bluuebunny/crossref_metadata_2025_split huggingface dataset:
Lessons Learned From Relative Permeability Modifications in Colombia, South America
Authors: Gonzalez Pinto S. , Gutierrez M. 
Published: May 2009

Abstract

Description
This paper discusses well-interventions in Colombia that use a new generation of polymeric selective-water-reduction (SWR) product for selected candidates, treatment definition, differences of composition, radius of penetration, stages according to formation petro-physical properties, and well-productivity response in the short and long term. The evolution and improvements in technology over the past five years and its application in Colombia will also be discussed.
Previous papers have presented databases with information from interventions around the world, including case histories from Colombia (Dalrymple et al. 2007). This paper will focus on more detailed information for selection, treatment, and operational procedures in Colombian fields.

Application
There are hydrocarbon-producing formations in Colombia that have productivity limitations because of their high relative-permeability to water. This condition has generated increased tendencies to water-coning, historical and gradual water cut increases, and promoted a negative impact during the productive well life. This technological application includes new perforated wells (which are characterized for a potential rapid water-coning based on the geographical area or the formation) or producing wells in mature fields where the intervention still presents economical benefits. Information will be presented from wells with zones covering mid-to-high permeability, clean sandstones, and argillaceous sandstones at temperatures ranging from 125 to 250°F.

Results, Observations, and Conclusions
There are records of successful treatments, allowing for a reduction in the water to oil ratio, with increased productivity which has been maintained for more than three years. It has been possible to identify benefits from the technology, its evolution, and improvements during recent years. However, candidate-selection criteria have been continuously adjusted, which has generated more successful cases.

Significance of Subject Matter
Selective water reduction (SWR) is a viable technology with an extensive history of applications worldwide, and its usage has increased during the last five years in the productive basins of Colombia. A strong, continuous improvement effort has been in place for better reservoir characterization, understanding of water-production mechanisms, laboratory protocols, candidate selection, treatment design (volume estimation, placement techniques), and treatment follow-up.
Long-Term Post-Frac Performance Analysis Based on Flowback Analysis Using Chemical Frac-Tracers
Authors: Munoz A. V. , Asadi M. , Woodroof R. A. , Morales R. 
Published: May 2009

Abstract
Chemical frac tracing is used to evaluate flowback and cleanup efficiencies for eight different wells in a field located Central America. The technique utilizes a family of unique, environmentally-friendly, fracturing fluid compatible chemical tracers to quantify segment-by-segment recovery for individual fracturing treatments and stage-by-stage recovery for multi-stage fracturing treatments. Each well was traced with a number of different tracers during hydraulic fracturing. Upon flowback, samples were collected and analyzed for tracer concentrations. With the use of the mass balance method, total flowback and flowback efficiency for each stage were calculated. Production for each well was closely monitored for three years. This paper presents in-depth details relating short-term total flowback and fluid stage-by-stage flowback efficiencies to the long-term post-frac performance.
When Water Means Oil: Block 16 Case History
Authors: Feria C. Correa , Pazmin R. Gomez 
Published: May 2009

Abstract
In heavy oil reservoirs with strong water drive, oil production with high water rates is expected. Block 16, located in the Ecuadorian rainforest, is not an exception.
Currently Block 16 has an average oil production of 50,000 bopd (15° API mixture) with 940,000 bwpd. As the oil production rate declines, produced water increases and adjustments on the water handling systems must be made in order to ensure a safe and efficient process.
The purpose of this paper is to present an overview of the challenges that implies the water handling management on such a sensitive and changing environment, placing a particular focus on the modeling and simulation techniques employed to optimize the injection system.
In order to predict and improve the disposal water management, an integrated water handling model for the southern area of the block was built; this model includes all pumping stages (booster, medium and high pressure), an extensive pipeline network and the 21 water disposal wells. The model helps to identify bottlenecks, overloaded equipment and the best equipment repositioning strategy to improve energy consumption.
Once the model was ready, several simulations were ran, and they were useful to identify that the main issues to increase the water handling capacity were not about surface equipment, but the disposal wells' capacity. This helped to redefine the water handling investment strategy, pointing towards to improve wells' disposal capacity rather than investing on surface equipment upgrades.
As the main conclusion, the study lead to identify the need of a scientific approach to characterize the water handling processes taking into account all the systems involved, rather than the single well to well traditional analysis.
Swabbing Test Interpretation Using Nonlinear Regression in San Jorge Gulf Basin
Authors: Naranjo Euver , Bravo José , Díaz Eugenio , Caldera José 
Published: May 2009

Abstract
In the San Jorge Basin in Southern Argentina swabbing test is the conventional testing technique used by YPF to evaluate production potential on those reservoirs that do not flow naturally to surface. During the well completion phase, a swabbing device is lowered subsequently to individually test each reservoir layer. These wells, which produce from multilayer formations, are later completed for commingled production. Accordingly, the swabbing test represents the only opportunity to measure dynamic properties for every individual layer.
So far pressure transient analysis of such test has been limited to the use of conventional interpretation methods applied to the Infinite Acting Radial Flow portion, on those tests where such flow regime is observed. This can happen if a bottomhole shut in valve is used or if the shut-in period is given long enough time for the bottom hole pressure to reach conditions close to initial reservoir pressure. Unfortunately, both practices substantially increase the completion cost, which strongly affects well economics. As a result of this economic limitation, neither of such practices are applied on a routine basis so most of the time transient pressure interpretation is not performed.
In an attempt to get value from routine swabbing tests, where Infinite Acting Radial Flow condition is not observed, a different methodology of test interpretation has been introduced. Through the computation of the instantaneous flow rate from the pressure trend increase during the swabbing period, it is possible to use nonlinear numerical regression to make an estimation of the reservoir permeability even if Infinite Acting Radial Flow is not present.
With this innovative approach YPF is, for the first time, constructing representative production models for each well, improving reserve estimations and production forecasts.
A correlation between dynamic permeability from nonlinear regression and permeability from Nuclear Magnetic Resonance Tool has also been constructed in order to reevaluate production response in old wells.
Simulation Study of Steamflooding with Horizontal Producers Using PEBI Grids
Authors: Gonzalez K. , Bashbush J. L. , Rincon A. 
Published: May 2009

Abstract
Steamflood with conventional vertical wells results in poor vertical sweep efficiency and steam breakthroughs when it is applied to heavy oil reservoirs. The use of horizontal producers provides a larger contact area with the reservoir resulting in a better drainage and therefore enhancing the well productivities by improving the steam sweep efficiency.
This study explores and compares the efficiencies of steamflooding in an improved version of an inverted 7-spot pattern with a vertical injector in the center and horizontal producers versus vertical producers in a representative numerical geological model from the Orinoco Oil Belt.
The simulation of the complex displacement processes1 combined with the well configuration results in challenging computational issues. As a result of the mechanisms involved in steamflooding, including oil viscosity reduction, steam condensation into hot water, large mobility ratio differences in the displacement processes, etc., the Grid Orientation Effects (GOE) could be significant. A grid selection process was performed to reduce grid orientation effects comparing the steam displacement in a Cartesian grid versus those from an unstructured Perpendicular Bi-sector (PEBI) grid.
Once the grid was established, sensitivity analyses were carried out to define the optimal design parameters to improve sweep efficiency and reduce recovery times. The parameters analyzed were: (1) placement of the horizontal producers within the vertical reservoir pay, (2) placement of the toe and heel of the horizontal producers, and a sensitivity analysis to (3) bottom hole flowing pressure, and (4) steam injection rates.
Reservoir conditions were also studied to explore the effects of: (1) pay thickness, (2) variation of horizontal permeability, (3) permeability anisotropy generated from geostochastic distributions, (4) and previous cold production, in the overall process performance.
The use of PEBI grids allowed to model in a more accurate way complex thermal-compositional displacement processes involving horizontal wells not aligned with the orthogonal Cartesian axes, and demonstrated that steamflooding using horizontal producers offers the potential to improve conventional schemes achieving higher oil recoveries from heavy oil reservoirs.
Energy Balance in Steam Injection Projects: Integrating Surface-Reservoir Systems
Authors: Valbuena E. , Bashbush J. L. , Rincon A. 
Published: May 2009

Abstract
Steam injection projects consume considerable amounts of energy to generate steam. Understanding where the heat goes at various times and places during the process provides the means to improve the performance of a project. Enhancements can be achieved integrating an energy balance analysis from the steam generator through the injection network, the reservoir, the producing network and the journey of the produced fluids to the separator.
This investigation presents a workflow to analyze the integration of surface and reservoir systems for a Steam Assisted Gravity Drainage (SAGD) project, to properly estimate energy transfers in the various components of the system thus providing information to improve project planning and enhance both the oil recovery and the economics of the project.
The elements considered in the systems were: boiler, heat exchanger, steam trap, steam injection and well networks, reservoir heat usage, heat losses to the over- and under-burden, production wells and surface networks. Parameters such as completion schemes, artificial lift and boiler-wellhead distances were also analyzed.
Results show that surface-reservoir integration, using reservoir and network simulators, is a powerful tool to estimate heat losses in steam injection projects, helping to understand and successfully optimize their performance. The integration allowed the detection of steam quality variations at injection wells at various times during the process as a function of injectivity changes. Adequately insulated production wells under certain circumstances could produce under natural flow for some FAJA types of reservoirs. However, artificial lift methods had to be incorporated into other completion schemes to compensate for high heat losses and their correspondent increased oil viscosities that imposed higher pressure drawdowns in the production and surface gathering networks.
The SAGD processes analyzed were energy efficient in spite of retaining in the reservoir less than a third of the energy from the steam. In all the scenarios, oil production was considerably greater than the fuel consumed to generate steam.
The paper shows how the analysis of steam injection processes integrating surface, well and subsurface mechanisms allows the identification of critical components of heat losses to optimize the design and operations to maximize oil recovery and reduce energy consumption.
Evaluation of the Effect of Oil Viscosity on the Disproportionate Permeability Reduction of a Polymeric Gel Used for Controlling Excess Water Production
Authors: Prado M. , Reyna M. , Rauseo O. , Ferreira I. 
Published: May 2009

Abstract
The property by which polymeric gels reduce water permeability in larger proportion than oil permeability is known as disproportionate permeability reduction (DPR). This phenomenon is believed to be the result of preferential blockage of water pore channels combined with the exclusive capacity of oil to deform the gel. This property represents an opportunity to successfully control water production, regardless the cause of the excess water inflow or the type of well completion. For this reason, many investigations intended to understand and improve DPR have been carried out.
The relationship between DPR and parameters such as rock permeability, wettability and flow rate has been widely described. Nevertheless, no efforts have been made yet to evaluate the influence of oil viscosity. Considering the importance of heavy oil production for Venezuelan oil industry, as well as the growing impact of excess water production in these reservoirs, an experimental study was carried out to evaluate how DPR is affected by oil viscosity.
Four coreflood experiments were carried out in high-permeability Berea cores to measure oil and water permeability before and after gel placement. In the first three tests, DPR was determined using oil with viscosities of 1.8; 67 and 140 cp. The last test consisted on sequentially measure the permeability of each of the oils when flowing through the same fully gel-saturated Berea core.
Experimental results indicate that DPR improves as oil viscosity increases because 1) oil viscosity affects gel placement favouring selective plugging of water channels; and 2) the more viscous the oil, the larger the deformation of the gel, thus the easier for the oil to open a channel through it. According to this, a large potential of controlling excess water production in viscous oil reservoirs through gel technology application was established.
Guando Field: Underpressured-Field Development, Part II
Authors: Valbuena Amaris O. H. , Moreno J. M. Montoya , Martinez B. Duran , Rovira D. L. 
Published: May 2009

Abstract
SPE paper 94569 (2005) presented the generalities, characterization and initial development plan of the Guando field, an extremely underpressured, sandstone, partially naturally fractured reservoir. This paper will present global results of the initial development program and the bases which guided to implement a reduced spacing project based on decreasing wells distance from 250 to 145 meters. Results of this new development stage are presented and discussed.
This project increased field reserves in 15% and accelerated the production, allowing a 15% recovery factor in just seven years since the field exploitation started and nine years from its discovery and only with a total injected water of 0.25 volumes of its original oil in place.
Optimization in Completion Wells With a Packerless, Multistage Fracture-Stimulation Method Using CT Perforating and Annular-Path Pumping in Argentina
Authors: Bonapace J. , Kovalenko F. , Canini L. , Sorenson F. 
Published: May 2009

Abstract
This paper documents pinpoint fracturing (PPF) in Argentina. The implementation of this method has resulted in 193 fractures in 22 wells since October 2006.
The PPF method creates perforations by pumping abrasive slurry down the coiled tubing (CT) through a jetting nozzle, while the main treatment is then pumped down the annulus around the CT. Isolation between fracture treatments is accomplished using sand plugs (preferred method) or composite bridge plugs.
This technique has allowed greater selectivity in the stimulation of the areas to be treated; it has also allowed a more aggressive fracture treatment in terms of percent pad and the final proppant concentration because the CT is at the location in case of screen out. In gas fields, it offers the advantage of completing the well without killing it.
Different reservoirs with varying depths, temperature, types of fluid, and petrophysical conditions in the basins Golfo San Jorge and Neuquina were stimulated with different fracture fluids, proppant types, and frac gradients.
The Neuquina basin required fracturing without using a workover rig in oil and gas fields near the community, while significantly diminishing the working times with a reduction in environmental impact and noise generated during the completion. However, the main goal was the reduction of completion times in each well performed in the different basins of Argentina.
Multiple Fractures Transient Response
Authors: Restrepo D. P. , Tiab D. 
Published: May 2009

Abstract
The oil and gas industry has long recognized the inadequacy of existing theories to predict the behavior and outcome of some hydraulic fracturing treatments. Data sets compiled over the last two decades are incompatible with the conventional picture of a single planar hydraulic fracture. Multiple fracturing can occur in the near-wellbore region or far field, and the path of multiple fractures can be divergent, such that they grow out of each other's influence zone, as in the case of dendritic geometry, or narrow, as in the parallel geometry. Analytical, semi-analytical and numerical models have been developed for a well intersecting infinite conductivity vertical fracture. A hydraulically induced fracture is usually represented by a thin vertical plane that extends a finite distance from the well. The fracture is created by tensile stresses, and it exists in a single plane and grows in an orderly and predictable manner, in a pattern that can be defined as balanced. This model is not incorrect, but it is not representative of all hydraulic fracturing scenarios.
This study presents an analytical model to analyze the transient flow due to near wellbore multiple fractures in homogenous and naturally fractured reservoirs. The model considers arbitrary angles between the fractures. This study also uses a numerical model to calibrate and validate the analytical model. TDS technique is also used to analyze the linear and pseudo-radial flow regimes in order to find fracture length, fracture conductivity and several conventional reservoir parameters, e.g. permeability, wellbore storage and skin factor.
Multiple fractures create more surface area in direct communication with the wellbore. As a consequence greater volume of fluid can be produced from the wellbore per unit time. While fracture treatments continue to be designed using the best tools and techniques available, geometry estimates from fracture models have been difficult to verify. Pressure transient analysis is one of the fracture diagnostic techniques available to fill this knowledge gap, improving our understanding of hydraulic fracture behavior. It is an excellent calibration tool because it lets us evaluate the effective length of the fracture, which is the better length to use in history matching. Also, regardless of the application, identifying and understanding fracture complexities can lead to improved treatment designs, better completion strategies, and the potential for significant economic rewards through improved well performance and/or reduced completion cost.
Improvement of Drilling Operations on Horizontal Wells at the Orinoco Heavy Oil Belt, Venezuela
Authors: Andérico Luis , Larreal Ender , Ruiz Martín , Muñoz Nilson 
Published: May 2009

Abstract
Stuck pipe incidents and excessive torque and drag have been common problems encountered while drilling horizontal wells in the Orinoco Oil Belt which contains Venezuela's largest heavy oil reserves concentration. These incidents have been attributed mainly to high levels of friction between the drillstring and the heavy oil sands. To help prevent sticking, a common practice has been to add 10 to 20 vol% of diesel to the water-based fluid when drilling the horizontal sections. Open hole displacement of mud by diesel had also has been used to free stuck pipe. However, many of these incidents have resulted in the loss of the bottomhole assembly and the need to perform sidetrack operations.
Typically, engineered fluid solutions have been required to solve friction issues related to horizontal sections and tortuous well geometries. Additionally, a hydrocarbon-free and non-damaging lubricant option has been necessary to help prevent excessive torque and drag when drilling 2D and 3D well trajectories with a water-based fluid.
Recently, a viscoelastic drilling fluid comprised of a blend of special synthetic oils and surfactants has helped reduce the coefficient of friction in water-based mud by as much as 50% without adversely affecting the rheological properties, as well as dissolving bitumen and preventing emulsification of the heavy oil and sand. After the lubricant treatment, torque and drag values experienced while drilling highly deviated sections through unconsolidated sands at instantaneous penetration rates of up to 1,300 ft/hr have decreased from 18,000 to 12,000 lbf-ft. Also, because no stuck pipe incidents occurred and clean-up trips weren't required, considerable rig time was saved.
This paper discusses key aspects of the performance of the water-based, hydrocarbon-free, non-damaging lubricant used in drilling the Orinoco Oil Belt horizontal and multilateral wells, as well as the factors that enabled PDVSA to achieve project targets in a safe and timely manner and to minimize any detrimental environmental impact.
Critical Oil Rates in Naturally Fractured Reservoirs to Minimize Gas and Water Coning: Case History of a Mexican Carbonate Reservoir
Authors: Hidalgo O. J. , Brito L. E. , Garrido R. , Munoz J. , Paz F. , Flamenco F. , Aguilera R. 
Published: May 2009

Abstract
This study extends Birks (1963) coning method by defining various options for calculation of the critical oil rate in naturally fractured reservoirs through an explicit use of the radial pressure gradient in the fracture, ∂P/∂R. The study aims at minimizing gas and water coning, and introduces methodologies for estimating fixed and variable radius of drainage, as well as an iterative procedure for calculating the critical oil rate and the drainage radius within the fracture.
The methodology has been used with good practical results, allowing optimization of oil production, in various naturally fractured carbonate reservoirs in the southeast of Mexico.
Determining a critical or maximum efficient oil rate in naturally fractured reservoirs is very important in those cases where oil productivity can decrease significantly due to increases in water/oil and/or gas/oil ratios. Imposing a critical oil rate is also related to the capacity of fluids handling in surface installations and reservoir management when gas and/or water injection projects are being conducted in the reservoir.
It is concluded that the methodology, which is not developed with the idea of replacing detailed coning simulation studies, can be used quickly, easily and with a good level of certainty in naturally fractured reservoirs.