bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Reliability-Based Systemic Method for Water Production Analysis, Diagnosis and Solution Design
Authors: Reyes C. M. , Azuaje E. , Ortiz-Volcan J. L. 
Published: December 2010

AbstractThis practical method integrates petroleum engineering knowledge, reliability and six sigma tools in a reservoir production system model representing all potential cause effect relations and failure modes to identify the origin of water production and its classification as wanted or non-wanted. A general process is proposed to design a custom made solution for either controlling or handling water production. The solution is modeled with systems dynamics and stochastic simulation to calibrate cost, benefits, cycle time and required resources and data acquisition to close the loop during the life cycle of the field.The method has seven macro processes: 1) Data gathering and reliability analysis, 2) Determination of non wanted water production, 3) Analysis of causes related to mechanical problems in the well, 4) Analysis of causes related to well drainage area, 5) Analysis of causes related to the reservoir, 6) Definition of corrective and preventive actions and 7) Cost, cycle time and resources modeling to design a solution with the required actions during the life cycle of the field.Two examples from two fields in Venezuela are used to describe the application of the method. In these examples cycle time including solution design and implementation is 80 days with a total cost ranging between 300 to 600 thousand dollars.We provide a road map for water production analysis, diagnosis and solution design in oil and gas reservoirs that can be adapted custom- made to any field to address water origin identification, classification as wanted or non wanted water and solution design. This method is non-commercial so it can be used by operators as an alternative to others that could be biased to particular technologies. If used appropriately this method could increase hydrocarbon recovery and reduce risks and costs of environmental impact of water. Finally, this method is a framework for standardization of existing work processes and for integrating the work of all disciplines required for managing water production in an integral way.
Influence of Stress Field in the Productivity of Naturally Fractured Reservoirs in Metamorphic Basement: A Case Study of the San Pedro Field, Amotape Group
Authors: Meza O. E. , Peralta V. , Nuñez E. 
Published: December 2010

Abstract
San Pedro is a complex reservoir located offshore Bayovar Bay in the province of Piura in northern Peru. Stratigraphically, is located in metamorphic basement rocks of the basin Sechura, composed of Paleozoic rocks Amotape Group. The San Pedro reservoir corresponds to a naturally fractured reservoir, its structural complexity is linked to tectonic events that led to the formation of different types of fractures and presence of structural forms own metamorfics rock.
Geophysical characterization of the major structural features as faults and fractures, and characterization through special registers such as image registration, sonic dipolar and sonic scanner, conventional records which are taken as inputs for the construction and validation of continuous models petrophysical properties, discrete fracture models and geomechanical models in order to best characterize this reservoir.
Due to the highly complex network of fractures, well productivity is highly variable along the reservoir and is heavily influenced by the prevailing current effort in the field. The productivity of wells due to a directional permeability generates a drainage area of elliptic type which is difficult to define but which is reflected in the productive performance of wells and gas injection projects that were made in the reservoir. The productivity of the wells is also largely affected by the type of completion used in different parts of the reservoir, the completion type generally used "open hole" which has worked well in some parts of the reservoir but in other not because of the influence of the efforts and the structural forms that it has created.
All these models and production data history help us understand the nature of the dominant effort, the main trends of productive fractures and to identify areas and blocks with potential for further drilling of wells and carry out the development plan the field.
It Is All About Pressure: Drilling a High-Pressure Well in Record Time Using Real-Time Tools
Authors: Santos Gustavo , Serrano Mario , Villa Leonardo , Nieto Eduardo 
Published: December 2010

Abstract
The Lisama field located in the middle Magdalena basin is well known as one of the high pressure areas drilled in Colombia by ECOPETROL (NOC). Densities up to 21.0 ppg are often reached and side tracks due to hole instability are common in the area, sometimes as many as three (3) per well, making plans in days and costs difficult to control.
The use of real time tools such as Pressure While Drilling (PWD) on the Lisama No 167 well demonstrated that only monitoring the fluid density at surface is not enough to keep the hole open and stable. Monitoring with PWD demonstrates that real annulus pressure involves all kind of parameters affecting the mud density including temperature, solids content and compressibility, so that the real pressure and the Equivalent Mud Weight (EMW) can be determined at any point of the wellbore. In this directional well, the challenge for the service company is to use an MWD system that works with high-density fluid conditions. Conventional systems have an operational limit of 18.0 ppg, so an electromagnetic telemetry system was chosen.
Through continuous ECD monitoring and EMW management, combined with a good drilling plan plus the use of electromagnetic telemetry systems, it was possible to keep the wellbore under control and reduce operational time to 60% below the offset wells drilled in that area. The Lisama No. 167 well reaches expected densities around 21.0 ppg, enough to keep pore pressure under control and drill to the final depth of 7390 ft without problems. The successful combination of PWD tool plus electromagnetic telemetry made it possible to identify the events requiring improved hole cleaning, increased mud weight and optimized drilling parameters. It also facilitated decisions regarding circulating, tripping or casing point selection.
Massive Optimization Technique Improves Production of Mature Fields: San Francisco, Colombia
Authors: Suárez Andrés Felipe , Soto David , Borja Hubert , Daudin Remi 
Published: December 2010

Abstract
A breakthrough methodology has been implemented in the San Francisco field, Colombia, to yield an additional 12% in remaining reserves by optimizing production and injection based on key principles of the ‘learning theory’.
This paper presents a new massive optimization methodology applied in the San Francisco field. Such techniques are especially well suited to mature fields, as these have substantial infrastructure in place, which can be used in ways different to the usual.
Mature fields represent a challenge in terms of investment and allocation of resources. Still, there remain opportunities to improve production, since past strategic choices have created some heterogeneity in field pressure and saturation. These can be drastically revisited and production parameters rearranged. Since many production avenues have been explored in the past, a learning process can be applied: rearranged parameters can be implemented with very low risk. Still, there are billions of ways to operate mature fields: injection and production rates can be varied, conversions made.
Massive optimization of a field means selecting and playing with thousands of production scenarios and identifying the best. This is possible only with a reliable and fast simulator. The "statistical learning theory" defines under which conditions such a simulator can be devised. The Production Simulator is designed in such a way that it complies with the conditions of a reliable long-term forecast.
This new approach has been successfully implemented in the San Francisco field in order to re-organize the water-flooding regime, in particular through the conversion of producers into injectors. The entire process took only three months.
Our methodology has led to an expected additional production of 1.2 mmbo, a +12% increase in remaining reserves, with a total development cost of 4.5 US$/bbl. Current production data, one year after implementation, is in line with the forecast.
Casing-Drilling Application in the Depleted La Cira Infantas Mature Field, Colombia
Authors: López E. A. , Bonilla P. Antonio 
Published: December 2010

Abstract
Field redevelopment reflects the unique foci of the integrated project team built between Ecopetrol and Oxy to redevelop the LCI oilfield. La Cira Infantas (LCI) is the oldest Colombian field, production started almost at the beginning of the twentieth century and since late 2005 is under a redevelopment phase, increasing production by more than 5 times in less than 5 years. Redevelopment involves over 1500 wells being drilled or worked over in order to increase recovery factor by about 8% from the C sands. Hundreds of wells are scattered throughout this brownfield which is divided in two principal areas, Cira and Infantas. This field is crossed by faults characterized by depleted and shallow gas bearing formations, challenging drilling with loss of circulation and well control issues, somehow unpredicted given the faulty nature of the area and the impact on the producing sands of previous EOR and drilling campaigns (early to mid twentieth century) (Fig. 1).
This paper will describe the benefits of using the casing while drilling technology to drill wells where loss of circulation is anticipated, successfully eliminating flat times that otherwise would be used to cure losses when drilling conventionally due to the smearing effect which is enhanced by the addition of bridging agents and loss circulation material; and setting casing at the planned TD.
Drilling with casing has shown that 10% cost reduction and 30% time savings were achieved against conventional drilling, with additional potential to reduce costs and time by improving the operational times employed for drill-out, BHA recovery, and cementing operations.
Drilling Optimization of Wells From Crater Field: Decreasing Drilling Times and Operational Risks
Authors: Tellez Carlos Perez , Santiago Hector Mandujano , Puentes Ferney , Isacci Jose , Marino Luis , Obediente Rodolfo 
Published: December 2010

Abstract
In the past, wells drilled in Crater field required an average of 310 days to reach total depth (TD), mainly because of operational problems, including drillstring twist-off, stuck pipe, unplanned sidetracks, excessive directional complexity when drilling, and under-reaming. Low rates of penetration (ROP) while drilling the Eocene and Paleocene intervals also impacted drilling time.
Design optimization provided by a major service company allowed the operator to finish the recent Crater-52 well 95 days ahead of plan and 155 days ahead of the average duration for previous wells. This achievement significantly reduced operating costs and helped facilitate an anticipated production of 285,000 barrels of oil.
Key achievements are summarized below:
Drilled the 17.5-in. section 500 m deeper than the original design using 5.5-in. drillpipe instead of the traditional 5-in. Set 9.875-in. casing at the Medium Eocene Level, which made it possible to drill the 8.5-in. section with a much lower differential pressure, increasing ROP from 1 to 5 m/hr. Saved $3.4 MMUSD in operational costs and recovered 285,000 barrels of oil ahead of schedule. Reduced non-productive time (NPT) from 30% to 5.5%.
Lithological characterization, calibration, and updating of the geo-mechanical model helped the operator drill 500 m deeper in the 17.5-in. section, which eliminated the need for hole enlarging in two problematic sections. Using 5.5-in. drill pipe improved hole cleaning, with faster ROPs as a direct consequence. Drilling the 12.25-in. section to the Medium Eocene made it possible to drill the 8.5-in. section with lighter mud weights, decrease differential pressure, and elevate ROP. Lost circulation risks were also minimized. The NPT was 83% lower than the field average.
Based on these results, future Crater field well designs will also be optimized, and the drilling team is evaluating the feasibility of applying the optimized design in other fields. The improved hydraulics parameters helped increase hole-cleaning effectiveness and ROP while preventing operational incidents in the 17.5-in. and 12.25-in. intervals.
Application of an Artificial Neural Network ANN for the Correction of NMR Total Porosity, Effective Porosity and the Bulk Volume Irreducible Water Data Obtained from a Heavy Oil Reservoir using an Oil Based Mud Drilling Fluid in the Samaria: Tertiary on the Southeastern of Mexico
Authors: Granado L. M. , Sosa J. C. , Galicia J. A. , Rodriguez-Monroy R. , Escamilla G. , Ponce B. , Rueda M. C. , Quirein J. 
Published: December 2010

Abstract
Samaria Tertiary field in southeastern Mexico produces extra-heavy to medium grade oil (5 to 23° API) from sand-shale sequences. It is well known that the nuclear magnetic resonance (NMR) logging application can provide the total and effective porosity values, as well as free and related fluids independent of mineralogy. When the NMR logging tool is run in heavy oil deposits, oils of varying viscosities can be distinguished qualitatively. Unfortunately, however, in the presence of heavy oils, this measurement process underestimates the total porosity and effective porosity, and overestimates the bulk volume irreducible water (a key parameter for estimating permeability). Although the literature specifies methods that can correct this porosity and fluid volume bias by using fundamental magnetic resonance principles and conventional borehole information, they are only effective when the drilling fluid used is water-based mud.
The artificial neural networks (ANN) have traditionally been used to correct well log data corrupted by tension pulls on the tool or degraded by poor borehole conditions. They have also been used for cases in which it is not feasible to obtain a traditional set of openhole well log data. In such cases, a neural network is used to generate synthetic openhole data from pulsed neutron logging data.
In this application of ANN, the data is first manually interpreted to delineate uncorrupted zones of the data. This interpretation will correspond to zones in which there is no hydrocarbon or the hydrocarbon type is not heavy oil. The aggregate of such zones is used to define a training set. The remaining data is used to define the application data set. Traditional openhole data (such as resistivity, neutron, bulk density, and thorium) is used to train a neural network to predict NMR fluid volumes. The network obtained is then applied to the application data set, and it is shown that the resulting predicted NMR fluid volumes have been corrected for heavy oil effects in the presence of oil-based mud.
This paper demonstrates the effectiveness of this approach and discusses the results obtained. It also demonstrates how the process can be automated.
Analysis of Operative Variables for Establishing a Procedure to Obtain Representative Fluid Samples in Gas/Condensate Fields
Authors: Torres T. R. 
Published: December 2010

AbstractDuring the exploratory phase, reservoir fluid analysis is an important tool for obtaining the hydrocarbon volume In-Situ, for understanding the behavior of fluids based on the field pressure changes, for defining a fluids production strategy, and as an input for production facilities design, among others. Due to the importance of this information, sampling procedures must guarantee that collected fluids are representative of reservoir ones to allow for reliable results which will be obtained during the PVT laboratory studies.In the ABC Fieldcase, located in Cusco Peru, a Gas-Condensate reservoir with a dew point close to the initial reservoir pressure, it was necessary to develop a detailed operative design in order to guarantee that fluid samples would be representative. This study allowed us to define some steps which must be present in the operative procedure in order to achieve an optimum sampling process.Additionally, it was possible to see the effects in the representativeness of the samples due to pressure depletion, condensate banking, and its compositional analysis. The behavior of the Gas-Condensate ratio, the turbulent flow effects in the formation face, permeabilities, the optimum time for sampling, and flow rates.Finally, it was possible to evaluate the sampling procedure effects and its influence in the representativeness of fluid. An equation of state tuning was carried out for two fluids which were sampled in the same well. In this case, the effects of the different sampling procedures and their repercussions in liquid recovery are analyzed.With the information contained in this study, we can identify the importance of selecting an exclusive sampling period outside of the normal transient pressure testing period and the effects of the main system variables. Keeping in mind the importance of this information and the costs associated with the project, failure is not an option.
A New Methodology for Prediction of Bottomhole Flowing Pressure in Vertical Multiphase Flow in Iranian Oil Fields Using Artificial Neural Networks (ANNs)
Authors: Mohammadpoor M. , Shahbazi Kh. , Torabi F. , Qazvini A. 
Published: December 2010

AbstractIn this paper, Artificial Neural Networks (ANN) are used to predict the bottom-hole flowing pressure in vertical multiphase flow. Two-phase flow of gas and liquids is commonly encountered in the production and transportation of oil and gas. Knowing the bottom-hole pressure (BHP) of a well and the productivity index (PI or J) can help predict the well potential during its life-cycle. In other words, well production monitoring can be performed, which is a key objective for oil production maximization and operational cost reduction. Different correlations considering different operating conditions and flow models were studied in order to find the most effective input parameters. ANN accuracy is highly dependent on the validity of the input and output data. After gathering the input and output data from selected southern Iranian oil fields, all the data were filtered with the help of existing models to eliminate the unreliable data. Then, 167 data sets were normalized and carefully imported into the ANN models. Different ANN models with different numbers of hidden layers and transfer functions were developed and tested, and the best one with the least error was chosen. The accuracy of the pressure predicted by the developed ANN model was improved by approximately five times as compared with existing correlations. To show the accuracy of the method, the results are compared with those obtained from the existing correlations.Accurate prediction of pressure drop in vertical multiphase flow is needed for effective design of tubing and optimum production strategies. Different kinds of two-phase flow correlations have been developed and are currently being used in industry. In addition to the limitations on the applicability of all existing correlations, they all fail to predict the desired accuracy of pressure drop predictions.
New High Density Phosphate-Based Completion Fluid: A Case History of Exploration Wells: KRE-1, BOP-1, TBR-1 and KRT-1 In Indonesia
Authors: Sangka N. B. , Budiman H. 
Published: December 2010

Abstract
Due to its capacity and stability in extreme subsurface conditions, such as in HTHP and high concentration of sour gas and because of its non corrosive, re-useable, low cost and environmentally friendly, high-density Phosphate based Completion Fluid (CF) has been used in several exploration wells in Indonesia.
The main challenges during testing in exploration wells with extreme subsurface condition and high concentration of sour gas was how to maintenance and keep CF stability properties to support operating testing devices.
In exploration well KRE-1 in West Java Field, in a fracture Metasediment and Conglomerate lithology, subsurface conditions of HTHP, H2S 21 ppm, and CO2 25%, the Non Productive Time (NPT) that related with testing was 202.5 hours due to the constraints in the testing device, both the string configuration and the rubber component, it were caused by unfamiliarity in handling this brine.
After the evaluation, we changed the CF field handling and changed a configuration and specification of testing device.
The result showed that the CF properties bécame stable and the operational testing worked well.
The same procedures were applied in three exploration wells from different fields with several characteristics lithology and subsurface. First well BOP-1 in Bunyu island Field, in Sand-Shale-Silt-Coal lithology with subsurface condition of swelling shale with loose sand. Second well TBR-1 in East Java Field, Limestone lithology with subsurface condition of high concentration H2S up to 20.000 ppm and CO2 35%. Last well, KRT-1 in fracture Metasediment, Conglomerate, Sandstone and Limestone lithology and subsurface condition of HTHP, H2S 13 ppm, and CO2 6%. The related NPT with testing gradually dropped to 119.5 hours and then 78 hours and finally only 2 hours.
This paper describes the field experiences of handling Phoshates based CF during testing with lessons learned for operational testing devices from testing companies.
Analysis of the Effect of Different Forchheimer's Beta Correlations in the Results of Numerical Simulation of Gas Flow in Naturally Fractured Reservoir
Authors: Souza G. , Zacchi A. L. , Barretto A. B. , Pires A. P. 
Published: December 2010

Abstract
This work focuses the numerical simulation of gas flow in naturally fractured reservoirs (NFRs), when non-Darcy effects play an important role in the pressure behavior. Based on the conservation law of the gas phase, the real gas compressibility model and the Forchheimer's Equation, a code was developed to solve the hydraulic diffusivity equation and used to evaluate the pressure behavior when Darcy's Law does not model flow adequately. A layered reservoir model was considered to represent fractures. The discretization of the system of nonlinear equations was made through the finite difference method, the implicit formulation was applied and the bi-conjugate gradient method was used in order to obtain the numerical solution. The physical problem is related to equilibrium between viscous and inertial forces. At moderate flow velocities in porous media, pressure gradient is proportional to fluid velocity and can be expressed by Darcy's Law, based on viscous effects. However, at high velocities besides viscous forces there is also a force component due to inertia. In these cases, Forchheimer's Equation, which includes non-Darcy effects through a non-linear term added to the Darcy's Law, is an alternative to model compressible fluids porous media flow. The non-linear term has a factor called Beta, a function of permeability, porosity and in some cases of tortuosity. In this work, our main objective is the analysis of the effects of different correlations for Forchheimer's Beta factor in the wellbore pressure behavior. Results for pressure and pressure derivative followed the typical and expected behavior of the reservoir model chosen for fractures. Furthermore, comparison involving simulations with and without addition of non- Darcy effects showed significant differences between results, confirming that production flow rate, permeability and fracture thickness present strong impact on the reservoir depletion. Influence of Beta correlations was verified in several different results. Finally, it was clear that using Darcy's Law in cases where inertial effects are significant can lead to erroneous production estimates.