Conventional horizontal gravel pack completions typically require multiple trips. Disadvantages of the conventional system may include the loss of rig time due to multiple trips and repeated rig-up / rig-down of pumping equipment, formation damage due to completion fluid losses and fluid loss pills, and incomplete filtercake cleanup across the entire gravel packed interval. A novel single trip horizontal gravel pack and selective stimulation (SHGPSS) system has been developed and implemented. This system allows the gravel pack assembly to be installed, the gravel pack to be pumped, and selective stimulation of the entire packed interval to be performed - all in a single trip. The benefits of the SHGPSS system include valuable rig-time savings and, efficient mechanical diversion of the stimulation fluid. This paper outlines the first applications of the SHGPSS system to successfully complete five deepwater horizontal injection wells in the Campos Basin, offshore Brazil. Hydrostatic pressure was maintained on the formation during all treatment phases, thus preventing any underbalance that could lift the filtercake off the formation and cause undesirable fluid losses. After gravel packing, a secondary ball was dropped opening a bypass area and converting the gravel pack tool to a selective stimulation tool. The system then provided the ability to perform a filter cake cleanup and stimulation by selectively treating the horizontal interval 40 ft to 80 ft at the time, depending on the screen joint length. Economic considerations along with completion efficiencies are especially important on deepwater, subsea completions. The novel SHGPSS system can reduce rig-time generating significant cost savings. Exceptional mechanical diversion of the stimulation fluid allows effective filtercake and formation damage removal yielding efficient completions. Case history information on five subsea, offshore Brazil, deepwater wells will further detail the optimized completions accomplished utilizing the SHGPSS technology. Introduction Most oil and gas reserves in Campos Basin (Figure 1) are located in deepwater (300m - 1000m) and ultra-deepwater (greater than 1000m). Economics dictate field development and planning is the key for successful return on investment. Completion systems that can minimize rig time and future interventions are particularly important for deepwater and ultra-deepwater environments. The reservoirs of the Marlim and Marlim Sul fields located in Campos Basin are described as sandstone without water influx and require substantial water injection for pressure maintenance. Historical experience has verified that the reservoirs are unconsolidated and require sand control for both injectors and producers1. Economic development of deepwater projects demands that a minimum number of wells be drilled and still effectively drain the reservoir2. The horizontal completions can be producers or water injection wells, depending on the needs of a specific location. A major concern for these completions is to minimize formation damage caused by drilling mud left in the hole. Prior to running the completion tools, drilling fluids are circulated out of the wellbore at high rates in order to leave a thin filtercake at the formation interface. The filter cake is necessary to maintain wellbore stability and minimize fluid losses during gravel packing operations in order to achieve a successful gravel pack of the entire interval. However, fracture gradients can limit flow rates necessary to lift drilling fluids out of the wellbore. The result is high skins due to mud trapped between the gravel pack and formation, requiring well intervention. This is particularly true for injectors where no flowback of produced hydrocarbons clean up the skin damage caused by drilling the well. The SHGPSS system was developed for horizontal open hole injectors as well as producers by allowing for gravel packing and selective stimulation in a single trip as well as fluid loss control.

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fax 01-972-952-9435. AbstractThe challenge of the alpha/beta waves gravel packing open hole in offshore Brazil is how to successfully displace the proppant slurry in a large wellbore with a low fracture gradient formation, deep to ultra-deep water depths, and extended reach horizontal section.Since 2001, job data from more than 72 open hole horizontal gravel packings have been compiled into a database. This paper reviews the well information and the key gravel packing parameters: pump rate, fluid density, injection proppant concentration, inner/outer annulus area ratio, dune ratio, packing rate, packing time and packing efficiency during alpha/beta waves. The engineering implementations and challenges, the best practices and lessons learned for open hole horizontal gravel packing are also summarized. The data analysis yields a better understanding about the open hole horizontal gravel packing in the Brazil offshore and provides a good guideline for future practice. A historical review is also presented showing how the gravel packing methodology has improved packing efficiency and success rate.Case histories are provided demonstrating how to deploy the single trip system and pack the extended reach wellbore utilizing ultra-light-weight (ULW) proppant under extreme with improved packing efficiency and the success rate.

Most of deepwater Campos Basin reservoirs, offshore Brazil, have unconsolidated formations that require sand control. Openhole gravel packing has proven to be the effective completion method of choice. The main objectives were to achieve low damage ratios, maximize completion efficiencies and reduce completion cycle times. The project was conducted in one of the largest deepwater offshore field in Brazil, Marlim Sul. This paper describes the learning curve and completion optimization obtained during planning, execution, and post job analysis of six horizontal wells campaign with five water injectors and one oil producer. A combination of integrated service lines and experienced personnel were important to achieve excellent injectivity and productivity ratios. Several key operations from drilling to completion contributed to successfully complete these wells: openhole stability, drilling practices, drill-in fluids, wellbore clean-up, filtration, completion fluids, completion tools, sand control, gravel pack software simulator and job execution. The efficiency of the service company was measured with a system of penalties and rewards allowing the operator to monitor and measure the progress of the learning curve on completion. As final result, the partnership between operator and service companies contributed to more economic completion costs by reducing completion time, and improving well performance. Introduction Economic development of deepwater projects demands a minimum number of wells to effectively drain the reservoir. Due to the high cost of deepwater subsea environment, wellbore intervention must be minimized and completion life sufficient to achieve depletion of the reservoir. Typical for the Campos Basin, the Marlim Sul reservoir is a Tertiary unconsolidated sandstone, particularly within the Oligocene and the Eocene ages, without strong water drive. It is a heavy oil reservoir (API 17–24), with 32% porosity, and 2000 mD permeability. Due to the need for high-rate injection to maintain reservoir pressure, and since high-rate producers are needed for economic development, Petrobras decided to develop Marlim Sul and several of the other fields in the Campos Basin with a series of horizontal producers and horizontal injectors. [1] Marlim Sul is a giant field located offshore Rio de Janeiro State, Campos Basin, Brazil (Fig. 1). The field was discovered on December 1987 and it has been under development since 1994. It contains 1.47 billion BOE of proved reserves and additional 1.15 billion BOE of probable reserves. Laying in 2,625 to 8,530 feet (800 to 2600 meters) water depths, the field contains 14 reservoir blocks in a 600 square kilometers area. To lessen risks, Petrobras decided to develop the field in four modules. The wells mentioned on this paper are part of Marlim Sul, Module 1, with 35 wells in total (21 producers and 14 injectors). [2]

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