The method for modeling of a multilateral well design that is completely independent on the simulation grid and fluid properties is proposed. The method takes into account friction in the lateral branches and crossflow between them. Well parameters, such as trajectory, perforation intervals, roughness and diameter, are directly used to calculate pressure distribution along the wellbore at the current fluid composition and tubing head pressure (THP).
Well connections with grid blocks in a finite volume approximation for dynamic model should be created. The automatic creation of the well connections during dynamic simulation based on specified well trajectory and completion intervals is proposed. The connection factor is suggested to be calculated based on length of completion intersection with the block, trajectory direction and rock properties during the run time. To calculate pressure drop on well track intervals between connections and the well track intervals between top completion and tubing head the well-known correlations are utilized. The correlations are used for the current fluid composition in the wellbore in each connection using information for well trajectory, roughness and diameter.
Such an approach makes it possible to get rid of the use of the tabulated bottomhole pressure (BHP) as a function of tubing head pressure for a number of phase compositions. Such traditional use of phase compositions gives a non-physical response in compositional models, where the component composition of the product varies significantly throughout the life of the field. Usage of real coordinates (x, y, z) for setting well trajectory and perforation intervals, instead of the traditional grid block numbers (i, j, k), allows to calculate layer intersection, connection factors and pressure distribution along wellbore with arbitrary changes in the dynamic model grid, for example, when introducing local grid refinement or dynamic grid and rock properties variation used to describe hydraulic fracturing.
The proposed method is successfully used for modeling of a multilateral well design in dynamic simulation. The results of such dynamic simulation are consistent with the real samples from reservoir.
Video images have traditionally provided intuitive visual analysis in a wide range of wellbore diagnostic situations. Step changes in computer vision techniques and image processing have led to the ability to make measurements from images (visual analytics). This paper demonstrates several applications where the application of this new data analytics source, combined with state-of-the-art acquisition technology, have further improved understanding of complex well issues while reducing operational time, risk and cost. Examples include hydraulic fracturing, well integrity, erosion, restrictions and leaks. The paper will describe the methods and process of this visual analytics technique through discussion of the three main work flow stages from data acquisition to final analytical product, including the innovative developments in sensor, system and computer vision applications that support each step: 1. Acquisition of full circumferential, depth-synchronized video data of the wellbore. An array of four orthogonally positioned cameras, pointing directly at the pipe wall, concurrently record overlapping images, enabling a continuous full-well video dataset to be obtained.
Jackson, A. C. (Chevron Corporation) | Dean, R. M. (Chevron Corporation) | Lyon, J. (Chevron Corporation) | Dwarakanath, V. (Chevron Corporation) | Alexis, D. (Chevron Corporation) | Poulsen, A. (Chevron Corporation) | Espinosa, D. (Chevron Corporation)
Reservoir management for an economically successful chemical EOR project involves maintaining high injectivity to improve processing rates. In the Captain Field, horizontal injection wells offshore have been stimulated with surfactant-polymer fluids to reduce surrounding oil saturations and boost water relative permeability. The surfactant-polymer stimulation process described herein enables a step change in injectivity and advances the commercialization of this application. This paper explains the damage mechanism, laboratory chemical design, quality control through offshore field execution and data quantifying the results.
Phase behaviour laboratory experiments and analytical injectivity models are used to design a near wellbore clean-up and relative permeability improvement. Three field trials were conducted in wells that had observed significant injectivity decline over 1-3 years of polymer injection. Surfactant and polymer are blended with injection water and fluid quality is confirmed at the wellheads. Pressure is continuously monitored with injectivity index to determine the chemical efficiency and treatment longevity. Oil saturation changes and outflow profile distributions are analysed from well logs run before and after stimulating. Learnings are applied to refine the process for future well treatments.
The key execution elements include using polymer to provide adequate mobility control at high relative permeability and ensure contact along the entire wellbore. Repeatability of success with surfactant-polymer injection is demonstrated with decreased skin in all the wells. The key results include the oil saturation logs that prove the reduction of oil near the well completion and improves the relative permeability to aqueous phase. The results also prove to be sustainable over months of post-stimulation operation data with high injectivity.
Injectivity enhancement was supported by chemical quality control through the whole process. From laboratory to the field (from core flood experiments to dissolution of trapped oil near wellbore), surveillance measurements prove that the chemical design was maintained and executed successfully. The enhanced injectivity during clean-up allows for higher processing rate during polymer injection and negates the need for additional wells.
The application of surfactant-polymer technology can rejuvenate existing wells and avoid high costs associated with redrilling offshore wells. This improves processing rate for EOR methods and can even be applied to waterflood wells to improve the injectivity, e.g low permeability reservoirs.
A long-term suspended subsea exploration well within a producing gas reservoir needed to be decommissioned after 21 years. During a pre-decommissioning diving campaign, bubbles confirmed as reservoir gas were observed to be percolating from the well bore through a hard silt / cement debris plug inside the wellhead. A pressure study established that the reservoir may have re-charged to 2,200 psi. An alternative pressure controlled well re-entry method was required to safely re-enter, tie-back the well to surface with 16-in. high pressure riser, install BOP while preventing gas from reaching the rig floor from seabed. Two existing cement plugs would then be drilled out under controlled conditions due to the potential for high-pressure gas beneath the plugs. Casing integrity evaluation and cement bond logging would be carried out to establish the path of gas ingress into the wellbore. Remedial work would be conducted, and permanent abandonment barriers installed in the well. Casings and wellheads would then be recovered from a depth below the seabed.
A customized managed pressure drilling (MPD) system was designed using a rotating control device (RCD) and modified drilling chokes. A pioneering plan was developed to meet the specific well re-entry requirements of the percolating suspended well to account for the potential for virgin reservoir pressure at seabed and the wellhead silt plug preventing deployment of BOP test tools. A hazard and operability study (HAZOP) was conducted with key personnel, which supported development of well-specific operating procedures and decision matrices. Successful deployment included MPD system calibration, well behavior fingerprinting, and training of rig personnel at the well site.
The combination of experienced personnel, innovative MPD equipment, specific procedures, team interactions and risk analyses were key to safely completing this well re-entry and decommissioning scope. The strategy enabled drilling out of two cement plugs with potential high-pressure gas trapped beneath them. Both cement plugs, 356ft and 669ft long, were drilled without any well-control or plugged-choke events. Throughout the process, the well was monitored using MPD equipment, which included an RCD on top of rig's BOP, modular drilling chokes and multiple pressure gauges and sensors installed at critical points. Additionally, temporary modifications were made to the rig and new lines of communication between the rig crew and the MPD team were established to ensure all pressures were correctly interpreted and the decision matrix was correctly applied. An effective close partnership developed between the equipment service provider, well operator and drilling contractor was a key enabler to deliver this very challenging novel implementation of MPD technology within eight weeks. The MPD approach was estimated to have saved 9 days of rig time, when compared to alternative coiled tubing-based solutions.
This paper describes the first MPD-assisted well re-entry for well decommissioning in the UK North Sea sector. The novel application of existing technology can help operators to cost effectively re-enter and decommission troublesome legacy wells without harm to people, environment or assets. This new approach resulted in the safe unconventional re-entry and decommissioning of a potentially live gas well.
Understanding pressure and pressure relationships is the key to safe well control. Yet, to date, the primary focus of well control has centred on recovery rather than prevention. Incidents related to loss of well control largely occur when the primary barrier, hydrostatic pressure from the drilling fluid, fails to prevent an influx; thus requiring the secondary barrier, closing of the BOPs, to engage in order stop the breach from becoming a full-blown, well control incident. Influxes occur, most often, during the tripping operation where the swab effect lowers the bottomhole pressure below the formation's pressure and can be commonly misidentified when "wellbore breathing," nuisances gases, or cement setting are involved. Influxes can also occur when drilling into unexpected, higher-pressure zones.
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Improvements in MEMS sensor technology are creating rapid momentum toward the use of tiny, rugged, and inexpensive sensors to replace larger, costlier, and more fragile legacy-technology sensors in directional drilling. A new holistic approach to optimizing wellbore economics is bridging the gap between planning and execution and bringing well construction into the digital era to improve data use, enhance collaboration, boost efficiency, and increase safety.
The effects of adding iron oxide NPs on the rheological and filtration properties of aqueous bentonite suspensions have been studied by several researchers. This paper presents an investigation into the effect of catalytic nanoparticles on the efficiency of recovery from continuous steam injection. A number of ongoing industry research projects are developing nanoparticles that work at the reservoir level and for fluid treatment. Though they may be a few years away from finalization, these efforts highlight nanotechnology’s increasingly sophisticated and growing application scope. This work focuses on the laboratory techniques for developing, assessing, and analyzing innovative water-based drilling fluids containing iron oxide (Fe2O3) and silica (SiO2) nanoparticles.
A common theme worldwide in the production of gas fields is the eventual requirement to deliquify the wells. Depending on depth and location, many successes and challenges are encountered. This session looks at field cases to document industry best practices, funda.m.entals and applications for gas well deliquification leading to optimal field development. We invite stories covering the widest variety of measures ranging from the most common (automated intermittent production, surface compression and velocity string) and the well specific (foa.m.-assisted lift, plunger lift) to the most advanced (gas lift, downhole pumping). Production wells in gas reservoirs with an active aquifer are vulnerable to liquid loading issues as the gas-water contact rises with depleting reservoir pressure and ultimately reaches the well.