bluuebunny/crossref_metadata_2025_split huggingface dataset:
Probabilistic Production Forecasts Using Decline Envelopes
Authors: Brito L. E. , Paz F. , Belisario D. 
Published: April 2012

Abstract
One of the most frequently method used for production forecasting is the decline curves analysis, which can be harmonic, exponential or hyperbolic; being the most commonly used the exponential decline curve.
However there are wells that exhibit complex production behaviors, where the exponential decline curve does not fit the entire production history. One of the solutions that have been used is to divide the production history into several segments and then apply different decline factors for each segment. This complex behavior results from a long transient period observed in formations with very low permeability that have been stimulated with hydraulic fractures.
In this paper, we propose an approach that considers a table of time-dependent factors; each factor results from dividing the production rate at time t, q (t), by the initial production rate, q (0), so the production history becomes a profile of factors with values between 0 and 1, which represents more accurately the behavior of the well decline. When this method is used to analyze a reservoir or a field, each well produces a decline profile, and using the information from all wells generates an area in which a profile for each well can be found. This area is defined by two envelopes, an upper bound, representing the most favorable performance, with lower production decline, and a lower bound which represents the worst performance with higher production decline. The upper bound is generated using the maximum function, and then a smooth curve is found with a hyperbolic fit; for the lower bound a similar process is used but using the minimum function. Additionally an average curve is determined.
In order to perform a probabilistic production forecast using these envelopes, a profile is generated within the envelopes using a probabilistic distribution of the ubication. A random value between 0 and 1 is generated and added to the respectives values for each month of the lower envelope, to get a new profile. Using this profile a production forecast can be made and multiple simulations can be performed to obtain a probability distribution curve of all the possible outcomes.
Hydraulic Fracture Geometry Evolution and Pressure During Pumping: Chicontepec Experiences Indicate that Natural Fractures or Fissures Are not Activated
Authors: Luces J. , Salguero J. , Morales J. M. , Riano J. M. 
Published: April 2012

Abstract
Natural fractures exist in many oil and gas reservoirs. The activation of these fractures can have a significant influence on the initial production and the EUR of the wells. It is therefore very important to know whether they are interconnected and their impact on oil recovery, thus optimizing the development plans of the reservoirs. The giant Chicontepec field, located in central eastern Mexico, with 140 billion barrels of oil in place (OOIP), with laminated turbidite sequences, limited lateral extent, low porosity and permeability, very low current recovery, there are natural fractures or fissures. These natural fractures have been observed in many cores, as well as image logs and outcrops. It is considered that the natural fracture system must be analyzed in Chicontepec in more depth and more importantly, the degree of interconnection may have and its impact on oil recovery because it is estimated that may not be effectively interconnected.
Due to the low permeability of the rock, wells are hydraulically fractured. The analysis of the evolution of the pressure at the bottom of the well and or net pressure during a fracturing job is a valuable tool to infer the geometry of the fracture that was generated by the fracturing job. Furthermore, this analysis of the pressure is a powerful tool that can support the identification or existence of interconnected natural fractures and therefore with a certain level of contribution to the producing wells and the recovery of oil from the reservoir.
This report presents the application of the analysis of the evolution of the pressure during fracturing jobs in Chicontepec with examples that allow inferring that the natural fractures in Chicontepec are not interconnected or very little.
Formation Damage Modeling Improves Well Candidate Selection and Stimulation Treatment Design in Western Area of Putumayo Basin, Colombia
Authors: Franco C. A. , García C. C. , Henao W. A. , Zapata J. F. , Ortiz J. C. , Gonzales J. G. , Bahamon J. I. , Madera K. 
Published: April 2012

Abstract
A special engineering methodology was developed to understand the complexity of formation damage mechanism currently affecting the well productivity of the oil fields being operated by SOP (Superintendencia de Operaciones Putumayo) Ecopetrol.
The initial stage of this study involved the characterization and analysis of reservoir fluids samples taken along the time during different exploitation stages. The analyzed data was processed through specialized software to identify formation damage associated with both organic and mineral scales. Simultaneously a second stage was developed to determine and quantify the influence of production parameters on both fines migration and water production.
The data obtained during the previous stages were properly combined to generate a comprehensive formation damage model. Nodal system analysis, material balance, reservoir fluids characterization, and mineral/organic scale models and correlations were finally combined to identify and quantify the main formation damage mechanisms taking place in SOP′s fields.
Once the main formation damage mechanisms were identified and quantified then an extensive lab job was performed. This lab study determined the Best In Class (BIC) fluids required to dissolve and mitigate the formation damage.
The combination of formation damage model with lab data allowed designing an optimized treatment schedule by each well producing in SOP fields. Finally, an economical study was involved in the study in order to help in well prioritization to start the stimulation and inhibition campaign for SOP field.
A 3D simulation of certain formation damage mechanism was included as the final stage in this study. It was very important, especially when optimizing the stimulation-inhibition designs in those wells in which local grid refinement is required to better understanding of certain critical formation damage parameters.
The final list of well prioritization was optimized and stimulation-inhibition campaign for SOP fields was finally outlined to be started during the second semester of 2011.
Comparison between Real Field Data and the Results of Wax Deposition Simulation
Authors: Noville I. , Naveira L. 
Published: April 2012

Abstract
This study used transient simulation to represent the wax deposition phenomenon in the subsea pipelines. The aim was to identify another tool able to estimate the pigging operation frequency to remove wax from wells in which topside arrival temperatures are below the measured WAT (Wax Appearance Temperature). This tool may also be applied to those wells in which data of pressure and temperature, PDG (Permanent Downhole Gauge, installed in the tubing, close to the reservoir) and TPT (Temperature and Pressure Transmitter, installed in the subsea Christmas tree) sensors, are not available.
Reservoir Evaluation & Completion Optimization in Heavy Oil Sands with Dielectric & Diffusion Measurements
Authors: Ramos Y. , Chavez M. , Bustos U. , Decoster E. 
Published: April 2012

Abstract
Major heavy oil accumulations are found in the tertiary sandstones of the Lagunillas Formation of the Costanero Bolivar Field, located in Lake Maracaibo, Venezuela. The hydrocarbons are found in poorly consolidated shaly-deltaic sands, at depths of around 1200 ft to 2350 ft. The oil ranges from 10 to 18 degrees API, with viscosities ranging from 400 cP to 10000 cP. The formation water salinity is below 5000 ppm and variable within the reservoir, after years of injection of fresh water and steam to increase recovery. Consequently there is today no correlation between water cut and resistivity and the differenciation between oil and water with conventional petrophysical techniques is inaccurate. Conventional log analysis has limited potential since the resistivity shows identical values in both oil and water bearing levels.
Deciding on a completion strategy from an inaccurate saturation computation is a major challenge. Additionally, the free water presence reduces the net pay and rapidly increases the probability of water production in this high oil viscosity environment. Therefore an accurate assessment of free water and oil viscosity is a critical factor in the economics of the field. The present work incorporates dielectric and molecular diffusion measurements, showing significant progress in detecting free water from oil and defining the most prospective intervals.
Movable oil and fresh water are clearly identified using dielectric polarization at multiple frequencies. The dielectric measurement provides the water-filled porosity, while the magnetic resonance identifies the irreducible versus free water within that volume. This allows predicting the likelihood of producing hydrocarbon or water in areas with high oil saturation. In conclusion, the integration of dielectric polarization and diffusion information at multiple depths into the reservoir enable to distinguish oil from free and bound water and to estimate the oil viscosity, a result impossible to obtain with conventional logs in these environments. This integrated methodology allows accurate reservoir characterization and definition of the production potential of these heavy oil sands, leading to improved completion decisions.
The development campaign in Lagunillas sands now has a new workable technique to reduce uncertainties and to optimize heavy oil production.
Managing Risk in EOR Projects
Authors: Hite J. Roger , Blanton M. Lee , Kuhlman M. , Fair W. 
Published: April 2012

Abstract
Many companies, both international and national producers, are faced with the challenge of increasing reserves and production. Opportunities are often limited – enhanced oil recovery (EOR), gas shales, ultra-heavy oils, deep reservoirs and exploration - each with their own challenges. Understanding best practices in managing risk for EOR projects will facilitate using these processes to commercialize new resources in existing reservoirs.
The challenge for EOR is typically one of managing risk, so that investments can be made with an acceptable certainty of achieving the desired objectives. EOR is new to many organizations. It is frequently not well established in areas of interest. Performance histories are lacking. Support systems are weak. Training needs for engineers, operators and managers are high.
In this paper we recommend management and engineering design processes to manage technical and business risks. When followed, wasted time and money are minimized and the chances of success are increased.
There is a structured approach to developing technology in an efficient and cost effective manner and to bringing all stakeholders together as decisions are reached.
Unload Procedure with Control of Liquid Flow Rate Through Gas Lift Valve
Authors: Garcia Artur Posenato , Rosa Vinícius Ramos 
Published: April 2012

Abstract
Gas lift unloading is a transient process to lift well bore fluids and remove the liquid from the annulus (between tubing and casing). The field procedure developed in this work consists of finding the maximum allowable gas lift injection pressure during unloads. Its objective is to avoid erosion of gas lift valve by liquid flow rate and increase its service life. It was observed that the maximum injection pressure was not constant during the unload process. Two pressure gauges are required, one at the tubing and one at the casing (or gas lift flow line) since the pressures must be monitored during the unloading process. The liquid flow rate during its displacement is controlled by the gas lift injection choke.
The procedure was designed for offshore gas lift wells due to its high intervention costs to replace damaged valves by erosion. Damages in gas lift valves might decrease the maximum flow rate and cause production instabilities. This procedure can be equally applied to all gas lift wells that have at least two pressure gauges, one in the tubing and the other in the casing. The practice can only be applied in wells which have one single gas lift injection point.
Given that it is not possible to measure the liquid flow rate through gas lift valves in field applications, the procedure was validated against transient simulations. It was possible to observe a very good match with simulation results.
The Injectivity Index (II) could be used to calculate liquid flow rate through the gas lift valve. Unfortunately, the Injectivity Index is usually unavailable. Besides that, the production flow rate measurement is likewise sometimes unavailable during unloading. The procedure was developed to deal with these limitations. Other possible benefit is the optimization of unloading time by injecting the maximum liquid flow rate allowable.
Semi-Analytic Time-Domain Solution to Reservoir Models
Authors: Garcia Artur Posenato , de Souza Carvalho Renato 
Published: April 2012

Abstract
Analytic time-domain solutions are not possible even to some simple reservoir models, such as the finite radial model, which has a Laplace domain closed form solution. Several numerical inversion techniques of Laplace transform are available and find ready application for reservoir simulations. Stehfest is the most applied, however it leads to a purely numerical timedomain solution and all computational effort must be repeated for each required point of the response curve. This work develops a simple and efficient numerical inversion technique that leads to an explicit time-domain solution. The idea is to select a transfer function Gn(s) having an explicit inverse and evaluate its parameters by a curve fitting technique (Weighted Least Squares) with the impulse response of the reservoir model in the Laplace domain. The explicit function gn(t) obtained provides an accurate approximation for the impulse response. As we are usually interested in the step response, the function gn(t) still needs to be integrated in time and we find another analytical function for the step response.
Any reservoir model which can be described in the Laplace domain by a combination of Bessel functions that is impossible to by analytically inverted is suitable to this method.
The first test consisted of matching the results of this semi-analytic method with a model which has an analytic time-domain solution. The infinite reservoir model was approximated by a semi-analytic solution and the time-domain response was compared with the integral exponential solution. Next, the finite reservoir model was approximated by the same semi-analytic function of the infinite reservoir but with different coefficients. The time domain response was compared with the Stehfest inversion algorithm and results showed good agreement.
A method of numerical inversion of Laplace domain solutions is described in which the problem is converted to the solution of linear systems. It leads to a series of explicit equations for the time domain that reasonably matches with the traditional Stehfest inversion algorithm. The semi-analytic reservoir model can be applied to reservoirs in which the quality of the information does not warrant the use of a more sophisticated model.
A Thorough Diagnostics-Solution Approach to Increase the Recovery Factor from Horizontal Wells in Complex Dolomites
Authors: Fouchardiere Benoit de , Sapon Ronaldo , Valencia Diana , Guatemala Perenco , Aviles Rodrigo , Flores Jose G. , Resendiz Tadeo , Roman Igork San , Quevedo Manuel A. , Davila Luis E. , Vaquer Luis , Paz Alvaro 
Published: April 2012

Abstract
Xan is Guatemala's largest oil field, accounting for more than 90% of the country's production. Xan produces from a complex dolomite reservoir at average rates of 10,500 BOPD, with most of the production coming from 8 horizontal wells with typical open-hole completion lengths of 1,500 ft. The majority of the horizontal wells at Xan do not produce at their fullest potential because of near wellbore damage, associated to drilling fluid residues, and problems related to the high production of water, averaging 90% water cut at the field level.
This paper presents an innovative approach combining diagnostics supported with fiber optics distributed temperature survey data feedback and matrix stimulation systems, tailored to address specific needs, including viscous-highly retarded emulsified acid systems, multifunctional solvents, and surfactant visco-elastic diverting agents, all deployed through coiled tubing to remove the damage and maximize the treatment penetration in the reservoir. The solution was tested in two horizontal wells with severe formation damage and water production problems. The use of coiled-tubing deployed fiber optics facilitated monitoring and evaluating the stimulation treatments and fluids behavior in realtime, by capturing a sequence of temperature profiles and temperature responses to the acid injection at different times through the treatment. As a result, zonal coverage and effectiveness of the stimulation and diversion systems could be quantified as the treatment was pumped; allowing optimization of the stimulation program and pumping variables to accommodate to the actual well's response.
Production results have been outstanding, oil production increased by 54% from the two horizontal wells, which is equivalent to the production of a brand-new development well in this field, at a much lower cost. The diagnostics-solution approach developed for this reservoir helped accurately diagnosing the problem and implementing a fit-for-purpose stimulation treatment that actually improved oil production. The proposed methodology has substantially changed the process of stimulating horizontal sections in the Peten basin of Guatemala.
Oil Reserves Positive Adjustment of the Middle Eocene Calcarenites Reservoir Through a Correct Interpretation of the Oil/Water Contact: Ku Maloob Zaap Fields, Mexico
Authors: Angeles J. , Del Angel J. G. , Lopez M. C. 
Published: April 2012

Abstract
The middle Eocene calcarenites from the Ku, Maloob and Zaap fields are formed by packstone-wackstone limestones of high porosity; 20%, permeability between 10 and 400 md and low shale content. They are formations with excellent petrophysical quality. The core data contains the following fossils groups: Globorotalia lenheri, Globorotalia spinulosa, Truncorotaloides rohri, Lepidocyclina antillea, Porticulasphaera Mexicana; wich all are representative of the Middle Eocene. There is also Wackestone and Mudstones textures and few illyte mineral precence. It presents a lowstand slope fan deposit. The area is limited by the ausence of the Calcarenite rocks and sismic interpretation, their vertical limit are the silicate rocks of the same age.
The fields are pressure connected through a common aquifer. Within an open and connected system, with a normal hydraulic gradient, very close to 0.11 kg/cm2/m. The lower limits for the three fields are located at very close depth: 2720 TVDSS for Ku field, to 2710 TVDSS for Zaap field and 2750 TVDSS for Maloob.The oil production in the Middle Eocene Calcarenites reservoir (CCE) began in 1986 with the well Ku-10, which produces 17 ° API oil with viscosity of 8.5 cp. In previous studies
The objective of the present study was to correctly identify the depth of the fluid contacts, which directly impacts on the reserves and increased the original volume of hydrocarbons; since the oil water contact was located about 200m deeper the original oil in place increased 200%. Also it rules out the possibility of compartments from previous studies.
Gas Coning and Channeling Management in Naturally Fractured Reservoirs with Applications to the Akal-Cantarell Field
Authors: la Garza F. Rodríguez-de , Ortega-Galindo R. , Garcia-Pietri E. 
Published: April 2012

Abstract
A strategy to manage and control gas coning problems in the Akal-Cantarell field, based on correlations developed by extensive single-well dual porosity numerical modeling of gas coning phenomena, is presented in this paper. Attention was given to the range of reservoir parameters and production conditions that were found relevant to and representative of the Akal field. The effect of high permeability channels, left behind in the casing by improper cementation, on the evolution of gas coning was also analyzed.
It was found that the main variables that govern gas coning and channeling phenomena in the naturally fractured Akal field are: the effective permeability of fractures, Kf, oil production rate, qo, and the distance between the gas-oil contact and the perforations at gas breakthrough, Dzcp. A range of qo and Kf values, characteristic of the Akal field, was considered. For each pair of qo and Kf values, the distance between the gas-oil contact and perforations, Dzcp, at which the gas cone breaks into the well, was determined. A log-log graph of Dzcp versus qo, for given Kf value, resulted in a straight line for both coning and channeling phenomena.
Correlations developed for Dzcp as a function of qo and Kf as well as those developed to determine the times required for gas cones to dissolve, when the well is shut-in or choked, were used to define a production strategy to maximize the life of wells and optimize production. A field application is presented.
Use of Liner Drilling Technology to Ensure Proper Liner Setting: A Mexico Case Study
Authors: Belloso A. , Scott J. , Rivera J. M. , Piña J. , García J. V. , Mendez J. C. , Robles J. L. 
Published: April 2012

Abstract
Historically, wells drilled in the on offshore fields located on the bay of Campeche in Mexico face severe fluid losses and hole instability caused by the drastic lithology changes when drilling the Paleocene formation before entering the BTPKS formation (Breccia). Conventional drilling, even though slow and problematic, has been able to drill the interval in this particular environment.
Advances in liner drilling technologies have provided better solutions to the challenges of drilling wells where conventional drilling may not lead to optimal results. Three wells in Mexico used liner drilling technology to drill with a 7-in. liner through the Upper Paleocene, the calcareous body and the Lower Paleocene. The main objective was to isolate the shale/clay body and to enable setting the liner at the top of the BTPKS FM (Breccia), making it possible to drill the next section with sea water.
This paper will discuss the three cases where liner drilling was applied. We will cover the planning process, project analysis, operational problems faced and results. Using this technology has made it possible to: manage equivalent circulation density (ECD) to avoid inducing circulation loss; successfully isolate the shale/clay body; drill through the calcareous body; set liner in the Lower Paleocene; successfully cement the liner; and recover the running tool without setbacks.