bluuebunny/crossref_metadata_2025 huggingface dataset:
The Next Generation Inflow Control, the Next Step to Increase Oil Recovery on the Norwegian Continental Shelf
Authors: Mathiesen Vidar , Werswick Bjørnar , Aakre Haavard
Published: June 2014

One of the challenges on the Norwegian shelf is declining oil production and relatively low recovery rate. At current estimate, less than half of the oil will be remaining in the reservoir after shut down. A major challenge is to improve recovery from existing fields by developing and implementing new technologies that make mature and marginal fields more profitable. It's vital to develop technologies that can increase recovery before fields shut down. In most fields on the Norwegian continental shelf is the draining mechanism of pressure support from gas and / or water. This means that after a period of production, all wells will have gas and/or water breakthrough. As the breakthrough expands the production have to be limited due to excessive gas and/or water production. This means that production from the well have to be choked or stopped, even there is oil left along the wellbore. Inflow Control Device (ICD) and Autonomous Inflow Control Device (AICD) developed and installed by Hydro and Statoil have shown that the oil production and recovery can be increased significantly with better inflow control along the well. However, neither ICD nor AICD is able to shut off the unwanted gas and water production completely. The newly developed and patented Autonomous Inflow Control Valve (AICV) can shut off the unwanted fluid completely. This technology will probably be the next major step for increased oil recovery on the Norwegian Continental Shelf, in new and old wells. The new completion technology is presented and experimental test results with gas, oil and water are presented together with reservoir simulations that confirm that the AICV will give significantly increased recovery in field suffering from gas or water breakthrough.
Successful Use of Multilateral Technology to Improve Oil Recovery in the Brazilian Amazon
Authors: Mendes S. , Albuquerque M. , Vento M. , Batista N.
Published: June 2014

Petróleo Brasileiro S.A. (Petrobras) assessed many technologies to increase production and reduce costs while protecting the environment in the Brazilian Amazon. For this project, where access to likely wellsites is restricted both by limited infrastructure and Brazilian regulations, minimizing environmental impact was the primary factor in the operator's decision process.

To address both environmental and production issues, the operator selected multilateral technology, which minimizes the wellsite footprint, yet allows for drainage of a much larger volume of the reservoir from a single surface location. This is a significant advantage when compared to the cost and environmental impact of drilling multiple wells or using large drilling pads.

Petrobras implemented this technology in the Urucu field, located 650 km southwest of Manaus, in the heart of the Brazilian Amazon. The Urucu has three reservoirs and more than 95 wells. The target formation is Jurua in the Paleozoic Solimões basin—a basin that includes an important petroliferous system (Jandiatuba-Jurua). The reservoir rock consists of eolian and marginal, marine carboniferous sandstones.

This paper presents the results of a successful multilateral technology project in the Urucu field in which three TAML Level-4 dual-lateral wells were installed by Petrobras. These wells had an average production rate of 1.75 times more than a typical horizontal well while spending only 1.42 times the average cost of the same.
Characterization of Semipermeable Stratigraphic Layer of the Upper Cretaceous based on the Sedimentary Model of the Ku-Maloob-Zaap Production Asset
Authors: Carmona J. Garcia , Lopez M. Correa , Figueroa R. Rojas , Franco N. Aguilera , Pena M. Prado , Ibarra R. Martinez
Published: June 2014

The detailed study of the Cretaceous stratigraphic column and diagenetic studies in the Ku, Maloob and Zaap fields, have identified a low porosity, low permeability rock unit, which acts as a vertical barrier across the Cretaceous reservoir. This semi-permeable rock unit which reduces vertical transmissibility between adjacent strata has been called KSA. This calcareous-clayey and sometimes dolomitized layer has been associated with oil generating rocks and potential seal rocks. The aim of this work is to establish the sedimentological conditions, age and areal distribution of the KSA unit to understand its influence on the dynamic behavior on the Cretaceous reservoir for the Ku, Maloob and Zaap fields.

The interpreted sedimentary model is based on microfacies interpretation. All sedimentological and paleontological data is obtained allowing a reconstruction of depositional environment and origin of the sediments. Subsequently, paleoenvironments are interpreted by correlating stratigraphic sections to establish the lateral and vertical facies changes as well as the construction of the sedimentary model.

To understand the presence of the KSA unit it was necessary to know the Cretaceous sedimentary evolution. Eighteen (18) microfacies were defined. There is an open and shallow platform development. On top of the Cenomanian and Middle Turonian, we found a deepened area due to rising sea level (Oceanic Anoxic Global Event).

Based on sedimentological analysis and the correlation of electrofacies and gamma ray log, we can conclude that the KSA corresponds to a maximum flooding surface with clay peak values in the gamma-ray log averaging 15 to 40 ° API. The relative lack of planktonic and other organic matter suggests that this level is associated with an oceanic event caused by a deficiency of oxygen and possibly an increment in nutrients. Stratigraphic correlations of this interval yield an average thickness of about 35 m in Ku, Maloob and Zaap fields.

The new geological understanding of the semi-permeable KSA unit has been incorporated into a 3D model thus helping to optimize the position of new wells.
Selection and Optimization of Artificial Lift System in Heavy Oil Fields
Authors: Kaplan Vedat , Duygu Ersan
Published: June 2014

Emulsion which occurs in all phases of oil production and processing in heavy oil fields causes several operational problems. Especially, it can preclude performance of artificial lift system and induce malfunctions due to high pressure drop in production string and high shear stress around rod.

Existence of rod string in tubing heavily reveals production limitations in artificial lift systems used in deep wells which produce emulsifying heavy oil. Artificial lift systems do not only require power for lifting heavy oil up to the surface, but also they require power for coping with resistance of high viscous fluid during movement of rod string in tubing.

Movement of rod string originates shear stress that is very sensitive to viscosity of fluid. In case of using progressing cavity pump, radial shear stress occurs during clockwise rotation of rod string. In contrast, as sucker rod pump is used, axial shear stress takes place on the up and down stroke of rod string.

As far as negative effect is concerned, radial shear stress on the progressing cavity pump system is less detrimental than axial shear stress on the plunger pumping system in theoretical and practical aspects. It is also evident that it is possible to decrease negative effect of radial shear stress by selecting large displacement pump and reducing rotation speed of rod string by means of variable speed drive system provided that the same amount of production is received. Moreover, tubing back-off, twist-off caused by reversed movement of rod string and rod being screwed off when being shut down can be avoided owing to decrease in radial shear stress or torque created by high viscous fluid.

This paper aims to expatiate that progressing cavity pump is viable choice for particularly deep wells producing emulsifying heavy oil in terms of operation and energy consumption.
Changing the Way To Drill in Ecuador: Experience Using Point-the-Bit and Hybrid RSS in Horizontal and 3D Complex Wells
Authors: Carrizo Hector R. , Sanchez Jose L. , Perdomo Luis , Bertarelli Mario
Published: June 2014

To face up the drilling of complex oil wells, the point-the-bit rotary steerable technology was introduced in Ecuador in 2010. The excellent drilling performance results and savings (both in time and money) have pushed the rest of oil fields in Ecuador to introduce and apply point-the-bit rotary steerable system (RSS), which was the key technology implemented in the drilling campaign for this paper. Twelve horizontal wells with complex 3D configurations were drilled.

The point-the-bit RSS for 8-½-in and 12-¼-in hole sections was promoted, accepted and used based on desing and operational advantages. The drilling campaign developed in 2011, 2012 and 2013 showed very good results: 107, 061 ft were drilled in 2, 821 operational hours with a significant average rate of penetration improvement of 20% in comparison with conventional technology in the same field for the same oil operators.

The point-the-bit RSS provided the way to solve common catastrophic events observed before (i.e., stuck-pipe and lost-in-hole situations). Aditionally it allowed to reach geological objectives for very complex wells offering several advantages like: Drill through all the proposed targets with a minimum separation from the planned trajectory.Reach higher dog leg severities in rotary mode with a minimum well tortuosity.Minimize reactive formation exposure by a faster drilling speed.Improve hole cleaning.Minimize stuck-pipe events while drilling and while tripping.Run 7-in liner and completions without any issues.Improve landing development and horizontal navigation process.Allow to drill longer horizontal sections.Possibility to run a reamer to enlarge the hole while drilling.

The successful drilling campaing with this point-the-bit RSS in Ecuador leaves the door open to the next generation of RSS which is a combination of push-the-bit and poin-the-bit RSS technologies that improves the capability to generate dog leg severity without compromising the rate of penetration and will allow to redefine the planning and execution phases of drilling process considering that the new wells to be drilled are every time more complex. Those RSS are part of the integrated drilling solutions to adapt in the directional drilling process in Ecuador for extremely challenging drilling environments.
Advanced Technique for Enhancing Fracture Conductivity in Tight-Gas Condensate Reservoirs through Applying Liquid Resins: Case Histories from Burgos Basin, Mexico
Authors: Lopez-Bonetti E. , Cuessy A. , Coronel H. , Suarez-Fromm J. D.
Published: June 2014

The purpose of this research was to identify challenges related to optimizing hydraulic fracturing in tight-gas condensate reservoirs using liquid resins to coat fracturing proppants. The selected case histories illustrate specific documented solutions of recent, successful approaches using this technology in the Burgos basin by analyzing production behavior before and after treatment in an exploratory well.

When discussing post-treatment production evaluation, the immediate pressure response and water flowback are commonly the very first parameters to observe during the cleanup stage. This surging process may indicate whether the objective was reached or not. However, additional uncertainty can arise when undesired monthly decline rates are observed, suggesting a loss of conductivity that can be caused by several factors—fracture embedment, early diagenesis, proppant crushing, fines migration caused by high producing rates, and stress cycling, among others—compromising the propped fracture effectiveness.

Real fracture growth during stimulation treatments, which can be monitored by microseismics, determines production longevity and is the actual criteria for determining fracturing success. This ultimate goal has been achieved in Burgos basin by applying the appropriate fracture design and considering a wide range of permeabilities present in the reservoir, as well as using proper geomechanical models along identified gas-condensate pay zones. Based on these findings, the recommended and applied treatment design used a liquid resin coating on 40 to 100% of the ceramic proppant, which was applied on-the-fly during pumping of the high-concentration proppant stages. This new technique led to obtaining an important production increase, maximizing reserves, and creating new opportunities for the operator to drill several wells in the area.
Applications of Computational Fluid Dynamics To Study: Slurry Flow in Pipeline for Heavy and Extraheavy oil
Authors: Zambrano Meza H. J. , Brito A. , Márquez J. G.
Published: June 2014

The Faja Petrolifera del Orinoco (FPO), located in the southern part of the Eastern Basin of Venezuela, has the largest reserves of heavy and extra heavy oil in the world. These oils are highly viscous and their API gravities values are between 7 and 15, these properties together with the existence of multiphase flow make the production and transportation of these oil is highly complex. Therefore, it is necessary to use heavy oil transportation methods focused on reducing the viscosity of oil, this is achieved be removing or modifying the oil compounds that have been pointed out as the main cause of the high viscosity of these oils, such as: partial or total upgrading or slurry transportation.

This study presents a flow modeling of a solid-liquid dispersion through horizontal pipes, which represents a slurry transportation, using a software of computational fluid dynamics (CFD) called FLUENT 6.3. For the simulation methodology was selected Euler-mixture in a three dimensional pipe model, with different concentrations of solids. The simulations were validated with experimental data development by PDVSA Intevep that contains pressure drops, temperature, solid characterizations and reological behavior of the slurry.

The performance evaluation by the CFD model showed an acceptable fit when it is compared against experimental data, this results allow to understand the hydraulic behavior of heavy oil slurry transport through pipeline.
LWD Formation Tester Applications in Colombian Basins
Authors: Galindo J. A. , Rincon C. C. , Hemsing J. J.
Published: June 2014

Because of the complexities of the Colombian geological basins, logging-while-drilling (LWD) is recognized as a preferred method of acquiring data for formation evaluation. This paper will present experiences with a new formation tester tool, which has the potential to evaluate reservoirs in wells that are mechanically complex or pose a high risk to the operator.

Current challenges for new oil and gas discoveries in remote locations, added to the geological and structural complexity of the Colombian basins has made LWD technologies the best method of reservoir evaluation. With complex stress regimes and common wellbore stability issues, formation evaluation programs frequently run over budget or fail to acquire the desired information. As a direct consequence of the difficulties encountered, a wide array of LWD sensors has been developed, based around the three principles of investigation, innovation and technology. A new technology has recently been deployed to several basins within Colombia providing a method of acquiring formation pore pressure measurements in real time.

Data from two projects, one in the Putumayo basin and the other in the Upper Magdalena Valley basin, will be presented. The addition of an LWD formation tester provides increased data assurance because it was run as part of the drilling bottomhole assembly (BHA). Overall, the LWD formation tester succesfully obtained valid formation pressure measurements in over 90% of the attempts to date. This data has allowed the operators to identify several compartments inside their reservoirs.

This paper will demonstrate how the addition of a formation tester into the LWD suite has enabled reliable reservoir evaluation, providing both technical and economic benefits. With the integration of a formation tester as a part of the drilling BHA, the operators were able to acquire a complete real-time profile of their reservoir and to allow long-term behavior to be predicted.
Engineered Fiber-Based Loss Circulation Control Pills To Successfully Combat Severe Loss Circulation Challenges During Drilling and Casing Cementing in Northern Pakistan
Authors: Arshad U. , Jain B. , Pardawalla H. , Gupta N. , Meyer A.
Published: June 2014

Loss circulation is the biggest challenge after drilling and weather-related problems during the process of constructing new wellbores. As per industry figures, more than USD 2 billion per year are spent in combating losses. In the Kohat-Potwar plateau of the Upper Indus basin of northern Pakistan, a harsh and complex environment, a well usually takes anywhere from 180 to 270 days to drill. The overall time taken to drill depends on the formation thicknesses, severity of the losses, and the concession location within northern Pakistan.

High-pressure water zones are located close to salt and shale formations, above the potential reservoirs. While drilling through the high-pressure formations, high mud weights greater than 1980 kg/m3 (16.5 lbm/gal) are required to maintain a well under control, which often leads to induced losses during drilling and also while running casing. The mud weight is typically lowered to 1500 kg/m3 (12.5 lbm/gal) or lighter to combat massive losses in naturally fractured limestone formations in the production hole.

Engineered fiber-based loss circulation (EFBLC) control pills, based on a specially engineered fiber system and the particle size distribution principle, were developed to control the losses. The pills were effective in curing losses during drilling and while cementing; prior to the introduction of the EFBLC pills, operators spent days in combating losses with numerous traditional methods. Also, the pills were robust enough to work in water-base mud (WBM), oil-base mud (OBM), or synthetic-base mud (SBM) environments with weights up to 2040 kg/m3 (17.0 lbm/gal).

In applications in northern Pakistan, the EFBLC pills were successful in combating the losses while drilling and cementing, thus reducing the threat of nonproductive time (NPT);minimizing the quality, health, safety and environmental (QHSE) concerns of well control; and preventing costly remedial jobs due to poor zonal isolation.
Integrated Conceptual Probabilistic Model Forecast to Optimize and Prioritize the Development Plans of Exploration Prospects, Early Visualization: Sur Lago Trujillo Field Case
Authors: Pérez F. , Albarracin R. , Jazzan W. , Valera A. , Llavaneras A. , Arguello V. , Griborio G. , Novaes K. , Acosta I. , Luján L.
Published: June 2014

Generating an integrated conceptual probabilistic model forecast for exploration of hydrocarbon fields is essential to the decision-making process when developing a strong portfolio of exploration prospects. It is important not only when considering the potential volume that could be discovered within each prospect, but also when considering drilling plans for extracting these reserves. It is important to both define the best strategies for achieving strong growth and sustainable profit over time and to consider possible risks and uncertainties that could impact such results.

Southeast of Lake Maracaibo, the most important axis of production growth is located within the western part of Venezuela, formed by the Ceiba, Tomoporo and Franquera fields, where a set of exploratory prospects comprise 36 potential reservoirs. Exploratory wells are planned to validate the estimated reserves of the development to help increase oil production. The optimization and prioritization of exploration prospects provides the foundation for creating an interactive workflow that is automated, versatile, and innovative to help optimize the portfolio of the defined prospects.

This workflow provides a strategy based on the generation and use of a probabilistic conceptual reservoir model based on information from neighboring fields and exploratory studies. Using this approach, the initial potential for each well and each of the prospects' different production profiles can be probabilistically calculated based on the development strategy. This allows visualization of how many wells should be drilled, the capabilities of the surface facilities, the number of personnel required to operate the field, and other additional important aspects.

This conceptual probabilistic model forecast (prospects—wells—surface) is connected to an economic-risk-uncertainty model, creating fully integrated modeling. When new information is gained, automated adjustments can be made, thus achieving quick optimal viewing of opportunities within the portfolio of prospects and improving decision making.
Reservoir Characterization and Estimating EOR Potential with a Sector Model Simulation of Señal Picada, a Large Mature Field in Argentina
Authors: Manestar Gastón , Thompson Anthony , Rivarola Laura Gómez , Mykietiuk Karina
Published: June 2014

A number of fields in the Neuquén Basin are currently mature waterfloods. To obtain significant incremental volumes of additional oil, EOR technologies need to be screened and then implemented.

Señal Picada is one of Argentina's largest fields with nearly 500 wells in 2013. These wells have exploited all the oil bearing areas of the field and have identified all of the oil water contacts in the various reservoir that make up this field. In 2013 the field was producing with a 96% water cut. Therefore for this field to have a long term future, post waterflood opportunities need to be identified.

To accelerate the characterization of such a large field, it was decided to study a sector of the field which was thought to be suitable for an EOR pilot and where an excellent quality core has been acquired.

By focusing on a sector, the construction and data QC of both the static and dynamic models was faster than if an attempt was made to construct a full field model. Additionally more iterations between static and dynamic models were possible in less time to identify which variables had the greatest impact on the history matching process and forecasts. With the main reservoir layers characterized, it was possible to both extrapolate the learning to the whole field and to evaluate EOR processes in more detail.

The sector modeling demonstrated that 3–4 stratigraphic cycles had the highest potential for EOR. However within these cycles two very different facies were identified by the study, a high permeability sandstone suitable for EOR and a low permeability carbonate which would negatively impact any chemical injection program.

The dynamic modeling of the field combined with analysis of the logs of infill wells surprisingly demonstrated that there was significant attic oil potential. This was interpreted as being due to the high vertical permeability in the field resulting in a waterflood which was more affected by gravity forces than viscous forces.

In conclusion the sector modeling study characterized the reservoir, identified the key sands with potential for exploitation by EOR and that there was remaining oil to be recovered both by the reduction of the residual oil saturation to water or by improving the vertical sweep efficiency.
Evaluation of Different Types of Operation for Inflow-Control-Valves Based on Production and Reservoir Data
Authors: Barreto Carlos E. , Botechia Vinícius E. , Schiozer Denis J.
Published: June 2014

Intelligent valves provide more flexibility for well operation and different options to improve field production. The number of control alternatives is large and the decision of using inflow-control-valves is not simple, mainly for choking valves. Therefore, it is necessary to quantify economic and technical impacts in order to avoid undesired results. This work uses reservoir simulation to evaluate valves operation as the basis for the decision-making process. The process is based on simulation results to quantify real-time production and reservoir data on the short and long-term effects. Observed data, such as water breakthrough, water front movement and production economic limit are used to make control decisions. A test example is created to represent a fracture region of a reservoir with channel configuration; then, different reservoir size models and different well production constraints are created. The results show that actions to control water front and to shut down regions in which the breakthrough occurs, significantly increase the NPV. Conversely, attempts to control water front and breakthrough in cases in which the production rate is not constrained may lead to a significant NPV reduction without providing any significant increase in oil recovery. It is also shown that it is essential to shut down regions where the production economic limit is reached, even if a higher oil recovery factor can be achieved. As a conclusion, inflow control valves operation based on real-time production and reservoir data may efficiently improve field production when an adequate control is applied. The decisions are complex and must be made carefully, observing the real-time data and associated limiting conditions. This paper provides information that supports the use of water front movement, water saturation and production data to operate inflow-control-valves. It is proved that the use of the production and reservoir data considered in this work can help real-time operation to achieve relevant long-term effects. However, it is important to observe reservoir conditions to make an adequate use of data.
Novel Gas Shutoff Resin System for Well Abandonment Applications in Colombia: A Case History
Authors: Urdaneta J. A. , Arroyave J. M. , Jones P. , Amaya J. L. , Coral A. , Hernandez H.
Published: June 2014

Recent studies have shown an increase in the percent of wells affected by sustained casing pressure over time. Both the oil and gas industry and governments are studying the causes of sustained casing pressure and methods to help prevent undesired flow that can potentially result in the loss of wellbore integrity and environmental problems.

In the Caribbean region in northern Colombia, various natural gas production fields have been developed for decades. Because of mechanical problems or low economic return rates, some producing gas wells have been abandoned. Some wells in this area have been abandoned using conventional cement techniques without success, sometimes resulting in gas communication through the annulus to the surface. This has even been observed in some cases where the primary top of cement (TOC) was planned to surface. Potential gas communication through the wellbore annulus has been an issue in the industry for a long time. There are several factors influencing gas communication, such as flow through mud channels, micro-annuli, and flow through unset cement, among others.

This paper presents the successful application of a new resin with superior mechanical properties and solids content designed according to the needs of the well, which allow it to penetrate areas previously inaccessible to conventional cement slurry, such as small fractures, channels, or micro-annuli. The case study presented shows how a sustained casing pressure problem was caused by a channel in the primary cement job. The novel resin system was pumped successfully as a squeeze job ahead of neat cement slurry to isolate the gas-producing formation, and no further gas production was observed at surface, bringing the well back into compliance with government regulations for proper well abandonment.
Increasing the Efficiency of Artificial Lifting System in the Production of Heavy Crude: A Colombian Field Application
Authors: Jaimes M. G. , Pachon Z. , Villar A. , Dorado R.
Published: June 2014

The light crude reserves are increasingly scarce and every day there are new discoveries of heavy oil. The heavy oil, extra heavy and bitumen make up approximately 70% of total oil resources of the world, which focuses the attention of the industry in this type of oil. An adequate management of heavy crude oil production in mature fields requires optimizing the efficiency of artificial lifting systems (ALS), in order to increase the productivity of the assets at appropriate levels.

The main difficulty in the low efficiency of ALS in the production of heavy crude oil is the high friction pressure losses in the system due to high viscosities that are handled (greater than 1000 cp). The selection, evaluation and application of chemical treatments to reduce the viscosity of crude oil in down hole was visualized, in order to improve the efficiency and ensure the adequate conditions of extraction and recollection to maintain optimal levels of production.

This study presents a detailed assessment of mobility enhancing additives (MEA) in fields operated by the Colombian state owned oil company, Ecopetrol, Which includes:

Characterization of the problem Selection of candidates State of the art of the MEA Characterization and Evaluation Methodology: Qualitative Evaluation, Rheological Behavior, Evaluation in the capillary viscometer Evaluation of compatibility with the additives added in the extraction, recollection and treatment system. Selection and Evaluation of treatment at different conditions of temperature, Shear Rate, percentage of water in emulsion Effect of viscosity in the efficiency of ALS (optimum range of operation) Nodal analysis to determine incremental production Evaluation of the technical and economic benefits.

This paper presents the application results in an Apiay oilfield well, in Colombia.

Finally, conclusions, recommendations and field results obtained in this study are presented and among which are: Increased of the efficiency of the ALS in 30%.Increased of oil production in 50%.Profit of USD $1, 000, 000 for implementation of the MEA in the Apiay Well.
Improving the Performance of Steam Drive in Channeled Heavy Oil Reservoirs: A Global Optimization Strategy
Authors: Awotude Abeeb A , S Azad Madhar , Naranjo Suarez C E
Published: June 2014

The thermal methods commonly applied in developing fairly homogeneous heavy-oil reservoirs may not be viable options in channeled heavy-oil reservoirs mainly because the injected fluid (steam) would bypass the heavy oil by flowing through the high permeability channels. Experimentally, it was found that the key to success in developing such reservoirs is to have optimum heat conduction which overcomes the reservoir heterogeneity. Hence, steam flooding, if properly optimized, could overcome this problem. Injection rate and steam quality are the main operational parameters that controls the economic heat propagation in the reservoirs. Additionally, placing the wells in more conducive areas to ensure that the regions with low-to-medium permeability get enough heat, is crucial.

In this work, we propose the optimization of steam quality using CMA-ES. A three-dimensional channeled reservoir model undergoing steam flooding was built and CMA-ES was used to estimate the optimal values of three variables of steam flooding. The Net Present Value (NPV) of the project was used as the objective function and three cases of optimization were studied. In Case 1, only the injection and production rates were optimized. In Case 2, well placement was optimized along with the rates. In Case 3, steam quality was included in the list of optimized variables. Results indicated that Case 2 gave higher NPV than Cases 1 and 3 signifying the importance of optimum selection of well placement. Also, it is understood that steam quality is an important parameter which controls the overall steam flooding process and a large number of function evaluations is required to obtain optimum values of steam quality.
Stochastic Sensitivity Analysis for effective Parameters Ranges on 3D Fracture Network Using Stress Distribution, Outcrops and Wellbore Data Adjusted to Well Production History in Mature Field
Authors: Bustamante E. J. , Cabello Rios V. , Escobedo Cabrera D. , Manrique Cáceres P. , Choque L. , Espíritu W. T.
Published: June 2014

The Mogollon Formation of the lower Eocene is among the most productive of the Block X that is located on the continental shelf along the northem coast of Peru. The Mogollon Formation is considered a Natural Fractural Reservoir that has been produced for 50 years; because of the age of the wells, they have not image log information even more the study area does not have seismic information; therefore, these lacks of data does not allow characterizing appropriately the fracture distribution and its impact on the production.

Previous studies tried to establish a methodology to characterize fracture sets but not reached to establish a proper relationship with production.

The aim is the stochastic Sensitivity Analysis to find effective parameters ranges on 3D Fracture Network using information of Stress Distribution, Outcrops and Wellbore Data adjusted to well production history in the mature field, 50 Wells were used in the study.

The Methodology consists in finding the ranges of variation of the indicators of fractures which are fracture density, aperture, orientation, length, distribution on the fracture site and configuration strain studies, which are obtained from a few available core data and outcrops; ranges allowed to develop a stochastic model with multiple realizations which were simulated numerically to find the best fit with the production history of the zone.

The study allowed establishing drainage preferential direction and 10 blocks with the same conditions was extrapolated. This methodology was incorporated in reservoir studies performed in the drilling project in the Block.
Computational Fluid Dynamics For Estimating Oil-Water Relative Permeability Curves
Authors: Cuevas J. , Gasbarri S. , Asuaje Miguel
Published: June 2014

Reservoir simulation is essential for defining the best exploitation and production strategy during different stages of development in a hydrocarbon field. The phenomenological understanding of fluid dynamics within the porous media is vital for reservoir engineers. The more accurate the permeability curves, the better the planning for exploitation. Several analytical and experimental techniques are used to determine the permeability curves with the least amount of associated uncertainty. Sometimes they have high degrees of complexity and cost, using direct and indirect methods in which the scale ranges from microscopic to macroscopic.

CFD has been moderately used in the oil industry for mechanical modeling of sand and Cutting Transport in Wellbores. It has also being used in the design and development of new drill bits and Inflow Control Devices (ICDs). The potential of using these packages in microfluidics studies (Glatzel 2008) has been shown recently.

This study provides evidence of the feasibility of using CFD for fluid flow modeling through a specific-shape porous media so core plug experiments may be optimized. Through this modeling, the relative permeability curves for oil and water in a porous medium can be estimated. The system was modeled in a rhombohedral-packing geometry with dual-sphere array. It was tested for different multiphase models available. A quantitative comparison with analytic-experimental models shows excellent results. The simulated displacement of the fluids is qualitatively comparable to those reported by visual experiments reported previously.

With little cost of money and time, this technique can be used for characterization of micro-phenomena within the porous media such as: Distribution of fluids in steady-state and transient processes (drainage and imbibition), Interaction of injection agents for improved or enhanced oil recovery, rock wettability and temperature effect on relative permeability curves, and nanotechnology applications.
Evaluation of Different Secondary Recovery Process in the Bachaquero-01 Reservoir
Authors: Rosal Z. , Mieres K. , Chourio G.
Published: June 2014

Since there are a lot of reservoirs of highly viscous heavy oil, whose extraction is a challenge for petroleum engineers in Venezuela, and also the significant gas shortage, which makes many of the gas injection projects in our reservoirs in the west of the country have been suspended are reasons why it has raised the need to explore alternative sources for the recovery of such highly viscous oil.

Improved Recovery processes emerge as an alternative to increase hydrocarbon recovery, changing the characteristics of the fluids and the capillary forces acting on them. Enhanced recovery is mainly based on sophisticated techniques in operation, is usually costly, but very effective, therefore, the enhanced hydrocarbon recovery is defined as oil production, by injecting a fluid, in addition to displace oil, favorably modifies the oil recovery mechanisms. The techniques can be applied at any stage during the operation of the reservoir; in fact, there are formations which for its geological and petrophysical characteristics can only be exploited by Enhanced Recovery techniques. Several factors play a role in the selection of the most economically attractive alternative, these factors are: The rock type and characteristics that have the greatest influence on the pattern of exploitation is undoubtedly the porosity, permeability, reservoir fluid, and the last factor is the injection fluid to be introduced to the reservoir. The selection of the fluid to be injected either to maintain reservoir pressure, move, or modify the mobility of hydrocarbons, are carried out based on the analysis of the molecular interaction between the injected fluid and oil in a reserve.

The present study shows the results of the Evaluation of Different Secondary Recovery Process in Reservoir BACH-01 to increase the recovery factor of the same; this reservoir is located on Lake Lagunillas Exploitation Unit. It was built a numerical simulation compositional model using the simulator STARS of CMG company, to represent the geometry and dynamics of the reservoir fluid flow, thereby validating the rock / fluid properties. Among the different methods studied is the CO2 injection, the Alternating Steam Injection more Gas (IAV + GAS), SAGP y VAPEX.
Development of a Finite Element Computer Simulation Platform for a Coupled Reservoir and Geomechanics System
Authors: Morillo A. , Moreno J. , Quintero R. , Gambús M. , Zambrano O. , Marcano V. , Araque J. , Rincón N. , El Mejmissani N. , Guíñez J. , Pirela M. Perez
Published: June 2014

The aim of this article is to describe the development of a finite element computer platform for the modeling, analysis, and simulation of a coupled reservoir and geomechanics system. The conditions that are assumed are the simplest possible, so that we assume homogeneity and isotropy in the material, an elastic behavior of the rock with small deformations, a quasi-static equilibrium, the absence of fractures and isothermal state. The study evolves sequentially in stages, from the flow of a single fluid in a porous medium, through the two-phase case, up to the three-phase black oil model. The starting point is based on a mathematical model that is an extension of Biot's theory for flow in porous media, and which accounts for coupling the reservoir of fluid flow to the rock deformation and stress states. The mathematical model is reformulated in variational terms, in order to get a proper formulation that enables us to apply the weighted residuals methods of Galerkin with linear interpolation functions. The use of linear interpolant functions reduces the computational work but at the cost of having to face some inestabilities in the solutions. Once the model is discretized, we make use of appropriate software to built an unstructured meshing domain using tetrahedral elements. We carried out a computational model founded in the design of a program based in the C++ language, to perform the tasks of numerical calculations of the coefficients, assembling the stiffness element by element matrices, and for solving the resulting equations. It is intended to develop the computer program in a modular structure, so that the solution of the coupled geomechanics/reservoir system can be performed through an iterative procedure. The development of this code is still in its initial stage, but the approachs show promise. At the end two case studies are presented, which are compared with analytical solution for verification of the approach
Early Detection and Diagnosis of Operating Events in Real-Time for Producing Wells With Artificial Lift Systems With Submersible Pumping
Authors: Mejía J. A. , Gutiérrez C. A.
Published: June 2014

The rise of automation technologies has enabled storage and sensing of operational data in real-time for key variables in oil production wells. These data are a key component in decision-making in the operation and control of the production of the field, if they can be converted to timely and reliable information.

This paper focuses on the early detection and diagnosis in real time of operating events mainly by the presence of gas and solids that negatively impact the well production. Expert systems techniques for the characterization of reference operational events are used. They are based on known rules of behavior of electrical and mechanical operating variables, constructed by combining knowledge of the phenomenon and empirical data.

The matching of behavior of real-time operational variables processed by techniques of statistical process control - SPC together with reference events determine the presence of operational problems by generating real-time alerts that allow it to act in a timely way and mitigate the negative impact on the production of hydrocarbons from the oil fields.

Early detection algorithms and real-time diagnostic operational events were programmed in a software tool for real-time processing, which was applied to the monitoring of two case studies in wells Castilla and Guatiquia operated by Ecopetrol SA in Colombia. Finally the main findings, conclusions and recommendations from this study are submitted.
Optimizing Waterflooding Process for Recovery Using Nonlinear Model Predictive Control: Case Yariguí - Cantagallo
Authors: Prada Mejía J. A. , Osorio Suárez J. P. , Camacho Navarro J.
Published: June 2014

This paper describes the results of applying a strategy of nonlinear model predictive control (NMPC) for closed-loop optimization of the water flooding process simulation on a reversed pattern of 5 wells in the field YARIGUÍ –CANTAGALLO operated by Ecopetrol SA in Colombia.

Field modeling and predictions are made through the use of a commercial reservoir simulator. The solution of the optimization problem of nonlinear control loop is determined using an approach that uses the reservoir model as a black-box by looking for patterns and sequential algorithms.

To manage the information of operational variables required by the optimization strategy, an interface was developed by managing online the output files of the commercial simulator. NMPC algorithm stability is achieved by finding sub-optimal solutions of the optimization problem.

The robustness and performance of the NMPC strategy is illustrated by its implementation to optimize the water flooding process simulation represented by a model with 814.226 cells of which 352.034 are active, 199 layers, 38 failures, 26 areas of balance and heterogeneous distributions of permeability and porosity. Thus, by appropriate adjustment of the water flow rates, it is proposed to increase the production of oil for the case study. Finally the main findings, conclusions and recommendations from this study are submitted.
The Stratigraphic-Sedimentology Model of Upper Cretaceous to Oil Exploration Field "Campeche Oriente"
Authors: Cervantes A. , Gonzalez L. Montes
Published: June 2014

The main objetive of this job is elabotared "The Stratigraphic-Sedimentology Model of Upper Cretaceous to oil Exploration Field, by use of the deposicional characteristics, this reservoir rocks and advanced techniques to estimate the Original Oil in Place (OOIP) and associated reserves. For this field, the total area is 1282 km2 and consists of thirteen exploration field. The Upper Cretaceuos (Upper Breccia) is the principal reservoir rocks for their petrophysical properties (Naturally-fractured reservoirs), área and thickness. The total average porosity is from 8% to 10% with average thickness of 11 to 105 metros, thinning to the south-west. The model sedimentology is interpretation as the grains flow and debris flow or mudflow unto seafloor, on the edge of a carbonate platform, limestone naturally-fractured and Breccia in-situ. In these units, the brecha is defined for outer-platform (island-reef-shoal cycles) and talud, and fragmental material, observed in the stratigraphic columns, also they can come from the event castrastofy Chicxulub.

The used workflow goes from the structural modeling (147 fault), the size of the grid 500*500 (semi-regional model), 3 seismic horizonts in deep (Breccia, Upper Cretaceuos, Middle Cretaceuos). The facies definition was two: submarine fan and Stratified sediments using formation micro imager (FMI) of 21 wells drilled. The detritus flow "Apron" are submarine fan, the geometrical form is minor width, mayor width and orientation.

The well to well is not possible correlation this submarine fan because the depositional time are different and can be related to several factors: (1) accommodation space (space available for sediment to accumulate, which relates the position of sea level relative to the flooded preexisting sediment surface or sea bottom), (2) rate of sediment accumulation, (3) rate of base-level change, (4) slope of the flooding surface, (5) mechanical sediment and diagenetic compaction, and (6) isostatic, thermal-tectonic, and active-fault subsidence [see also Kendall and Lerche (1988)].

Consideration to several factors for the geometrical body was used workflow with polygons and probability map. This skill helps us to generate a model probabilistico of the submarine fans.
Uncertainty Analysis and Risk Assessment Methodology in Early Development Fields
Authors: Salinas R. , Di Nezio A. , Huerta V.
Published: June 2014

The development of a new field requires a special effort to recognize and evaluate static and dynamic reservoir uncertainties. Since there is limited information of the fields during exploration and appraisal phases, reservoir modeling is such a challenging task towards managing uncertainties and assessing the risk associated to it. The first step towards managing reservoir uncertainties is to identify and rank key reservoir parameters affecting hydrocarbon in place and recovery factor; then, key variables impact should be quantified by tornado or Pareto plots.

The current study gives an approach about Petrel™ tools in order to perform sensitivities and uncertainties analysis to some parameters; therefore, obtaining a reliable variation range of main outputs in this evaluation; in addition, achieving an indicator of main variables that affects the original volumes in place and recovery factors.