High pressure stimulation of tight sandstone formations is occasionally combined with flowback of proppant and formation sand during the onset of production. This is generally attributed to characteristics of unconsolidated sandstones and their response to high pressure hydraulic stimulation. This brings an additional challenge to openhole multi-stage completion systems that now require a filtration mechanism as part of the completion design, to introduce a sand exclusion technology alongside the multi-stage ball activated frac sleeves. A novel openhole multistage fracturing system was developed combining the operational efficiency of ball activated frac sleeves with sand control efficiency of multi-membrane filtration sand screens. This combination of technologies deliver a robust completion design and a unique intervention-less solution to enable stimulation at high pressures and provide sand exclusion on production. The system comprises of a series of incrementally sized high strength disintegrating frac balls to activate and close stimulation frac sleeves while simultaneously also opening production sand control screens. The design allows for several production sand control screens in one stage to maximize reservoir contact for unrestricted production. The system allows to efficiently complete the frac treatment and start sand-free production of the well without any intermediate manipulation of downhole tools with coiled tubing (CT) or wireline. This technology brings substantial value by not only early sand-free production, but also flexibility to add additional sand screens within the stage without compromising stage count. The intervention-less design of the tools eliminates the need for coiled tubing (CT) manipulation of downhole tools and hence associated high intervention costs. Keeping in mind the increased need of high-pressure stimulation for unconventional and tight reservoirs, the system is designed to 15,000 psi rating. The sand screens are designed to be isolated from stimulation pressure while maximizing inflow area without compromising on sand control. Further, to enable full efficiency, the system includes high-strength disintegrating frac balls to enable an early production of the well. This paper encapsulates the design, functionality, and development testing of the intervention-less multistage fracturing sand control system. This novel technology is designed keeping in mind operator challenges associated with high cyclic stimulation pressure on completion tools, undesirable well intervention and associated high production costs.
Existing pressure-sensitive firing heads are either hydraulic or electronic. Hydraulic firing heads have the advantage of simplicity and cost. In addition, hydraulic firing heads do not have batteries and can, therefore, remain downhole for several months before functioning. This enables the operator to utilize their assets and equipment more economically. Electronic firing heads, however, enable operations in small pressure margin wells and allow for more advanced completion equipment and services. The newly-developed electro-hydraulic firing head combines the long downhole life of a hydraulic firing head with the capabilities of an electronic firing head. An electronic module is programmed at surface to respond only to a pre-programmed pressure signature. Upon detecting this signature, the electronic module activates the hydraulic firing mechanism, initiating the perforating guns below. This hybrid design incorporates safety features that were previously unique to each type of firing head. The hydraulic firing mechanism, which uses a percussion detonator, eliminates the need for electronic detonators that are sensitive to electro-magnetic interference (EMI) caused by rigsite communications devices. Additionally, this mechanism must have several thousand PSI to function, making surface detonation impossible. The electronics module prevents the firing head from functioning from an unintended overpressure of the wellbore, greatly reducing the possibility of firing off-depth. This paper will discuss the design, development, and testing of this firing head from a mechanical and electrical engineering point of view, as well as the operational reliability, safety, and human interface features included in the design. In addition, it will discuss the test plan to qualify the tool for reliable and safe operations at up to 30,000 psi at 400ºF, as well as the test results.
The past several decades have shown a steady trend of work performed in increasing well temperatures and pressures; however, the industry has been slow to adopt new methods in the design of equipment to be used for these wells. As a result, certain types of equipment are now insufficient for operations in high-pressure, high-temperature (HPHT) wells. This hinders the development of HPHT fields and reduces the ultimate recovery from those fields; technologies that are successfully used in conventional wells are only very reluctantly used in HPHT wells.Drillstem Testing (DST) valves are used for DST work, but also for tubing-conveyed-perforating (TCP) "shoot and pull" operations. These valves enable under-and over-balanced perforating, increasing the perforation quality and minimize the formation damage caused by kill fluids. However, these types of valves are frequently perceived as insufficiently reliable for TCP operations in HPHT wells, and frequently simpler perforation jobs are performed, sacrificing perforation performance for reliability.A new DST Combined Test tool was designed with advanced analysis methods. These methods include not just stress and deflection analysis, but also an analysis of historic failure modes, including human factors, and the implementation of mechanical fail safes to prevent them in the new valve. The valve was tested to 30,000 psi hydrostatic with tubing pressure in excess of 40,000 psi, and at 400°F. Finally, the valve has been successfully deployed on field trials. This paper will present an overview of the valve development as a case study for the development of future HPHT tools.
Typical wells in the Filanovskogo field are in a multi-zone reservoir with heterogeneous production flow profiles. The use of inflow control devices (ICD) in conjunction with zonal isolation packers, though successful, continues to evolve to improve overall ICD performance. However, in a contemporary cost-driven oil and gas market, persistent innovation has resulted in ICD performance improvement, and it has introduced changes that yield cost-effective deployment approaches, as evident in this case for Filanovskogo field. This paper details the inherent production challenges posed by the heterogeneity of Filanovskogo reservoir flow profiles. Analysis of the flow profiles facilitated an optimal inflow control modeling that efficiently balanced the production inflow across the various zones and provided means to restrict water inflow selectively. The ICD modeling yielded a solution that assured an improvement in oil recovery from the reservoir. In addition to the sought-after production benefit, the completion design incorporated equipment that collectively reduced operation sequence. The executed completion design features installation of nozzle-type ICDs fitted with premium screens and integral screen isolation valves. An in-depth look into the operational steps is provided, along with a comprehensive review of the technologies that facilitated this streamlined execution. This review includes a technical overview of the integral sliding choke sleeve of the ICD that can be actuated open/close in the future to manage water ingress. The outcome of this completion design is a solution that saves wellsite operating hours, allows execution of multiple steps simultaneously, depicts production flow balance, and ultimately delivers an enhanced oil production lifespan. This completion design has leveraged the successes from industry best practices, particularly in ICD applications, to devise a region-specific solution that is relevant in today's cash-conservative market.
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