bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

AbstractThe 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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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 &lt; 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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.