Considering demands for internal Brazilian market and international crude oil trade, PETROBRAS has taken the decision to concentrate a significantly part of the future of crude oil production from three deep-water fields; Roncador, Marlim Sul and Marlim Leste, all of which are in Campos Basin, with one off-shore terminal. The name of this project is PDET. This project comprises of a fixed central pumping station, PRA-1, a large FSO (2,1 million barrels storage capacity), and two calm buoys systems, at a depth of 100 m. The start-up of this project involves the crude oil from three producing platform; P-52, P-51 and P-53, which are all currently under advanced construction. In the future PDET will receive the production of crude oil from two additional new platforms. Each producing platform will have its own export pipeline, direct to PRA-1. The peak production of this system will achieve 600,000 bbl/day. PRA-1 will have special requirements to pump crude oil either to FSO or to the calm buoys systems. Based on a steel jacket structure the capacity of power generation will be 75 MW, up to 34 inches pigging capacity and many diverse pipings. The FSO has special specifications such as the electrical power and optical swivels, both are at a high level of technology and capacity. To achieve system's targeted reliability extensive studies were done. Integrity protection system, leak detection system, offloading time, sub-sea layout and flow rates were taken into consideration. Environmental risks were fully mitigated. The final configuration, which achieved high standard integrity assurance, produced a valuable project. This paper describes the logistics of this project focusing PRA-1 pumping, the export system through calm buyos, sub-sea facilities and the FSO. Also it will be highlighted some management programs used to implement this project. This work reviewed the major aspects of implementing this important infrastructure offshore facility to transport crude oil. Several technical and managerial challenges were surpassed through introduction of new technologies, tools and techniques. Introduction Campos Basin is the most important Brazilian E&P region, located offshore, in the southeast region of the country. As of June 2007, it has produced 1.5 million barrels of oil per day, which has accounted for 74% of PETROBRAS' total production worldwide and 82% of its domestic oil production. Campos offshore oilfields will continue to be the main source of Brazilian crude oil, in the near future. Expecting a sharp and steady increase in crude oil production, especially in deep water areas, PDET looked for the best integrated solution for Campos Basin offshore petroleum fields. In 2010 PETROBRAS domestic targets call for 2.4 million barrel of oil per day, meaning a huge increase in comparison with 2006 production. This will demand infrastructure of transport improvement to assure excellence concerning safety and operational procedures and environmental protection, which are strict requirements for Petrobras projects. PETROBRAS' strategic plan has officially achieved 2006 for one the company's greatest-ever achievements: Brazilian self-sufficiency in crude oil production. Reaching this level of production not only call for intense efforts in upstream to keep production increasing, but also perfect coordination with the downstream segment. E&P and Downstream areas conceived, approved and implemented a robust system to transport oil from the offshore deep water fields. So, PETROBRAS has now put in place its Campos Basin Oil Outflow and Treatment Plan (which goes by the Brazilian acronym of PDET), for the transport and delivery of the output's part from the Campos fields to the refineries. Three fields have been included in this approach: Marlim Sul, Roncador and Marlim Leste, all of them considered massive petroleum fields.

This paper describe in details the design and successful operation of an acid diversion completion system, which was used for first time in an exploratory project offshore Brazil. The most significant discoveries in a recent exploratory campaign in Campos Basin were in carbonate reservoirs. The first vertical well test showed a high heterogeneous and natural fractured carbonate reservoir. Considering the reservoir characteristics, analytical and numerical modeling was performed to assess the productivity of horizontal wells compared to vertical wells. As part of the Operator strategy of developing this oil field using maximum reservoir contact, a well test evaluation project in the open hole section, mitigating the risk of reducing the production, fractures cementation, etc. was performed. The whole project was developed to address the challenges of carbonate horizontal wells i.e. low permeability sections contributing marginally to the total production. A multistage horizontal open hole completion was designed and installed to perform a separately and selective stimulation in more than 3,000 ft of horizontal section. Previously, the most advanced technologies for open hole completions with mechanical isolation were reviewed to have the ability to perform multiples stimulations (fracture or matrix) in one continuous and more efficient operation. Based on final reservoir data obtained during the horizontal open hole navigation and a calibrated Geomechanical model, the acid diversion completion system was selected to perform an acid stimulation instead of a high pressure acid fracture job. The application was successfully run in this anisotropic carbonate reservoir and eight compartments were stimulated using an acid plant and high pressure pumps mounted on a Supply Boat dynamically positioned. More than 1000 barrels of stimulation fluid; a mixture of hydrochloride acid, and a visco-elastic agent to improve diversion were pumped stage by stage to the reservoir with a real time monitoring at the operator Support Center in Rio de Janeiro. After all the stimulation jobs and to prevent the high fluid losses, the well was shut in downhole using the reservoir formation isolation valve. A DST string was run. CT and Nitrogen were used to kick off the well and after 6 hours the well started to flow naturally, with first oil at surface within the first 8 hours of flow.

In 2007, a new Independent Brazilian Oil and Gas company acquired 21 exploration offshore blocks, increasing its portfolio up to 29 blocks by March 2009. Ambitious exploration and production goals were set, such as Drilling Commencement by Q3 2009, Minimum Well Drilling Commitments in four Basins by 2010/11, Initial Development in the Campos Basin and First Oil by 2012. The first three initial goals have already been met and the fourth one is well online to be met as expected with the FPSO already in the Brazilian coast. One of the key elements to reach these objectives is recognized to be the implementation of a focused innovative decision workflow, supported by a real time monitoring process from a cross-disciplinary Operations Support Center (OSC). This paper presents this innovative work scheme, based on a collaborative working environment between the operating and service companies during the well testing operations, with the most advanced monitoring and interpretation tools. It includes a concrete field case which resulted not only in improved risk identification, prevention and mitigation, but also in operational performance optimization. This case was a horizontal open hole test of 1080 mts with 90 deg deviation. The real-time collaboration resulted in significant rig time savings, mitigation of unexpected events consequences, and delivery of higher productivity comparing similar wells results in the area. This innovative decision workflow implemented in Brazil is considered as a high-technological reference model for operating companies, locally in Brazil and others around the world, to achieve success during challenging Well Testing operations.

This paper describes a method for automated interpretation of drillstemtests (DST's) for the cases in which the produced fluids do not fill up the drillstring. The method is based upon the pressure matching of field data witha theoretical fluid flow model through the use of an unconstrained non-linearregression technique, coupled with numerical inversion of Laplace transforms of the wellbore pressure for both flowing and shutin periods. The parametergradients required to implement the fitting process have also been obtained bynumerically inverting closed form expressions from Laplace space. A DST has been treated as a "slug test" with a step change in the wellbore storage coefficient at shut-in time. With this concept it has been possible to interpret flow and shut-in pressure data simultaneously. Both simulated and field pressure data have been analyzed in order to illustrate the application of the method using a fluid flow model which considers a homogeneous and infinite reservoir system, including wellbore storage and skin effects. Application of the method presented in this work to field data may yield estimates of reservoir and wellbore parameters such as the formation permeability, the skin parameters such as the formation permeability, the skin effect and the initial reservoir pressure. Such parameters are important to the determination of wellbore condition and to the forecast of hydrocarbon production. The methodology described in this paper may be used to extend the automated data fitting algorithm to 'include more complex fluid flow models, such as fractured or composite systems and other flow geometries. Introduction Interpretation of drillstem test pressure measurements have been usually performed by means of either type-curve matching or specialized plots of pressure-time data. When the production period is small, only data from theshut-in period may be properly analyzed. However, in most cases flowing and shut-in pressure data have been analyzed isolately, as in two different tests. According to Correa, a DST may be viewed as a slug test with a step change in wellbore storage. Correa and Ramey have given an analytical solution to the DST problem using the concept of a time-dependent boundary problem using the concept of a time-dependent boundary condition. They have solved the diffusivity equation with a single inner boundary condition, which included production and shut-in effects. Therefore, their solution production and shut-in effects. Therefore, their solution can be used to analyze the overall DST history as a single process. This may be effectively achieved by means of process. This may be effectively achieved by means of a non-linear regression technique by fitting the pressure response of a theoretical flow model to data of both flow and shut-in phases. Rosa and Horne have described an automatedtype-curve matching process using parameter gradients computed from numerical in version of analytical equations in Laplace space. Barua and Horne have compared the performance of some regression analysis algorithms, concluding that if there is only one ill defined parameter the Levenberg and Marquadta lgorithm gives the best results. This work describes a technique to provide estimates of the reservoir parameters and wellbore condition, by means of an automated analysis of a DST pressure history. pressure history.

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