors working in parallel provide the smallest, most economic, and most flexible configuration for the TowerLab facility at Texas A&M University. The design of the pressure vessel hosting the porous medium will require a cylindrical body with top- and bottom-welded flathead covers with multiple openings to minimize weight. The required superficial velocities for air and water indicate that the system will need independent injection into the porous medium through two manifolds. Optimally, the system will use digital pressure gauges, coriolis or vortex technology to measure air flow and turbine meters for water flow.

The new facility will significantly improve our ability to mimic the physics of multiple phase flow for the development of liquid loading models and lead to better optimization of gas fields.
Successful Geosteering in Ecuador Using the Bright Spot Phenomenon from Deep Resistivity Images
Authors: Diaz M. , Iza A. , Rodas J. , Carrion C. , Manrique C. , Chemali R. , Pineda G. , Sandoval J.
Published: May 2009

The challenges presented by a field in Ecuador included placing the wells in the cleanest, most permeable portion of the reservoir, in the middle of the structure, without penetrating an overlaying kaolinitic bed or the caprock shale above the reservoir or penetrating the water bearing zone. These objectives could not be optimally achieved with traditional wellbore imaging sensors or with deep non-azimuthal wave resistivity. Wellbore imaging instruments identify the relative dip and azimuth of geological events intersecting the wellbore, but the information is clear only after leaving the reservoir. Non-azimuthal wave resistivity predicts the impending intersection with a reservoir boundary, but does not predict the azimuth of approach. In the first instance, a proper decision can be made only after exiting the reservoir; in the second instance, a proper decision requires other knowledge about the probable direction of the approaching boundary.

A newly deployed azimuthal deep resistivity while-drilling sensor produces a vast array of azimuthal measurements. When mapped into an image, deep resistivity behaves for the most part like traditional images in which "smiling" patterns indicate that the wellbore is going up stratigraphically and "frowning" patterns indicate that the wellbore is going down stratigraphically. One exception is the newly discovered phenomenon of the "bright spot" that appears when approaching a low resistivity shale or water bearing interval from a high resistivity reservoir. The bright spot clearly indicates an impending reservoir exit. Because it is keyed to the low side of the well, the bright spot indicates the direction of the required evasive action to remain within the desired interval. This visual indicator is complemented by a novel quantitative measurement, the Geosignal, which features a strong exponential dependence on the distance to the boundary of the reservoir. In the examples shown, the visual information from the bright spot is combined with the quantitative information from the Geosignal measurement to properly guide real-time geosteering decisions.
History Matching: Is it Necessary to Optimize?
Authors: Reis L. C. , dos Reis L. E. , da Silva L. C. , Becerra GG.
Published: May 2009

The oil industry has recently started to deal with probabilistic approach. Risk or uncertainty analysis have become part of the petroleum engineer's job. A set of curves with the associated probability instead of one deterministic curve is provided by the reservoir engineers. In order to use reliable curves, they shall have a history matched model. Assisted History Matching usually uses optimization processes. The aim of the optimization is to find the minimum of an objective function that represents the quality of the model. In this way, one can find the best model. The keyword is exactly "best". Why to make so much effort to find the best if we know that it is still far from the truth. Indeed, the concept of "best" is not suitable for the probabilistic approach.

This work discusses a functional history matching approach where an optimization process is no longer necessary. The functional history matching approach establishes that we have to look for a set of models that is above a level of quality according to the reservoir engineers. The method is quite simple. Among all possible models, we select those that have an objective function value under a pre-defined value.

In this approach the discussion lies not in the optimization issues like local minimum, convergence, and rapidity, but in how the quality of the model is measured. The objective function that usually measures the quality must be very well defined. Not only to better take into account the historical data but also to be suitable to the purpose of the study. Infill drilling and new secondary recovery systems would probably require different objective functions.

This work discusses the functional history matching approach coupled with uncertainty analysis. Usually very costly in terms of numerical simulations, uncertainty analysis can be done in this approach with simplified models (proxys). Different proxys were used - Surface Response Modeling (improved or not) and Artificial Neural Network. A simple synthetic case (PUNQ), and a real complex case (Brazilian onshore field) were used to illustrate the functional approach.