Saasen, Arild (University of Stavanger) | Pallin, Jan Egil (JAGTECH AS) | Ånesbug, Geir Olav (JAGTECH AS) | Lindgren, Alf Magne (Schlumberger Oilfield Services) | Aaker, Gudmund (Schlumberger Oilfield Services) | Rødsjø, Mads (AkerBP)
Different logging operations can suffer from presence of metallic particles in the drilling fluids. Directional drilling in Arctic areas can be a challenge because of magnetic contamination in the drilling fluid. This is a challenge especially when drilling east-west relative to the magnetic north direction. Magnetic and paramagnetic particles in the drilling fluid will shield the down hole compasses and introduce additional errors to the surveying than those normally included in the uncertainty ellipsoid. The objective of the project is to remove the magnetic particles being the largest contributor to this error.
On many offshore drilling rigs there is mounted ditch magnets to remove metallic swarf from the drilling fluid. These magnets will normally only remove the coarser swarf. In this project we use a combination of strong magnets and flow directors to significantly improve the performance of the ditch magnets. This combination, together with proper routines for cleaning the ditch magnets significantly helps cleaning the drilling fluid.
By the combined use of flow directors and ditch magnets it was possible to extract more than five times as much magnetic contamination from the drilling fluid. This is verified by comparing the ditch magnet efficiencies from two drilling rigs drilling ERD wells. The logging tool signal strengths of several down hole instruments were unusually good and insignificant down times were observed on the logging tools. The results are anticipated to have aided to the directional drilling performance.
Detailed information on how to clean the drilling fluid properly from magnetic contamination is presented. It is also shown that this cleaning is significantly better than conventional cleaning of magnetic debris from drilling fluids.
Leaders from two large US onshore rig contractors said their expectations that the rig-count slide would hit a second-quarter bottom were off and are now refraining from making new predictions as to when it will end. Moving their directional drillers into their Houston real-time remote operations centers has improved drilling efficiency for two of the top shale producers. What Happens to Directional Drillers When Computers Are Directing Drillers? Software that offers turn-by-turn directions for drilling a horizontal well could drastically reduce the number of directional drillers. A new rotary-steerable system (RSS) was designed to give geometrically greater dogleg-severity (DLS) capability while still being able to withstand the increased bending stresses.
The $5.6-billion deal includes the Prudhoe Bay field and the Trans Alaska Pipeline and vaults Hilcorp to be the second-largest Alaska producer and reserves holder, behind only ConocoPhillips. The green light comes 4 years after the privately-held firm filed its development and production plan. Liberty Island would consist of gravel, stretch 9 acres, and sit just a few miles offshore. The technology will provide Equinor a continual feed of updated reservoir information from its Johan Castberg and Johan Sverdrup fields with the aim of improving well placement, production, injection, and—ultimately—recovery. Norway hopes for a continued rise in offshore exploration and development activity to ensure steady oil and gas production through the next decade. Equinor has grabbed seven new licenses in the Barents and Norwegian Seas, the latest in a flurry of offshore activity in which the firm has added acreage off the UK and Brazil, gained approval for a big Arctic project, and awarded billions of dollars in service contracts.
Because of the inherent curvature (angle build sections) and angled bottomhole segment of directional and horizontal wells, optimization of a progressive cavity pump (PCP) system design for such applications begins with the drilling program. The first line of defense against rod/tubing-wear and sucker-rod fatigue problems in deviated and horizontal wells is a good wellbore profile (see previous sections on rod-string/tubing wear and rod loading). Ideally, the planned angle build rates should be kept as low as practical, and additional monitoring is typically required during drilling to ensure that the well closely follows the prescribed path. Note that slant wells (wells spud at an angle on surface), which typically have no planned curvature, often provide a good alternative to deviated wells for shallow reservoir developments as a means to avoid rod/tubing-wear problems. With slant wells, it is important to ensure that the well profile remains straight and does not "drop down" into the target bottomhole location.
Different factors are involved at each stage within the overall constraints of optimum reservoir penetration. Most directional wells are drilled from multiwell installations, platforms, or drillsites. Minimizing the cost or environmental footprint requires that wells be spaced as closely as possible. It has been found that spacing on the order of 2 m (6 ft) can be achieved. At the start of the well, the overriding constraint on the well path is the presence of other wells.
Directional drilling is defined as the practice of controlling the direction and deviation of a wellbore to a predetermined underground target or location. This section describes why directional drilling is required, the sort of well paths that are used, and the tools and methods employed to drill those wells. Field developments, particularly offshore and in the Arctic, involve drilling an optimum number of wells from a single platform or artificial island. Directional drilling has helped by greatly reducing the costs and environmental impact of this application. A well is directionally drilled to reach a producing zone that is otherwise inaccessible with normal vertical-drilling practices.
The following are some of the most common sources of error in directional drilling. The survey instrument's performance depends on the package design elements, calibration performance, and quality control during operation. System performance will functionally depend on the borehole inclination, azimuth, geomagnetic-field vector, and geographical position. Because of the dependency on sensing Earth's spin rate, the performance of gyro compassing tools is inversely proportional to the cosine of the latitude of wellbore location. For magnetic tools, high latitudes result in weaker horizontal components of Earth's field.
As the quest for new petroleum supplies has increased in the past few years, operators have been forced to drill deeper to find new reserves. Much of the higher cost of drilling deeper, especially onshore, is typically associated with decreased rate of penetration (ROP) caused by both harder rock and higher mud weights required to counter the overpressured reservoirs often associated with deeper drilling. The following discussion centers on technologies intended to enhance the deep drilling capability. Industrial hammers for hard rock drilling have been around for some time, but most have been air operated and used in the mining industry. Historically, hammers have been thought to have limited capability in oil and gas drilling operations, with their use limited to air drilling.
Klie, Hector (DeepCast.ai) | Klie, Arturo (DeepCast.ai) | Rodriguez, Adolfo (OpenSim Technology) | Monteagudo, Jorge (OpenSim Technology) | Primera, Alejandro (Primera Resources) | Quesada, Maria (Primera Resources)
The Vaca Muerta formation in Argentina is emerging as one of the most promising resources of shale oil/gas plays in the world. At the current well drilling pace, challenges in streamlining data acquisition, production analysis and forecasting for executing timely and reliable reserves and resource estimations will be an overarching theme in the forthcoming years. In this work, we demonstrate that field operation decision cycles can be improved by establishing a workflow that automatically integrates the gathering of reservoir and production data with fast forecasting AI models.
We created a data platform that regularly extracts geological, drilling, completion and production data from multiple open data sources in Argentina. Data cleansing and consolidation are done via the integration of fast cross-platform database services and natural language processing algorithms. A set of AI algorithms adapted to best capture engineering judgment are employed for identifying multiple flow regimes and selecting the most suitable decline curve models to perform production forecasting and EUR estimation. Based on conceptual models generated from minimum available data, a coupled flow-geomechanics simulator is used to forecast production in other field areas where no well information is available. New data is assimilated as it becomes available improving the reliability of the fast forecasting algorithm.
In a matter of minutes, we are able to achieve high forecasting accuracy and reserves estimation in the Vaca Muerta formation for over eight hundred wells. This workflow can be executed on a regular basis or as soon as new data becomes available. A moderate number of high-fidelity simulations based on coupled flow and geomechanics allows for inferring production scenarios where there is an absence of data capturing space and time. With this approach, engineers and managers are able to quickly examine a feasible set of viable in-fill scenarios. The autonomous integration of data and proper combination of AI approaches with high-resolution physics-based models enable opportunities to reduce operational costs and improving production efficiencies.
The integration of physics-based simulations with AI as a cost/effective workflow on a business relevant shale formation such as Vaca Muerta seems to be lacking in current literature. With the proposed solution, engineers should be able to focus more on business strategy rather than on manually performing time-consuming data wrangling and modeling tasks.