The Marlim field was discovered in February 19859 by the exploratory 1 RJS 219 A drilled in a water depth of 850 meters. This pushed the deepwater exploratory campaign culminating in several deep and ultra-deep water discoveries in Campos Basin. The necessity to overcome the environmental conditions, associated with a giant field located in high water depth and reservoir characteristics, were the main challenges in the search for new technologies in the way to operate the field. These developments were achieved by a research program created at Petrobras R&D Center. This program counted on Petrobras expertise acquired during Campos Basin development and with traditional oilfield equipment suppliers through technological agreements that led to the first oil in March 1991. The field extension and the reservoir characteristics required a large number of subsea wells and, consequently, several production platforms, so the development plan was based on the implementation of several phases in different periods. This model, also used in several other developments in Campos Basin, allowed that the required huge investments and resources to be distributed along the field development. Moreover, it allowed innovative solutions to be proposed and introduced by new oilfield equipment suppliers along the project in order to optimize CAPEX. Marlim is a remarkable achievement to the oil industry that culminated with a peak production of 650,000 bopd in 2002. It also served as a laboratory for other deepwater developments offshore Brazil. With the field maturation new challenges are being faced in order to increase the recovery factor and to reduce the OPEX. This paper will provide an overview of Marlim Field, the main achievements and problems faced up to this moment to manage its development. Introduction The Marlim field was discovered in February 1985 by the exploratory well 1 RJS 219 A drilled in a water depth of 850 meters. This discovery pushed the deepwater exploratory campaign culminating in several deep and ultra deepwater discoveries in Campos Basin. Located in the northeastern part of Campos Basin, about 110 km offshore the state of Rio de Janeiro, the Marlim field is part of the Oligocene Carapebus formation and covers an area of approximately 130 Km2, in water depths ranging from 650 meters to 1,050 meters. From rock quality point of view Marlim field Oligocene reservoirs are excellent with average porosity around 30%. The reservoirs have low silt, clay and calcite content. The core analyses of various wells indicate mean permeability of 2000 mD, mean porosity of 30% and highly friable sandstone. Marlim's reservoir exploitation strategy relies heavily on water injection as a source of reservoir energy replenishing. The field development plan was based on various phases by means of subsea wells, subsea manifolds and floating production units whose development had been scheduled in different periods in order to make feasible the huge investments and resources required. It also improved the overall performance of the field development once each phase guided the next ones through the experience obtained during its own development. To support the field development, a research program was created in the company in 1986 - the PROCAP - focusing on all the technologies required to install the first Floating Production Unit for the Marlim field.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractWhen operating companies and the service companies combine teamwork and technology development with cohesive communication and planning, the result is proper integration of multi-discipline technologies to ensure successful field applications. The authors will outline some of the obstacles encountered and describe how the tools and procedures were designed to optimize reliability and achieve completions with better well life.Completion case histories are reviewed for wells in Brazil's offshore and deepwater Campos Basin, and deepwater Gulf of Mexico. The discussion addresses well planning, pumping operations, frac-pack design, selection of well screens with extended longevity and fluid systems that prevent formation damage.Openhole deviated and horizontal completions continue to be a primary method for reducing cost and improving recovery by maximizing reservoir contact. Integrating this technology with Intelligent Well Systems achieves a significant reduction in the number of wells required to maximize well productivity and reservoir drainage. Openhole completions have been utilized to successfully develop many of the reserves in offshore Brazil. These completion types include horizontal producers and injectors, gravel packs, stand alone screens, openhole gravel packs with annular isolation and integration of Intelligent Well Systems.Globally, technology has enabled the successful application of gravel packs in lateral lengths exceeding 8,300 feet, and water depths exceeding 6,100 feet. The growth of frac packing in deepwater Gulf of Mexico has intensified engineering efforts to meet the demands specified by the operating companies for fracturing formations with high permeability. Frac-pack applications in deep water can require pump rates exceeding 60 barrels per minute and proppant concentrations of 15 ppa. Specialized tools and performance software have advanced to address the increasing demands and risk management required in today's deepwater market. The evolution of technology is enabling reduced operations risk, better reliability and enhanced oil recovery.
Problems related to wellbore stability can increase drilling and completion costs. At the limit it can be impossible to drill a well because of wellbore mechanical instability. Several wellbore stability simulators can be found in the literature. Some of them present very simplified analytical solutions while others are numerically complex. Besides choosing the simulator, it is necessary to know the elastic and strength properties of the rock, the in-situ stress field, rock porosity and permeability and original pore pressure. Determination of some of these input data are costly and sometimes impossible. This paper presents the data gathering and design of a horizontal well in the Potiguar Basin (fig. 1) in Northeast Brazil. The main goal of this work is the determination of the mud density to drill a horizontal well, safely and economically viable, in order to avoid wellbore collapse (inferior limit) and formation breakdown (superior limit). Introduction This paper presents an integrated wellbore stability design for drilling a horizontal well in the Potiguar Basin. An integrated wellbore stability analysis means data gathering and mechanical stability numerical simulation. Underground rocks are always under a compressive stress field. When drilling a well, an amount of material is removed and consequently the wellbore neighborhood needs to support the load that was supported by the removed material. This new stress state may cause the wellbore rupture depending on the mud density and formation strength parameters. Rock behavior is totally different if it is submitted to compressive or tensile loading. Because of this, it is necessary to consider two different failure criteria to properly represent rock collapse behavior (compressive stress state) and another to represent formation breakdown (tensile stress state). These two criteria are presented in Appendix A. Field data and lab tests have provided the in-situ stress field and rock mechanical properties for the horizontal well stability analysis presented in this paper. Fracture propagation and pressure decline were analyzed from step rate test (SRT) allowing the stress field evaluation. Unfortunately a minifrac was not scheduled for this field. Elastic and strength parameters were determined from triaxial (drained) and uniaxial compressive tests done by Rock Mechanics Laboratory at Petrobras Research Center (CENPES). Fluid properties, rock porosity and permeability, were obtained through lab tests. The bottom hole static pressure was determined in field. A Finite Element Method (FEM) simulator (AEEPECD) was developed at CENPES for mechanical stability analysis in plane strain problems - The material constitutive law was considered elastic-plastic. MTOOL and MVIEW were used as pre and post-processors, respectively. Input Data The in-situ stress field was determined from field tests while rock properties were obtained through lab tests. Permo-porous and fluid properties, shown in Table 1, were taken from the reservoir database. In-situ stress magnitudes determination. Two basic assumptions were made for determining the in-situ stress field:The vertical stress is one of the principal stresses;The minimum in-situ horizontal stress magnitude can be given by the fracture closure pressure and its direction is perpendicular to the fracture propagation direction. The formation was fractured at a depth of 4163 ft using brine. The overburden gradient (1.03 psi) was determined from logs while the horizontal stresses were determined using the SRT. Four cycles were run with the SRT (Fig. 2) but only the first and the third ones were utilized for computing the horizontal stresses. The fourth cycle had operational problems.
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