The new challenges of the oil exploration focused to the location in closed traps against faults in deep waters. The methodology has been developed for the juxtaposition studies by faults in structural traps that it analyzes the sealed surface, which is like an evaluation technique that quantifies of efficient way, the exploratory risk related with the sealed and the hierarchy of the prospective objectives in an opportune way speeding up the answer capacity for the taking of decisions that imply a high consumption of time and money. This summary synthesizes the method for the construction of the Allan's diagrams of juxtaposition. It consist of using computational tools that optimize the times of elaboration. The work flow has been directed in the realization of the juxtaposition (2D/3D) diagrams that it allows to evaluate the efficiency of the lateral sealed in traps against fault segment and obtaining of hydrocarbon new wells. To determine the capacity of sealed for the faults the seismic interpretation it is needed in depth of the roof-ceiling horizons, as well as the behavior of the segments of faults. Later on, it is carried out the seismic mapping of each geologic element to analyze. The principal stage of the methodology is the obtaining by means of an operation vector subtraction of the intersections of the objective horizon so much of the roof block and the ceiling block on the fault surface in the setting. Once certain, the vertical component of the fault jump for each one of the exploratory objectives. It proceeds to elaborate Allan's (2D) diagram in a profile made
up of the integration of the intersections of all the objectives for each contour of fault surface. Finally, It spreads in perspective the geometry 3D of each fault plan with their intersections type and their impact in juxtaposition. This method has been proven with success in the hydrocarbon locations on deep waters of area the Region Marina from Gulf of Mexico.
Managing Human Resources Development with an integrated and systematic approach is the key to individual and business success as it enables managers to identify and use the talent strengths for the benefit of the organization while motivating individuals towards their personal and professional growth.
Based on the though above mentioned, we developed a Continuous Human Development Model (CHDM)*, anchored to the Strategic Business Plan, with emphasis in the Human Resource Strategic Direction. The Model is composed of five interrelated processes. The first one is related to the Recruiting and Selection of Talents and the Induction - Training required before they are appointed to the organization´s positions. The three following represent the Core of the CHDM: Education and Training based on a previous Competencies level measurement, Career Development and Reward linked to Performance Appraisal. The Training based on Competencies process favors the identification of gaps between the employee's knowledge and the level they require to generate superior deliveries. The Career Development process includes: The Individuals Development Plan which is designed based on career paths and employee potentiality, and the Succession Plan for each key position, to assure the availability of candidates. The Reward, linked to Performance Appraisal, aligns individual to the Business Strategy, Mission and Vision. Last but not least, is the Retirement process which is conceived to prepare and enable employees to cope satisfactorily with a new environment and a different lifestyle.
The Model described was put into place by the Human Resource Department, of the Exploration and Production Division of two National Oil Companies located in South America and Central America, generating benefits to the business such as availability of: technical and managerial talents due to early talent identification, career paths and chart replacements for key positions and relay generation. It also brought some additional and intangible benefits like personal alignment to the organization strategic guidelines and reinforcement of a goal oriented culture, among others.
During production in a naturally fractured reservoir with natural water influx, under certain flow conditions an imbalance can be generated between gravity and viscous forces within the fracture system. This phenomenon is characterized by the gradual growth of a cone of water in the vertical and radial directions. When the radial growth of the cone base at the oil-water contact reaches the drainage radius, the cone of water reaches its maximum height. After this, the oil-water
interface advances without suffering deformation in the pseudo stationary regime. However, when this interface is a short distance from the bottom of the completion interval, the movement of the oil-water interface accelerates and water flows into the well. This phenomenon may shorten the well's life due to the complexity of oil-water separation offshore and resulting increases in operating costs.
In many of the Cretaceous formations of the offshore Mexico Bay of Campeche, oil recovery is limited at the top by the presence of a gas-oil contact and at the bottom by an oil-water contact. To recover the remaining hydrocarbon reservoirs it is necessary to: (1) define the optimal operating range which should be established for each well to delay water and gas breakthrough and (2) to schedule the necessary infrastructure to handle high production rates of water and gas as the field matures.
The objectives of this work are to:
Model in detail the water coning in the porous fracture system using a fine radial grid, with one meter thick layers concentric around the well, and 2 inches thick layers in the annulus, with and without cement.
Obtain an equation to determine the maximum height of water coning, the time it takes to form the cone, and the well shut-in time necessary to undo or "heal?? the water cone.
Investment projects are the primary vehicle for companies to achieve their goals, maximize the value of its shares by generating value. It is therefore important that the resources allocated to projects are used efficiently and that the promise of value of each project is met according to plan.
In response to this need, it was proposed to implement a project management system in the Vice-presidency of Exploration, Ref 1, based on international standards, industry best practices and definition of deliverables to achieve a continuous improvement process designed to develop more efficient exploration projects.
Implementation of the proposed management system for exploration activities has shown strong benefits, as evidenced in the systematic measurements of the FEL index over the past 5 years.
This paper presents an account of the FEL measurements of exploratory wells from 2006 to 2010 and its corresponding analysis considering the sustainability of the model's application in time, the benefits in terms of time, costs and characterization that determines the FEL index measurement.
Because of the confidentiality of information, for purposes of this article the names of projects were omitted were omitted and the figures are presented as monetary and time units.
In this work, a method is proposed for filtering the data recorded in formation tests and subtract the noisy parcel due to the tidal effects. The tidal effects originate on the variation of the gravitational potential applied to the reservoir as the moon and the sun change their position in space. This phenomenon, named tidal effect, can be observed when measuring the pore pressure of any accumulations of fluids in the pores of rocks in the underground, including petroleum reservoirs. Tidal effects were observed in petroleum reservoir pressure tests by the mid-seventies and a correlation between the amplitude of the tidal effect and the reservoir parameters were noted. From Biot poroelastic theory, methods were developed, using the tidal effect, to evaluate reservoir parameters such as compressibility, porosity, permeability. The selective extraction of the tidal effect is an important part of these methods. Fourier transform appears as great resource for this purpose, since the tidal effect is a sinusoidal signal with well-known component periods. The selective extraction of signals using the Fourier transform can also be important to assist in the determination of reservoir parameters, since the presence of the tidal effects may prevent or hinder the interpretation of the formation test from the diagnostic log-log plot. This paper shows the Fourier transform application to extract noise and tidal effect observed in formation evaluation data. The Fourier transform techniques were successfully used in three set of data recorded in formation tests performed in offshore wells.
In the past, numerous relations between sonic velocity (i.e., an inverse of sonic travel time, DT) and rock density were developed that were suitable for certain fields or certain rocks only. In this paper, the correlations between sonic- and densitylog measurements were investigated again using the data information from multiple fields in the Gulf of Mexico (GoM) and North Sea (NS). For sandstone-shale sequences, the dominant linear relationships between travel time (DT) and formation density (RHOB) were observed and compared with the popular Gardner's method (Gardner et al. 1974) along with other known methods. The implications of data clusters distinguished by formation lithologies and rock mechanical strengths were revealed from a cross-plot analysis. The probabilities and uncertainties of the developed correlations were determined using the actual histograms from the collected data of the GoM and NS fields coupled with Monte Carlo simulations.
Moczydlower, Bruno (Petrobras) | Salomao, Marcelo Curzio (Petrobras S.A.) | Branco, Celso Cesar M. (Petrobras S.A.) | Romeu, Regis Kruel (Petrobras) | Homem, Tiago Da Rosa (Petrobras - Petro Brasileiro) | De Freitas, Luiz Carlos (Petrobras) | Lima, Helena Assaf T Souza (Petrobras - Petro Brasileiro)
The Santos Basin Pre-Salt Cluster (SBPSC), Offshore Southeast Brazil, is a unique scenario, posing great development challenges. The microbial carbonate reservoir is unusual regarding its origin and petrophysical properties; the fluids have a variable CO2 content; the few analogue reservoirs around the world do not compare in terms of volumes, water depth and distance to the coast; and there are also flow assurance issues.
Considering the importance of these reserves for the Brazilian economy and the opportunity to accelerate cash flow, Petrobras and its partners have opted for a fast track development, including extended well tests (EWTs) and production pilots. The current Petrobras Business Plan (2011-15) foresees that the SBPSC areas alone will produce over 500,000 boe/d in 2015 and over 1,100,000 boe/d in 2020. These numbers refer only to Petrobras share and do not include the transfer of rights with economic compensation from the Brazilian government to Petrobras.
Therefore, the initial development phase will have to cope with several uncertainties, mainly the subsurface ones. Some of the most relevant are the quality and the heterogeneity degree of each reservoir zone; the compositional grading of the fluids; the performance of different EOR methods; and the presence of fractures affecting the flow. How to specify and anticipate the acquisition of expensive equipment, such as FPSOs and subsea devices, with uncertainties to be clarified? When is it worth to invest in more data acquisition, such as EWTs, core and fluid sampling, extensive lab analysis or even more appraisal wells? The timing and the uncertainty reduction foreseen for each initiative must be taken into account. On the other hand, when is it better to pay for extra flexibilities, accepting the inevitable CAPEX increase? Some examples would be: smart completions and possibility to inject different chemical products in the wells; gas and water separated lines for each satellite injector; flexible subsea layout, allowing multiples strategies and the addition of more wells; FPSO plants designed to inject desulphated water, or to export, import or reinject the gas, and also to separate variable CO2 contents in the produced fluids.
This paper aims to discuss the influence of the main subsurface uncertainties in the selection of alternatives to develop the giant fields in the SBPSC, in a fast track way.
Despite the fact that drilling activity through salt formations became an important issue for the oil industry since 1901, with the discovery of the Spindletop Field in Texas, wellbore stability in the neighborhood of rock salt has been seldom by analyzed. Considering that pore pressure is not present in salt formations because the low porosity they have, and that the fracture gradient is considered greater than the overburden; constraints for a safe mud weight is difficult to determine. Therefore, the mud weight program for salt section is mostly determined using the isothermal curves given by Leyendecker et al. (1975) or following rules-of-thumb. Currently, the approaches to study wellbore stability issues through salt formations are based on creep behavior, which is function of the activation energy. These models were elaborated under certain pressure and temperature conditions, so their reliability is not universal. Hunsche & Cristescu (1998) analyzed the deformations mechanisms due mostly for the volumetric behavior of rocks. They determined a compressibility/dilatancy boundary for rock salt which is function of the state of stresses that prevails. In 2007 Henglin et al. presented the hypothesis that a borehole would be stable only if the magnitude of the octahedral shear stress is below the dilatancy boundary given by Hunsche & Cristescu. This paper tries to explain the wellbore instability in rock salt based on Henglin et al. hypothesis. A new stability criterion is proposed and applied to field data from Yaxche and Sen Oil Fields to planning the appropriate mud weight for salt sections. Yaxche field is classified as high pressure-high temperature conditions, is offshore in the Gulf of Mexico; whereas Sen field is an onshore field, under low-pressure-high temperature conditions.
Fluid flow analytical models traditionally used in well test analysis not always yield adequate results for reservoir characterization. Contrastingly, fractal formulations have proved to be a more suitable tool. Among the various formulations, the Metzler-Glockle-Nonnemacher (MGN) equation includes a fractional time derivative. In this paper, that equation was applied to analyze interference tests in actual field cases. The MGN equation was applied and automatically matched to the observed pressures. Both usual reservoir properties -porosity and permeability- and also fractal exponents were varied in the matching procedure.
Automatic matches of the involved variables resulted in pressure increments that compare fairly well with observed data from the field tests. The responses show a high anisotropy in the rock properties.
The MGN equation implemented in this paper comprises fractal behavior in spatial variables as well as in the time term. Thus, well tests recorded in highly heterogeneous media, not amenable to standard techniques, can be analyzed with such analytical fractal approach.
An Interdisciplinary study for increasing oil recovery has been made in the present paper. This work has been adopted in the Upper Sandstone member/Zubair formation in South Rumaila Oil Field. The work was achieved by using optimization techniques for determining the optimal future reservoir performance regarding to infill drilling. Adaptive Genetic Algorithm (AGA) has been adopted in this paper to optimize the count and locations of infill wells. AGA uses Fuzzy Logic (FL) to determining optimal crossover rate, mutation rate and crossover form for each generation; in order to find accurate prediction. The main parameters depended in this study is the cumulative oil production obtained from the output of reservoir simulation software. This optimization tool depended on using the objective function of Net Present Value (NPV) as economic analysis. The optimal number of infill wells is three wells that have maximum cumulative oil production and maximum value of NPV. The locations of these optimal infill wells located in the crest of the oil field and far away from the east and west flanks because of the strong water drive from the infinite acting aquifer.