bluuebunny/crossref_metadata_2025_split huggingface dataset:
In-Situ Stress Constrain: A Geomechanics Study To Evaluate the Influence of the Structural Geology
Authors: Haddad J. , Ramos J. , Aldana M. 
Published: June 2014

Abstract
The in situ stresses constraint is one of the most difficult parameter in a geomechanics model. Most of them are simple models in which is not involved the influence of geological discontinuities such as complex fault system, bedding plane, folds and joints. Recent studies have pointed out that these can significantly impact on the in situ stress states, leading to changes in magnitudes and rotations of stress tensor along formation sections. However, taking into account the structural geology and projecting the stress state underground, its uncertainty can be reduced. It results in an improvement during the well construction design to obtain a safer operational fluid density window, optimum well trajectories and an effective borehole stability analysis.
This paper presents an integrated methodology to interpolate the magnitude of the stresses and their orientation, including the effect of structural geology. A case of study from Eastern Basin Venezuela, SJ Field, was analyzed. First, a review of the structural geology model was done to identify its origin and the fault history. Then, a geomechanics 1D model with the pore pressure calculation, rock mechanics properties and in situ stress estimations was developed to be integrated with a kinematic analysis in which the structural restoration was defined. Besides, dynamic analysis using a numerical simulation with finite element in a 2D structural section was performed.
The results confirmed that stress state changed not only in orientation, but also in magnitude near to the Anaco Thrust. As a main consequence, the boreholes located next to this structural element experiment variations in depth from normal to strike-slip regime.
Drawdown Management: A Technical and Economic Alternative for Sand Control in Wells: A Colombian Field Application
Authors: Jaimes M. G. , Quintero Y. A. , Contreras G. Y. 
Published: June 2014

Abstract
One of the most common problems during the hydrocarbon production is sand production. Efficient control of the sand production without causing formation damage will depend on the knowledge that we have of the reservoir and also of the designs and estimates that we make during the drilling, completion and production. Sand production causes many problems ranging from collapses in casing, failures of subsurface equipment and surface facilities and accumulation in downhole generating continuous interventions, up to the point of making unproductive wells, thus putting in risk the future interventions of the wells and the capacity thereof in the long term.
In the oil industry there is a diverse range of technologies to control and / or exclusion of sand in open hole and / or case hole that can be mechanicals or chemicals, but the selection must be done carefully, taking into account granulometric and mineralogical criteria for proper selection, because although that we choose the best alternative technique and do a good sand control, the solution may not be optimal from the economic standpoint.
A good decision making process considers other alternatives for sand control, such as handling the drawdown pressure, which in some cases proves to be a technical and economic alternative, especially when the critical drawdown pressure (CDP) presents values over 40% of the reservoir pressure.
A geomechanics evaluation establishes the predictive model of sand production, which allows us to determine the critical drawdown Pressure. From density logs, Vsh, sonic logs, etc. and correlations, the compressive strength (UCS), cohesion, angle of internal friction and mechanical properties of the rock (Young modulus, Poisson's ratio, etc.) are determined. With a geomechanical model (previously selected and evaluated with field and laboratory data), the pressure gradient and the mechanical properties of the rock, the predictive model of sand production is established.
This study was conducted in the fields: Lisama, Galán, Llanito, Yarigui, Cantagallo and Bonanza in Colombia. This article presents the case study in the well Lisama 166, where the drawdown management became a technical and economic alternative for sand control.
Finally, conclusions and recommendations obtained in this study are shown.
Well-Reservoir Coupling on the Numerical Simulation of Horizontal Wells in Gas Reservoirs
Authors: de Souza G. , Pires A. P. , de Abreu E. 
Published: June 2014

Abstract
Wellbore flow and its coupling with porous media has been an active field of research, mainly because wellbore hydraulics (especially in complex geometry wells, like horizontal or multilateral) plays an important role in the pressure and production profiles. An inherent difficulty is associated to the multiscale nature of the flow problem: the cell hosting the well is generally much larger than wellbore radius. As a consequence, average pressure in a cell is not a good approximation of the well pressure. Moreover, at the interface between well and reservoir there is a change in flow pattern, from porous media to pipe flow. In this work a well-reservoir coupling technique is developed and applied to the numerical simulation of horizontal wells in gas reservoirs. This model considers wellbore hydraulics and storage.
We consider the 3D single-phase isothermal flow of a compressible fluid in porous media and 1D single-phase isothermal flow of a compressible fluid in the wellbore. In both regions, mass conservation, momentum balance and real gas equation of state are the governing equations. Conservative forms are used for continuity and momentum. Flow continuity and pressure equilibrium are considered at the interface between well and reservoir. The nonlinear partial differential equations can be rewritten to allow the coupling of the pressure field between the porous media (reservoir) and the free media (well) by means of an implicit formulation for the finite difference method presented. A hybrid grid technique was applied to improve the description of the flow close to the wellbore. In addition, pressure in reservoir and wellbore are solved simultaneously, while velocities in wellbore are updated at every iterative step. An iterative method to solve numerically the resulting linear system for the primitive variable pressure was developed and it includes the wellbore/reservoir coupling into a finite difference numerical model.
This methodology is useful for the analysis of transient pressure and velocity behavior in both reservoir and wellbore including the change in flow pattern from porous media to pipe flow. Effects of permeability, gas specific gravity, formation damage and grid refinement are considered in different sensitivity analysis for several well-reservoir systems. Results for pressure and pressure derivative followed the expected behavior of the reservoir model chosen, both in early and long times. Effects of friction, convection and compressibility in wellbore hydraulics were successfully included in the numerical approach.
Downhole Testing Tools in Extreme Environments
Authors: Marcancola F. , Pontes T. , Adriano M. 
Published: June 2014

Abstract
Hydrocarbon exploration and production has ventured into deeper, more corrosive environments, requiring continual technology changes to address the challenges presented by the new environments into which the oil field has moved. Testing technology has had to redefine the operating envelopes for its tools in order to meet the new requirements. Not only high-pressure and high-temperature tools have been needed, but more debris-tolerant tools have been needed as well.
This paper discusses the application of downhole testing tools in formation evaluation jobs in extremely hostile environments; these include testing in such conditions as: Ultra-deep waterExtreme high-pressureExtreme high-temperatureDebris presence.
Ultra-deep-water wells are those that have at least 10,000 feet of water depth, and HP/HT well environments include those with bottomhole pressures above 10,000 psi and bottomhole temperatures above 300°F. When environments have bottomhole pressures above 15,000 psi and temperatures above 350°F, the wells are considered as extreme HP/HT.
Many testing operations have been severely challenged by these scenarios, as downhole tools available for standard projects only were capable of functioning efficiently to approximately 350°F and up to 10,000 psi of pressure. Now, special tools are available for conditions with temperatures of up to 450°F and 30,000 psi of hydrostatic pressure with maximum 15,000 psi of differential pressure. In addition, a new generation of more debris-tolerant tools is available.
The improved tools have enabled high-quality well testing to be performed safely, and when the tools are used in wells where solids problems are not anticipated, and unexpected debris does occur, they can avoid the unexpected rig time previously required to clean the well, further enhancing economic efficiency. Debris-tolerant tools also have allowed fracturing and acid operations to be performed with a test string, and with the same string, the well can be opened to a well-testing operation without compromising the functioning of the downhole tools.
Subsea equipment also has required adaptation to harsh environments. A major engineering/service company has now developed new subsea safety-tree equipment to be placed inside the BOP stack; with this new equipment, the fracturing operation and the drill-stem testing can be performed in the same trip, since the safety valve system has the capability to maintain integrity when functioning in heavy proppant, high pressure, and high pump-rate conditions. This capability saves time and adds economic value as well as increased safety features to the jobs.
This paper will discuss the innovations to testing technology as well as how formation evaluation jobs now can be performed satisfactorily in extremely hostile wells using the improved technologies. Best practice information that has now been gained concerning testing in extreme environments will also be presented.
Modifying the Zeta Potential of Formation Fines Utilizing Chemical Treatment: An Alternative to Sand Control to Increase Productivity: A Colombian Field Application
Authors: Jaimes M. G. , Valencia D. , Bahamon J. I. , Mendoza A. , Medina C. 
Published: June 2014

Abstract
Sand production in oil and gas wells is a complex problem that requires a multidisciplinary analysis to arrive at an optimal solution of the problem and thus increases the productivity of oil fields with problems of production of sand.
Many operators choose as first alternative, the exclusion of sand, avoiding doing a risk management, which ultimately provides lower index of productivity and in many cases convert the wells with sand problems in unproductive wells. Therefore always be a better option the sand management and take as a last option the sand exclusion, obviously framed within a technical and economic evaluation of alternatives.
In most cases when we refer to a chemical treatment for sand control, it tends to confuse with chemical consolidation treatments, however a different option, is the application of chemical treatments to modify the zeta potential of the formation fines that has been very successful.
Modifying The zeta potential to optimum range, provides a strengthened attraction between the particles to optimally align proppant type, sand particles, fines, etc., allowing the formation of conglomerates of proppant, sand, fines, etc., improving conductivity and control of fines migration.
This study focused on the evaluation in the laboratory of chemical treatment (compatibility, zeta potential and rock-fluid testing, etc.), mineralogical and granulometric analysis of sand and fines produced by wells with sanding problems, selection of wells and treatment zones, quantification of costs associated with sanding problems, technical and economic evaluation of the application of treatments in candidate wells, etc.
This paper presents the results of the laboratory evaluation of chemical treatment (satisfactory results in compatibility and modification of the zeta potential, permeability returns of over 80%, etc.) and implementation in the well Bonanza 39, located in the Basin of the Middle Magdalena Valley in Colombia, where dropped dramatically the frequency of interventions by sanding problems. Before chemical treatment, the well had a monthly intervention and after nine months of the treatment, has not required intervention, allowing increase productivity of the well.
Finally, the main findings, conclusions and recommendations obtained in this study are shown.
Design and Implementation of Software Tool to Select and Evaluate Sand Exclusion and Management Alternatives, During the Stages of Drilling, Completion and Production: A Colombian Field Application
Authors: Jaimes M. G. , Quintero Y. A. , Martin D. P. , Puentes M. S. 
Published: June 2014

Abstract
Sand production in oil and gas wells is a complex problem that requires a multidisciplinary analysis and the use of new methodologies and technologies to be solved, which often requires a combination of several of them to arrive at an optimal solution of the problem and thus increase the productivity of oil fields.
This comprehensive strategy must start from the drilling, continue in the completion and extends to the production stage. To implement this strategy, a methodology that includes the integration of field and laboratory data and is complemented by an assessment Geomechanics was developed.
In the industry there is no software that would make a comprehensive evaluation and analysis described in the previous methodology, therefore it is designed a tool for this purpose, which allows to automate and streamline the decision-making process (developing optimal workflows to reduce evaluation times per well to 50%) and create a friendly graphic environment for the user.
The tool includes the following modules: Production, completion and perforation. The Production module includes: selection of wells and quantification of costs associated with interventions by sanding problems, diagnostic charts for root cause analysis of the problem of sand production, characterization graphs of intervals with sand production (mineralogy and grain size), selection of alternatives for management and / or exclusion of sand, production modeling, technical and economic evaluation of selected alternatives, etc.. The completion and drilling module includes: Evaluation of tables of well logs and identification of sensitive areas to the sanding beginning from them, predictive modeling of sand production, conventional perforating optimal design, underbalance optimal, oriented perforating, etc.
As a case study, the application of software tools to assess the problem of sanding in the Lisama 166 Well in Colombia, is shown, in which the frequency of interventions was reduced in more than 100% and was increased the productivity, with recommendations implemented.
Finally, conclusions and recommendations obtained in this study are shown.
A Quantitative Approach to Analyze Fracture Area Loss in Shale Gas Reservoirs
Authors: Lawal H. , Abolo N. , Jackson G. , Sahai V. , Flores C. P. 
Published: June 2014

Abstract
Since the emergence of the shale gas multi-stage fracture stimulation era, many shale gas operators strive to contact as much reservoir volume from a single well as possible. In the process of optimizing production, completion practices tend to affect already producing wells. Altering the production of an existing well via the stimulation of an offset well, commonly referred to as a frac hit, has been a growing concern. The main driving force in producing any tight formation is the lumped parameter of fracture area and square root of reservoir permeability, Af√k. Often times during the producing life of a well, there is an apparent decrease or increase in the lumped parameter due to frac hits or refracs (a second fracturing or hydraulic stimulation at a later point in time of the same well), respectively. Previous work shows rate transient analysis as an option to evaluate the impact of frac hits or refracs on a well'sproductivity; however, a quantitative analysis will require a more detailed study that combines rate transient analysis with numerical modeling to tackle more complicated issues.
In this paper, we propose a performance based methodology to quantify the amount of area lost (frac hit) or gained (refrac) using analytical approaches that can subsequently be verified using numerical modeling to truly understand the change in stimulated area after the occurrence of a frac hit or a refrac. Several frac hit cases were examined in various shale gas plays such as the Haynesville and the Marcellus. The data from the field cases were used to quantify the impact of a frac hit. The stochastic modeling from rate transient analysis of future performance for the well was compared to the numerical solution. This approach is also valid for refracs to quantify the amount of area created based on well's performance and also pre-design stimulation techniques to study the area created during the refrac.
The approach will help operators to quickly compute the risk of performing refracs and selecting better spacing to control the occurrence of frac hits by quantifying the economical outcome. In addition, the approach might help to minimize the amount of time used in modeling, if required, by creating reasonable ranges for certain reservoir parameters. Lastly, the knowledge gained from this study will help to correlate the extent of potential fracture damage to reservoir properties (e.g. matrix permeability) and optimize future stimulation techniques prior to the stimulation job.
Successful Application of Water Injection to Increase Oil Recovery in Boscán Field
Authors: Méndez Alirio , Chacín Breidy , Balram Suman , Smith Bruce 
Published: June 2014

Abstract
Boscán field has an estimated 35 billion barrels of original oil in place (OOIP) of 10.5º API gravity asphaltic oil with a current production of just over 100, 000 BOPD. The current cumulative recovery factor is only approximately 5% OOIP after more than 70 years of production. Water flooding in such a heavy oil field was previously considered ineffective by the oil industry. However, water injection for pressure maintenance (WIPM) was successfully implemented in Boscán using a unique pattern configuration coupled with improved lifting capacity to take advantage of increased reservoir pressure.
A four-pattern inverted seven-spot pilot and a combination of pattern configuration and line drive arrangement pilots were implemented in the central portion of the field. The WIPM pilot performance data indicated local reservoir pressure increase with incremental secondary oil recovery. Based on the experience in the different pilot pattern configurations and ongoing reservoir modeling, the WIPM projects are being expanded with a pseudo 1-3-1 inverted 7-spot pattern configuration. In essence, an additional row of producers is being placed in-between pattern rows.
Successfully executing Water Injection Pressure Maintenance Projects within the Boscan field has already resulted in more than 75 million barrels of cumulative oil from secondary recovery with another 270 million barrels of oil in estimated recovey to the Economic Limit. Current Boscan production from WIPM areas is approximately 46, 000 BOPD, about 45 percent of the total field production. Future WIPM project expansions are planned in the East and Central areas of the field in the short and mid term in a 1-3-1 line drive configuration for which reservoir simulation forecasts were validated using existing production and analog forecasts, identifying an additional opportunity to recover 52 MMBO by 2026 (14 & 38 MMBO respectively) and 189 MMBO to the economic limit (59 & 130 MMBO respectively).
This paper demonstrates how the Boscan WIPM projects have successfully increased oil production and recovery in a mature heavy oil field by applying lessons learned, best practices and optimal reservoir simulation modeling.
An Environmentally Friendly Method to Control Halite Scale Deposition: Proven Case Histories from Latin America
Authors: Martinez R. , Parker W. L. , Hernandez E. , Misino C. , Ramírez I. E. 
Published: June 2014

Abstract
Various types of scaling are common causes of flow reduction associated with oil and gas production. Halite scaling is the most severe and often needs chemical treatments and physical intervention to put a well back in production. Producing wells with halite deposition often become uneconomic due to the severity of scaling and the short term between physical interventions.
This paper describes a physical, nonchemical, and environmental friendly method of controlling salt scale deposits to reduce nonproductive time required for maintenance on clogged production tubular. The proposed method proved cost efficient in allowing the production to flow without interruptions. By injecting a modulated electric signal on the tubular, the discussed method enhanced production by avoiding daily workover production interventions.
It was observed that this new method eliminated the need for daily interventions on the producing well and needed only a regular weekly visit to assess its working parameters. Based on the results from dozens of cases in Latin America, this method is proven to be efficient on controlling halite scale deposition. This method has been previously used on controlling carbonates and sulfates scales, but this is the first time worldwide it has been used to control halite scale on a producing well.
This paper will present the results from Mexico, where this environmentally friendly method proved very effective in controlling halite scale on wells where chemical and water injection had not provided a satisfactory solution. Prior to this treatment, production was severely impaired by tubular clogging with scale, and worsened by the amount of time spent on workover. The paper will present how this new method solved these issues with minimum impact to the client's installation.
Dynamic Model of Risk Assessment for Mature Fields
Authors: Cervantes Bravo R.J. , Huerta V.A. 
Published: June 2014

Abstract
Risk assessment is one of the crucial tasks to accurately account for estimating and booking technical recoverable volumes, as well as, valuating a petroleum asset. Usually these processes are affected by project maturity or non-technical issues, and usually embrace uncertainty due to lack of information and different criteria adopted by company and/or evaluators.
It is believed that deterministic cash flow methods are suitable and accurate to assess a project portfolio in mature oilfields. However, even in the very well known fields with strict surveillance plans, there is still uncertainty associated to volumes of recoverable hydrocarbons, oil & gas prices, capital investment estimations, government-take share among others input variables of economic models.
It is proposed a new approach for mature fields which includes a probabilistic model of reserves estimation (either applied for volumetric calculations or performance-data-based dynamic methods), an scenario matrix to account for the risk expressed in expectation curves, an estimation of the “pseudo-limiting” risk and value terms, and a decision tree to define a hierarchy of portfolio. Furthermore, it is proposed a methodology of life-cycle assessment and surveillance of reserves estimation by integrating of the “pseudo-limiting” risk and the ratio expected value to capital investment.
The application of this methodology in a mature oilfield, the Peruvian Block IX, show that proposed infill drilling campaign would require a better royalty share for the company (40% additional to the current rate), while the implementation of a pilot Water flooding project would need an improve by 50% in current royalty share.