Horizontal open hole gravel pack (OHGP) completions are increasingly required for the low API gravity oil fields in and near the Campos basin, offshore Brazil. Many successful horizontal gravel packs have been performed in this area, often in spite of increasingly difficult technical constraints on the operation. Critical limiting conditions on successful gravel pack placement include the combination of low fracture gradients, deep to ultra-deep water depths, and extended reach horizontal sections. This paper describes the lessons learned and best practices developed for offshore Brazil horizontal gravels packs under these severe conditions, supported by data from 20 jobs performed to-date. The analysis yields a better understanding of this type of open hole completion and demonstrates how to achieve a successful treatment under critical limiting conditions. Also discussed are several proven completion practices with application for future completion operations in the scenarios presented. Introduction Economic development of deepwater projects demands a minimum number of wells to be drilled and completed in order to effectively drain the reservoir. Heavy oil exploitation makes this approach even more difficult because extended reach wells are needed. Due to the high cost of operating in a deepwater, subsea environment, wellbore intervention must be minimized and completion life sufficient to achieve depletion of the reservoir. Gravel packing of horizontal wellbores in unconsolidated formations has proven to be an effective method to achieve these goals economically in the Campos Basin, offshore Brazil (shown in Figure 1). Stand-alone horizontal completions have common used to complete long, open hole horizontal wells in unconsolidated formations. However, in most applications the stand-alone devices become plugged or cut out with time. The consequences may be unacceptably low well rates or excessive sand production. Therefore, un-gravel packed screens and slotted liners in horizontal completions have been disappointing. Typical reservoirs in Campos Basin giant fields are high permeability turbidite sandstones with low API gravity oil. Generally, these unconsolidated formations are not strongly water driven. Due to the need for high rate injection to maintain reservoir pressure, and since large producers are needed for economic development, it was decided to develop several fields in the Campos Basin with a series of horizontal producers and injectors. Current gravel packing technology offers a great option for a horizontal well completion where sand production presents a problem. The advantages of gravel packing over a stand-alone completion are improved productivity or injectivity and completion longevity. Offshore Horizontal OHGP Best Practices While it is important to effectively prevent sand production, it is equally important to do so in a way that does not hinder productivity. The feasibility and success of gravel packing a long horizontal well depends on drilling techniques, drill-in fluids, wellbore clean-up, open hole stability, completions fluids, completion tools and equipment, sand control techniques, software/simulators, pumping schedules and field personnel experience. Monitoring Return Rate In the early OHGP's performed with floating rigs, the return rate was monitored through the choke/kill manifold with the annular BOP closed. An extremely high circulating pressure was observed during gravel pack pumping.

The paper presents an overview of the evolution of Petrobras open hole gravel packing operational practices after the 200th well has been successfully completed with this technique in Campos Basin (CB): a milestone in the history of Petrobras completion practices in deep and ultra-deepwaters. The paper also presents a comprehensive description of the main steps taken to improve our horizontal open-hole gravel packing (HOHGP) practices towards a best-in-class status in unconsolidated oil-bearing turbidites. Since the first HOHGP job done in 1988 we had to move progressively from shallow to ultra-deepwater completion scenarios. Along this path a series of innovations has been incorporated to our sand face completion practices due to the ever-growing-complexity of the wells geometry, longer intervals to be completed, heavier oil reserves to be developed, rock mechanics restraints (ever-lowering fracture gradients) and the necessity of damage-free-, high-performance-wells to cope with the skyrocketing capital expenditures which is a general rule for offshore ultra-deepwaters nowadays. Petrobras strategy conceived to continuously enhance its HOHGP completion efficiency index encompasses, the following interrelated subjects: -a comprehensive long-term plan to deal with the problem, -a multi-disciplinary team-work approach, -a strong cooperation with gravel packing tools & screens suppliers, -improvement of operational procedures and guidelines against which to measure well performance and -research & investment in cutting-edge technologies. Discussions on the challenges envisioned for HOHGP operations in ultra-deepwaters in the years to come are also presented. Introduction The most prolific reservoirs in CB are the Upper Cretaceous and Tertiary turbidites. These high-permeability (circa 1000 – 8000 mD), stacked and amalgamated reservoirs are spread over in shallow, deep- and ultra-deepwaters within the Basin. Figure 1. Dictated by the depositional model associated to turbidites, the sand uniformity of these poorly- or un-consolidated sand lenses vary quite a bit. The presence of reactive shale streaks is recurrent in some of these turbidites. As a trend in many other offshore basins in the world, the first oil discoveries (early in the 1980´s) in turbidites were located in shallow waters of CB. These good exploratory results have propelled us to move progressively from shallow to ultra-deepwaters scenarios. However, since the pioneer oil discoveries we have realized that a sand management strategy was necessary to achieve the desirable levels of production. In fact, sand control is an umbrella term comprising different approaches to dealing with sand production problems. Different sand control methods are known: frac-pack, chemical consolidation of sand grains, use of screens: sintered mesh, conventional, expandable (ESS); use of slotted liners, gravel packing, inter alia. Petrobras philosophy is one of zero tolerance concerning sand production in offshore fields lest the governing parameters for sand production are not well established for the vast majority of actual field situations and they may change along the life-span of the wells. Should there be the slightest chance of sand production, a sand control method is installed in our wells. In essence, this preventive approach to sand exclusion stems from the following facts: wellbore integrity concerns, prohibitively high well intervention costs, the need to maximize production rates, to achieve a maximum completion efficiency index, safety concerns, payback economics, and incapability of sand-dealing in top-side equipments. In fact, our offshore production facilities have not been designed to process sand-bearing crude oils.

Summary This article presents the detailed formulation for each of the three steps of a horizontal gravel-pack displacement operation, including sand injection and alpha/beta waves propagation. The main core of the model, aiming to define alpha wave height, is based on a well known two-layer model. Initially developed for hydrotransport applications, this kind of model has been adapted by several authors for drilled cuttings transport analysis. Additionally, a comparison between theoretical predictions and pumping charts from a field operation performed in Campos basin is presented. Introduction Gravel packing is today the most frequently applied sand control technique in Campos Basin, offshore Brazil. Because of the critical conditions, such as the deep and ultradeep waters and low fracture gradients, great precision is required to assure gravel-packing success. Several models available in the industry for horizontal gravel pack design are essentially empirical, resulting in imprecise predictions for extrapolated conditions. These aspects were the primary motivators for the development of a mechanistic model to describe the whole operation. It is a consensus among design and operation engineers that a physically based software is a necessary rigsite tool for determining operational parameters, especially when last-minute data have to be considered. Reliable and fast results are required to enhance the chances of a successful operation. Several authors present experimental results of horizontal gravel packing performed in test facilities: Forrest1 presents a correlation to estimate pack length limits in highly inclined and horizontal wells based on a full-scale model wellbore tests with viscous fluids and water. Nguyen et al.2 developed a 3D numerical simulator based on the finite-volumes method, which can monitor the transport process of the slurry in both axial and angular directions. Conservation of mass and momentum is considered in each sector element (finite-volume cell) to evaluate its fluid transport process. Each sector element is assumed to process homogeneous properties within its control volume. The model considers rheological properties of fluid, effect of gravel settling, and friction pressure calculation. Penberthy et al.3 present several field tests in a 1,500-ft-long simulator to identify the main variables that govern the phenomenon. Extensive field-scale testing has aided in the development of procedures and operational guidelines that are still today relevant. Software has also been developed that is based on correlations to determine gravel transport velocity and mechanistic models to determine pressure drop and friction factor. Sanders et al.4 present a numerical model based on a pseudo-3D approach aiming to simulate of an alternative flow path concept during the horizontal gravel-pack placement. The model solves the equations of volume and momentum conservation for the incompressible slurry in the wellbore. In order to validate the flow-path concept both small-scale and large-scale experimental tests using models ranging from 5 to 1,000 ft in length were performed. The dynamics of data acquisition to run gravel-packing simulations requires continuous updating, and part of the information is accurately available only a few hours before pumping starts. Other data, such as detailed caliper information, remain unavailable in several cases. Considering the several input uncertainties for the process, the necessity to run simulations in a short time, and the limited processing capacity of portable computers, a major premise for the development was to consider simplified models that could fullfil the operational requirements. Of course, such models should be able to capture the major phenomena governing the process and predict pressures properly.

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.

This article presents the development of a computational tool to guide horizontal gravel-pack design for long horizontal offshore wells. Mechanistic model hypotheses, experimentation at a largescale flow loop, and software development are detailed. The computer simulation results are then compared with field data collected in the Campos basin operations, offshore Brazil. A discussion on design alternatives for a long horizontal well at low fracturegradient formations is presented. This discussion includes a sensibility analysis on screen eccentricity, open and closed blowoutpreventer (BOP) configurations, and alpha (alone) vs. alpha plus beta wave displacement options.