Subsurface geomechanical stresses can cause formation faults, slippage, and compaction. These movements result in well failures, impacting production and resulting in significant expense and lost revenue. Traditional means for detecting such failures are limited and usually require interrupting production to re-enter the well, resulting in late detection of the problem and limited counteractive options. A fiber optic support device has been developed to permanently monitor strain and temperature on sand screen products for gravel-pack and frac-pack applications. This technology, especially when paired with an optical wet connect, provides for long-term reservoir monitoring at the sand face, resulting in early detection of subsurface movements at a high resolution. With this information, operators can plan early mitigative actions, and monitor the results of these actions in real time. This fiber support device provides a means of holding a helically wrapped optic fiber rigidly in place at the sand face, with no negative impact on the sand control functionality of the sand screens. New techniques were developed to manufacture this technology, as well as a new method to install the fiber. Dry connects have also been developed to allow connections between individual sand screens and enable longer monitored intervals. The paper will describe this new technology, review test results to date, and discuss potential applications.
Frac packing tool erosion is a growing concern as more high-profile deepwater wells are completed using this technique. Today many deepwater wells require frac pack pump rates of at least 40 barrels per minute (bbl/min) with proppant loads reaching 300,000 lbm. As zone lengths are increased and multizone operations are performed, jobs requiring 60 bbl/min pump rates with proppant loads reaching 1,500,000 lbm are becoming more typical. The current frac packing tool designs must be optimized to accommodate the higher pump rates and proppant volumes required to complete these deepwater wells. Extensive research and development, including computational fluid dynamics analysis and scale-model erosion testing, have led to the development of a new series of sand control tools that have been optimized for ultra-high-rate frac packing applications. Analyzing various patterns such as velocity, fluid path, erosion, and sand concentration at high rates helps identify critical areas within the system that require design optimization. Results from full-scale erosion qualification testing of this new series of sand control tools are discussed. The qualification tests are designed to simulate extreme applications for tools in terms of pump rate, treatment volumes, and proppant properties, while testing conditions remain consistent with actual job specifications. The qualification test parameters were chosen to emulate and, in some cases, exceed the parameters of frac pack treatments currently being planned for the deepwater Gulf of Mexico. Erosion properties of the crossover, extension, and casing will be discussed, and depicted.
This paper focuses on the first global installation of a water injector well with a lower completion system that incorporates both premium sand control screens and water injection profile equalization. The equalization of the water injection profile of horizontal wells has been a key issue in many development projects worldwide and has the potential to increase the reservoirs ultimate recovery by increasing the water sweep efficiency. Inflow Control Devices integrated with premium sand control screens have a long history of application in production wells. In these cases the main objective is to create a uniform inflow profile along the horizontal section, delaying unwanted water and gas production and increasing oil recovery. The method through which Inflow Control Devices equalize the inflow of oil can also be used to equalize the outflow of water. Historically, sand control completions for water injection wells include stand-alone conventional screens and open-hole gravel packs. Stand-alone conventional screen completions do not provide equalization of the water injection profile. Open-hole gravel packs provide for an effective acid treatment of the water injector well but present operational risks, high costs, as well as expensive rig time. The installation was carried out in a subsea horizontal sea water injector well in the Campos Basin, offshore Brazil. The paper presents the overall completion plan, the lower completion installation, the acid treatment through the Inflow Control Devices, and the initial water injection results based on production logs and water injectivity tests. The main concerns during the planning phase are discussed, highlighting the procedures adopted to overcome them. The good initial results have created the expectation of many applications of this system in Campos Basin. It is believed that sharing this information will benefit many operators with horizontal water injectors in their field development plans. Marlim The Marlim field, located in the northeastern part of Campos Basin, about 110 km offshore in the state of Rio de Janeiro, was discovered in January 1985. The field covers an area of about 145 km2, in water depths ranging from 600 m (1968 ft) to 1,100 m (3609 ft). The Oligocene sandstone reservoir quality is good. Core analyses of several wells indicate mean permeability of 2,000 md, mean porosity of 30%, and highly friable sandstone. Marlim's reservoir development strategy relies heavily on water injection as a source of reservoir energy maintenance. Currently 9 Floating Production Systems (FPS) are on stream with 129 subsea wells on operation (83 producers and 46 water injectors), including 36 horizontal wells. The total production reached its peak of 650,000 bbl/d in 2002, overcoming all former production forecasts. Currently Marlim field oil production, around 450,000 bbl/d, is supported by injecting 760,000 bbl/d of sea water. The recovery factor to date is 22.9 %. The water production is 217,150 bbl/d (water cut of 33 %) and GOR is equal to the initial solubility ratio, 83 STD m3/STD m3. Water injection is into the oil leg, concentrated in the lower portions of the reservoir and production is concentrated in the upper parts, to delay water breakthrough. A thorough history of the Marlim field can found in references 1 through 6. Injection Well Strategy The water injector well under consideration for this project was to be located in the south area of the Marlim field. This injector well was planned for pressure maintenance and for sweep efficiency in the thin reservoir border of the field. The injector well, IN, and its neighboring producer wells, A, B, C, and D are shown in Figure 1.
Frac packing tool erosion is a growing concern as more high-profile deepwater wells are completed using this technique. Today many deepwater wells require frac pack pump rates of at least 40 barrels per minute (bbl/min) with proppant loads reaching 300,000 lbm. As zone lengths are increased and multizone operations are performed, jobs requiring 60 bbl/min pump rates with proppant loads reaching 1,500,000 lbm are becoming more typical. The current frac packing tool designs must be optimized to accommodate the higher pump rates and proppant volumes required to complete these deepwater wells. Extensive research and development, including computational fluid dynamics analysis and scale-model erosion testing, have led to the development of a new series of sand control tools that have been optimized for ultra-high-rate frac packing applications. Analyzing various patterns such as velocity, fluid path, erosion, and sand concentration at high rates helps identify critical areas within the system that require design optimization. Results from full-scale erosion qualification testing of this new series of sand control tools are discussed. The qualification tests are designed to simulate extreme applications for tools in terms of pump rate, treatment volumes, and proppant properties, while testing conditions remain consistent with actual job specifications. The qualification test parameters were chosen to emulate and, in some cases, exceed the parameters of frac pack treatments currently being planned for the deepwater Gulf of Mexico. Erosion properties of the crossover, extension, and casing will be discussed, and depicted.
Offshore deepwater fields usually require a semisubmersible rig to drill and complete their wells. Additionally, if any intervention is required in the well, a costly workover rig will need to be moved to the site. Hence, solving problems remotely using a method requiring less intervention can provide substantial savings in the overall cost of the well. Such an opportunity emerged when working on a project in the offshore oilfields of Brazil, where use of water injection as a reservoir energy maintenance method is common. However, the mixture of water injection wells and oil producing wells can lead to the formation of barium sulfate on downhole equipment, which can precipitate under pressure change during production. Barium sulfate's insolubility makes its removal difficult; usually requiring the use of special tools for mechanically cleaning the gravel pack screens’ interior. This type of intervention method requires an offshore rig. It demands a considerable amount of time and resources to complete the cleanup procedure, especially in the case of long openhole horizontal gravel packs. However, by pumping inhibitors directly to the gravel pack screens’ interior, production suspension is avoided, along with any intervention-related time and cost. This paper will describe the world's first installation of a horizontal openhole gravel pack system specifically designed to allow continuous pumping of scale inhibitors. The chemicals were injected through a single flowline down to the interior of the sand-control screens at two distinct parts of the well pay zone, without interrupting oil production in offshore Brazil. This pay zone management system incorporates a hydraulic wet connector, an openhole zonal isolation packer, and two chemical injection mandrels with flow regulator valves. The mandrel valves evenly distribute the barium sulfate inhibitor, preventing its deposit inside the screen. Potential applications of this system in offshore Brazil are being considered on the basis of this successful first installation. Results of this project, as well as other compelling data, suggest that operators may benefit from its incorporation in their field development plan, maximizing their return on investment.
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